HomeMy WebLinkAboutReconnaissance Study of the Kisaraluk River Hydroelectric Power Potential & Alternate Electric Resources in the Bethel Area 1980UWftARALIK
CONTRACT NO. 9703
This report has been prepared by
Frank J. Bettine, E.I.T
Carl H. Steeby, P.E.
Dora L. Gropp, P.E.
Information on Geothermal Energy
Resources and Hydroelectric Site Geology
was provided by
C. C. Hawley Associates
---,--
;I~/ :. l
c. d...
RECONNAISSANCE STUDY
OF THE KISARALIK RIVER
HYDROELECTRIC POWER POTENTIAL AND
ALTERNATE ELECTRIC ENERGY RESOURCES
IN THE BETHEL AREA
Prepared for the
ALASKA POWER AUTHORITY
Prepared by
ROBERT W. RETHERFORD ASSOCIATES
Consulting Engineers
ARCTIC DISTRICT OF INTERNATIONAL ENGINEERING CO., INC.
P.O. BOX 6410
Anchorage, Alaska 99502
March 1980
Bethel -Table of Contents
APAI0/C3
I.
II.
III.
IV.
V.
TABLE OF CONTENTS
INTRODUCTION AND SUMMARY
EXISTING SYSTEMS AND FUTURE ELECTRIC
POWER REQUIREMENTS
PAGE
1-3
II-I
A. Existing Facilities 11-1
B. Historical Information 11-1
C. Future Electric Energy and Demand Projections 11-2
l.
2.
Bethel
Small Communities
ELECTRIC ENERGY RESOURCES
A.
B.
Introduction
Energy Resources
1. Hydroelectric Potential~
2. Coal/Wood Energy Conversion & Resources
3. Geotherma 1 Potentia 1
4. Wind Potential -Bethel Area
5. Transmission Interties
6. Conservation
ECONOMIC FEASIBILITY ANALYSIS
A. Introduction
B. Alternate Development Plans
C. Evaluations and Conclusions
RECOMMENDATIONS
A. Introduction
B. Development of the Kisaralik River
Hydroelectric Site
- i -
II-2
II-6
III-l
III -1
III-l
III -2
II 1-26
III-36
III-47
I II -64
II 1-68
IV-l
IV-l
IV-3
IV-6
V-I
V-I
V-I
Bethel -Table of Contents
APAI0/C4
APPENDICES
A. TECHNICAL DATA
1.
2.
3.
4.
5.
6.
7.
8.
Single Wire Ground Return Transmission
Distribution and Transmission Line Load
Limitations
Phase -and Frequency Conversion in Power
Transmission
Economic Distance for SWGR
Controlled Electric Heat - A Potential Market
for Unused Energy from Hydro Electric Power
Project
Nulato Coal Field Reconaissance Report
Listings of Biomass Energy Conversion Processes
Kisaralik Hydroelectric Project Hydrological
Analysis
B. COST ESTIMATES
1.
2.
3.
Transmission Systems
Wind Generating Equipment
Frequency and Phase Conversion Equipment
C. ECONOMIC EVALUATION -DETAIL SHEETS
1. List of A lternat i ves
11. Parameters Used for Economi c Eva 1 uat ion
II 1. Exp 1 anat i on of Computer Pri ntouts
D. ENVIRONMENTAL AND OTHER COMMENTS
1. Letter From State of Alaska -
Department of Fish & Game
2. Letter from BLM -Land Status
-ii -
PAGE
A-3
A-17
A-23
A-29
A-37
A-43
A-51
A-57
B-1
B-3
B-3
C-l
C-l
C-6
",.
•
• .,
•
..
..
-•
.' • -..
.,
Bethel -Table of Contents
APAI0/C5
FIGURE
I-I
1-2
II-I
II-2
II-3
II-4
II-5
II-6
II-7
II-8
II-9
I 1-10
II-ll
11-12
II-13
11-14
II I-I
III-2
III-3
III-3.1
III-3.2
III-3.3
III-4
III-5
III-6
III-7
III-8
II 1-9
II 1-10
IV-l
to
IV-4
A-l.l
A-4.1
LIST OF FIGURES
Lower Kuskokwim Vicinity Map
Transmission Interties -Bethel Area
Bethel Utilities Monthly Energy
Generation and Demand
Bethel -Power Requirements
Eek, Kasigluk & Nunapitchuk Month
Energy Generation
Akiachak -Power Requirements
Akiak -Power Requirements
Akolmuit -Power Requirements
Atmautluak -Power Requirements
Eek -Power Requirements
Kwethluk -Power Requirements
Napakiak -Power Requirements
Napaskiak -Power Requirements
Oscarville -Power Requirements
Tuluksak -Power Requirements
Tuntutuliak
Regional Electric Intertie
Kisaralik Project
Kisaralik River Area Capacity Curve
Mitchell Geothermal Site Map
Tuluksak Geothermal Site Map
Ophir Creek Geothermal Site Map
Kisaralik Project -General Plan & Layout
Kisaralik Project -Construction Schedule
Kisaralik Project -Tunnel & Powerhouse
Kisaralik Project -Typical Dam Section
Combination of Wind Speed Duration Curve
and WECS Power Characteristic
WECS versus Diesel
Bethel Plus 12 Villages Intertie
Graphical Comparison of Economic Alternatives
Spruce A-Frame Structure
Line Mile Multiplier
-iii -
PAGE
I-I
1-8
II-3
II-4
II-7
II-I0
11-12
II-14
I 1-16
11-18
11-20
11-22
II-24
11-26
II -28
II-3D
I II -3
III-6
II 1-18
II 1-38
II 1-42
II 1-44
I II -12
II 1-19
III-21
III-22
I II-53
II I-59
II 1-66
IV-I0
to
IV-13
A-6
A-33
Bethel -Table of Contents
APAIO/C6
TABLE
I-I
1-2
II-I
II-2
II-3
II-4
II-5
II-6
II-7
II-8
II-9
I 1-10
II-II
11-12
I 1-13
I II-I
I II-2
II 1-3
II 1-4
I II-5
I II-6
1V-l
1V-2
1V-3
A-2.1
A-3.1
A-5.1
A-5.2
C-1.1
LIST OF TABLES
Busbar Cost of Electric Energy
Power Requirements 1980-2000
Bethel Electric Power Requirements
Power Requirements 1980-2000
Akiachak Electric Power Requirements
Akiak Electric Power Requirements
Akolmuit Electric Power Requirements
Atmautluak Electric Power Requirements
Eek Electric Power Requirements
Kwethluk Electric Power Requirements
Napakiak Electric Power Requirements
Napaskiak Electric Power Requirements
Oscarville Electric Power Requirements
Tuluksak Electric Power Requirements
Tuntutuliak Electric Power Requirements
Table of Significant Data -Kisaralik River
Kisaralik River Project -Cost Estimates Summary
Kisaralik River Project -Cost Estimates Detailed
Average Power OUtput
WECS Mean Output Power
Regional Interties
Accumulated Present Worth & Equivalent Unit Costs
Cost Ratios of Accumulated Present Worth
Cost Ratios of Equivalent Unit Costs
Line Loading Limits
Low Frequency Line Loading Limits
Electric Heat, Bethel Area, High Load Growth
Electric Heat, Bethel Area, Low Load Growth
Fuel Cost for Bethel Area
- ; v -
PAGE
1-4
1-6
II-5
II-8
II-l1
11-13
11-15
II-l7
11-19
II-21
II-23
II-25
11-27
II-29
II-31
I II-4
II I -20
II 1-23
111-55
III-57
II 1-65
1V-7
IV-8
IV-9
A-19
A-24
A-39
A-40
C-4
..
.. '
..
.'
.,
.,
•
...
..
ALASKA \
\ \")~
• C~,,~
FAIRBANKS \
A oS .p O ••.. L£ LAN ..... I.Ir I A N IS 4fIo. .
III· ~ .IfIIli' ., .:.
VICINITY MAP
T _ 1
FIGURE 1-I
Bethel -Section I
APA013/I
A. INTRODUCTION
I. INTRODUCTION AND SUMMARY
This reconnaissance study has been performed for the Alaska Power
Authori ty (AKPA) under the contract "Reconnai ssance Study for
Hydroelectric Development at Lake Elva Near Dillingham and on the
Kisaralik River Near Bethel" dated August 13, 1979. The purpose of
this study is to evaluate the previously identified hydroelectric
power potential and other alternative electric energy resources for
the Bethel area.
B. SUMMARY
The Bethel area (Figure 1-1) 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
possible alternate developments have therefore been compared to the
basic case of continued exclusive diesel generation.
The most promising development plan has been found to be development
of the hydroelectric potential of the Kisaralik River. It has been
assessed as feasible in regard to cost, capacity, environmental
impact, and 1 and status. Sens i t i vi ty to load growth and vari ous
interest rates has been determined.
The following paragraphs will summarize the main sections of the
report.
1. Existing Systems and Future Power Requirements
Power requirements have been estimated for 12 communities in
the Bethel area. The communities included have been those
within an "economic" distance. This distance has been defined
by calculating the busbar electric energy cost in the community
for local diesel generation and comparing it to the bus bar
cost resulting from a potential transmission tie to a large
central generating plant. One scenario utilizing the historical
growth rate and one with a lower growth rate have been estab-
lished. Whether the "high" or "low" load growth case are
realized will 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 sO,urce of electric energy is available, it is
anticipated that the historic growth rate will continue and
industrial development will be encouraged. Table I-I summarizes
the anticipated power requirements.
1-3
mis8/nl
POWER REQUlrlEMENTS POWER REQUIREMENTS
[lETHEL . 12 SMALL COt'MliNITIES BETHEL' 12 SMALL COMMUN!TIES
19!:(1 -2000 19BO -2000
HIGH LOIID GROWTH LOW LOAD GROWTH
Loc~t;on 1979 ~ ~ ....1.Q.Q.Q.... Location 1979 ~ 1990 2000 ---
Akiachak Akiachak
Demand -kW 90.0 92.2 142.3 565.4 Demand -kW 90.0 92.2 101.9 204.7
Energy -M\\'h/yr 315.5 323.3 623.3 2,476.3 Energy -MWh/yr 315.5 323.3 446.5 896.5
Akiak Akiak
Demand -kW 45.0 46.7 76.1 242,9 Demand -kW 45.0 46.7 51.5 70,0
Energy -MWh/yr 157.7 163.5 333.3 1,063.9 Energy -MWh/yr 157.7 163.5 225.6 306.8
Akolmuit Akolmuit
Dem~nd -kW 147.1 151.1 342.5 986.1 Demand -kW 147.1 151.1 245.5 320.0
Energy -MWh/yr 644.1 662.0 1,500.1 4,319.0 Energy -MWh/yr 644.1 662.0 1 ,075.1 1,401.5
Atmauthluak Atmauthluak
Demand -kW 47.4 48.5 77.9 196.5 Demand -kW 47.4 48.5 53,8 61.S
Energy -MWh/yr 166.1 170.1 306.9 860.6 Energy -MWh/yr 166.1 170.1 212.0 270.6
Bethel Bethel
Dem~nd • kW 4,397.0' 4,666.4 9,022.8 20,016.4 Demand -kW 4,397.0 1 4,666.4 7,338,9 11,249.0
Energy -MWh/yr 1,9817 .0' 21,256.5 43,472,0 96,439.2 Energy -MWh/yr 1,9817.01 21,256.5 35,358.7 54,197.5
Eek Eek
Demand -kW 49.4 50.9 89.3 295.9 Demand -kW 49.4 50.9 58.8 78.4
Energy -MWh/yr 194.9 200.5 391. 5 1,296.2 ...... Energy -MWh/yr 194.9 200.5 257,5 343.5
I Kwethluk Kwethluk .+=> Demand -kW 104.8 108.8 233.8 672.3 Demand -kW 104.8 108.8 171.1 232.9
Energy -MWh/yr 367.2 381.4 1,024.0 2,944.9 Energy -MWh/yr 367.2 381.4 749.3 1,019.9
Napakiak Napakiak
Demand -kW 97.2 99.2 168.6 706.7 Demand -kW 97.2 99.2 119.7 248.3
Energy -MWh/yr 340.6 350.1 738.5 3,095.4 Energy -MWh/yr 340.6 350.1 524.5 1,087.5
Napaskiak Napa.kiak
Demand -kW 73.5 75.3 122.1 388.8 Demand -kW 73.5 75.3 83.8 119.7
Energy -MWh/yr 257.7 263.9 534.9 1,702.8 Energy -MWh/yr 257.7 263.9 367,1 524.2
O.carville O.carville
Demand -kW 20.1 20.4 31.6 97.0 Demand -kW 20.1 20.4 20.8 26.3
Energy -MWh/yr 70.6 71.4 138.4 425.0 Energy -MWh/yr 70.6 71.4 91.0 115.4
Tuluksak Tuluk.ak
Demand -kW 51.8 53.1 87.1 299.0 Demand -kW 51.8 53,1 59.4 88.5
Energy -MWh/yr 181.6 186.0 381.6 1,309.4 Energy -Ml'.'h/yr 181.6 186.0 260.0 387.6
Tuntutuliak Tuntutuliak
Demand -kW 64.8 66.4 117.0 420.4 Demand -kW 64.8 66.4 80.5 128.3
Energy -MWh/yr 227.0 232.7 512.5 1,841.4 Energy -MWh/yr 227.0 232.7 352.7 562.1
Total Total
Demand -kW' 5,188.0 5,479.0 10,511.0 24,887.4 Demand -kW· 5,188.0 5,479.0 8,385.7 12,827.9
Energy -MWh/yr 22,740.0 24,261.4 49,957.0 117,774.1 Energy -MWh/yr 22,740.0 24,261.4 39,920.0 61,113.1
. Noncolncident. " Noncoincident.
Extrapolated from 1978. Extrapolated from 1978.
POvJer Requi rements 1980 to 2000
Table 1-1
• • , , .. 1 f , f • , , ! , , , r I ~ I 1l • n " ~ .~ ~ 'I
Bethel -Section I
APA013II
2. Electric Energy Resources
The Kisaralik River, attributary to the Kuskokwim, has potential
for hydroelectric development. The site is located approximately
69 miles southeast of Bethel. By constructing a 300 1 high dam
near the Lower Falls a firm capacity of 15 MW or 131,400 MWh
per year can be obtained. The construction cost (1979-$) is
estimated at $99,657,000 for 2-15 MW generating units installed.
This includes the transmission line to Bethel. The construction
time is estimated to be approximately 4-5 years.
The hydro site is presently included in the 1978 federal
emergency withdrawals. Attempts to obtain a powersite exemption
should begin immediately.
A possible supplementary alternate energy resource to fuel oil
or hydroelectric resources appears to be wind energy conversion.
The available systems are still very costly, however, and
reliability of the equipment in Alaska has not proven to be
very high. 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 for
supplementary energy 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
Bethel area has to be anticipated between 30¢/kWh and 80¢/kWh.
(These costs are strictly for secondary, nonfirm energy and do
not include standby generators).
To utilize diesel generation more efficiently --if no other
source of electric energy is available --central generation
with transmission interties promises cheaper energy, if the
transmission ties are economically feasible. The single wire
ground return (SWGR) nne 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. Successful construction and
operation is expected to increase the use of this type of line
construction and make interties between small communities and
load centers possible. For this report the feasibility of
interties has been investigated for 11 communities in the
Bethel area. It is conceivable that busbar costs of electric
energy in the small communi ties coul d be lowered if the
interties to Bethel are built. This is mostly the result of
enhanced generating efficiency and lower fuel costs in Bethel
compared to the more remote communities.
Investigation of the Nulato coal field, to assess its potential
as an alternate energy source for the Bethel area yi e 1 ded
discouraging results. Commercial utilization of this resource
1-5
Bethel -Section I
APA0131I
does not appear to be feasible at this time. The presently
available information on wood does not allow proper assessment
of the utilization possibilities.
The geothermal resources i dent i fi ed are the Mi tche 11 site in
the Chuilnuk Mountains, Tuluksak Hot Springs near Nyal, and
Ophir Creek Hot Springs. Water temperatures below 150°F and
moderate fl ow rates make all but 1 oca 1 use uneconomi ca 1.
3. Economic Feasibility Analysis
The development of the Kisaralik River hydroelectric potential
and conservation of fuel by interconnecting small communities
to a central generating system appear to be the most promising
electric energy resources for the foreseeable future.
Alternate development plans have been evaluated for a regional
intertied system (See Figure 1-2) including up to 12 communities.
Ut i 1 i zing annual cost and present worth compari sons, the
following scenarios have been found to be the most advantageous
developments:
• Kisaralik River Hydro for a regional intertied systems.
• Regional Intertied System uS'ing Diesel Generation.
Transmission interties of 11 communities in the Bethel area to
the central generating plants in Bethel have been found feasibly
independent of hydropotential development. This is mostly due
to the high fuel cost in remote locations and low generating
efficiencies.
The following table will illustrate the economic differences
for the main alternate development plans investigated. Unit
costs for marketable energy (hi stori cal load growth) are
listed for a medium interest rate of 7%.
TABLE 1-2
Busbar
Cost of Electric Energy in ¢/kWh
Alternate Pl an 1980 1990 2000
Continued use of diesel (Bethe 1) 12.6 21. 0 35.8
Small communities, local diesel 32.7 62.0 102.1
Intertied system, diesel only 14. 7 20.8 35.1
Intertied system with Kisaralik Hydro 30.6 17.8
It should be noted that the above are bus bar costs --not costs to
the consumer.
1-6
...
..
...
.. ..
...
•
..
... "
-
Bethel -Section I
APA013/I
If the utilization of hydro generated electric energy in comfort
heating is considered, the busbar costs for 1990 and 2000 have been
calculated at 14.7¢/kWh and 15.6¢/kWh respectively.
4. Conclusions and Recommendations
The economic analysis clearly favors development of the Kisaralik
hydropotential for an intertied system of 12 communities. In
order to pursue implementation of this project an institution
must be identified that is capable of accomplishing the construc-
tion and operation of such a power system delivering the power
to the community distribution systems for use by the individual
utilities of each community. It is suggested that this
institution could be the Alaska Power Authority or a regional
entity that will receive the financial backing of the Alaska
Power Authority in order to obtain the lowest cost financing
for such projects as the Kisaralik.
A FERC license application for the Kisaralik hydro project
should be prepared as soon as possible to assure the earliest
possible start of construction.
1-7
H
I
:Xl
.I'i.'
~"
,.
"
K'rDAOELECTRJC 6t.NERATING PLANT WITH I~TALLED ~4NCJTY
SINGL~ ~WIRE GROUND RETURN TRANSMISSIOtf
TRANSMISSION LINt T9
AL~ERNMrE . ROUTE FOR SIH~~
REl'14AN. TRAt;fSMIS610N
\~--L~:
"," ,.: r ..w~sl fI) ,'f
~ 1\., v
,ot"
_ ... ......:..-~~-
t __ .~ !I •.
., .• -":<j(
),,~-
~--" .... r
.68.1
;_-";1.," . ,
~;;--~.
-'--~
" ~ .• ~" , . ~ -'~ -~
"
,:~ -
;:;-
Bethel -Section II
APA10/H
II. EXISTING SYSTEMS AND FUTURE ELECTRIC
POWER REQUIREMENTS
A. EXISTING FACILITIES
Electrical energy is supplied to Bethel and the surrounding villages
from a number of sources. The 1 argest s i ngl e source of power is
Bethe 1 Ut il it i es, wi th the e 1 ectri ca 1 load in Bethel bei ng some
5 times greater than the combined total of all villages within
50 miles of Bethel. All electrical energy in the area is produced
by diesel powered generators, and possibly a few gasoline powered
units serving individual homes. Following is a tabulation of known
village power sources.
Location Size (kW)l Owner 1
Aki achak4 330 City
Aki ak 250 City
Akolmuit 2 450 AVEC
Atmauthluak 50 Village Corp
. Bethel 8400 3 Bethel Utilities
Eek 206 AVEC
Kwethluk 4 125 Vi 11 age
Napakiak4 150 Napakiak Corp.
Napaskiak 4 200 Napaskiak Power
Oscarville Unknown Unknown
Tul uksak 4 200 Vi 11 age
Tuntutuliak4 Unknown Private
1 In addition to the units listed, most schools have standby
generators or provide their own prime power.
2 Kasigluk and Nunapitchuk combined.
3 Installing additional 2100 kW.
4 From 1978 survey, Alaska Department of Energy & Power
Deve 1 opment.
There are no interconnections between these systems, wi th one
I exception. Kas i gl uk and Nunapi tchuk are interconnected and are
often refered to as Akolmuit.
B. HISTORICAL INFORMATION
Available historical information is scarce, but enough does exist
to establish some trends. "1960 and 1970 population figures for
most villages were obtained from U.S. Census information. Actual
surveys of Akiachuk, Bethel, Kasigluk, Napakiak, and Nunapitchuk
II-I
Bethel -Section II
APA10/H
were performed in 1975 during preparation of a study, "A Regional
El ectri c Power System for the Lower Kuskokwi m Vi ci ni ty" performed
by Robert W. Retherford Associates for the Alaska Power Administra-
tion. That survey identified population, number of consumers by
class, and average electrical consumption by class of consumer.
Reliable historical records were obtained from Bethel Utilities for
Bethel and from AVEC for Akolmuit and Eek. Current population and
number of families for most villages was obtained from the AVCP
(Association of Village Council Presidents) Housing Authority. The
"1978 Community Energy Survey" published by the State of Alaska,
Department of Commerce and Economic Development, Division of Energy
and Power Development, provided information concerning population
levels and existing generating facilities.
The information available indicates a compounded annual population
growth rate of from 1 to 3% for the various villages, generally
decreasing family size, and moderate increases in intensity of
electrical usage for each consumer class.
C. FUTURE ELECTRIC ENERGY AND DEMAND PROJECTIONS
1. Bethel
Bethe 1 serves as the transportation and commerci a 1 hub for
surrounding villages and, as a result, participates indirectly
in the growth of all nearby villages. The electrical consumption
characteristics in Bethel already approach those of a typical
metropol itan area. Figure II-I shows the monthly energy
generation and demand for 1977-1978. Population is projected
to increase at 3% per year to 1985, and then at 2% through the
year 2000. Residential consumption is projected to increase
at 5% through 1985, and then at 4% through 2000. Consumption
by commercial and large power users is projected to increase
at 2% per year and large power users at 1% per year throughout
the period.
II-2
..
..
•
•
.,
--
..
.'
100
90
eo
70
60
50
40
30
20
4
10
9
8
7
6
4
3
2
C~~ ,
'c
---: (~---(
3
10
/,J
/
1)/
........ ........
........ (
~
'< ~ ~ '-'-..... c ~( -" 1,,;/
--~---~
"-----/ ,
? '( ~( ,
',< --~ ......
--
l~ ~ -(I>
\() ..... c --
~ ,.; \~1"
p""'" ~""'~
\() .,..
~ /
/ p ___ C
I
I
~
I.,. _ \,..1'. .41
--( ~ tc. ... _-< ~--
,) ~-~~ !)2
I
/ ,~ \,..1' .
/ M \918 -
/
~----
BETHEL UTILITIES
I
MONTHLY ENERGY GENERATION
AND DEMAND
1977 -1978
FI(;UKE II-I
JAN FEB MAR APR MAY JUNE JULY AUG SEPT OCT NOV DEC
Bethel -Section II
APAlO/H
100,000
90,000
80,000
70,000
80,000
110,000
40,000
30,000
20,000
10,000
9,000
8,000
7,000
8,000
11,000
4;000
3,000
2,000
1,000
For accelerated growth, consumption by residential & commerical
consumers in the year 2000 is projected to be approximately
200%, and large power consumption 140%, of that achieved
during "normal" growth. This implies that the individual rate
of electric energy use in Bethel will then be comparable to
the present average use in the Anchorage/Palmer area.
The power requirements for Bethel for 1978-2000 are illustrated
in Figure 11-2 and Table II-I.
BETHEL
POWER REQUIREMENTS 1978 -2000
~
--' ~
~
../' ---V" ~ ~
~ ~
--~ ~ ~~"
~ ",,7
",'
1'/ --.... ~ ..,.-~
-" .----.".-... --I~ ~-..".".
'I-~ >"'" ......... ---
."". ~-
1978 1980 1985 1990 1995 2000
FIGURE TI-2
II-4
..
...
HIGH
If'
lOW II<
iii ..
III
HIGH ... ..
lOW IIiIIF
•
~'
.,
iii>
•
iii
.,
" APA010/G5
TABLE 11-1
BETHEL
ELECTRIC POWER REQUIREMENTS 1979-2000
1978 1980 1990 2000
POPULATION 3,004 3,187 4,080 4,974
(1) # of residential 1,054 1,138 1,511 1,842
consumers
(2) average kWh/mol 346 381 (high) 709 1,500
consumers ( low) 593 877
(3) MWh/year residential 4,376.2 5,202.9 (high) 12,855.6 33,156.0
consumers (low) 10,752.3 19,385.2
(1)x(2)x1271000
(4) # of small commercial 225 ·265 369 449
consumers
(5) average kWh/mol 2,323 2,417 (high) 3,680 7,000
consumer (low) 2,946 3,591
(6) MWh/year 6,272.1 7,686.1 (high) 16,295.0 37,716.0
sma. com. cons. (low) 13,044.9 19,348.3
(4)x(5)x1271000
(7) # of large 5 5 6 7
cons. + public buildings
(8) average kWh/mo/cons 113,991 116,282 (high) 144,020 200,000
(low) 128,448 141,886
(9) MWh/year 6,839.5 6,976.9 (high) 10,369.4 16,800.0
LP's (low) 9,248.3 11,918.4
(7)x(8)x1271000
(10) System IVIWh/year 18,216.7 21,256.5 (high) 43,472.0 96,439.2
(3)+(6)+(9) (low) 35,358.7 54,197.5
(includes losses) 4.2% (high) 10% 10%
(low) 7% 7%
(11) System .52 .52 .55 .55
Load Factor
(12) System Demand 3,999.1 4,666.4 (high) 9,022.8 20,016.4
kW (low) 7,338.9 11,249.0
(10)78.7607(11)
11-5
Bethel -Section II
APA10/H
2. Small Communities
Population growth rates of from 1% to 3% per year were applied
to individual villages based upon historical growth rates,
location with respect to intensified commercial activity (up
river or down river from Bethel) and known planned activity.
Unless historical data indicate otherwise, family size is
projected to decrease 2% per year (affects number of residential
consumers), number of commercial consumers per residential
consumer is increased 1% per year, and an additional large
power consumer is added when population reaches approximately
500-600.
Annual load factor is assumed to be .40, gradually increasing
to .50 and losses plus power plant use are assumed to be 10%
unless available data indicate otherwise.
Monthly energy use in the 3 AVEC villages in the area is shown
in Figure 11-3 for 1978.
The above components, when combined, produce a conservative
project i on of II norma 111 growth, based upon current conditions
and continued reliance upon diesel fuel for electrical energy
and for heating. II Acce 1 erated ll growth is based upon the same
population growth rates, but assumes that hydroelectric or
other more economical power will become available. In that
case, rate of consumption for individual consumers is projected
to be approximately 4 times that projected for the IInormal"
growth rate in the year 2000. Table 11-2 lists the anticipated
electric power requirements through the year 2000 for the
entire Bethel area.
As stated earlier, the load in Bethel is some 5 times the
combined load of all other villages within 50 miles of Bethel.
This being so, inaccuracy in projecting loads in the villages
will not have a significant effect upon power requirements
projections for the total area if the Bethel projections are
reasonably accurate. However, an attempt has been made to
make reasonable projections for each village based upon
historical information and anticipated future conditions.
These individual projections are based upon trends for the
total group of villages.
For accelerated growth, consumption per residential consumer
is projected to be 3.7 to 4 t'imes "normal" consumption by the
year 2000, commercial consumption will be 3 to 5 times "normal"
and large power consumption will be 2 to 2.5 times normal.
There is a trend toward decreasing family sizes. As more
houses are built, households which consist of more than one
generation are able to divide into multiple households. Since
II-6
..
•
•
..
..
II>
..
10
9
8
7
6
5
4
2
9
8
7
6
5
4
2
"-'.
" .
t" ....... .... -\-
\.
\
'"
I ~\
~x 10-.-....... I \
1'-....1 \.
./ "'" f', ~./ , , I
,~ ---'" \
\ ~ .....
/\ .-
I \ /'
~.
./ ....... , I ~. I I /,;, ~.--\ I
........ II \ I --r--!. --"'" \ VI
/
I'"
EEK,KASIGLUK
8r NUNAPITCHUK UTILITIES
MONTHLY ENERGY GENERATION
1978
FIGURE 1I-3
EEK
_._._.-KASIGLUK
---------NUNAPITCHUK
I I I 10 2
JAN FEB MAR APR MAY JUNE JULY AUG SEPT OCT NOV DEC
TT-7
misB/nl
POWER IlEQUI!HMCNTS POWER nEQUIREM~NTS
OETHtL • 12 SMALL COMMUNITIE!:. BETHEL. '2 SMALL COMMUNITies
1900 • 2000 19UO • 2000
HIGH LOAD GROWTH LOW LOAD GROWTH
Location 1979 .....illL '990 2000 Localion 1979 1980 ~ ...2QQL
Akiachak Akiachak
Demand· kW 90.0 92.2 142.3 565.4 Demand· kW 90.0 92.2 101.9 204.7
Ene"gy • MWh/y" 315.5 323.3 623.3 2,476.3 Enerogy • MWh/yro 315.5 323.3 446.5 896.5
Akiak Akiak
Demand· kW 45.0 46.7 76.1 242.9 Demand· kW 45.0 46.7 5'.5 70.0
Ene"gy • MWh/yro 157.7 '63.5 333.3 1,063.9 Enerogy • MWh/yro 157.7 163.5 225.6 306.8
Akolmult Akolmult
Demand· kW 147.1 151.1 342.5 986.1 Demand· kW 147.1 151.1 245.5 320.0
Energy • MWh/y" 644.1 662.0 1 ,500.1 4,319.0 Enerogy • MWh/yro 644.1 662.0 1,075.1 1,401.5
Atmauthluak Almauthluak
Demand· kW 47.4 48.5 77.9 196.5 Demand • kW 47.4 48.5 53.8 61.8
Ene"gy • MWh/y,. 166. , 170.1 306.9 860.6 Ene"gy • MWh/yro 166.1 170.1 212.0 270.6
Bethel Bethel
Demand' kW 4,397.0 1 4,666.4 9,022.8 20,016.4 Demand· kW 4,397.0 1 4,666.4 7,338.9 11,249.0
Energy· MWh/y,. , ,9817 .0 1 2',256.5 43,472.0 96,439.2 Ene"gy • MWh/yro 1,98" .0 1 21,256.5 35,358.7 54,197.5
Eek Eek
Demand· kW 49.4 50.9 89.3 295.9 Demand· kW 49.4 50.9 58.8 78.4
...... Ene,.gy • MWh/y,. 194.9 200.5 391.5 1,296.2 Ene"gy • MWh/yro '94.9 200.5 257.5 343.5 ...... Kwethluk Kwethluk I D~molnd • kW 101\.8 108.8 233.8 672.3 Demand. kW '04.8 108.8 ",. , 232.9 CP Ene"gy • MWh/y,. 367.2 381.4 ',024.0 2,944.9 Ene"gy • MWh/yro 367.2 381.4 749.3 1,019.9
Napakiak Napakiak
Demolnd • kW 97.2 99.2 168.6 706.7 Demand· kW 97.2 99.2 119.7 248.3
Ene,.gy • MWh/y,. 340.6 350.1 738.5 3,095.4 En","gy • MWh/y,. 340.6 350.1 524.5 1,087.5
Napaskiak Napaskiak
D~mand • kW 73.5 75.3 122.1 388.8 Demand -kW 73.5 75.3 83.8 119.7
Energy· MWh/y" 257.7 263.9 534.9 1,702.8 Energy • MWh/yr 257.7 263.9 367.1 524.2
Oscar"ille Osc:ar"ill~
Demand • kW 20.1 20.4 31.S 97.0 Demand· kW 20.1 20.4 20.3 25.3
Energy • MWh/y~ 70.6 71.4 138.4 425.0 Ene:-gy -Mw:-./y,. 70.6 71.4 91.0 115.4
Tuluksak Tuluksak
Oema~d • kW S1.8 53.1 87.1 299.0 De~and • kW 51.a 53.1 59.4 88.5
:~~"gy • MWh/y~ 1S1.6 186.0 381.5 1.309.4 E~er9V -MY.'h/y,. 181.5 185.0 260.0 387.6
Tuntutuliak Tu~tutuliak
Demand· kW 54.8 66.4 1".0 420.4 Demand' kW 64.S 66.4 SO.5 128.3
E~ergy • MWh/y:-,27.0 232.7 512.5 1,841.4 Energy • MWh/y,. 227.0 232.7 352.7 562.1
Total Total
Demand -kW· 5,188.0 5,479.0 ·10.511.0 24.S87.4 Dema~d • kW" 5,188.0 5.479.0 a.385.7 12.927.9
Energy· MWh/y" 22.740.0 24,261.4 49,957.0 117.774.1 Ene"gy • MWh/y" 22.740.0 <:4.261.4 39.920.0 51.113.1
. Noncoinc:idrnt • " Nonc:oi~cide~~.
1 Extra;>olatl'd f~om 1978. Ext:-a:loleled f:-::>~ 19;<:.
Power Requirements 1980 to 2000
TABLE II-2
1 , ~ ~ ~ I f , ~ ~ , J
Bethel -Section II
APA10/H
each household represents a potential consumer, a decreased
population/residential consumer ratio of 2% per year has been
anticipated for most villages.
The present ratio of population/residential consumer is higher
for Akiak than the other vi llages. It has been assumed that
this ratio will decrease at 5% per year through 1985 and then
1 eve 1 off at a decl i ne of 2% per year to match the other
villages.
In Atmautluak and Eek the family size is already below that
found in the other vi 11 ages. A decrease in the rati 0 of
population/residential consumer of only 1% per year has
therefore been used.
A nominal relationship exists between the number of commercial
and residential consumers. As the number of residential
consumers increases, a greater number of commercial service
businesses can be supported. With the increasing commercial
nature of most village as opposed to the traditional subsistence
lifestyles, the number of commercial consumers per residential
consumer should increase or conversely the ratio of residential
consumers/commercial consumers should decrease. A 1% per year
change for all villages has been assumed.
Electric energy consumption per individual residential consumer
is projected to increase at 2% per year for all villages
except Akolmuit. Based upon historical information, a growth
rate of 1.5% is projected for Akolmuit. For all villages,
consumption of individual commercial and large power consumers
is projected to increase at 1% per year.
In small communities the availability of cost stable electric
energy is anticipated to increase the rate of consumption by
individual residential consumers to that presently experienced
in Alaska1s southcentral region.
II-9
Bethel -Section II
APA10/H
8000
4000
1000
1000
~
eoo
100
800
eoo
4()()
zoo
100
90
80
70
80
so
40
30
10
Akiachak
Population growth since 1970 has averaged approximately 1.9%
per year. The growth rate is projected at 2% during the study
period. 1979 base data are estimated, based upon 1974
information.
AKIACHAK
POWER REQUIREMENTS 1979 -2000
/
V
J'
J' ~
~ .JIll'
~ -----."'~~ ~ ~ ~
..... "J-~ ---------/
~ /
-' 1/
"E,.fl
,.",p "",'"
~E~' ~ ." ~ ..---------
1~85 2000
FIGURE il-4
II-IO
..,
HIGH
•
f;'i<-
LOW ..
~
~lIeH ..
... ..
LOW ... ..
..
..
..
APA010/Gl
TABLE 11-3
AKIACHAK
ELECTRIC POWER REQUIREMENTS 1979-2000
1979 1980 1990 2000
POPULATION 371 378 461 562
(1) # of residential 50 52 78 117
consumers
(2) average kWh/mol 130 133 (high) 257 800
consumers (low) 162 197
(3) MWh/year residential 78.0 83.0 (high) 240.6 '1,123.2
consumers (low) 151.6 276.6
(1)x(2)x1271000
(4) # of small commercial 6 6 10 16
consumers
(5) average kWh/mol 400 404 (high) 647 1,500
Consumer ( low) 446 493
(6) MWh/year 28.8 29.1 (high) 77.6 288.0
sma. com. cons. (low) 53.5 94.7
(4)x(5)x1271000
(7) # of large 1 1 1 2
cons. + public buildings
(8) average kWh/mo/cons 15,000 15,150 (high) 20,703 35,000
(low) 16,735 18,486
(9) MWh/year 180 181.8 (high) 248.4 840.0
LP's ( low) 200.8 443.7
(7)x(8)x1271000
(10) System MWh/year 315.5 323.3 (high) 623.3 2,476.3
(3)+(6)+(9) ( low) 446.5 896.5
(includes losses)
( 11) System .40 .40 .50 .50
Load Factor
(12) System Demand 90.0 92.2 (high) 142.3 565.4
kW ( low) 101.9 204.7
(10)78.7607(11 )
II-ll
Bethel -Section II
APA10/H
ISOOO
4000
3000
I()()()
~
800
700
eoo
BOO
400
100
SIO
80
10
80
80
40
20
10
Aki ak
Population growth since 1970 has averaged 1.2% per year. It
is projected to increase at 1% during the study period. 1979
base data are estimated, based upon comparison with Eek &
Akolmuit.
A K I A K
POWER REQUIREMENTS 1979 ~ 2000
,
--Ill
~
" .JII'
~
~
"""""" ~
.f:~" .-' V' -
----~ / ----~/ -
./ -, ... " ..,..
• C to'/.' _ ..
"'-.. ;-.,,----------------~-
HIGH
I.OW
IIIGH
LOW
1t79 ,gao IHO '995 .000
FIGURE II-5
II-12
...,1
I."
•
..
APA010/G2
TABLE 11-4
AKIAK
ELECTRIC POWER REQUIREIVIENTS1979-2000
1979 1980 1990 2000
POPULATION 190 192 212 234
(1 ) # of residential 25 27 42 57
consumers
(2) average kWh/mol 130 133 (high) 257 800
consumers (low) 162 197
(3) MWh/year residential 39.0 43.1 (high) 129.5 547.2
consumers ( low) 81.6 134.7
(1)x(2)x12-:-1000
(4) # of small commercial 4 4 7 10
consumers
(5) average kWh/mol 175 177 (high) 326 1,000
(low) 195 2"16
(6) MWh/year 8.4 8.5 (high) 27.4 120.0
sma. com. cons. (low) 16.4 25.9
(4)x(5)x12-:-1000
(7) # of large 1 1 1 1
cons. + public buildings
(8) average kWh/mo/cons 8,000 8,080 (high) 12,171 25,000
(low) 8,925 9,859
(9) MWh/year 96.0 97.0 (high) 146.1 300.0
LP's (low) 107.1 118.3
(7)x(8)x12-:-1000
(10) System MWh/year 157.7 163.5 (high) 333.3 1,063.9
(3)+(6)+(9) (low) 225.6 306.8
(includes losses) 10% 10% 1 O~)
( 11) System .40 .40 .50 .50
Load Factor
(12) System Demand 45.0 46.7 (high) 76.1 242.9
kW (low) 51.5 70.0
(10)-:-8.760-:-(11)
I1-13
Bethel -Section II
APA10/H
10,000
9,000
8,000
7,000
6,000
&,000
4,000
3,000
2,000
1,000
900
800
700
600
I!OO
400
300
200
100
Akolmuit
Population growth since 1979 has averaged 1.3%. Growth throu~h
the study peri od is projected at 1%. 1979 base data ay'e
estimated from AVEC records for 1978.
AKOLMUIT
(INCLUDES KASIGLUK., NUNAPITCHUK)
POWER REQUIREMENTS 1979 -2000
-'"
/
L V
~ V -
~
",~9 ~ ~
-..... ~~ ~ ./
~ L
~ -... ' L
/'
~" ~
~ -~/ -------, ..,.""",----
...
t~~~ .:;r..:;-. ...
~ ~
HIGH
!.-OW
HIGt<
lOW
198!! 1990 199!! 2000
fiGURE n-6
II-14
•
..
....
...
... '
...
APA010/G3
TABLE 11-5
AKOLMUIT
(INCLUDES KASIGLUK AND NUNAPITCHUK)
ELECTRIC POWER REQUIREMENTS 1979-2000
1979 1980
POPlJLATION 592 598
(1 ) # of residential 110 113
consumers
(2) average kWh/mol 135 137 (high)
consumers (low)
(3) MWh/year residential 178.2 185.8 (high)
consumers (low)
(1)x(2)x1271000
(4) # of small commercial 23 25
consumers
(5) average kWh/mol 188 190 (high)
(low)
(6) MWh/year 51.9 57.0 (high)
sma. com. cons. (low)
(4)x(5)x1271000
(7) # of large 2 2
cons. + public buildings
(8) average kWh/mo/cons 14,810 14,958 (high)
( low)
(9) MWh/year 355.4 359.0 (high)
LP's (low)
(7)x( 8 )x1271 000
(10) System IVlWh/year 644.1 662.0 (high)
(3)+(6)+(9) (low)
(includes losses)
( 11) System .50 .50
Load Factor
(12 ) System Demand 147.1 151 .1 (high)
kW (low)
(10)78.760-:-(11 )
II-15
1990 2000
660 730
153 209
260 800
159 185
477 .4 2,006.4
291.9 464.0
36 55
341 1,000
2'10 ")?")
L.JL
147.3 660.0
9C.7 153. 'I
3 3
20,528 35,000
16,523 18,251
739.0 1,260.0
594.8 657.0
1,500.1 4,319.0
1,075.1 1,40'1,5
.50 .50
342.5 986.1
245.5 320.0
Bethel -Section II
APA10/H
1000
900
800
700
600
500
400
300
200
100
90
80
70
60
50
40
30
20
10
Atmautluak
The population has declined slightly since 1974, the first
year for which population information was obtained. Growth
has been projected at 1% per year. 1979 base data are
estimated by comparison with Akiachak.
ATMAUTLUAK
POWER REQUIREMENTS 1979 ~ 2000
F-~--'---
~ -. ./
./'
/
V
~ -,. ... ~.J-. .-/~ I"""""
~.
V/
~
--' ~ .... I"'"
I 'i £.!.: .,.,..
\I. ... :;: ~-------fo----
.. ~--~-
--
HIGH
LOW
lilGH
LOW
1979 1980 19S~ 1990 199~ 2000
FIGURE II-7
11-16
... '
.,
•
•
..
.. '
•
APA010/G4
TABLE 11-6
ATMAUTLUAK
ELECTRIC POWER REQUIREMENTS 1979-2000
1979 1980 1990 2000
POPULATION 140 141 156 173
(1) # of residential 26 27 33 39
consumers
(2) average kWh/mol 130 133 (high) 257 800
consumers (low) 162 197
(3) MWh/year residential 40.6 43.1 (high) 101.8 374.4
consumers (low) 64.2 92.2
(1)x(2)x12+1000
(4) # of small commercial 3 3 4 6
consumers
(5) average kWh/mol 400 404 (high) 647 1,500
(low) 446 493
(6) MWh/year 14.4 14.5 (high) 31.1 108.0
sma. com. cons. (low) 21.4 35.5
(4)x(5)x12+1000
(7) # of large 1 1 1 1
cons. + public buildings
(8) average kWh/mo/cons 8,000 8,080 (high) 12,171 25,000
(low) 8,925 9,859
(9) MWh/year 96.0 97.0 (high) 146.1 300.0
LP's (low) 107.1 118.3
(7)x(8)x12+1000
(10) System MWh/year 166.1 170.1 (high) 306.9 860.6
(3)+(6)+(9) (low) 212.0 270.6
(includes losses)
(11) System .40 .40 .45 .50
Load Factor
(12) System Demand 47.4 48.5 (high) 77 .9 196.5
kW (low) 53.8 61.8
(10)-:-8.760+(11 )
II -17
Bethel -Section II
APA10/H
eooo
4000
1000
900
100
700
eo<)
eoo
400
too
100
SIO eo
70
eo
eo
40
to
Eek
The population declined from 200 in 1960 to 186 in 1970, and
appears to have fluctuated between those two levels since
1970. Based upon a present population of 185, a growth rate
of 1% per year is projected. 1979 base data are estimated
from 1979 AVEC data.
EEK
POWER REQUIREMENTS 1979 -2000
./
~
."
~
~
,
~
~
~ -
~ "".-~/
~"", v 7
.. ~ ..Jt'
_ ,,\(.1' :-r
Lid! Y:"--------~--------------...----
HIGH
tow
HIGH
LOW
1SJ7~ 1~80 1~85 IHa '"5 1000
FIGURE ll-8
11-18
..
•
"
III'
"'r'
1It'.
...
• .-
...
... .!
, 8',1>:
_I,
..
•
APA010/G6
TABLE 11-7
EEK
ELECTRIC POWER REQUIREMENTS 1979-2000
1979 1980 1990 2000
POPULATION lB5 187 206 228
(1) # of residential 47 49 59 74
consumers
(2) average kWh/mol 118 120 (high) 242 BOO
consumers (low) 147 '179
(3) MWh/year residential 66.6 70.6 (high) 171.3 710.4
consumers (low) 104. '1 159.0
('I )x(2)x12-:-1 000
(4) # of small commercial 7 7 10 14
consumers
(5) average kWh/mol 165 167 (high) 312 1,000
( low) 184 203
(6) MWh/year 13.9 14.0 (high) 37.4 16B.0
sma. com. cons. (low) 22.1 34.1
(4)x(5)x12-:-1000
(7) # of large 1 1 1 1
cons. + public buildings
(B) average kWh/mo/cons 8,061 8,141 (high) 12,233 25,000
(low) 8,993 9,934
(9) MWh/year 96.7 97.7 (high) 146.8 300.0
LP's (low) 107.9 119.2
(7)x(8)x12-:-1000
(10) System MWh/year 194.9 200.5 (high) 391.1 1,296.2
(3)+(6)+(9) (low) 257.5 343.5
(includes losses)
(11) System .45 .45 .50 .50
Load Factor
(12 ) System Demand 49.4 50.9 (high) 89.3 295.9
kW (low) 58.B 7B.4
(10)-:-B.760-:-(11)
II-19
Bethel -Section II
APAIO/H
10,000
9,000
8,000
7,000
elJO(J
apoo
41JO(J
r.poo
1000
900
800
700
600
!iOO
400
$00
100
Kwethluk
Population growth since 1970 has averaged 1.4% per year.
Growth has been projected at 1.5% through the year 2000. 1979
base data are estimated by comparing with Akiachak.
KWETHLUK
POWER REQUIREMENTS 1979 -2000
7
V V
-~
~ ----" .JIll'" ---"""'""'" • I:!:;. ". ~ -'" ~-" "" JII'--'
~ /r
~ /" io""
/" --..------~ ~ -
t~~ "t.~' ",.. """....--~ .,..,..,.----~~-...
""" I....-o~ ......
11'-'
HIGH
LOW
"I8H
LOW
1979 19.0 1985 1990 1995 2000
FIGURE II-9
II-20
""
...
••
I> .. .,
.,
""
• ..
•. fIt"
.... ..
.. ~
III'
..
APA010/G7
TABLE 11-8
KWETHLUK
ELECTRIC POWER REQUIREMENTS 1979-2000
1979 1980 1990 2000
POPULATION 457 464 538 624
(1) # of residential 74 76 108 '152
consumers
(2 ) average kWh/mol 130 133 (high) 257 800
consumers (low) 162 197
(3) MWh/year residential 115.4 121.3 (high) 333.1 1,459.2
consumers (low) 210.0 359.3
(1)x(2)x12-:-1000
(4) # of small commercial 8 9 13 21
consumers
(5) average kWh/mol 400 404 (high) 647 1,500
(low) 446 493
(6 ) MWh/year 38.4 43.6 (high) 100.9 378.0
sma. com. cons. (low) 69.6 124.2
(4)x(5)x12-:-1000
(7) # of large 1 1 2 2
cons. + publ ic buildings
(8 ) average kWh/mo/cons 15,000 15,150 (high) 20,703 35,000
(low) 16,735 18,486
( 9) MWh/year 180.0 181.8 (high) 496.9 840.0
LP's (low) 401,6 443.7
(7)x(8)x12-:-1000
(10) System MWh/year 367.2 381.4 (high) 1,024.0 2,944.9
(3)+(6)+(9) (low) 749.3 1,019.9
(includes losses)
( 11) System .40 .40 .50 .50
Load Factor
( 12) System Demand 104.8 108.8 (high) 233.8 672.3
kW (low) 171 .1 232.9
(10)78.760-:-(11 )
I I-21
Bethel -Section II
APA10/H
&000
4000
1000
eo<)
800
700
soo
BOO
400
100
90
eo
70
eo
eo
40
20
10
Napakiak
The population appears to have increased approximately 5% per
year since 1974. However there are confl i ct i ng reports of
population which could give growth rates from 0% to 6.2% per
year. A growth rate of 3% per year has been used for these
projections. 1979 base data are estimated, based upon 1974
information.
NAPAKIAK
POWER REQUIREMENTS 1979 -2000
/
./ '/
JIIA
~ ~
.JI' ~
~ ,-
~ ----~
." .. " ............... -~ /
~ ~ ~'
I""""" /'
.;
/~ ~.
f1f.. .. .,.¢" ~ .. ,,~
.,.~ ------" -...-----.. ---------
-
lilGH
LOW
HIGH
I_OW
1979 1980 .1990 19t5 1000
FIGURE 1I-10
11-22
..
...
II'
!lit,. ..
li.'
II'
IiOl
II'
,::i>t
'"',
..
...
II'
/\P/\010jCB
TABLE 11-9
NAPAKIAK
ELECTRIC POWER REQUIREMENTS 1979-2000
1979 1980 1990 2000
POPULATION 293 302 406 545
(1) # of residential 48 50 83 136
consumers
(2) average kWh/mol 175 179 (high) 339 1,000
consumers (low) 218 265
( 3) MWh/year residential 100.8 107.4 (high) 337.6 1,632.0
consumers (low) 217.1 432.5
(1)x(2)x12-:-1000
(4 ) # of small commercial 6 6 11 19
consumers
(5) average kWh/mol 400 404 (high) 647 1,500
(low) 446 493
(6) MWh/year 28.8 29.1 (high) 85.4 342.0
sma. com. cons. (low) 58.9 1"12.4
(4)x(5)x12-:-1000
"--
(7) # of large 1 1 1 2
cons. + publ ic buildings
(8) average kWh/mo/cons 15,000 15,150 (high) 20,703 35,000
(low) 16,735 18,486
(9) MWh/year 180.0 181.8 (high) 248.4 840.0
LP's (low) 200.8 443.7
(7)x(8 )x12-:-1 000
(10) System MWh/year 340.6 350.1 (high) 738.5 3,095.4
(3)+(6)+(9) (low) 524.5 1,087.5
(includes losses)
("11 ) System .40 .40 .50 .50
Load Factor
( 12) System Demand 97.2 99.9 (high) 168.6 706.7
kW (low) 119.7 248.3
(10)-:-8.760-:-(11)
11-23
Bethel -Section II
APA10/H
5000
4000
3000
2000
1000
.00
800
700
100
800
400
100
.0
80
70
eo
eo
40
20
10
Napaskiak
The population of Napaskiak has varied from 154 in 1960 to 259
in 1970. Since 1974 the population appears to have been
relatively stable at approximately 210 to 220. It is projected
to grow at 1% per year from 1979 through 2000, based upon a
1979 base of 2l0. 1979 base data are estimated, based upon
Napakiak information.
NAPASKIAK
POWER REQUIREMENTS 1979 -2000
/ HIGH
.JII'
~
.JI'
"" ."' ... ~ .-V" -LOW
\l"''f.~
~ ~ /
HIGH
I"'" //
,//
-.
,,(E ,.~ -----J'" pEP."~ LOW ----1.0.--'" -
1979 1980 It85 1890 1885 1000
FIGURE II-II
II-24
..
II, ..
•
iii·
APA010/G9
TABLE 11-10
NAPASKIAK
ELECTRIC POWER REQUIREMENTS 1979-2000
1979 1980 1990 2000
POPLJ LAT ION 210 212 234 259
(1) # of residential 43 44 60 81
consumers
(2) average kWh/mol 175 179 (high) 339 1,000
consumers (low) 218 265
(3) MWh/year residential 90.3 94.5 (high) 244.1 972.0
consumers (low) 157.0 257.6
(1)x(2)x12-:-1000
(4) # of small commercial 5 5 8 12
consumers
(5) average kWh/mol 400 404 (high) 647 1,500
( low) 446 493
(6) MWh/year 24.0 24.2 (high) 62.1 216.0
sma. com. cons. ( low) 42.8 71.0
(4)x(5)x12-:-1000
(7) # of large 1 'I 1 1
cons. + publ ic buildings
(8) average kWh/mo/cons 10,000 10,100 (high) 15,008 30,000
(low) 11,157 12,324
(9) MWh/year 120.0 121.2 (high) 180.1 360.0
LP's ( low) 133.9 147.9
(7)x(8)x12-:-1000
(10) System MWh/year 257.7 263.9 (high) 534.9 1702.8
(3)+(6)+(9) (low) 367.1 524.2
(includes losses)
( 11) System .40 .40 .50 .50
Load Factor
(12 ) System Demand 73.5 75.3 (high) 122.1 388.8
kW (low) 83.8 119.7
('10)-:-8.760-:-(11 )
11-25
Bethel -Section II
APAIO/H
1000
900
800
700
600
GOO
400
200
100
90
80
70
60
GO
40
20
10
Oscarvi 11 e
Population has varied between 51 and 60 since 1960, with no
noticeable trend. Growth rate has been projected at 1% per
year. 1979 base data are estimated, using Eek as a reference.
OSCARVILLE
POWER REQUIREMENTS 1979 -2000
...
~
/"
"" V
.~ft/ V
.\l I ~
~ ,
~
..#'
.JJ"
~ ~ .......
-
:... /"'"
'II .£J.'
,'1£"" .""."",..-~------.!--. ....,. ,...~ ...... ---. ---
,
HIGH
LOW
HIGH
LOW
1979 1980 198& 1990 1995 2000
FIGURE IT-12
II-26
...
..
•
• ..
..
•
APA010/G10
TABLE 11-11
OSCARVI LLE
ELECTRIC POWER REQUIREMENTS 1979-2000
1979 1980 1990 2000
POPULATION 52 53 58 64
(1) # of residential 10 10 14 19
consumers
(2) average kWh/mol 118 120 (high) 242 800
consumers (low) 147 179
(3) MWh/year residential 14.2 14.4 (high) 40.7 182.4
consumers (low) 24.7 40.8
(1)x(2)x1271000
(4) # of small commercial 1 1 2 2
consumers
(5) average kWh/mol 165 167 (high) 313 1,000
( low) 184 203
(6) MWh/year 2.0 2.0 (high) 7.5 24.0
sma. com. cons. (low) 4.4 4.9
(4)x(5)x1271000
(7) # of large 1 1 1 1
cons. + public buildings
(8) average kWh/mo/cons 4,000 4,040 (high) 6,467 15,000
(low) 4,463 4,930
(9) MWh/year 48.0 48.5 (high) 77.6 180.0
LP's ( low) 53.6 59.2
(7)x(8)x1271000
(10) System MWh/year 70.6 71.4 (high) 138.4 .0
(3)+(6)+(9) (low) 91.0 115.4
(includes losses)
(11 ) System .40 .40 .50 .50
Load Factor
(12) System Demand 20.1 20.4 (high) 31.6 97.0
kW (low) 20.8 26.3
(10)78.7607(11)
II-27
Bethel -Section II
APAlO/H
11000
4000
3000
1000
900 eoo
700
eoo
IlOO
400
100
90
80
70
80
80
40
10
Tuluksak
Population growth since 1970 has averaged 2.3%. Growth has
been projected at 2% per year from 1979 through 2000. 1979
base data estimated by compari son with Eek and Aki achi ak.
TULUKSAK
POWER REQUIREMENTS 1979 -2000
/ ..,
-""
./'
"'" ~
~
~ ------~ ~ L/
"'""" ./'
-~/
... 11.' .;-
.", .. \Co (;,;;. ------\I. ... .:..--------... -------~----
IIIGH
lOW
IIIG"
lOW
IW9 19&0 IlUIS IHO 1000
FIGURE. Ir-13
II-28
...
l1li
b ..
.' .,
.-
5,
•
~' ..
...
!-''\I ..
..
APA010/G11
TABLE 11-12
TULUKSAK
ELECTR IC POWER R EQU I R EMENTS 1979-2000
1979 1980 1990 2000
POPULATION 240 245 298 364
(1) # of residential 32 33 50 74
consumers
(2) average kWh/mol 130 133 (high) 257 800
consumers (low) 162 197
(3) MWh/year residential 49.9 .7 (high) 154.2 710.4
consumers (low) 97.2 174.9
(1)x(2)x12-:-1000
(4) # of small commercial 4 4 6 10
consumers
(5) average kWh/mol 400 404 (high) 647 1,500
(low) 446 493
(6) MWh/year 19.2 19.4 (high) 46.6 180.0
sma. com. cons. ( low) 32.1 59.2
(4)x(5)x12-:-1000
.. _--
(7) # of large 1 1 1 1
cons. + public buildings
(8) average kWh/rna/cons 8,000 8,080 (high) 12, 171 25,000
(low) 8,925 9,859
(9) MWh/year 96.0 97.0 (high) 146.1 300.0
LP's (low) 107.1 118.3
(7)x(8)x12-:-1000
(10) System MWh/year 181.6 186.0 (high) 381.6 1,309.4
(3)+(6)+(9) (low) 260.0 387.6
(includes losses)
( 11) System .40 .40 .50 .50
Load Factor
(12) System Demand 51.8 53.1 (high) 87.1 299.0
kW ( low) 59.4 88.5
(10)-:-8.760-:-(11)
II-29
Bethel -Section II
APAIO/H
6000
4000
3000
2000
1000
900
800
700
eo<>
600
400
100 eo
eo
70
eo
eo
40
20
10
Tuntutuliak
Population has grown at a rate of 3.9% per year since 1970.
It appears from available information that the growth rate was
higher until 1977, and then leveled off. The growth rate from
1979-2000 has been projected at 3%. 1979 base data are estimated
by comparison to Napakiak.
TUNTUTUTLI AK
POWER REQUIREMENTS 1979 0 2000
/
liteH
.JI' ..,
""""" ../
t/' ~ LOW
... -"" ---~
ta~ ~-----~ ~/ HIGH
~ ........ P""" // -!'-
.,/
,,"" !!!-'l.. ~~~ -------~ LOW
~ ..,.,..
;;00;'''' ---;;;;iiiiiiiI"
1979 1980 1~8S 1t90 1000
FIGURE 1I-14
II-3D
.,,,
!III
.' ..
..
iii
.,
APA010/G12
TABLE 11-13
TUNTUTULIAK
ELECTRIC POWER REQUIREMENTS 1979-2000
1979 1980 1990 2000
POPULATION 223 230 309 4't:, I~
('I) # of residential 32 33 55
consumers
(2) average kWh/mol 175 179 (high) 339 1,000
consumers (low) 218 265
.... ----.--
(3) MWh/year residential 67.2 70.9 (high) 223.7 1,080.0
consumers ( low) 143.9 286.2
(1)x(2)x12-;.1000
(4) # of small commercial 4 4 8 13
consumers
(5) average kWh/mol 400 404 (high) 647 1 ,~,OO
(low) 446 493
(6) MWh/year 19.2 19.4 (high) 62.1 234.0
sma. com. cons. (low) 42.8 76.9
(4)x(5)x12-;'1000
(7) # of large 1 1 I
cons. + public buildings
(8) average kWh/mo/cons 10,000 10,100 (high) 15,008 30,000
(low) 11, 157 12,324
(9) MWh/year 120.0 121.2 (high) 180.1 360.0
LP's (low) 133.9 147.9
(7)x(8 )x12-;.1 000
(10) System MWh/year 227.0 232.7 (high) 512.5 1,841.4
(3)+(6)+(9) (low) 352.7 562.1
(includes losses)
( 11) System .40 .40 .50 .50
Load Factor
(12 ) System Demand 64.8 66.4 (high) 117 .0 420.4
kW (low) 80.5 128.3
(10)-;.8.760-;.(11)
II -31
Bethel -Section III
APA15/E
III. ELECTRIC ENERGY RESOURCES
A. INTRODUCTION
Thi s section presents an ana lys i s of exi st i ng energy resources in
the Bethel area, based on available information. Published reports,
USGS maps, field investigations and other available literature as
listed in the bibliographies with each part, as well as communication
with people in the area, have been utilized to complete knowledge
on resources that can be developed with known technology within the
next twenty years.
Resources have been analyzed in regard to economic and environmental
feasibility. Except for the potential oil and gas discoveries,
which would require a very large scale development and are not
addressed in this report, the development of the Golden Gate
hydroe 1 ectri c site appears to be the best prospect to pl'ovi de the
required electrical energy in the futUl'e. Small communities without
access to hydroelectric or geothermal energy will have to rely on
diesel, coal/wood generation, transmission interties or implement
wind and solar power on a small scale. Unfortunately neither coal/
wood generation or wind and solar power appear to be economically
advantageous at this time.
Severe restraints on development of most potential resources are
created by the present land status uncertainties. Developeable
potential resources are, however, mentioned and economically
evaluated on an approximate basis in this study regardless of the
potential land usage conflicts.
B. ENERGY RESOURCES
The following potential energy resources will be discussed:
1. Hydroelectric Potential
2. Coal/Wood Energy Conversion
3. Geothermal Potential
4. Wind Power Potential
5. Transmission Interties
6. Conservat ion
The available energy resources will be evaluated in regard to their
potential to replace or supplement the present use of petroleum
fuels.
III-l
Bethel -Section III
APA15/E
The present state of the art in wind and solar energy conversions
are considered to be uneconomical on a "utility" scale due to
either high cost or questionable reliability. It is expected that
both these energy convers i on techno 1 ogi es wi 11 be pursued on a
demonstration -or private individual level-in the near future.
Overall energy needs, however, must be filled by means of proven
techno logy and economi ca lly feas i b 1 e developments. Emphas is has
been placed on renewable resources. This does not imply that other
resources have been overlooked but rather attempts to put them in
perspective in regard to possible development and costs.
1. Hydroe 1 ectri c Potential
a. Introduction:
The Golden Gate Hydro Site on the Kisaralik River has the
potential to supply the entire future needs of the Bethel
area through the year 2000. The energy from the Golden
Gate hydro project can be absorbed by interconnecting
numerous small villages surrounding Bethel to a centralized
power distribution point located in Bethel I which is in
turn supplied via a 69 mile long transission line from
the Golden Gate Hydro project. This concept is shown in
Figure III-I. It is estimated that 1986 would prove to
be the earliest possible completion date for the project
assuming all necessary permits can be readily acquired.
Thi s comp 1 et i on date is, however, quest i onab 1 e as the
present and future land status of the area is uncertain.
The project lies within the proposed uYukon Delta" National
Wildlife Refuge created by the Federal Land Policy
Management Act of November 16, 1978, Emergency Order 204E.
The following pages address the preliminary geologic
investigation, construction, construction cost, environ-
mental impact and energy potential of the Golden Gate
Project.
b. General Description:
The Kisaralik River originates in the Kilbuck Mountains
and flows west-northwest approximately 110 miles where it
empties into the Kuskokwim River near the village of
Akiak. The proposed dam site is located in a narrow
meandering gorge at approximate river mile 67 and 63.5
airline miles east-southeast of the City of Bethel. This
site is in section 17, T4N, R62W, Seward Meridian and
identified as "Lower Falls" on the U.S.G.S. Bethel (B-3)
quadrangle although there are no falls at the location.
There are no significant falls anywhere along this section
of river where a substantial head could be utilized.
III-2
..
..
•
•
•
..
, \ ; i
r,
(,
:; j
, <
• 'f" j -.. " ;.
, ..
,,\( , ., ..,
'.
FIGURE III-l
."$MIIi:'''
" :~r"'~
, "
Bethel -Section III
APA15/E
TABLE III-1
TABLE OF SIGNIFICANT DATA
Kisaralik River Hydroelectric
RESERVOIR
Ora; nage Area
Normal Maximum Water Surface (msl) El.
Minimum Water Surface El.
Tailwater El.
Surface Area -Normal Max. W.S.
Live Storage (70 ft. drawdown)
Regulation
DAM
Type
Height
Crest Elevation (msl)
Volume
Impervious Facing
SPILLWAY
Type
Crest Elevation
Width
Design Discharge
POWER TUNNEL
Length
Finished Diameter
POWER PLANT
Type
Capacity
Maximum Gross Head
Type of Turbines
TRANSMISSION LINE
Voltage
Length
Conductor Size
1II-4
544 sq. mi. (1409 sq. km)
1110 ft. (338 m)
1060 ft. (323 m)
805 ft. (245 m)
6700 Ac. (2680 a)
320,750 ac.ft. (395.7 MCM)
800 cfs (22.7 cms)
Rockfi 11
315 ft. (96 m)
1125 ft. (343 m)
2,500 t OOO c.y.
(1,911,500 c.m.)
Asphaltic Concrete
Ungated Side Channel
1110 ft. (338 m)
375 ft. (114 m)
87 t OOO cfs (2,464 cms)
925 ft. (282 m)
16 ft. (4.9 m) modified
horseshoe, concrete lined
Underground
30,000 kW (2 units)
305 ft. (93 m)
Vertical Francis
138 kV
69 mi. (111 km)
795.5 KCM, ACSR
Ill">
-
•
•
•
..
•
Bethel -Section III
APA15/E
The selected site offers several advantages over other
possible dam sites on the Kisaralik River. These are:
(1) The topography is such that the volume of material
to construct a dam of sufficient height to provide
suitable storage and head for low winter flows is
less than at the other sites.
(2) The U-shaped bend in the river provides for a very
short power tunnel; a feature not evi dent at the
other sites.
(3) More favorable geologic conditions.
(4) A natural bench at an appropri ate hei ght for the
excavation of a side channel spillway.
Severa 1 dam hei ghts were investigated with respect to
available prime power and the cost of dam vs. cost of
power. Preliminary studies indicate a reservoir with
normal maximum water surface at elevation 1110 will
provide the greatest benefit to cost ratio when using a
regulated flow of 800 cfs. All head and storage is
developed with a rockfill dam 315 feet high with a crest
at elevation 1125 and a spillway crest at elevation 1110.
Thi s wi 11 create a reservoi r havi ng a capac; ty of
716,000 acre-feet of storage. A usable storage of 320,750
acre-feet is provided with a drawdown of 70 feet. Figure
111-2 shows the extent of the reservoir.
This chapter gives a description of the Project, the
preliminary design of the major project elements, the
schedul e for the construction of the project and the
estimated project costs.
c. Project Arrangement:
The Kisaralik River Project would consist of the following
principal elements:
(1) A rockfill dam across the river, founded on rock,
with a side channel spillway having a crest at
elevation 1110 on the north abutment. The upstream
slope of the dam would be 1.7 horizontal to 1 vertical.
The downstream slope would be 1.5 horizontal to 1
vertical. Oversize rock would be placed against the
downstream face for earthquake stability_ The dam
would have a crest of 550 feet in length and 20 feet
1II-5
~~ /
/ ..
I"
I')
~."-
\
" '. . ., , .
~~". ' ,
\ , ~
SCALE IN MILES
2 3 4 -----
ALASKA POWER AUTHORITY
KISARALIK PROJECT
RESERVOIR
JAN. 1980 9703
FIGURE m-2
..
..
• •
•
•
-
•
•
•
Bethel -Section III
APA15/E
in width. An impervious membrane of asphaltic
concrete on the upstream face and a concrete grout
cap along the upstream toe would be provided.
(2) A concrete intake structure with invert at elevation
820 is provided with a trashrack on the right abutment
of the river.
(3) A rei nforced concrete 1 i ned tunnel 925 feet in
length with a finished diameter of 16 feet.
(4) An underground powerhouse containing the turbines,
generators and electrical switchgear.
(5) A surface switchyard adjacent to the powerhouse adit
contai ni ng the transformers, switches, etc. and
transmission take-off structures.
(6) Other facilities, including a 50 mile winter
construction access road from near Akiak and
transmission line.
d. Hydroelectric Power Production:
The powerp 1 ant wou 1 d contain two generators rated at
15,000 kW each, powered by vertical Francis turbines of
23,000 HP each. The project would produce 131,400 MWh
per year.
The net operating head would be in the order of 265 feet;
average flow is 800 cfs.
The generating units would have a overload rating of 15%
above their nameplate rating.
The head at which the units would be required to operate,
300 feet, is in the range normally covered by reaction
(Francis) turbines. Vertical units were selected to
minimize the horizontal dimensions of an underground
powerhouse.
A minimum of two units should be installed so that the
project, which would be the major source of energy to the
system, could operate with one unit out of service.
The installation of more than two units would require a
larger powerhouse excavation and three 10 MW units with
appurtenances would cost considerably more than two 15 MW
units. If two 10 MW units were installed initially with
1II-7
Bethel -Section III
APA15/E
e.
provisions for a future unit, all of the necessary excava-
tion for the unit, in the powerhouse, tailrace and supply
line would have to be done initially. The cost of
installing three 10 MW units would be considerably higher
than two 15 MW units in a one stage development and the
cost of installing two 10 MW units with provisions for a
future unit would cost approximately the same as installing
two 15 MW units. The cost of mobilizing and providing
camp facil ities in this remote location is extremely
high; therefore, stage development is not recommended.
The installation of three or more units has the advantages
of being able to operate the machines at a higher rate of
efficiency and providing a greater peaking capacity with
one unit down. During the early years of surplus energy,
operation at a higher efficiency would result in spilling
more water over the spillway. As energy requi rements
approach the prime capacity of the plant, the units would
operate wi thi n a reasonable range of effi ci ency. Wi th
the long transmission line being the most vulnerable
portion of the Project and hydroelectric units being very
re 1 i ab 1 e, two 15 MW uni ts have been se 1 ected for the
purpose of this report.
Geology, Foundation and Construction Materials:
The geology of the Bethel quandrangle was published in
1959 by Hoare and Coonrad (Map 1-285); there has been
little addition to this work since then. According to
their classification, the bedrock in the Lower Falls area
is part of the undifferentiated Gemuk group (KCg), of
probable late Paleozoic and Mesozoic age. The unit is
comprised of chiefly massive and thin-bedded, fine-grained
siliceous rocks, some volcanic rocks, calcareous siltstone,
and limestone.
At the damsite, the rocks are siliceous metasiltstones or
argillites and cherts. The rocks are generally massive,
displaying little evidence of former bedding planes.
However, parting and outcrop patterns i ndi cate a N20W
stri ke for the ori gi na 1 structure. Overpri nt i ng thi s
texture are several zones of cherty, more resistant rock
that trend roughly northwest and east-west, and at least
two main joint sets (N80E/80N and N30W/80E).
While the structure of the unit is somewhat complex on a
local scale, it appears to present no special problems
for construction of a dam. Bedrock outcrop on the hillsides
above the river is generally frost-riven and fractured,
but fresher exposures adjacent to the scouring action of
the river are more uniformly competent.
III-8
•
..
.. .'
•
Bethel -Section III
APA15/E
A zone of especially resistant cher'ty material cuts
across the river in an east-west direction near the Lower
Falls area. The zone is subparallel to the proposed axis
of a dam and would underlie the major portion of a rockfill
structure. From numerous outcrops on both sides of the
channel and midstream, it is presumed that only a few
feet of alluvium would need to be removed from the stream
bottom itself.
Right and left abutments are covered by a thin veneer (up
to 10 feet, but generally less than 3 feet) of colluvium
and talus with bedrock cropping out in several places.
As well as removal of this overburden, some of the highly
fractured bedrock wou 1 d need to be removed from the
keyway. Major joint sets cut both across and downstream,
but are generally tight and grouting shou'ld be minimal.
No signs of faulting were observed, and there is no
indication of such from the regional mapping of Hoare and
Coonrad. The mountai ns i des of the gorge area appear to
have been fairly stable with no evidence of major lands1ides.
Construction material for rockfill could be obtained from
either abutment. The crosscutting joi nts generate
equidimentional blocky debris that is generally less than
one foot in diameter. Aggregate for concrete is unavailable
from the gorge itself, but sandbars approximately one-and-
one-ha If mil es downstream contai n well-graded sandy
gravels.
Geologically, the damsite is favorable. The most important
construction problem would be adequate grouting of the
joint sets.
f. Hydro logy:
The watershed above the proposed damsite was determined
to be 544 square miles from the U.S.G.S. map Bethel,
Alaska 1:250,000.
A conservative annual mean runoff of 20 inches was chosen
based on NOAA Technical Memorandum NWS AR-I0 Mean Monthly
and Annual Precipitation, Alaska by Gordan D. Kilday.
This bulletin shows a mean annual precipitation of 20 inches
for Bethel, 40 inches for the mountainous region near the
Kisaralik River damsite and 80 inches along the ridge
dividing the Kuskokwim and Wood River Basins.
II I-9
Bethel -Section III
APA15/E
g.
The 544 square miles or 348,160 acres with 20 inches of
runoff (1.67 feet) calculates to 580,270 acre-feet of
runoff per year. The total runoff of 580,270 acre-feet
per year equates to an average annual flow of 800 cfs.
It is believed that 800 cfs average would flow during the
driest year and the power available used in this study
would be firm with annual regulation. With a net head of
265 feet, the project would develop 15,000 kW continuous
or 131,400 MWh of firm energy per year. (See Appendix A-8).
It is strongly recommended that a stream gage be installed
near the proposed damsite at the earliest possible date.
If the average annual flow is much greater than used in
this study, the dam should be designed for future raising,
the power tunnel diameter increased, and the powerhouse
designed for future expansion, if feasibility -level
studies so indicate.
Description of Project Facilities:
(1) Dam: The dam would be a non-overflow rockfill type
founded on bedrock. The rockfi 11 woul d have a
maximum height of 308 feet from elevation 810 to
1118. The crest would be 550 feet in length and
20 feet in width with a 7-foot high concrete coping
wall on the upstream edge to elevation 1125 The
rockfi11 in the dam, with upstream slope of 1.7h:1V
and downstream slope of 1.5h:1V, will be zoned and
compacted in the lifts with vibratory compactors. A
concrete grout cap will be placed along the upstream
toe to grout the rock joint sets. The dam would be
sea 1 ed between the grout cap and the copi ng wall
with asphaltic concrete pavement on the upstream
face with an average thickness of 12 inches.
A 20-foot high cofferdam placed upstream from the
grout cap would divert the power water through the
power tunnel during dam construction. The cofferdam
would not be removed.
A typical dam section is shown on Figure 111-7. An
area-capacity curve for the reservoir is included in
Figure III-3,
(2) Spillway: The probable maximum flood for the Kisaralik
River has not been determined for this study. For
estimating purposes, a spillway at elevation 1110
with a channel width of 375 feet and a slope of 5%
II 1-10
•
.,
WI
•
..
..
•
Bethel -Section III
APA15/E
would pass the probable maximum flood before over-
topping the dam. Routing of a PMF flood through the
large reservoir would probably result in the inflow
being at least twice that of the spillway outflow.
The spillway would be excavated in bedrock around
the right (north) abutment of the dam and discharge
into the side canyon downstream from the powerhouse.
See Figure 111-4 for general layout.
(3) Power Tunnel and Intake:A tunnel 925 feet in length
and mi nimum rock excavation di ameter of 18 feet
woul d 1 ead from the powerhouse through the ri ght
abutment to an intake structure located upstream
from the cofferdam. The tunnel would slope 0.020
downstream and be concrete lined to a finish diameter
of 16 feet.
The concrete power structure intake structure would
be flared to reduce entrance losses and be provided
with a trashrack, having slots for an emergency
closure gate. The gate operator would be located
above the highwater at elevation 1125. The gate
stem would be sealed in an oil filled housing to
prevent freezing.
The downstream end of the tunnel would terminate in
a trifurcation. Two legs of the trifurcation would
be connected to turbines in the powerhouse for power
generat i on and the thi rd used as a bypass duri ng
construct i on. The bypass woul d remai n for future
emergency drawdown.
(4) Powerhouse: The powerhouse would be an underground
cavern excavated in bedrock. Rei nforced concrete
would enclose the draft tubes and spiral cases. The
turbine pit, turbine floor, turbine floor walls and
generator floor would be reinforced concrete. The
walls above the generator floor and the ceiling
would be unlined, natural rock; rock bolted and/or
gunited as required for stability. Personnel and
equipment would be protected from spalling rock with
an aluminum alloy shield suspended from rock bolts
in the crown of the cavern.
An appropriate sized overhead travelling crane would
be i nsta 11 ed for erection and mai ntenance of the
generating equipment.
II 1-11
.," '. ,. ,
I " ~ J '. t, 'I "
ALASKA POWER AUTHORITY
KISARALIK PROJECT
2 X 15MW
GENERAL PLAN & LAYOUT
FIGURE m-4
DATE DEC. 1979 CONTRACT 9703-1
, •
Bethel -Section III
APA15/E
Each leg of the trifurcation would contain a spherical
valve for positive closure of each waterway.
The turbines and generators wll be connected by a
verti ca 1 drive shaft. Each generator woul d have a
continuous overload rating of 15 per cent.
Tunnel & Powerhouse are shown on Figure III-6.
(5) Transmission Lines: A sUbstation at the powerhouse
would transform the generated voltage of 13.8 kV to
the transmission voltage of 138 kV. Utilization of
138 kV nominal voltage and a 795 KCM conductor would
assure adequate voltage 1 eve 1 sin Bethel. Energy
losses would be low due to the relatively large
conductor chosen. An overhead 1 i ne woul d stri ke
northwest for approximately 56 miles turning sharply
northward near Kweth 1 uk and cross the Kus kokwi m
Ri ver. The 1 i ne woul d then turn southeast and
terminate in a SUbstation near Bethel. The total
length of the transmission line would be approxi-
mate ly 69 mil es.
(6) Access Roads: There are no access roads to the site
at the present time. A winter access road approxi-
mately 50 miles in length from the village of Akiak
to the project s He waul d provi de the means of
construction mobilization and demobilization.
A permanent road approximately 2 miles in length
would be constructed downstream from the powerhouse
to the concrete aggregate borrow area. A gravel air-
strip would be constructed at the end of the permanent
road for project access with fixed wing aircraft.
h. Environmental and Other Concerns:
Preliminary investigations indicate that caribou, moose,
wolf, wolverine, grizzly bear, and black bear habitats,
and numerous raptor nesting sites along the Kisaralik
River would probably be lost.
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.
III-13
Bethel -Section III
APAI5/E
The Kisaralik river impoundment would require further
study to accurately assess the fishery in the river.
Chums, king and silver salmon are known to spawn in the
Kisaralik River and its tributaries above the Golden Gate
Falls (See Appendix 0-1).
The transmission corridors would cross several small
streams. As there is a possibility that the transmission
1 ine 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 possible, would minimize visual impact.
i. Land Status:
j.
The power-development site is presently located within
the proposed Yukon Delta Wildlife Refuge (Federal Land
Po 1 icy Management Act of November 16, 1978, Emergency
Order 204E). The 204E withdrawal is valid for 3 years.
The Kisaralik River is also considered under Emergency
Order 204C, which has not been invoked yet. This order
would withdraw the river and a 2-4 mile corridor along
each bank for a period of 20 years and be more restrictive
than the 204E order. If bi 11 s HR39 or 59 pass, the
Kisaralik might also be included in the "Wild & Scenic
River" system.
Project Construction:
The project construction would be carried out by separate
supply and civil works construction contracts. A single
general contractor would build the project.
The contractor would be required to provide access to the
site by constructing necessary barge facilities on the
Kuskokwim River for unloading construction equipment,
materials, supplies, etc. as necessary to construct the
project. The contractor woul d construct the wi nter
access road, airstrip, permanent road, construction camp,
etc. as well as the other project features and equipment
installation.
Overburden containing organic matter and decomposed rock
removed from required excavations would be used as fill
material in the operator housing area on the left abutment
of the ri ver downstream of the powerhouse tai 1 race.
III -14
..
III
•
..
..
Bethel -Section III
APA15/E
Spillway rock excavation would be used in the rockfill
for the dam. Tunnel and powerhouse spoil woul d be used
to surface the permanent road from the powerhouse to the
airstrip.
A tentative construction plan follows:
(1) Fi rst Year: The contractor woul d begi n mobil; zing
equipment and materials early enough to barge them
to the unloading site on the Kuskokw'im River before
freeze-up. C1 eari ng and construction of the access
road, airstrip and transmission line would begin in
early fall. Road and airstrip would be completed by
year end.
(2) Second Year: The contractor woul d beg; n movi ng ; n
the mobil e camp and tunnel i ng equipment fi rst;
followed by other necessary materials and equipment
needed for the summer construction season. Upon
completion of erecting the camp, shops, etc., the
contractor would begin constructing the tunnel,
intake, powerhouse excavation, diversion bypass and
finally installing the spherical valves in the
trifurcation. This work should be completed by
mid-July.
In early June, the contractor would begin drilling
for the spillway excavation, dam stripping, rock
quarrying, grout cap and preparing for the installa-
tion of the cofferdam for diverting the river flow
through the tunnel. Diversion should be complete by
September 1 and the remaining grout cap across the
river channel installed and grouting of the bedrock
completed. Fill in the lower reaches of the dam
could be carried out simultaneously with the completion
of the grout cap and grouting. It is anticipated
that rockfill would continue to be placed until the
first of December.
Asphalt, paving equipment, bridge crane, etc. would
be barged to the landing on the Kuskokwim River.
Concrete and asphalt aggregate would be processed
and stockpiled during the summer.
(3) Third Year: Additional equipment, materials and
supplies would be transported over the winter road
before breakup.
1II-15
Bethel -Section III
APA15/E
Spi 1 1 way excavation, dam construction, powerhouse
excavation, rock bolting, etc. would resume in early
summer. Transmission line clearing and construction
would also commence. By the end of the third year
construction season the following work should be
complete:
(a) Spi llway;
(b) Rockfill in the dam;
(c) Tailrace;
(d) Powerhouse excavation;
(e) Powerhouse first stage concrete;
(f) Overhead travelling crane;
(g) Powerhouse cavern rock bolted and crown shield
install ed;
(h) Intake gate, operating stem and operator;
(i) Transmission line right-of-way cleared.
Dur; ng the summer the contractor woul d barge the
turbi nes, generators, governors and appurtenant
equipment to the barge landing on the Kuskokwim
River.
(4) Fourth Year: The remalnlng equipment, materials and
supplies to complete the project would be transported
to the site over the winter road before breakup.
Equipment installation would proceed upon delivery
to the site (about February 1).
When the weather and temperature condi t ions are
suitable, the contractor would install the asphaltic
concrete membrane on the face of the dam and close
the intake gate to start fi 11 i ng the reservo; r.
Th;s should be completed by July 15. The 7-foot
high coping wall would be placed on the crest of the
rockfill after the asphalt paving is complete and
the closure made.
Transmission line, substations and equipment installa-
tion would continue through the summer and be completed
by the first of November.
Test i ng of equi pment woul d beg'i n in November and the
first unit would be on line by the end of the fourth
year.
(5) Fifth Year: Testing of the second unit should be
complete by the end of February and ready to go on
1 i ne.
III -16
...
..
•
..
.,
Bethel -Section III
APAIS/E
The contractor would demobilize the camp, equipment,
etc. and transport them to the barge landing on the
Kuskokwim River.
A construction schedule is included as Figw'e III-5.
k. Cost Estimate:
A cost estimate for the project is included as Table
III-2 and 1II-3.
The cost estimate is based on utilization of conventional
3$, 60 cycle generating and transmission equipment. With
the relatively long transmission line required, it has
briefly been investigated, whether single phase, low
frequency generation and transmission could produce any
cost-savings. It has been found that this alternative
could result in a construction cost reduction of approxi-
mately 5-7%. A description of the concept can be found
in Appendix A-3.
III-l7
115 0
110 0
105 0
....... 100 0
I
f->
CP
....
IIJ
IIJ
I&. ,n 95
Z
Z
0
S >
0 IIJ
..J 90
IIJ
85 0
0 80 0
I "
AREA (ACRES X 1000)
12 II 10 9 8 7 6 5 4 3 2 o
I I I I :~~ ---~ !
~ i I : : I
I I ! .
I ~l><~ ~ !
~ "' ~ ~,", I el">-
I /
I / ~
'" i
I ~ /
/ V
(
f i
I
I
I
! I
100 200 300 400 500 600 700 800
CAPACITY(ACRE -FEET X 1000)
, . . " ,. '. " ., ~ ,
"-f--. __ ...
I
I
!
!
i i
I
900 1000
~
" " \
\
1100 1200
KISARALIK RIVER
AREA-CAPACITY CURVE
FIGURE m-3 ,
\
1300
,
...... ...... ......
I .......
\.0
Dillingham -Section
APA 111M2
Year
Item Quarter
Mobilization
Access
Tunnel
Spillway
Dam Stripping
Quarrying
Grout Cap
Cofferdam
Rockfill -Dam
Powerhouse
Transmission & Substations
Equipment Installation
Testing First Unit
Testing Second Unit
Demobilization & Clean-Up
First
1 2 3
I
I I
I
CONSTRUCTION SCHEDULE
Second
4 1 2 3 4 1
•
L
I I
L i
i-
i
Third Fourth
2 3 4 1 2 3 4 1
•
I I ~
I I I
~
, I
ALASKA POWER AUTHOR ITY
K I SARALI K RIVER PROJ ECT
CONSTRUCTION SCHEDULE
FIGURE m-5
I
Fifth
2 3 4
I
Bethel -Section III
APA 12/D1
TABLE 111-2
KISARALIK
2 x 15 MW
PRELIMINARY COST ESTIMATE
SUMMARY
Capital Expenditures
FERC
ACCT.
by Year in $1,000 -(1979-Base)
1982 1983 1984 1985
331
332
333
334
335
336
352
353
354
356
Hydraulic Production Plant
Structures and Improvements
Reservoirs, Dams & Waterways
.1 Dams
.2 Spillway
.3 Tunnel
Waterwheels, Turbines, &
Generators
Accessory Electrical Equipment
Misc. Plant Equipment
Roads (40 mi.)
Transmission Plant
Structures & Improvements
Station Equipment
Poles & Fixtures (69 mile,
138 kV, 30)
Overhead Conductors & Devices
General Plant
10,495
2,000
1,145
3,800
390 Structures & Improvements
381/389 Miscellaneous
Direct Constr. Cost
Contingencies
On Underground Work (25%)
All Other Work (10%)
Engineering 15% of Direct
Constr. Cost
Total Construction
Allowance for inflation (8% per
year to 1984, 4% per year for
17,440
5,784
580
2,616
26,420
1985) 6,862
I nterest during Construction 9% 2,995
Total Investment 36,277
Total Project Cost in 1979 -$(1,000)
Used in economic evaluation
Inflated at 8% per year to 1984
and 4% thereafter results in
10,495
2,000
1,145
50
200
13,890
5,784
225
2,084
21,983
7,925
5,686
35,594
'1,405
10,495
1,145
1,675
100
1,800
2,400
50
19,970
5,784
633
2,995
29,382
13,790
~
52,743
99,657
15~
1,405
5,000
650
2,300
2,300
1,166
1,748
14,569
7,694
11,574
33,837
•
-
-
..
..
H
H
H
TUNNEL SECTION
POWERHOUSE SECTION
KISARALIK RIVER
HYDROELECTRIC POWER POTENTIAL
TUNNEL So POWERHOUSE SECTION
FIGURE m-6
....... ....... .......
I
N
N
I 1 f I ,
ZONE m MATERIAL
VERSIZE ROCK
ELEY. 1120
ZONE II MATERIAL
IS" MAX. SIZE. PLACE 80
COMPACT IN 2' LIFTS W/4
PASSES MIN. 10 TON VISRATORY
COMPACTOR .
ELEY. 810
MAXIMUM DAM SECTION
2'_0" "I
-js"\--i - -J _1.____ . ;,. i
1.l'-o:J: 2-0 4:;\" .. !
TYP. COPING WALL SECTION
• f I
MAX. W.s. ELEV. 1110
12" ABOVE CATCH
POINT OF DAM
HEEL ON BEDROCK
• B BAR W HOOKS jrt
GROUTED 1'TI B R
PLACE BARS OIt'EACH
SIDE OF GROUT PIPE
-DIMENSIONS NORMAL TO HEEL OF DAM
GROUT CAP DETAIL
,
KISARALIK RIVER
HYDROELECTRIC POWER POTENTIAL
TYPICAL DAM SECTION. GROUT
CAP a COPING WALL
FIGURE m-7 ,
APAI41I1
TABLE III-3
KISARALIK RIVER
DETAILED COST ESTIMATE
(1979 -$)
FERC UNIT TOTAL
ACCT. ITEM QUANTITY PRICE PRICE
HYDRAULIC PRODUCTION PLANT
331 Structures and Improvements
.1 Powerhouse
Excavation, Rock 10,000 c.y. 50.00 500,00
Structure Concrete 1,200 c.y. 750.00 900,000
Structure Steel 40,000 lbs. 1. 50 60,000
Misc. Metal 20,000 lbs. 3.00 60,000
Water & Sewerage L.S. 100,000
HVAC L. S. 200,000
Entrance Structure L. S. 350,000
Miscellaneous, Lighting,
Drainage, etc. L.S. 140,000
Mobil i zat ion 500 1 000
Total Account 331 $2,810,000
332 Reservoirs, Dams and Waterways
.1 Dams
Reservoir Clearing 10 Ac. 5,000.00 50,000
Foundation Excavation 50,000 c.y. 8.00 400,000
Embankment 2,500,000 c.y. 10.00 25,000,000
Asphaltic Concrete 25,000 tons 100.00 2,500,000
Grouting L. S. 1,000,000
Concrete Toe Block 1,600 c.y. 600.00 960,000
Mobilization 1 z575 2 OOO
Subtotal $31,485,000
.2 Spi 11 way
Excavation 118,000 c.y. 25.00 2,950,000
Concrete 500 c.y. 600.00 300,000
Mobilization L.S. 750 1 000
Subtotal $4,000,000
.3 Power Tunnel & Intake
Rock Excavation 11,445 c.y. 200.00 2,289,000
Steel Supports 70,000 lb. 1.80 126,000
Rock Bolts 5,000 l. f. 8.00 40,000
Concrete L i n"j ng 1,250 c.y. 600.00 750,000
Coffer Dam L.S. 90,000
Wheel Gate & Frame L.S. 100,000
Trashracks 16,000 lbs. 2.50 40 2 000
Subtotal $3,435,00
Total Account 332 38,920,000
III -23
APA141I2
FERC
ACCT.
333
ITEM
TABLE 111-3 (continued)
KISARALIK RIVER
DETAILED COST ESTIMATE
(1979 -$)
QUANTITY
UNIT
PRICE
TOTAL
PRICE
Waterwheels, Turbines & Generators
.1 Turbines, 23,000 HP 2 ea .
2 ea .
L.S.
1,150,000.00 2,300,000 .•
334
. 2 Generators, 15,000 kW
. 3 Appurtenances
Total Account 333
Accessory Electrical Equipment l. S.
335 Miscellaneous Plant Equipment
.1 Spherical Valves 2 ea.
.2 Bridge Crane L.S .
. 3 Miscellaneous, (Fire
protection, Compressed Air, etc.) L.S.
Total Account 335
336 Roads Railroads & Bridges
352
353
.1 Winter Access Road 50 mi.
.2 Mobilization L.S.
Total Account 336
TRANSMISSION PLANT
Structures
.1 Concrete Foundations
.2 Structural Steel
Total Account 352
Station Equipment
.1 Transformer 138 kV, 15 MVA
. 2 Transformer 138 kV, 30 MVA
.3 Oil Circuit Breakers 138 kV
. 4 Three Phase Disconnects
. 5 Potential Transf. 138 kV
.6 Lightning Arresters 138 kV
.7 Insulators, Busbar, etc.
Total Account 353
l. S.
l. S.
2 ea .
1 ea.
4 ea .
6 ea .
6 ea.
6 ea.
l. S.
III -24
1,200,000.00 2,400,000
300,000
$5,000, 000 ,~
$650,000
500,000.00 1,000,000 ,.
375,000
300 1 000 ,.
$1,675,000 ,,1.,;
."
55,000.00 2 ,750,000
1z050~000 lilt
$3,800,000 "
II!
iff'
50,000 •• 100,000 ".
150,000
'"
200,000.00 400,000
300,000.00 300,000 ,,-80,000.00 320,000
10,000.00 60,000
15,000.00 90,000
6,000.00 36,000 tI'"
594,000
$1,800,000
.'" .,
""
APA14/I3
FERC
ACCT. ITEM
354 Poles and Fixtures
.1 Right of Way Clearing
. 2 Structures TX-10
. 3 Insulators
.4 Connectors & Hardware
Total Account 354
TABLE 111-3 (continued)
KISARALIK RIVER
DETAILED COST ESTIMATE
(1979 -$)
QUANTITY
69 mi.
350 ea .
400 ea .
L. S.
356 Overhead Conductors and Devices
.1 Conductor 795 kem, ACSR 69 mi
Total Account 356
GENERAL PLANT
390 Structures & Improvements L. S.
381/389 Miscellaneous
DIRECT CONSTRUCTION COST
III -25
UNIT
PRICE
6,000.00
7,000.00
3,000.00
1,110.00
TOTAL
PRICE
414,000
2,450,000
1,200,000
$ 636!OOO
$4,700,000
2 1 300 2 000
$2,300,000
200,000
50,000
$62,955,000
Bethel -Section III
APA15/E
2. Coal/Wood Energy Conversion and Resources
a. I ntroduct ion
b.
Fuel resources of bituminous coal and native woods are
considered for energy uses in small communities for heat
and power generation. Available reports indicate that
coal from the Nulato coal field, which is located closest
to the Bethe 1 area, is not economi ca 11 y recoverable at
this time. Assessment of wood as an energy resource is
not possible with the available information. Two
alternative systems using coal/wood conversion have been
explored along with the economic aspects of using coal/wood
fue 1 s for gene rat i on of power and heat, to show the
possible effects when the resources become available.
These alternative systems are presently under laboratory
testing, field development or practical demonstrations
but will require a few more years of operational development
before being suitable for general utility use.
Coal Resources
Information concerning coal resources was obtained from
reference [18J, Nulato Coal Field Reconnaissance Report
which is duplicated in full in Appendix A-6.
The report covers an area two miles either side of the
Yukon River between Galena and Kaltag. The following
conclusions can be drawn from this study.
(1) Although several coal seams were found in the area,
because the coal seams are so thin, the topography
so steep and the seams di p adverse to hi 11 side
exposure, no surface mining potential currently
exists.
(2) Due to the lack of seam thickness underground mining
would be prohibitively expensive.
(3) Commercial coal production is not currently feasible
in the Nulato Coal Field.
c. Wood Resources
The western limit of wooded country is located east of
Bethel. The forested areas on the upper Kuskokwim River
have not been assessed in regard to their potential as an
energy resource. Investigations in other parts of Alaska
III -26
•
•
•
•
...
Bethel -Section III
APA15/E
CKobuk River) show however, that with proper management,
wood could supply most of the energy needs of sma 11
communities.
The following paragraphs represent an attempt to evaluate
the possible uses of coal or wood on a relatively small
scale.
d. Community Needs:
The tabulation below lists the estimated community
requirements for power and heat in the Bethel area.
Communities:
Range of Electric Power
Demand:
Annual Home Heating:
Annual Total Community
Heating:
Hourly Maximum Community
Heating:
50 to 600 residences
100 kW to 4000 kW
90 X 10 6 BTU/year/residence
5.4 X 10 9 to 54 X 10 9 BTU/year
3.3 X 10 6 to 40.6 X 10 6 BTU/hour
The fuel consumption for the community requirements at
0.8 plant factor using bituminous coal with an average
heat of combustion of 13000 BTU/lb or native wood with an
average heat of combustion of 4500 BTU/lb in the wet or
green condition are as follows:
Power Plant Capacity at 100 kW:
or
1.2 to 1.5 tons/day/Ccoal)
3.4 to 4.5 tons/day/Cwood)
Power Plant Capacity at 4000 kW: 48 to 60 tons/day/Ccoal)
140 to 170 tons/day/Cwood)
The community fuel needs for space/domestic hot water
heating at average hourly requirements when not having
the advantage of a cogeneration plant would be:
For 50 residences:
or
For 600 residences:
or
1.9 to 2.1 tons/day/Ccoal)
5.5 to 6.1 tons/day/Cwood)
22 to 24 tons/day/Ccoal)
65 to 70 tons/day/Cwood)
III-27
Bethel -Section III
APA1S/E
Interpolation between the values listed is proper to
determine an intermediate consumption rate.
Examination of these fuel requirements 'indicates that the
integration of power generation with space/water heating
would permit a major reduction in fuels needed for space/
water heating.
e. State-of-the-Art
Biomass conversion processes are listed from the current
sources available in Appendix A.
f. Alternative Energy Use Systems
Small communities having access to resources of coal
and/or wood, or biomass waste materials such as peat or
agricultural wastes, could obtain more economical energy
production in plants arranged for cogeneration of electric
power with waste heat from the power cycle to be used for
space heating and domestic hot water heating. Numerous
alternative energy schemes are presently under laboratory
testing, field development, or practical demonstration.
Alternative plant arrangements to be considered in this
report are selected from the most practical and promising
schemes from the state of the art and are listed in the
fo 11 owi ng decl i ni ng order of proven techno logy with; n
existing systems.
(1) Steam Generating Plant: Wood and/or coal fired steam
boiler-steam turbine generator-extracting steam from
turbine used for space heating and water heating -
practical limit of 1500 kW up to the maximum of
4000 kW. Waste heat distributed to community through
buried and insulated heating water conduits -which
requires close spacing of structures for conduits to
be economically feasible.
Advantages
All equipment is available from existing designs.
Boiler will be able to burn other biomass materials
such as community garbage, peat, or agricultural
wastes. Space heating as a by-product permi ts high
overall efficiencies.
II 1-28
..
..
..
Bethel -Section III
APA15/E
Disadvantages
Minimum of seven steam plant operators are required
for continuous ope rat ion. Economi cs of bud ed
heating conduits at $100 per linear foot is critical
to the success of th; s cogeneration arrangement.
Convent i ona 1 plant des i gn is too complex for the
small amounts of power and heat to be generated in
contrast to existing large central heating plants.
Cost Estimates
The cost estimates have been prepared assumi ng
resource availability at $4.50 per million Btu.
This represents approximately $40/ton of wood and
$1l7/ton of coal delivered in Bethel. With the
limited information available on the resources, a
second case with half the above fuel cost has also
been investigated.
Wood/Coal fired steam boiler-steam turbine generation
Capacity 5000 kW
Capital cost plant (1979-$) $2,500/kW
Fuel cost, delivered $4.50 ($2.25)/million BTU or
$100 ($50)/5000 lbs
Plant factor 0.5
Annual Cost (1979-$)
Fixed charges at 35 years $ 965,375
life and 7% interest (capital
recovery factor 0.07723)
o & M cost at 18% of
initial costs $2,250,000
Fuel costs at $4.50 ($2.25)/10 6
BTU for wood waste delivered as
wet or green fuel with plant
heat rate of 14000 BTU
input/kW-hr. (21,900 MWH/yr) $1,379,700
Total power generation
costs at the plant busbar $4,595,075
or 21¢/kWh
(965,375)
(2,250,000)
(689,850)
(3,905,225)
(17.8¢/kWh)
This compares to 11¢/kWh for diesel generation in
1979.
III-29
Bethel -Section III
APA15/E
(2) Biomass Gasifier:
The second configuration of an energy plant to be
considered for each community would include a biomass
gasifier accepting a mixture of reduced size wood,
coal, peat, agri-wastes, or dry refuse as fuel with
a gas output of a low heat value (150 BTU/C. F. ).
This low BTU gas could be adapted for use as fuel in
existing gas water heaters, space heating gas furnaces
and gas engine driven generators of piston type for
small communities or gas turbine type for the larger
communities. The gas distribution system would be
adapted to suit the community residences with the
lowest capi ta 1 cost arrangement most probab ly
consisting of pressurized gas mains routed to each
residence and to each power generator engine. Since
the district heating type of steam-condensate mains
would not be economically justified for this arrange-
ment, the waste heat in the gas turbi ne exhaust
would be best utilized in a recuperator for improved
cycle efficiency. An alternative gas turbine
arrangement is the semi-open loop cycle as developed
by Hague International and Solar Aircraft as outlined
in Appendi x A; thi s cyc 1 e has the advantage of
allowing clean air to pass through the turbine with
reduced maintenance. Some representative small size
gas turbines that might be adapted for this application
include the following:
AVCO Lycoming
Ruston
Bet-Shemesh
Centrax
Garrett
Kawasaki
Klockner-Deutz
1. H. I.
Microturbo
TF 25
TA 1750
M2TL
Type 33
IE 831
SIA-02
T 216
IGT-90
101
Consequent ly, the range of gas
could be made adaptable to the
power loads of 100 to 4000 kW.
flame out at part load with the
required.
II 1-30
1835 kW
1365 kW
720 kW
500 kW
490 kW
180 kW
80 kW
45 kW
30 kW
turbines available
range of community
Protection against
low BTU gas would be
•
•
Bethel -Section III
APA15/E
Cost Estimates
The cost estimates have been prepared assumi ng
resource avail abil ity at $4.50 per mi 11 ion Btu.
Thi s represents approximately $40/ton of wood and
$l17/ton of coal de 1 i vered in Bethe 1. With the
limited information available on the resources, a
second case with half the above fuel cost has also
been investigated.
Low BTU gas production
Generator capacity
Capital cost for plant plus
heat recovery (1979-$)
Fuel cost delivered
Plant factor (1979-$)
Annual Cost
Fixed charges at 35 year
life and 7% interest capital
recovery factor 0.07723)
o & M costs at 15% of
initial cost
Fuel costs $4.50 (2.25)/10 6
BTU for fuel at 18000 BTUI
kW-hr. heat rate (21,900
MWH/yr)
Total power generation cost
at the plant bus bar
or
5000 kW
2000/kW
$4.50/million BTU or
117 (58)/ton
0.5
$ 772,300
$1,500,000
$1,773,900
$4,046,200
18.5¢/kWh
$ (772,300)
$(1,500,000)
$( 886,950)
$(3,159,250)
(14.4¢/kWh)
This compares to 11¢/kWh for diesel generation in
1979.
Advantages
Five multiple fuels fed to the gasifier have the
potential of a reliable supply and potential cost
savings. A common fuel supply piped through un-
insulated gas mains feeding conventional gas water
and space heaters is most similar to conventional
low cost residential systems.
111-31
Bethel -Section III
APA15/E
Gas turbine cycle for power generation would require
less operating staff because it is simpler than the
alternative of a steam boiler-turbine power plant
which would require a cooling tower, numerous water
piping and pumping systems, chemical make up water
treatment and auxiliary systems not required by a
gas turbine cycle. Gas turbine cycle using all
clean air should have reduced maintenance and improved
re 1 i ab i1 ity.
Disadvantages
Wood-coal-biomass gasifiers are still in developmental
stage even though the state of the art began in
Germany in 1839, in France in 1840, in Sweden in
1845 and in Engl and in 1879. Gas burners wi 11
requi re adaptation for use wi th the low BTU gas.
This gas cannot be used in conventional gas ranges
nor in systems subject to leaks since it contains
carbon monoxide.
Cost estimates for the power heat system cannot be
accurate for the present.
(3) Another alternative biomass energy use scheme would
be similar to that described before except that the
residence space and water heating systems would be
replaced by direct burning air tight wood stoves to
be installed in each residence. The gas main
distribution system as outlined in paragraph (2)
would be deleted. The gas turbine-gasifier cycle
would not require revision except for sizing.
Advantages
A current federal tax incentive program is provided
for installing wood burning stoves. New technology
would not have to be developed for this portion.
Disadvantages
Wood fuel for residences would require local dry
covered storage areas sufficient to cover bad weather
periods when normal supply is interrupted. Hand
firing of stoves is not as convenient as gas fired
units described before.
II 1-32
..
•
-
..
Bethel -Section III
APAIS/E
Economic Aspects:
The biomass energy conversion systems as applied to
the Bethel area can be only approximate estimates
because of the small scale of the plants, the known
spacing between residences, the transport and storage
costs for the fuels from source (mine or forest) to
user could not be identified, and special design
considerations in regard to the arctic climate have
only been taken into account in the order of magnitude.
111-33
Bethel -Section III
APA15/E
REFERENCES
1. Stambler, Irwin; Wood Burning Cogeneration Plant with 65%
Efficiency; Gas Turbine World; September 1979.
2. Fox, E. C., and Anderson, T. D.; Convers i on to Coal in the
Industrial Sector: A Study of the Problems and Potential Solutions;
U.S .. Department of Energy/Oak Ridge National Laboratories;
CONF-780801-34; 1978.
3. International Engineering Company; 55 MW Power Plant: H~brid -
Geothermal-Wood Resldue wlth Cogeneration Wendel-Amedee KGRA,
Lassen County, California; State of California, Department of
Water Resources, Energy Oivision; May 1978.
4.
5.
6.
7.
B.
Brown, Owen D., P.E.; Energy Generation from Wood-Waste;
Eugene Water & Electric Board, Eugene, Oregon; Extracted from
"Wo6d Ener~y -Proceedings of governor William G. Milliken's
Conference held in Ann Arbor, Michigan, November 29, 1977.
Noonan, Frank; The Utilization of Forest Biomass for Electric
Power Generation: An Economic Feasibility Study; Extracted from
"Wood Enerw -Proceedi ngs of Governor wi lliam G. Mill i ken IS
Conference held in Ann Arbor, Michigan, November 29, 1977.
Power Engineering; Waste Wood and Bark; p. 43; May 1979.
Williams, R. O. and Horsfield, B.; Generation of Low-BTU Fuel Gas
from Agricultural Residues, Experiments with a Laboratory Scale
Gas Producer; University of California, Davis, Department of
Agricultural Engineering; April 1977.
Battelle Columbus Laboratories; Preliminary Environmental Assess-
ment of Biomass Conversion to Synthetic Fuels; Industrial
Environmental Research Laboratory, Office of Research and
Development, U.S. Environmental Protection Agency, Cincinnati,
Ohio; EPA-600/7-78-204; pp. 110-111; October 197B.
9. Moody, Dale R.; Advances in Utilizing Wood Residue and Bark as
Fuel for a Gas Turbine: Forest Products Journal, Vol. 26,
No.9; September 1976.
10. Hagen, Kenneth G.; Wood Fueled Combined Cycle Gas Turbine
Power Plant; Hague International, South Portland, Maine;
Presented at the California Energy Commission, Energy-From-Wood-
Workshop; July 15, 1977.
11. Power; 1977 Annual Plant Design Survey, Fossil-Fired Central
Sections; p. S.4; November 1977.
III-34
...
.,
..,
.'
lit .
•
Bethel -Section III
APA15/E
12. Culbertson, Robert W.; Onsite Conversion of Coal to Gas; Plant
Engineering; March 16, 1978.
13. Moskowitz, S. and Weth, G.; Pressurized Fluidized Bed Pilot Plant
for Production of Electric Power Using High Sulfur Coal;
Curtiss-Wright Corp.7ERDA; Extracted from Proceedings of the
12th Inter-society Energy Conversion Engineering Conference,
Volume 1 of 2, #779108, Washington, D. C., August 28 -
September 2, 1977.
14. Schwieger, Robert G.; Burning Tomorrow's Fuels -Gases: Low-BTU;
Power; p. S.4; February 1979.
15. Pease, David A.; Green Bark Replaces Natural Gas as Plywood
Plant's Energy Source; Forest Industries; October 1977.
16. Personal Corres ondence with Catalo ue Bulletin #1176) from
John C. Calhoun, Jr. of orest Fuels anufacturing, Inc.,
Wood-To-Gas Energy Systems, Antrim, New Hamsphire, to Thomas
J. Beard, Director of Fire Management Staff of Lassen National
Forest, Susanville, California, November 17, 1977.
17. Power; 1977 Annual Plant Design Survey, Industrial Steam;
p. S.12; November 1977.
18. Nulato Coal Field Reconnaissance Report, October 24, 1979,
Marks Engineering, Anchorage, Alaska.
III -35
Bethel -Section III
APA15/E
3. Geothermal Potential
a. Introduction
Three hot spri ngs have been reported in the Kuskokwim
region; (1) the Mitchell site in the Chuilnuk Mountains,
(2) the Tuluksak hot springs near Nyac, and (3) the Ophir
Creek hot springs near White Bear Lodge. The Ophir Creek
occurrence is the only one wh; ch i s currently bei ng
utilized. Mr. Faulkner of White Bear Lodge uses a portion
of the spring to heat his home and lodge facility.
Temperatures and flow rates in all three springs are too
low to allow anything but local utilization.
The three hot springs are described in the following
pages.
III-36
.I\t'"
Bethel -Section III
APA15/E
SITE:
LATITUDE & LONGITUDE:
QUADRANGLE:
BARRIER:
DESCRIPTION:
Mitchell
61° 18 1 N., 157° 40 1 W. Approx.
Sleetmute T14N, R47W, SW Approx.
Remote
The Chuilnuk mountains are centered on a semielliptical stock. The
exposed contacts of the stock dip generally outward. The contacts
are well exposed. The stock is completely surrounded by a contact
metamorphic zone in adjacent sedimentary rocks. This zone averages
2 miles (3 km) wide. A well defined fault is noted on the north
front of the mountains.
The stock in the Chuilnuk mountains range from granodiorite on the
west, comparable to that of Kiok1uk mountains, through quartz
monzonite, to granite on the east. The presence of the granodiorite
on the west side of the stock, nearest to the Kiokluk mountains,
suggests that the rocks of the two stocks derived from a common
magmat i c source, connected at depth. The igneous rocks of the
mountains are unaltered. Hot Springs occur along the Northeastern
contacts of the stock near the largest of several lakes. (Cady 1965).
The hot springs of the Mitchell site in the Chuilnuk mountains were
visited in 1975 by representatives of the Calista Native Corporation.
In a letter to the State Energy Office, Mr. Ron Dagon of ESCA-Tech
made the following observations: "Active thermal discharge takes
place within an area 3000 1 x 1000 1 from numerous springs and seeps.
Water temperatures have been measured for most of the area within a
range of 50° to 150°F, and at an approximate average of 100°F. No
vapor discharge was observed when the site was last visited but the
rate of discharge from these springs is on the order of 25 gallonsl
second. Exotic vegetation surrounds the spring area and a local
abundance of animals was noted by the field crew.1I
The above characteristics do not indicate that large-scale generation
of electricity is feasible, although the discharge could furnish
heat to large hatchery or other development. Small-scale electrical
generation for local use only might be possible using a small
ORMAT-type generator. These hot springs constitute the most important
known geothermal resources along the Kuskokwim drainage.
SOCIQ-ECONOMIC:
The land near Chuilnik mountain has been selected by the State of
Alaska under terms of the statehood act.
The location of this system is very remote. The nearest population
is Sleetmute 25 miles (40 km) to the north. The mode of transportation
to the springs would probably have to be by helicopter.
I II -37
. il. f III I 1 I 1 :1 !:.-'.
/'.. l'Ii(HI~lAI! ,.." Ml
; 'I (:1 1';,'\ i II ! I~. j' l' ,.'",
,., ! ~ I J
I; t l Ii f f f j I
mOl ,
SCALF I 63360
. ,
('ONTOUR INTERVAL 50 FEET
I: l Nf S r;[PR[SENl 25-FO:)1 CON10URS
MEAl\ Sf A
SLEETMUTE (8-5), ALASKA
iOr)')
E .-::,j
l<'l"}ME [::1.<;
FIGURE 1II-3.1
"
Bethel -Section III
APAIS/E
No exploration has taken place on this spring system. Any future
application would require~temperature and flow rates measurements.
The Kuskokwim mountains are part of an extensive mineralized zone.
Rare metals have been found in the streams.
111-39
Bethel -Section III
APA15/E
SITE:
LATITUDE & LONGITUDE:
QUADRANGLE:
BARRIER:
DESCRIPTION:
Tuluksak
61 0 00' N., 160 0 30' W. Approx.
Russian Mission/Bethel T10N R63W SM Approx.
Remote
There has been a reported hot spri ng along the Tu 1 uksak River.
Algae growth and a distinct sulphurous odor were reported. (Waring
1917) .
The geology of the region is covered in the flats by coastal and
alluvium sediments. Jurassic to Cretaceous interbedded layers of
graywacke and shale outcrop in the hills. Cretaceous granite rocks
intrude these sediments. (Selkregg 1976).
Little is known about the Tuluksak hot springs. Their precise
location is not referred to ;n the literature, although they are
approximately twenty miles up the TuluKsak River from the village
of Tuluksak. Without further information the value of the site is
impossible to assess. If the site had suitable characteristics,
its heat might be used locally for a fish hatchery or for a greenhouse.
Due to the lack of greater surface manifestations, it is doubtful
that a large resource exists here.
SOCIO-ECONOMIC:
The hot springs are presently contained within the proposed "Yukon
Delta" National Wildlife Refuge.
The nearest village is Tuluksak at the confluence of the Tuluksak
and Kuskokwim rivers. Tuluksak River is navigable over much of its
course. The springs are approximately 20 miles (32 km) from the
village. They are also 15 miles (24 km) from Nyac mining camp.
Air service is available from Bethel to either of these areas. One
swamp buggy road exists from Nyac along the Tuluksak River.
The springs have had no evaluation. In fact, they have not even
been confirmed at this time. If a viable resource can be confirmed,
a possible development project could establish a market for fresh
vegetables. This would supplement the subsistence lifestyle of the
area residents. Geothermal energy could make this a viable project.
III-41
..
III ..
; { I' : i,
FIGURE III-3.2
? '~~'"''
, I
em, TOIJR INH.Rvtl l'reT
P;1 if P L:NI J t~: f'i<1 :~Hil H'lil, ;~', ,,-", III'
f.." 1', t-HI\N ~lA lL'lti
." !I \'1 IAN MISSION (A-41 fA-51 RFTHFI tn-4i (0-51 ·TTT ...; I,?
Bethel -Section III
APA15/E
SITE:
LATITUDE & LONGITUDE:
QUADRANGLE:
BARRIER:
DESCRIPTION:
Ophir Creek
61° 111 N; 159 0 51 1 W
Russian Mission, T13N, R59W, Section 21
Remote
A spring occurs on Hot Springs Creek at the headwaters of Ophir
Creek within the Kilbuck Mountains PGRA 274,856 acres (111,234 hectares).
The valley floor slopes at about five degrees and adjacent hill
slopes are about 10-15 degrees. The Ophir Creek drainage descends
down the northeastern flank of Mt. Hamilton.
The main bedrock types underlie the Ophir Creek valley. The mountains
to the south of Ophir Creek and the divide between hot springs and
Ophir Creek are composed of intrusive igneous rocks of granitic
composition. The igneous intrusion is a stock composed predominantly
of quartz monzonite of Tertiary Age.
The stock has been intruded into Cretaceous volcanic rocks, chiefly
massive andesitic flows interbedded with greywacke, siltstone,
pebble conglomerate, limestone and shale. These rocks outcrop to
the east, north and west of Ophir Creek (Baker, 1977).
The springs are composed of one major and one minor pool near the
head of the Hot Springs Creek valley.
The Ophir Creek hot springs discharge at approximately five gallons
per second, with an observed temperature of about 140°F.
Presently, the lease holder, Mr. Harry E. Faulkner, diverts water
through a 4" (10 cm) pipe 1,500 feet (457 m) to his house for
heating purposes. The 4" line diverts a third of the output of the
springs. The rest of the flow runs into a nearby creek.
In a 1976 report produced by a Mr. William Ogle, he suggests that
the springs could support a salmon hatchery which could produce up
to 200,000 smo 1 ts per year. Because of thei r low temperature and
small discharge there is little chance that the springs could
support a large scale development.
SOClO-ECONOMIC:
Approximately 40 acres of land surrounding the geothermal springs
is subject to a mineral springs lease issued to Harry E. Faulkner,
P.O. Box 153, Bethe 1, Alas ka 99559 (IFF 019136). A 11 the 1 and
below the geothermal spring along Hot Springs Creek to its confluence
with Ophir Creek, including the airstrip, is owned by Mr. Faulkner
as a homestead and patented land. Surrounding lands are classified
as public interest lands (d)(l).
1II-43
/
/
\
5
J!
20
APPHOXI MA rr MI AN
I
, I
4
1ft;
21 ~
'! j;;-
/
/'
/ -5,1
11 i
···>ib 2~ . ': 3~3------~~--~~
1 I ' ) .
2
SCALE 1 fi3360
CONrOUR INTERVAL SO Ff:ET
D(;TT(L' L,N!,:; R[pr,t.SEt-H .:rJ_~~;OT ,
NATIONAL GEODETIC VERTICAL DATUM
4 MILES
=~=:=--==--==-l
FI GURE II 1-3.3
..
..
.'
•
..
• ..
•
..
Bethel -Section III
APA15/E
An historical place application AA 10267 has been filed by Calista
Corporation upstream in nearby Section 28.
The State Fish and Game Department has rated the spring as being a
moderate potential fish hatchery site. The major drawback was the
logistics of building it there. The associated fishermen of Lower
Yukon and Kuskokwim regions and Calista Native Corporation have
been interested in the salmon enhancement possibilities of Ophir
hot springs. There are also mining interests in the area.
111-45
Bethel -Section III
APA15/E
BIBLIOGRAPHY
Dagon, Ron, 1976, Letter report to the Alaska Energy Office, Ms.
Joan Ray; ESCA-Tech/Calista Corporation.
Markle, Don, 1978, Unpublished reports on Geothermal Site in
Alaska; State of Alaska, Department of Commerce and Economic
Development, Division of Energy and Power Development.
Ogle, William, 1976, Report of a visit to Ophir Hot Springs (White
Bear Lodge); Energy Systems, Inc.
U.S.G.S. Circular 790, 1978, Assessment of Geothermal Resources
of the United States.
III-46
..
...
-
•
11/
•
.. .. ..
..
•
..
Bethel -Section III
APA15/E
4. Wind Potential -Bethel Area
a. Introduction
This is a preliminary survey of the wind energy potential
of the communities in the Bethel area. This potential
relates to the practical application of wind energy
extracted by a contemporary wind energy conversion system
(WECS) .
The history of use of wind generation units is very
limited in Alaska. There is a spasmodic use of wind
power along the western coast of Alaska, continuing on a
small scale today. WECS have in the past been installed
in Dillingham, Unalaska, Big Delta, and Kotzebue and none
of these systems is presently operational. The Geophysical
Institute of the University of Alaska operated a WECS at
Ugashik in 1975. A small unit at Port Alsworth is presently
providing significant power to a private residence and
another small machine is operational today at Portage
Creek. The central questi on addressed here, however, is
the magnitude of the wind resource available for electrifi-
cation or supplemental supply of energy to villages and
communities.
b. Wind Generation
The extraction of energy from wind has been accomplished
since the earliest days of interest. Multiblade wind
mills have been a part of the American farm and homestead
scene for over a century, and have been used to pump
domestic and irrigation water, generate electricity and
perform similar functions. Most are small, with typical
power ratings of less than one horsepower.
Windmills are generally connected to an electric generator
(either direct or via a gear arrangement). The energy
generated is either AC or DC. Most wind generating
systems built in the past employ an energy storage system
(batteries) and an inverter to make the stored DC energy
compat i b 1 e with 60 cyc 1 e AC equ i pment. The equ i pment
required for these conversions is costly and reduces the
efficiency of the plant. Recently small wind generators
employing induction generators have become available.
Induction generators can only be used as part of a system
where voltage and frequency are maintained and reactive
power is supplied by other generating means (synchronous
generator). Conversion equipment can then be eliminated.
Approximately 1/3 of a system l s basic demand can be
supplied by induction generators without causing instability
1II-47
Bethel -Section III
APA15/E
1
c.
or reqUlrlng additional reactive power supplies. If
these conditions can be met, the use of induction generators
can lower the cost of a wi nd generator i nsta 11 at ion
considerably. The life expectancy is generally assumed
to be 5-10 years. Cost estimates for two arrangements
are given in Appendix B.
Wi nd power suffers from one obvi ous di sadvantage; the
intermittent and fluctuating nature of wind itself. When
a wind energy conversion system (WECS) cannot be used
where its full instantaneous output is used to supply the
load while displacing utility supplied power, an energy
storage system must be contemplated -at cons i derab 1 e
expense. The consensus today is that the most cost
effective way to use wind power is on a utility grid to
save fue 1 when the wi nd blows and eli mi nate the extra
costs for batteries and inverters. A small utility
system must therefore install sufficient primary generation
capacity! to provide for its total firm capacity require-
ments. This basic power supply system must also be able
to accomodate the relatively unpredictable energy input
from wind powered units. To date wind machines have not
found widespread use in industry or in utility systems.
With the steadily increasing cost of fossil fuel and its
major influence on the costs of fuel generated electricity,
the interest in utilizing wind generators is increasing.
Basic Definitions and Methodology
The primary criterion for determining the feasibility of
WECS use is the average wind speed V at the rotor hub
height h of a WECS. An annual V of 12 MPH is desirable,
but lower V may still be useful in energy-deficient
areas. The pr; nci pa 1 equations be low wi 11 be used,
always leading toward the calculation of the average
power PM produced by a wind machine. Thus, monthly and
annual V for each community are sought.
i.e., diesel, gas turbine, hydro.
1II-48
-
•
.,
•
.,
."
Bethel -Section III
APA15/E
(1) Power in the nd (no WECS involved here)
A wi nd wi th instantaneous speed V wi 11 have an
instantaneous power density or flux PIA (for a
vertical or "sheet of wind" area A) of
(1)
Co depends on the uni ts of A and V, and the ai r
density.
The average power flux Pw/A in a wind regime (the
collection of V values over a long period, say a
month or year) is not
(2)
but is (3)
The value of f(k) depends on the speed distribution
of the winds, i.e., the shape of the so-called
frequency distribution curve. For Alaskan winds
f(k) = 2.14 is a good value for estimation purposes,
and it is used herein when actual f(k) are not
known. Then, for A in square meters, V in miles per
hour (MPH), Co is 0.05472 if Pw is in watts (w) and
equation (3)
becomes
(4)
1II-49
Bethel -Section III
APA15/E
So, a rough "rule-of-thumbll is that the average
power flux of a wind regime is 1/8 of the cube of
the average wind speed, for the units given above.
However, see the caution under "Power Output of a
WECS II regarding use of equation (4).
It is important to remember that the above refers to
the power (or energy content) of the wind. Now the
question of the energy extraction by a WECS must be
considered. In the following this is done, in terms
of average power del ivered at the output of the
wi nd-dri ven turbi ne (generator), with no further
losses such as those due to transmi ss i on 1 i nes,
inverters, etc., be; n9 cons i dered.
(2) Power Output of a WECS:
The average power produced by a speci fi c (model,
size, etc.) WECS is defined as PM' One can define
an analog to the wind flux Pw/A by PM/A, where in
the windmill case A is the disc area swept out by
the blades. There is no theoretical simple relation-
ship between Pw and PM' except that, of course, the
larger the Pw the larger the expected PM'
Detailed calculations of the coupling of a windmill
with a given power characteristic (PM vs. V) and the
actual full wind distribution curve for a given
location lead to a set of values Pw V. This is
displayed in Figure 1II-8 with the associated
computational procedure given later.
III -50
•
.,
•
•
.'
..
Bethel -Section III
APA15/E
One must be careful in applying equation (4) to
engineering situations. While the mean wind power
flux is useful as a guide to determining the wind
power potential of a site, the Pw/A is appreciably
greater than PM/A. First, only 59.3% of Pw/A at
most can be extracted by an ideal single unshrouded
disc WECS, and then only if the WECS operates at all
V in the wi nd spectrum. Thi sis
limitation (like the Carnot Law).
cut-in and cut-out V of a WECS make
a fundamental
In practice
some of the wind
spectrum unusable. Second, for a rotor the efficiency
or power coeffi ci ent at vari ous Vis vari ab 1 e,
ranging from zero to some maximum value (0.3 to 0.45
at best) and then back to zero, for increasing V.
This power coefficient depends on the ratio of the
wi nd V I rotat i ona 1 speed of the blade tips. There
are additional inefficiencies, as in any geared
rotat i ng system. Thus, in practice the PM/A of
contemporary wind machines will be of the order of
115 to 1/10 of Pw/A.
(3) Computation Method:
Given the assumption of a specific WECS installed at
a hub height hi (above ground) where the average
wind speed is Vi' the mean average power PM from the
WECS can be predicted from simple empirical equations.
These are of the polynomial form
(5)
I II -51
Bethel -Section III
APA15/E
The a i depend, of course, on the machine selected.
Table III-l gives the a i for two contemporary
machines; one is rated (maximum power) at 15 kW, the
other at 100 kW.
For most locations the hi of installation will be
different from the ha of anemometers yielding the
measured Va' The key relationship here is
(6)
where a good approximation is p = 0.2.
Equations (5) and (6) are the most important equations
used herein. Justification of these, especially in
determination of the ai' is outlined here. The
first step in getting the a i of equation (5) requires
that the frequency statist; cs (% of the time the
wind blows at a specific V) are summed in a way to
yield the V and also the so-called wind speed V
duration curve. The latter gives the fraction or
percentage of the time of the measurement peri od
that the wi nd blew at V or greater than V. The
duration curve is then coupled with the WECS power
characteristic PM vs. V to provide a third curve
giving the percentage of time the WECS delivers a
given P. See Figure III-B. The area under this
last curve is then the total energy extracted by the
WECS, since the product of power and time is energy.
Thus this total energy divided by the absolute time
(e.g. in hours) of the V measurement period gives
the average power PM for the period involved. In
this way a large number of V statistics from the
wind regime are boiled down to a single PM' V point
III-52
II'
•
..
•
lIII
•
..
..
•
t
v
FURLING _____________________ .. ______ ...::L... ___ ~
v
% t V>V
LIMITING
DURATION CURVE !
I
VCUT-IN I
WECS
CHARACTERISTIC
-------/----------
I
I
I
I
I
100
I I
I I
I I L ______ 1 ________ _
I
I
I
I
I
I
I PRATED L ______________ ---a..~:;
L ________________ ----4~~~~~~~~q
-P
COMBINATION OF A WIND SPEED DURATION CURVE AND WECS POWER
CHARACTERISTIC TO OBTAIN THE WECS TOTAL ENERGY PRODUCTION
For the \\fECS I V 1 = limiting V; V co = cut-out or furling V
The average power P is obtained from the total energy produced
(shaded area) divided by the total absolute time of the measurement
period of the duration curve (taking into account that the curves
above express time as a percentage of the period involved).
III -53 FIGURE III - 8
t
V
100
% t.
V::V
Bethel -Section III
APA15/E
characterizing the behavior of a given WECS at a
specific location for a selected period. Then a
large number of such points can be used to obtain
plots and curve fitting computer routines yield fits
(give the a i ) corresponding to the plotted points.
For example, several hundred duration curves from 50
Alaskan sites have been treated to arrive at the
constants of Table 111-4.
(4) WECS Power Production:
(a) Average Powers:
Detailed calculations of PM were made for two
contemporary WECS. The results are given in
Table III-4. This data represents magnitudes
to be expected, but does not indicate optimum
performance.
(i) 15 kW-rated WECS: Thi s machi ne (25 ft.
disc) is not optimized; the rotor and
controls evidently are designed to limit
(at 15 kW) before the 20 kW generator
capability. It is inherently a high V
machi ne. It is a prototype of the WECS
being tested at Nelson Lagoon, which may
be rated near 20 kW.
(i i) 100 kW-rated WECS: Thi s machi ne (125 ft.
disc) as used in our calculations involves
a rotor capable of over 200 kW mechani ca 1
dri ve to the generator. The prototype
used a 100 kW-rated generator, but a new
III-54
...
•
.. ,
•
..
•
.,
Bethel -Section III
APA15/E
TABLE 1II-4
AVERAGE POt-IER OUTPUT POL YNOf4IAL COEFFIC I ENTS FOR CONTEMPORARY WECS
Max. P a o \ a 1 a2 a 3
(Ra ted Pl ..
15 Id~ -0.247 -0.1169 4.333 E-2 -9.041 E-4
100 kH -19.59 3.222 0.1935 -7.280 E-3
III -55
Bethel -Section III
APAIS/E
vers i on wi th a 200 kW generator is now
operational at Clayton, NM. Thus, one can
estimate that a WECS with an 88 ft. disc
and 100 kW generator woul d produce PM
similar to our tabulated values.
The PM in the tables are for the heights
and sites designated, but correspond to
the Windspeed. Thus, these are also
applicable to other situations where the
designated windspeed may exist.
(b) Duration of Wind Power:
The power output (PM) quoted take into account
the wind variability, including calm periods.
Thus, PM will range from zero to the rated PM;
hence power conditioning and distribution
equipment must be rated at the maximum WECS
power.
Energy storage is not considered here, since,
for municipal systems a better and well-developed
approach is the synchronous inverter or an
induction generator.
A windspeed of about 12 MPH has been used in
USDOE wind power work as a practical criterion
for economically viable use of WECS. This
criterion can be changed, depending on the
other energy sources at a 1 ocat i on and the
fossil fuel costs there. Table III-S show
that this Windspeed is available at Bethel for
all months, at 60 ft.
II I-56
..
•
•
..
.,
Bethel -Section III
APA15/E
TABLE III-5
WECS MEAN OUTPUT POWER, MEAN KWH
Bethel 15 and 100 kW-Rated WECS at H = 60 ft. P in table are mean Powers.
v (mph)! V (mph)2 P(15) Energy P(100) Energy
Month 20 ft. 60 ft. kW kWh (15) kW kWh (100)
January 12.2 15.2 4.8 3,570 48.5 35,710
February 13.1 16.3 5.4 3,630 52.8 35,480
March 12.3 15.3 4.8 3,570 48.9 36,380
April 15.5 14.3 4.3 3,100 44.8 32,260
May 10.5 13.1 3.6 2,680 39.5 29,390
June 10.2 12.7 3.4 2,450 39.6 27,070
July 10.0 12.5 3.3 2,450 36.7 27,300
August 10.5 13.1 3.6 2,680 39.5 29,390
September 10.6 13.2 3. 7 2,660 39.9 28,730
October 11.0 13.7 4.0 2,980 42.2 31,550
November 11.4 14.2 4.2 3,020 44.3 31,900
December 11. 3 14.1 4.2 3,120 43.9 32,660
Annual 11. 2 13.9 4.1 35,910 43.1 377 ,820
1 Wind data obtained from the Alaska Regional Profiles, Volume III, Southwest
Regions. Wind velocity recording height assumed as 20 ft.
2 Calculated wind velocity using equation (5) page 111-49.
III-57
Bethel -Section III
APAI5/E
d. Economi c Ana lys is:
e.
There is general agreement that the correct criterion for
the economic selection of a generating unit is that its
cost, when combined with those of other generating units
making up a total electric utility generating system,
should result in minimum cost of electricity while
maintaining an adequate level of reliability of service
to the consumer. The established method of checking this
criterion ;s that of simulating total utility generating
system performance and cost over a period of time which
represents a major fraction of the 1 ife of the uni ts
under consideration. Since the WECS units discussed here
produce only secondary energy the economic analysis of
the wi nd energy supported system vs. the same system
without wind energy need consider only the cost of fuel
displaced by the WECS. (It;s assumed that all other
costs of the basic power supply system are incurred in
either case).
Fuel Displacement Cost:
The process of fuel displacement cost is simple. Calculate
the annual fixed charges on the WECS unit's investment,
plus its annual operation and maintenance costs; calculate
the annual fuel cost at the average heat rate of a thermal
unit to provide an equivalent amount of energy, total the
costs for each method, and divide by the kilowatt hours
generated. The resulting ratio is $/kWh. The difference
in $/kWh between the two methods ;s a direct comparison
of the savings or deficit expected when using a WECS to
displace fossil fuel.
Figure 1II-9 shows the breakeven cost per gallon of
di ese 1 fuel above whi ch i nsta 11 at i on of a 15 kW and a
100 kW WECS becomes economical for various WECS utilization
factors. The utilization factor is defined as the
percentage of annual e 1 ectri ca 1 energy ava"j 1 ab 1 e from the
WECS which is actually utilized. This factor accounts
for machine malfunctions, excess energy produced during
light load conditions, maintenances etc. The graphs show
that the breakeven cost is quite sensititve to the utiliza-
t; on factor.
The following is a listing of statements and assumptions
used in preparation of these graphs:
(1) A 15 kW machine is used for cost comparison in small
communities having a peak load of 100 kW's or less.
The larger 100 kW machines could present system
II I-58
ft·
",.
•
•
•
•
30
25
20
J:
3=
~
........
~
l-
fI) 15 0 u
z
0
i= u
:::l
Q
0 cr
l1-10
(/)
u
IJJ
3:
5
l 0
15 KW WECS AT
SHOWN UTILIZATION
___ jif'=" BREAKEVEN" FUEL COST
I
I
DIESEL COST
AT 8.5 KWH/GAL.
GENERATING EFFICIENCY
_____ 80% ___ --------------
I
I
___ ~O% __ I --T------
___ 100% __ I I
I I --I --T---
I I
I I
I I GENERATING EFFICIENCY
I I 100KW WECS I
AT SHOWN I I I
I I
I UTILIZATION I I ~~t1 I I I
,I I I = I~~~ =---1-__
,
I
I I I I , I I I I 'I I I I I I I I ,
, I II , , I I
'I I I I I , , , I I I I I I I, I , ,
I, , I I I
, I , I I I
I I I I
I, I , I
: ~ I I I I
I I J I II J I
.5 1.0 1.5 2.0 2.15 3.0
DIESEL FUEL COST I + /GAL
FIGURE m -9
111 -59
Bethel -Section III
APA1S/E
stability problem during high windspeeds and light
load conditions without additional costly controls.
Generating efficiency for small village diesel
plants assumed at 8.S kWh/gal. Maximum annual WECS
output = 35,910 kWh.
(2) A 100 kW machine is assumed installed in the Bethel
system where its full instantaneous output power can
be utilized. Generating efficiency for the Bethel
utility is assumed at 13.0 kWh/gal. Maximum annual
WECS output = 377,820 kWh.
(3) Present fuel oil prices at Bethel -0.89/gal.
Villages -$1.60/gal.
(4) WECS maintenance cost estimated at $2,000 per year
for IS kW machine and $6,000 per year; 100 kW machine.
(S) Cost estimates for the WECS can be found in Appendix B.
(6) A single interest rate of 9% is used to determine
the WECS fixed annual charges. This rate is felt .to
be representative of a interest rates obtainable for
such projects.
(7) A 15 year payoff period is assumed.
Graph 111-9 clearly illustrates that at the current fuel
prices (October 1979) of $0.89 per gallon in Bethel and
$1.60 per gallon in many of the surrounding small villages,
WECS is becoming an increasingly competitive energy
source. This does not imply, however, that we should
proceed headlong and install a WECS in every small village.
What the graphs do illustrate, however, is that the cost
of energy produced by a WECS is now comparable to the
fuel cost of energy produced by convention fuel oil fired
generation. In this light, if would seem useful that
stUdies be made to formulate a long range plan to implement
the i ntegrat i on of WECS into the power gri d of "bush"
communities should other renewable resources such as
hydro be unavailable. This plan should include sufficient
research, development and testing of selected WECS to
insure a reliable, maintenance free machine capable of
operat i ng unattended for long peri ods of t"j me in the
severe weather conditions encountered in Alaska.
I II -60
..
•
.,
..
..
Bethel -Section III
APA15/E
There are unfortunately a great many additional factors
beside strictly energy cost which have further limited
the use of WECS by electric utilities. These include but
are not limited to the following:
(1) Beside the fickleness of local wind conditions,
technical environmental, and social problems must be
addressed. Technical and social barriers that must
be dealt with include power system stability; voltage
transients; harmonics; fault-interruption capability;
effects on communications and TV transmission;
public safety; legal liabilities and insurance; and
land use issues.
(2) Wind machines are susceptible to damage during high
wind conditions. High winds and/or strong wind
gusts can cause blade or tower structure failure.
(3) The questionable reliability associated with present
day wind machines limit the use of wind generation
by electric utilities. Investment costs, maintenance
costs, etc, for a WECS which is not operational
increase the overall cost of power ina system
without the benefit of supplemental energy being
available.
(4) WECS as used in this evaluation are not stand alone
systems. They require a stable external voltage and
frequency source to which they may be synchronized.
This is generally provided by intertying the WECS to
a utility grid or fuel fired generation units. If a
grid is not existing, energy storage and conversion
equipment have to be added.
(5) Wind power energy ;s a supplementary or secondary
form of energy and there must at all times be
sufficient conventional generation or energy storage
to IIbackup" the WECS.
It should be further emphasized that most of today's
wind machines which are capable of generating large
quantities of power are prototypes and not production
model machines. It will take a few years of testing
to ensure a reliable machine suitable for production
and sale to the utilities.
In summary, although the technical feasibility of wind
power has been demonstrated many times over, its fluctuating
nature, quest i onab 1 e re 1 i ab i 1 i ty under severe weather
conditions and the present cost of equipment, still make
III-61
Bethel -Section III
APA15/E
it a marginal proposition for most utility applications.
However, a long range plan to consider the intergration
of WECS into the power grids of small communities where
other renewable resources are unavailable should be made.
I II -62
.. '
•
..
•
•
.'
•
•
Bethel -Section III
APA15/E
REFERENCES
1. Bristol Bay Energy and Electric Power Potential, U.S. Department
of Energy, Alaska Power Administration, October 1979.
2. City of Unalaska Electrification Study, 1979. Robert W.
Retherford Associates, September 1979.
3. Alaska Regional Profiles, Volume III, Southwest Region, State
of Alaska.
4. Wind Power Digest, #16, Summer 1979.
111-63
Bethel -Section III
APA15/E
5. Transmission Interties
Q. 11 Villages in The Bethel Area:
Diesel generating plants in small communities produce
e 1 ectri c energy of much hi gher cost than for 1 arger
systems due to the following factors.
(1) Fuel costs are higher due to transportation.
(2) Small engines operating under highly variable loads
are less efficient than larger ones -operating
under comparatively steady loads -(6-8 kWh/gal of
fuel compared to 12-14 kWh/gal.)
(3) Operating and maintenance costs are higher due to
remote locations and inefficient energy conversion.
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
for the eleven communities within a 50 mile
Bethel (listed in Section II). 50 miles has
to be the lIeconomic distance" at this time.
investigated
radius from
been determined
(See Appendix A-4).
The interties with the existing Bethel systems have been
assumed to be s i ngl e phase 1 i nes ut il i zing the s i ngl e
wire ground return scheme (see Appendix A-I). 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
convers i on equipment can readily produce three phase
power where needed.
Two demonstration projects -utilizing single wire ground
return lines -are under contract to be built in the
Bethel and Kobuk area in the near future.
It is anticipated that this scheme can eventually provide
primary power supply from larger centralized plants and
assign use of the small, village diesel plants for standby
and make less costly power available to remote communities.
To as sure adequate vo 1 tage 1 eve 1 sin the commun it i es
under consideration, the interties have been chosen at
40 kV wi th conductors 7#8 A 1 umowe 1 d. The approximate
routing has been shown on Figure III-II.
I II -64
.'
•
• ..
...
..
..
Bethel -Section III
APA1S/E
The following table lists the central utility and the
communities to be intertied with their expected peak
loads in the year 2000, the distance from the load center
and the required tie-lines.
It has been assumed that the interconnected system costs
would be shared equally by all communities served.
111-65
H
H
H
• l I.
f ,
'\ l (. _I '.
LEGEND' \~-.~
4 '.' ~r'\--.~ '" ">--
•
, I , t
< ' .... ~
'\..AHT WITH
.~ ,
Lrl"" IETWEEN't,j
: AND· JUNeTIO,. P
'~. ";' ~ I .,
,
I "
.!fo;'\" • . .. .... ' ... 'j. .... 'ft ... ,
'IO)ot* f 1I."'~
"--~ ',j' • " ~
~. r.~'
j,
: I. '
: .>:"",.
-\1'
.
~
\
':~\ i ....... ;..-.,~ .. ..,..,..(.1\.~ ... ~J.'b .
. "c.,:' ." ~ \ ...............
, . ." ,
":,,~~,;,, ... ..... '--' '>:.' . I, ' , ,;
, ,
FIGURE III-10
, t ,
Bethel -Section III
APA014/El
TABLE III - 6
REGIONAL INTERTIES
(2000) Operating
From To Distance
Location Location (Mil es)
Bethel Jct. 7.8
Jct Akiachuk 6.0
Akiachuk Akiak 7.9
Akiak Tuluksak 17.1
Jct. Kwethluk Jct. 7.4
Kwethluk Jct Kwethluk 4.2
Kwethluk Jct Napaskiak 9.1
Napaskiak Eek 39.2
Bethel Oscarvi 11 e Jct. 4.7
Oscarvill e Jct.
Oscarvi11e Jct.
Napakiak
Bethel
Atmautluak
Total
1 Feeder 1 Load
2 Feeder 2 Load
3 Feeder 3 Load
Oscarville
Napakiak
Tuntutuliak
Atmautluak
Akolmuit
4 Total of Feeder Loads
Installation Cost
2.9
7.2
32.3
17.8
6.7
170.3
170.3 miles 7#8 Alumoweld @ $15,000
(1) River Crossing
15 Terminals @ $35,000
Total
Use
Max. Load Vo ltage
kW (kV)
794 1 40 kV
363 40 kV
158 40 kV
88 40 kV
431 40 kV
233 40 kV
198 40 kV
78 40 kV
402 2 40 kV
26 40 kV
376 40 kV
128 40 kV
382 3 40 kV
320 40 kV
1578 4
1979 $
$2,554,500
16,000
525,000
(3,095,500)
3,100,000
III -67
Conductor
Size
(AWG)
7#8
7#8
7#8
7#8
7#8
+ river crossing
7#8
7#8
7#8
7#8
7#8
7#8
7#8
7#8
7#8
Bethel -Section III
APA15/E
6. Conservation
The transmission intertie described in the preceding section represents
one form of conservation by utilizing highly efficient generat'ing
equipment rather than smaller less efficient engines in small
communities. This investigation can be extended one step further
to the "individual/community" 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 fuel but also
produce electric energy more reliable and less costly. Other forms
of conservation in the Lower Kuskokwim area, where the electrical
hook-up saturation is extremely low, can be achieved by the following
measures:
1
2
a. Variable Speed Engines:
This unorthodox method of improving the efficiency and
life expectancy of diesel engines has been described in
various studies 12 and basically employs a gearbox between
prime mover (diesel engine) and generator to allow speed
reduction for the prime mover at times of low load and
sti 11 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 movement.
b. Waste Heat Recovery and Utilization
Engihe jacket water heat and exhaust heat can be used for
spacing heating purposes. Since approximately 70% of the
energy input into a diesel engine generator is lost as
waste heat, 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.
IIBristol Bay Energy and Electric Power Potential" -December 1979
for the Alaska Power Administration.
"Waste Heat Capture Study" -June 1978 for the Division of
Energy and Power Development.
1II-68
..
...
•
•
-
•
Bethel -Section IV
APA12/I
Resul ts of the bus bar cost of power have been summari zed:
• In graphical form showing the unit costs in ¢/kWh on an
annual basis for the study period.
• As totals of the present worth of annual total costs for
alternate scenarios for the study period.
• As equivalent of unit costs for alternate scenarios for
the study period.
The graphi cal exhi bit shows breakeven poi nts cl early and
allows easy demonstration of the results of various developments.
Comparison of accumulated present worth allows analysis by
establishing Benefit/Cost ratios for alternates for the entire
study period and will determine the best economic development.
Accumulated present worth of the unit costs of energy will
make it possible to assess the impact of changes in load
growth and service area.
Inflation rates have been assumed at 8% per year through 1984
and at 4% per year thereafter. Fuel oil costs have been
escalated an additional 2% above '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 REA financed projects, while
the hi gher rates woul d represent the rates for bonds or
institutional loans obtained for private financing.
The evaluated alternates refl ect two different routes of
development:
• • Independent systems in the various communities.
Intertied regional systems.
In the case of independent system development, the primary
electric power source will in most cases be diesel generation.
Supplemental use of wind generation may be possible but is not
addressed in the power cost study due to the uncertainties of
useful life and equipment maintenance costs. Only low load
growth scenari os have been evaluated for the independent
system development, as it is not expected that the historical
growth rate will be maintained under this condition.
Costs in all cases evaluated include investment amortization,
insurance, operation and maintenance, and fuel where applicable.
Investments for additional generating equipment and/or
transmission lines have been assumed in timing and magnitude
to assure reliable capacity in the scenario under consideration.
IV-2
III! ,
..
...
...
..
..
..
Bethel -Section IV
APA12/I
B. ALTERNATE DEVELOPMENT PLANS
A summary and analysis of each of the alternatives is narrated
below. Statistical and graphical comparisons are provided following
the narrative. Tables IV-1 "Accumulated Present Worth ll and IV-2
"Cost Ratiosll as well as Figures IV-1 through IV-5 IIUnit Cost ll
present a summary of the cost of power calculations in Appendix C.
I-A Bethel, Low Load, Diesel Generation
This alternative assumes that the electrical energy requirements
;n the Bethel community will continue to be supplied by diesel
dri ven generators throughout the study peri od. Generati ng
additions have been assumed to be of similar size or larger
than presently installed equipment. This alternative represents
the mi nimum in capital 'j nvestment, but e 1 ectri ca 1 energy rates
are almost entirely dependent on diesel fuel cost. Energy
costs will continue to rise indefinitely under this alternative.
2-A Villages, Low Load, Diesel Generation
This alternative assumes that the villages will continue to
operate small diesel driven generators to supply electrical
energy. Generat i ng addi t ions have been assumed to be of
similar size or larger than presently installed equipment.
This alternative represents the most inefficient and expensive
alternative for producing electric power in the village
communities, with energy costs expected to exceed $1.00/kWh by
the turn of the century (equivalent to about 36¢/kWh in 1979).
3-A Intertied System, Low Load, Diesel Generation
This alternative assumes diesel generation and a Single Wire
Ground Return (SWGR) transmission intertie (See Appendix A)
between Bethel and eleven of the surrounding communities. The
maj or advantage of thi s alternate is that ita 11 ows the
surrounding communities to be served from a more efficient,
centralized generation facility. This results in a sUbstantial
regional fuel savings as compared to independent generation ;n
Bethe 1 and each of the communi ties as out 1 i ned in the two
previous plans. Investments include the transmission interties
and diesel generating equipment as required to maintain firm
capacity in Bethel and the small communities. Energy costs ;n
the year 2000 are decreased drastically for the village
communities under this alternative, from in excess of $1.00/kWh
to an average of $0.35/kWh (equivalent to about 13¢/kWh in
1979). In addition a small decrease in energy cost is experienced
IV-3
Bethe 1 -Section IV
APA12II
in Bethel (approximately $.Ol/kWh) when compared to independent
generation. This alternative is the best of the diesel
generation alternatives, but energy costs are directly related
to fuel costs and will continue to rise.
4. Intertied System -Golden Gate Hydro
4-A Low Load:
This alternative takes advantage of the SWGR transmission
intertie as outlined in 3 above and the use of hydroelectric
generation to replace diesel generation. Energy from the
Golden Gate Hydro project will be supplied to a centralized
distribution point in Bethel via a 69 mile transmission
line. This energy will then be distributed to Bethel and
to the surrounding communities through the SWGR intertie
system. The major disadvantage of the alternative is the
large investment required, approximately $158,000,000 by
1986, to construct the hydro project. As shown in the
accompanying graphs, this large investment cost is reflected
in the high cost of energy during the first few years
a fter project comp 1 et ion. Energy costs wi 11, however,
continue to decrease until such time as all of the hydro
capacity is utilized. This should occur approximately in
the year 2030, using low load projections. The graphs
show breakeven years for the energy costs (when compared
to diesel) between five and thirteen years after project
completion, depending upon interest rates.
With only one transmission line planned to connect the
hydroelectric project to the intertied system, installation
of additional diesel capacity has been assumed in Bethel
and the small communities in addition to the hydroelectric
plant to maintain firm capacity.
This is an alternative which is unfavorably affected by
the limited study period. Obvious benefits from hydro
will extend for fifty years, or to approximately 2030.
However, the present worth of the accumul ated energy
costs for hydro, when compared to the present worth of
accumulated energy costs for diesel for the twenty year
study period, does not reflect the true potential savings
available from the hydro alternatives, if assumed parameters
continue beyond the twenty year period.
4-B High Load:
This alternative is identical to 4-A above except that it
assumes the high load growth projection. It is believed
that the high load growth projection would be the most
IV-4
..
..
•
",
..
..
•
Bethel -Section IV
APA12/I
probable growth projection experienced ;n the region if
lower cost electric energy were made available. Due to
the higher utilization of the hydroelectric energy, this
case results in a substantial reduction in cost of energy
when compared to the "l ow growth tl a 1 ternat i ve. Excess
hydro capacity will, however, be exhausted by the year
2002 and supplemental generation must be provided.
The breakeven year for energy from the hydroproject as
compared to diesel is between three and eight years after
project completion depending upon the interest rate
elected. Comparison of this alternative to the continued
use of diesel generation in an intertied system (Plan 3)
indicates however, that diesel generation could be more
des i rab 1 e if interest rates above 5% are cons i dered.
This comparison is of course biased by the 20-year study
period and it can be assumed that the hydro project would
breakeven at a higher interest rate if the study period
were extended.
5-A/B Intertied System, High/Low Load, Electric Heat, Golden
Gate Hydro
These two alternatives explore the possibility of using
the excess hydro capacity available during the first
severa 1 years of ope rat i on of the project to provi de
electric heating to consumers. In this case electric
energy for home heating would be provided at equivalent
or slightly lower costs as for fuel-oil heating.
Installation and control of the electric heating equipment
wou 1 d be prov i ded by the ut il i ty. A detailed exp 1 anat ion
of this concept can be found in Appendix A-5.
The most noticeable effect of these two alternatives is
the substantially lower bus bar cost of energy when compared
to previous alternatives. Figure IV-5 compares the cost
in mills/kWh for the high and low load projection plus
electric heat and the high load growth alternative outlined
in 4B.
In addition to providing lower energy bus bar costs, these
two alternatives will save approximately 25 million
gallons of fuel oil over the span of this study period.
It should, however, be pointed out that this magnitude of
savings will not be realized by the consumers. While the
busbar cost of electric energy and the required gallons
of fuel oil are substantially lowered, the consumer will
now be consuming larger quantities of electrical energy
for heating and thus partially cancel any savings
experienced from decreases of fuel oil purchases.
IV-5
Bethel -Section IV
APA12/I
The major benefit of these two alternatives is that the
costs of electrical energy are levelized over a period of
several years, and lower cost electric energy is made
available to all consumers.
C. EVALUATIONS AND CONCLUSIONS
In light of the foregoing discussion the following conclusions and
recommendations can be drawn.
1. Conc 1 us ions
The two Alternatives 5-A and 5-B which assume the addition of
electric heat provide the lowest busbar cost for electrical
energy, and tend to levelize the unit cost of energy over a
several year period. These two alternatives also result in a
substantial additional decrease in regional fuel oil consumption
when compared to the other scenarios and are economically
feasible at all interest rates.
A 1 ternat i ves 4-A and 4-B (Hydroe 1 ectri c development) both
result in substantially decreased energy costs in the latter
years of the study. They are, however, both adversely affected
during the first few years following completion of the project
due to the high initial construction costs of the hydro project
and lower electric energy requirements. Alternative 4-B (high
load growth) appears feasible at an interest rate of 5% and
below. Alternative 4-A (low load growth) is only feasible for
an interest rate of 2%.
Of the diesel alternatives, Plan 3 (central generation in an
intertied system) proves to be the most promising. Alternatives
and 2, utilizing strictly local generation, should be avoided
if at all possible.
2. Recommendations
Develop the Golden Gate Hydro Project. This will result in
the lowest power cost for an interest rate of 5% or less if
small communities are included and intertied to Bethel. The
addition of even moderate amounts of electric heating loads
results in the lowest power cost at all interest rates.
IV-6
1
't<
"".
..
1Iif:
..
If<
•
• .' ..
III!
*~
...
....
-
~,
•
'" .. ..
.,
iii
Bethel -Section IV
MISC09/F1
I-A
2-A
3-A
4-A
4-B
5-A
5-B
TABLE IV-l
OF
ACCUMULATED PRESENT WORTH
Annual Cost in $1000
Equivalent Unit Cost in ¢/kwh
FOR 1980-2000 AT 7% DISCOUNT
INTEREST RATE
ALTERNATE 2% 5% 7%
Bethel -Diesel 77 2218 77~960 78!542
Low Load 20.9 21.1 21. 3
Vi 11 ages -Diesel 26 z693 26!768 26,850
Low Load 60.3 60.5 60.6
Intertied. System 83,924 85 1 688 87 1 042
-Diesel -Low Load 20.2 20.7 21. 0
Intertied System 76 1 086 96 1 940 114,465
-Hydro -Low Load 19.4 24.0 28.0
Intertied System 82,813 104 1 897 123 1 361
-Hydro -High Load 16.7 20.2 23.2
Intertied System 80!970 101,727 119 1 176
-Hydro -Low Load 12.8 14.9 16.6
+ Electric Heat
Intertied System 86 1 415 108 1 435 126!836
-Hydro -High Load 12.7 14.6 16.2
+ Electric Heat
IV - 7
9%
79,170
21.5
26 1 912
60.8
88,492
21.4
132 1 391
31. 9
142 1 361
26.3
137!020
18.3
145 1 733
18.0
Bethel -Section IV
MISC09/F2
TABLE IV-2
COST RATIOS OF ACCUMULATED PW OF ANNUAL COST
FOR ALTERNATE DEVELOPMENT PLANS
INTEREST RATE ALTERNATES
COMPARED 2% 5% 7% 9%
I-A + 2-A Bethel + Villages -Local Diesel
3-A Intertied System -Diesel 1. 24 1. 22 1. 21 1.2
I-A + 2-A Bethel + Villages -Local Diesel Q 4-A Intertied System -Hydro 1. 37 1.08 .8
3-A Intertied S~stem -Diesel
4-A Intertied System -Hydro 1.10 .88 .76 .67
IV - 8
..
.,
..
I-A
3-A
I-A
4-A
I-A
4-B
I-A
H
I-A
5-B
2-A
3-A
2-A
4-A
2-A
4-B
2-A
5-A
2-A
5-B
Bethel -Section IV
MISC09/F3
TABLE IV-3
COST RATIOS OF EQUIVALENT UNIT COSTS
FOR ALTERNATE DEVELOPMENT PLANS
ALTERNATES INTEREST RATE
COMPARED 2% 5% 7%
Bethel -Diesel 1. 03 1. 02 1. 01 Intertied System -Diesel
Bethel -Diesel 1. 08 .88 .76 Intertied System -Hydro -Low Load
Bethel -Diesel 1. 25 1 1. 04 1 .921 Intertied System -Hydro -High Load
Bethel -Diesel 1. 63 1. 42 1. 28 Intertied System -Hydro -Low Load +
Heat
Bethel -Diesel 1. 65 1 1. 45 1 1. 31 1
Intertied Sysetm -Hydro -
High Load + Heat
Villages -Load Diesel
Intertied System -Diesel 2.99 2.92 2.89
Villages -Local Diesel
Intertied System -Hydro -Low Load 3.11 2.52 2.16
Villages + Local Diesel
Intertied System -Hydro -High Load 3.611 3.0 1 2.61 1
Villa~es -Local Diesel
Intertled System -Hydro -4.71 4.06 3.65
Low Load + Heat
Villages -Local Diesel 4. 75 1 4.141 3. 74 1
Intertid System -Hydro -
High Load + Heat
9%
1.0
.67
.82]
1.17
1.19 1
2.84
1. 91
2.311
3.32
3.38 1
1 Approximation, since compared to "Low Load -Diesel ll
; accurate ratio is
slightly lower due to additional diesel investment required for IIHigh Load ll
case.
IV -9
::t:
~
lC:
IOOO.----------------.----------------.-----------------r---------------~
900+---------------~----------------~--------------~~--------------~
800+---------------~----------------~--------------~~_---~2~A~------~
VILLAGES -DIESEL
700+---------------~~------~------~--------------~--~~~L~OW~L~0~A~D~------~
600+---------------~----------------~----------------~--------------~
500+---------------~----------------~--------------~~----~A~------~
BETHEL -DIESEL
LOW LOAD
400+---------------~----------------~--------------~~--------~~--~
"-
~300+-----~4nAr-------~--------------~-----------------r----~~~~--~
j iNTERTIED SYSTEM
HYDRO -LOW LOAD
3A
iNTERTIED SYSTEM
DIESEL -LOW LOAD
100+--4~_r--~--~~--_r--+_~~_+--~--r_~--~--+_~~-+--~--+_~--~
1980 1985 1990
YEAR
IV -10
1995 2000
BETHEL
BUSBAR COST Of POWER
AT 2 % INTEREST ON
INVESTMENT
FIGURE :m: -I
•
iIii'
•
.,
•
:r
~
:.::
1000~--------------'---------------1I---------------r---------------.
900+-------------~--------------4_------------~~------------~
800t---------------;_--------------~--------------_+----~2~A~----~
VILLAGES -DIESEL
700+---------------;_------~------~-------------~--~~~L~0~W~L~0~A~D~----~
600T---------------r-------------~--------------_4--------------~
500r---------------~--------------;_--------------_r----~IA~------~ BETHEL -DIESEL
LOW LOAD
4oo+---------------r---------------+---------------4---------~----~
3
3oo j:34 ~rJ~:::t~;;f~:J i INTERTIED SYSTEM
HYDRO -LOW WAD
200L-~IN~T~E=RT~I~E~D~S~Y=S~T~EM~-~1.~-~~~------.~~~~~~~~--.----L--------------J
HYDRO -HIGH WAD
3A
INTERTIED SYSTEM
DIESEL -LOW LOAD
100+-~--1___.~_r--+__;--_r--~_+--~~~_r--+_~--~--~~--~--~~
1980 1985 1990
YEAR
IV -11
1995 2000
BETHEL
BUS BAR COST OF POWER
AT 5 % INTEREST ON
INVESTMENT
FIGURE JJZ: -2
::t:
!t
1000~--------------~----------------.----------------,,---------------·,
9o0+---------------~--------------_+----------------r_------------~
800+----------------+----------------~--------------~~-----~------~ VILLAGES -DIESEL
700+----------------+--------~------~-------------~--_r~LO~W~L~0~A~D~------~
600+---------------~·----------------~----------------~--------------4
500+----------------+----------------~--------------~r_----~1~------_; BETHEL -DIESEL
LOW LOAD,
400+----------------r~r=~--.. --~::r_--------------_t----------~--__i
~3001-------TT--------l-JIl--~::~~=:dl~---=::~~~~~~
.J
::I!
48 200t-~IN~T~E~R~T~IE~D~S~Y~ST~E~M~+I~~~--~~~~----------------~~~~---------;
HYDRO -HIGH WAD
3A
INTERTIED SYSTEM
DIESEL -LOW LOAD
lOO+--4r--r--~--r_,_4--_r--+_~r__+--~--r__4--_r--~--r__+--~--+__1--_;
1980 1985 1990
YEAR
IV -12
1995 2000
BETHEL
BUSBAR COST OF POWER
AT 7 % INTEREST ON
INVESTMENT
FIGURE Ill: -3
...
11M.
..
•
..
.'
Wi
III
..
•
•
.,
• ..
1ooo,----------------,---------------.----------------.---------------,
::r::
:J:
::.:: ......
900T----------------r---------------+--------------_4~------------~
800'+----------------r--------------~----------------~-----~2~A------~
VILLAGES -DIESEL
100+-______________ ~_--------~----_+--------------_4~0~W~L~0~A~D------~
600+---------------+---------------+---------------r-------------~
500C=n~b::=~=u BETHEL -DIESEL
LOW LOAD\
400+----
~300+-----~~------~lf-------------+----~~~----~~~~~~~--~
..J
i
4B 200~-IN~T=E~R=T~,E~D~S~Y~S~T=E~M-4H-r-------~~~~--------------4---------------~
HYDRO -HIGH LDAD
....,..,.,.----~
3A
INTERTIED SYSTEM
DIESEL -LOW LOAD
100~_;--~--r__T--4_--~_+--~~~~--~~r__r--+-_4--~--r__+--~~
1980 1985 1990
YEAR
IV -13
1995 2000
BETHEL
BUS BAR COST OF POWER
AT 9 % INTEREST ON
INVESTMENT
FIGURE ll[ -4
1000.----------------,--------------~~--------------~--------------~
900+----------------;----------------~--------------_4--------------~
:J:
~
:.::
.......
800+---------~-----4----------------+_--------------_4~-------------~
VILLAGES -DIESEL
700+-________ ~ ____ -4 ________________ +_------~~----_4~L~0~W~L~0=A~D~----~
600~--------------~------------~--1_--------------_4--------------~
500+---------------~~------------~--------------_4--------------~ BETHEL -DIESEL
LOW LOAD
400+----------------_4----------------+---------------_+-----------+----4
~300+----------------;----------------~--------------_4------~~~--~
..J
~ INTERTIED SySTEM---1t--_..
HYDRO -LOW WAD
20°t-~IN~T~E!R~T~IE~D~S~Y~ST~E~M~l1~~~:s~~~~~~~~--------f_;;~~:::::::::J
HYDRO -HIGH WAD
INTERTIED SYSTEM
DIESEL -LOW LOAD
100+-~--_r--;---~_+--1_--r__4--_r--+_-;--_r--~~r__+--~--r__4---r~
1980 1985 1990
YEAR
1995 2000
BETHEL
BUSBAR COST OF POWER
AT 2 % INTEREST ON
INVESTMENT
FIGURE Dr -I
I
I
1000
900
BOO
VILLAGES -DIESEL
700 LOW LOAD
600
500
BETHEL -DIESEL
LOW LOAD
400
::I:
~
~
.......
~300
...J INTERTIED SYSTEM
~ HYDRO -LOW LOAD
200~-IN-T~E~R~T~IE~D~S~YS~T~E~M~lJ~,-----~~~~~~~~~------L---------------J
HYDRO -HIGH LOAD---""---
INTERTIED SYSTEM
DIESEL -LOW LOAD
100+--'---r--+-~~-+--~~r--+--;---r--+--~--+-~---r--+-~r--r--+--;
19BO 19B5 1990
YEAR
1995 2000
BETHEL
BUSBAR COST OF POWER
AT 5 % INTEREST ON
INVESTMENT
FIGURE :m: -2
I
I
I
I
I
I
I
I
1000
900
BOO
VILLAGES -DIESEL
700 ..... LOW LOAD
600
500
BETHEL -DIESEL
LOW LOAD
400
:J:
~
~
........
~300
...J INTERTIED SYSTEM i HYDRO -LOW LOAD
200 INTER TIED SYSTEM
HYDRO -HIGH LOAD
INTERTIED SYSTEM
DIESEL -LOW LOAD
100+-~--~--~~r--+--~--~-+--~--r-~--~--+-~~~--~~~-+--~~
19BO 19B5 1990
YEAR
1995 2000
BETHEL
BUS BAR COST OF POWER
AT 7 % INTEREST ON
INVESTMENT
FIGURE :nz: -:3
I
1000
900
800
700
600
500
400
:x:
~
:.:: ......
~ 300
..J
~
INTERTIED SYSTEM
HYDRO -LOW WAD
VILLAGES -DIESEL
OW LOAD
BETHEL -DIESEL
LOW LOAD
200+--IN-T-E-R-T-IE~D--S-Y~ST~E~M~~~--------~"E+----------------+---------------~
HYDRO -HIGH WAD
INTERTIED SYSTEM
DIESEL -LOW LOAD
100+-~--~--+-~r--+--~--~~--~--+-~r--+--4---~-+--~--+-~---r~
1980
\.
1985 1990
YEAR
1995 2000
BETHEL
BUS BAR COST OF POWER
AT 9 % INTEREST ON
INVESTMENT
FIGURE :m: -4
Bethel -Section V
APAI2/M
A. INTRODUCTION
V. RECOMMENDATIONS
Alternate electric energy sources to replace diesel generation in
the Bethel area or make it more efficient that have been found
technically and economically feasible are the development of the
Kisaralik River hydroelectric potential and the construction of
transmission interties.
Other resources may be suitable alternatives in the future but
cannot be recommended for immediate implementation. These are wind
energy conversion systems, utilization of wood or coal and geothermal
energy. Equipment technology and availability on the scale required
as well as lack of sufficient resource information make comparably
realistic assessment of these resources impossible.
These recommendations concentrate therefore on the next steps
required to facilitate the hydroelectric development and transmission
interties.
B. DEVELOPMENT OF THE KISARALIK RIVER HYDROELECTRIC SITE
The economic evaluation of the Kisaralik River, Golden Gate hydro-
electric development and possible alternatives, clearly indicate
that implementation of the recommended alternative will require
regional consent and cannot be undertaken by any single community
in the area alone. Cooperation among the various communities and
state support is therefore a necessity if cost stable electrical
energy is to be provided.
Development of the Kisaralik River Golden Gate hydro project will
result in the lowest power cost at an interest rate of 5% or less
if small communities are included and intertied to Bethel via
single wire ground return lines. The addition of even moderate
amounts of electric heating loads results in the lowest power costs
for all interest rates.
As the project area 1 i es wi thi n the boundari es of the proposed
Yukon Delta National Wildlife Refuge, FERC license application and
exemption of the dam and power plant sites as well as the transmission
corri dor and requi red roadways from the intended wi 1 derness
designation of the area should be undertaken immediately.
V-I
Bethel -Section V
APA12lM
The necessary steps to initiate development are seen as follows:
1.
2.
1
Organizational Framework
A state or regional entity with state backing is needed to
pursue the
• Filing of a preliminary permit with FERC.
• Preparation of the FERC license application.
• Investigation in financing possibilities.
• Removal of the Kisaralik plant and dam, transmission
corri dor and roadways from the "Wil dl i fe Refuge ll des i gnat ion.
• Construction and eventual operation of the facilities and
necessary transmission interties.
Various ways are open to the area communities and utilities to
found and finance such an organization:
• An informal rerional commission which would work closely
with local uti ities and the AKPAI. In this commission
the communities and utilities could be represented by an
elected member.
• A regional Generation and Transmission (G&T) cooperative
would be formed by existing utilities. This G&T which
would sell the electric energy to local utilities.
Fi nand n9
Depending on the type of regional entity formed the methods of
project financing will vary. With only 2 communities in the
are being members of a REA Co-op, successful initiation of a
G&T Co-op is doubtful. This precludes low interest REA financing.
A regional commission without a state agency as backup would
have difficulties obtaining financing for a project of the
magnitude of the Kisaralik. If it is therefore assumed that
either the Alaska Power Authority or a regional commission in
close cooperation with the AKPA would be the owner and operator
of the project, the following methods could be used:
(1) Funds can be appropriated by the State of Alaska legislature.
(2) bonds can be issued. In this case it is most likely that
AKPA would be the issuing agency.
Alaska Power Authority.
V-2
•
..
•
.'
It·
.,
•
.,
•
Bethel -Section V
APA12/M
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.
a. File an application for a preliminary permit with FERC.
b. Contact the Alaska Department Fish and Game, the Department
of Fish and Wildlife, the U.S. Forest Service and BLM to
assure their input and cooperation in regard to
(1) Environmental study requirements.
(2) Right-of-way and permits.
c. Initiate preparation of a definite project report.
d. Initiate environmental studies.
e. Plan and install SWGR transmission interties to the small
communities.
If the shortest possible times are allocated to the various
prerequisites named above, the following time frame is considered
IIminimum time to date in operation ll :
Institution is identified
License to study is obtained
Prepare FERC license application
License granted
Design
Construction
Earliest Date on Line
4. Transmission Interties
1980
1980
1980
1981
Mid 1981 to Mid 1982
1982 to End 1985
1986
If the Golden Gate hydro project is ruled out, as a minimum a
regional intertie system should be completed. This will
result in an average energy costs of $0.35/kWh in the year
2000, a savings of approximately $0.65/kWh in the small villages
and $O.Ol/kWh in the community of Bethel. This alternative
relies exclusively on diesel generation, but is far superior
to individual generation in each of the communities.
V-3
Bethel -Section V
APA12/M
5. Further Investigations
Utilizing single phase, low freguency generation and transmission
should be pursued, since substantial savings in the initial
cost of the hydroelectric developments are conceivable.
Manufacturers have shown interest in supplying this type of
equipment, but a detailed evaluation including detailed
equipment data availability and cost has yet to be performed.
The concept of utility installed and controlled electric heating
devices in connection with hydro developments appears to be
viable and beneficial for relatively large projects in regard
to ex; st i ng load. There a more detail ed study coul d address
technical details and other parameters.
Wi th development of more re 1 i ab 1 e wi nd energy convers ion
systems it is extremely important to gather wind data, so that
the potential especially for small communities -can be fully
assessed. Installation of are nonmeters is therefore strongly
recommended. If this is made a school project, the benefit
can be considered two fold.
An assessment of the available wood and its growth potential
is mandatory, especially since coalcannot be mined economically.
V-4
...
..
..
..
..
• -
•
oiIIII'
..
APPENDIX A
TECHNICAL DATA
Bethel -Appendix A
APAI4/C
A-I SINGLE WIRE GROUND RETURN TRANSMISSION
A-I
Bethel -Appendix A
APA14/C
GENERAL CONCEPT
MINIMUM COST TRANSMISSION SYSTEM
Single Wire Ground Return Transmission of Electricity
The Single Wire Ground Return (SWGR) transmission concept described
in this proposal has evolved from a recognition of certain basic
facts-of-life concerning electric 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. Fue 1 pri ces in the western and i nteri or regi ons, 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 real it i es.
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],
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
A-3
Bethel -Appendix A
APA14/C
opinion of this writer that the SWGR system proposed here would in
no way create an operating system with a lesser safety
than the "conventional" system now in use throughout Alaska.
Robert W. Retherford Associates has applied to the State of Alaska
for an exception to the NESC to allow construction of 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 feasibility 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
..
..
•
..
., .. ..
•
Bethel -Appendix A
APA14/C
PHYSICAL DESIGN AND CONSTRUCTION CONSIDERATIONS
Lack of a road system, permafrost, and limited or no accommodations
for constructon crews throughout most of the region being studied
establish some limitations that must be dealt with to find appropriate
solutions. Conventional construction techniques and line designs
might be used -but at premium costs.
A design believed most adaptable to these limitations is based on
the use of an A-frame structure shown in the following sketch
1 abe 1 ed Fi gure 1. The arrangement is we 11 sui ted to the SWGR
design.
It is believed that the design has certain features that will
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 local
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).
Longitudinal 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 by fore and aft 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 retail 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 equivalent to a #4
ACSR conductor will require one half as many
structures per mile as the #4 ACSR under the
same Heavy Loadi ng Des i gn Conditions. (The
line could also be converted to 30 at a future
date by adding another structure in each span,
and adding the new conductors.)
A-5
Bethel -Appendix A
APA14/C
PRELIMINARY DESIGN DATA
"A"-FRAME, SPRUCE POLE t GRAVITY STRUCTURE
APPROX. LOCATI~
OF NEl.1T. (if any) 14'-4"
INE
Figure A-I. 1
A-6
..
•
. '
..
... ..
., .. .. . '
\IW ..
IIif, ..
II, .. .. .. .. .. -..
..
• .,
Bethel -Appendix A
APAI4/C
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 efforts
as follows:
The high strength conductor is laid out on the
ground between anchor points (at typical intervals
of 1 to 2 mil es) and tensioned whil e on the
ground to the approx'imate 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). Thi s
could be done in winter time by using snow
machines rigged with a small "jig!! to underrun
the conductor and 1 i ft it to predetermi ned
heights for observation.
At poi nts selected by the engi neer, 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 attachment 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.
Several such crossings have been in successful operation in
Alaska using this same 7#8 Alumoweld wire as follows:
Naknek River (5. 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
Bethel -Appendix A
APA14/C
The gravity stabil i zed A-frame 1 i ne des i gn us i ng 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 IIlive with ll 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
successful 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 differential frost
action. The basic structural philosophy 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
...
..
•
•
Bethel -Appendix A
APA14/C
ELECTRICAL CHARACTERISTICS
Seri es impedances and shunt capaci t i ve reactance for se 1 ected
conductor sizes have been calculated using the following formulas
[12]:
Series Impedance
.e 2160 ;/ f
Zg = rc + 0.00158 f + jO.004657f 10910 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
XI = .0683 6
f
O 1 (Capacitive Reactance at 1 ft. spacing) z 10g10 r
XI -12.3 10g10 2h (Zero Sequence Shunt Capacitive
e --f---Reactance Factor)
h =
f =
r =
height above ground in ft.
frequency in Hz
conductor radius in ft.
A-9
Bethel -Appendix A
APA14/C
The line data have been calculated with the following assumptions:
Frequency:
Height above ground:
60 Hz, 25 Hz
30 ft.
Earth Resistivity: 100 Ohm-m (swamp),
1000 Ohm-m (dry earth)
Ground Electrode Resistance: R Ohms of each end
60 Hz IMPEDANCES AND SHUNT CAPACITIVE REACTANCES
Zg (ohm per mile) R GMR(Ft) X
(Ohm Diam. p = 100 p = 1000 (Meg hhm
Conductor Size Per Mile) (inch) Ohm-m Ohm-m Per Mile)
7#8 Alumoweld 2.354 .0116 2.449 + 2.449 + .244
.385 j 1. 504 j 1. 643
266.8 MCM .35 .0217 .445 + .445 + .229
ACSR . 642 j 1.428 j 1. 567
397.5 MCM .235 .0278 .33 + . 33 + .222
ACSR .806 j 1. 397 j 1. 537
556.5 MCM .168 .0313 .263 + . 263 + .218
ACSR .927 j 1. 383 j 1. 523
795 MCM .117 . 0375 .212 + .212 + .213
1.108 j 1. 361 j 1. 501
A-10
..
.'
_'i
III'"
\J--; ..
iii, ..
IIiII .. .. ..
'"', ..
... .. .. ..
""
e'
""
., .. .. .. ..
•
Bethel -Appendix A
APA14/C
25 Hz IMPEDANCES AND SHUNT CAPACITIVE REACTANCES
R GMR(Ft) Zg (ohm per mile)
(ORm Diam. p -100 P -1000
Conductor Size Per Mile) (inch) Ohm-m Ohm-m
7#8 Alumoweld 2.354 .0116 2.394 + 2.394 +
.385 j .649 j .707
266.8 MCM .35 .0217 .390 + .390 +
ACSR .642 j .617 j .675
397.5 MCM .235 .0278 .275 + .275 +
ACSR .806 j .604 j .663
556.5 MCM .168 .0313 .207 + .207 +
ACSR .927 j .598 j .657
795 MCM .117 .0375 .157 + .157
1.108 j .589 j .647
A-II
X
(MegCohm
Per Mil e)
.586
.549
.533
.523
.511
Bethel -Appendix A
APA14/C
LIST OF REFERENCES
[1] "A Regional Electric Power System for the Lower Kuskokwim
Vicinity, A Preliminary Feasibility Assessment" prepared for
the United States Department of the Interior -Alaska Power
Administration, by Robert W. Retherford Associates, Anchorage,
Alaska, July 1975.
[2]
[3]
[4]
Alaska Electric Power Statistics 1960-1975, published by the
United States Department of the Interior -Alaska Power
Administration, Fourth Edition, July 1976.
"Grounding Electric Circuits in Permafrost ll , a paper by J. R.
Eaton, P.E., West Lafayette, Indiana (formerly Professor of
Electrical Engineering, Purdue University and visiting Professor
of Electrical 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.
"Single Wire Ground Return Transmission Line Electrical
Performance ll , a paper prepared for Robert W. Retherford
Associates by J. R. Eaton, visiting Professor of Electrical
Engineering, University of Alaska, Fairbanks, Alaska, April
1974.
[5] IIGround Electrode Systemsll, by J. R. Eaton, Professor of
Electrical Engineering, Purdue University, Lafayette, Indiana,
sponsored by Commonwealth Edison Company, Chicago, Illinois,
June 1969.
[6] IIPerformance 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.
(7] IIRural Electrification by Means of High Voltage Earth Retur"n
Power Li nes ll
, 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-12
..
..
..
.,
..
--
.. ..
Bethel -Appendix A
APA14/C
[8] "Wire Shielding 230 kV Line Carries Power to Isolated Areal! -
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.
[9] "Single-Phase, Single-Wire Transmission for Rural Electrifi-
cation", 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 AlEE, both of Bihar Institute of Technology, P.O.
Sindri Institute, Dhanbad (Bihar) -India.
[10] "Single Wire Earth Return High Voltage Distribution for
Victorian Rural Areas", by J.L.W. Harvey, B.C.E., B.LL,
H.K. Richardson, B.E.E., B. Com., and LB. Montgomery, B.L,
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. Thi s paper No. 1373 was
presented at the Engineering Conference in Hobart, Australia,
6 to 21 March, 1959. The paper recalls that " ...... 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 .... "
[11] "Using Ground Return for Power Lines", 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-13
Bethel -Appendix A
APA14/C
A-2 DISTRIBUTION AND TRANSMISSION LINE LOAD LIMITATIONS
A-15
Bethel -Appendix A
APA14/C
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 stab~lity.
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, load, and conductor size and configuration.
Volta e Oro (9:) = Voltage sent -Volta~e received g p I) Voltage received X 100
Maximum tolerable voltage drops are for:
Distribution Lines (up to 24.9 kV)l
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 were performed in accordance with
REA Bulletin 45-1 where:
Megawatt -Mil es = VD) (kV2) (cos e) P
R cos e + X Sln e 1 0
Where VD =
kV =
e =
P =
R =
X =
Allowable voltage drop in %
Line to ground voltage
1
2
Phase angle between voltage and current
# of phases
Resistance in ohms per phase per mile of line
Reactance in ohms per phase per mile of line
REA Bulletin 169-27, January 1973
Standard Handbook for Electrical Engineers.
10th Edition.
A-17
Fi nk & CarrolL
Bethel -Appendix A
APA14/C
For transmission lines tables published in REA Bulletin 65-2 have
been utilized and for Single Wire Ground Return Lines the following
formula l is considered to render adequate results for preliminary
investigations:
Receiving End Voltage =
Where Vl =
R =
X =
o =
X I V, 12 -(Q12) (R2+X2)
Vl [ X cos 0 + R sin 0 ]
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
( ) ]
Where Pl2 = total real power (MW)
The reactive power Ql2 ~ Q2 + Q Loss -Yc Vl 2
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
"short" line models (up to 50 miles) and that the following
assumptions have been made:
1.
2.
3.
4.
R ~ 115 X
6 and V2 are calculated by solving for each alternatively,
assuming 0 ~ 10°
V1 and V2 differ less than 10%
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.
1 From: Electric Energy Systems Theory by Olle 1. Elgerd.
by McGraw-Hill, Inc.
A-18
Published
""
..
•
-
1;;".,,,1,. 1.-2 -
A?A~12/.nl
O:S;KI~7icS Lr~~s
C,;~'!uctor
su~ • A".G p.r.
(A.::sil/MC) .9
p':' 1.1
1f'J 1.9
4:'1 2.8
lH.S
(6.61\ Volt_ae Drop)
7.:tkV-I!
P.F. P.F.
.95 1.0
J.Z 1.4
2.2 3.1
3.3 5.4
~r.n.~i5Iion lines (st Voltage Drop)
P.F.
.9
3.9
1.3
13.3
19
Ceodactof 69 tV (8.S'" equiv. spacing)
Siu -A\le P.F. P.F. P.F.
(o\eS8) .9 .95 1.0
' .. rtridile
ZOS .• 301 362 513
IBIS
391.5 310 450 188
J)ove
55S.S 423 526 991
CroOke
195 416 603 1228
~ABLE A-2.1
LINE LOADING LIMITS IN MEGAWATT MILES
IN REGARD TO ALLOWABLE VOLTAGE DROP
FOR SELECTED CONDUCTOR SIZES
7.2Ir.V-3! 14."kV-1! 14.4kV-3!
P.F. P.F. P.f. p.r. P.F. P.L P.F.
.95 1.0 .9 .95 1.0 .9 .95
4.1 4.6 4.3 4.1 S.6 15.5 16.7
'.9 n.1 7.4 8." 12 33.3 36.1
lS.S 23.3 11 l) 21 51 60
U 44 74 91
115 loV (13."8' eguiv. spacing)
P.F. P.F. P.F.
138 loV (19.53' equiv. ~pacln&~
p.F. P.f. p.r.
.9 ,95 1.0 .9 .9S 1.0
819 913 1511
980 U91 2142 1359 1668 3030
1112 nst 2685 1535 1924 3110
1243 1581 3271 1106 ~118 4SSe.
Siaale Vire Cround Return Lines (st Voltage Drop)
Cou6 .. cte.r
She -AWG 40 loV
( ... ~S8 ...ale .. p.r.
othervi$e noted) .9
1.8 Alu=",eld 25
P .. rtrid .. " 266.8 70
I!lIS )97.5 J5
llo,,~ S56.!> 80
66 loV
P.F.
• 9
65
180
200
21S
80 ltV p.r.
.9
95
265
290
:ns
133 loV
p.F •
.9
120
800
860
Duk" 79S 85 225 3)5 910
cco~~a re.istivlty = 100 obm-m (chAract"flz"5 Iwa.pv wetland$). Vol tag" drop at ~he ground el"~trodes hi. not heen taken iute.
.C.CO&.:Jlt.
CalculAted usia, A,B,C,D constants.
A-19
1'.1".
1.0
111.9
46.1
91
.13
Bethel -Appendix A
APA14/C
A-3 PHASE AND FREQUENCY CONVERSION IN POWER TRANSMISSION
A-21
Bethel -Appendix A
APA14/C
PHASE AND fREQUENCY CONVERSION IN POWER TRANSMISSION
Power transmission lines are limited in their capacity to transport
energy by conductor sizes and voltage levels. Theoretically higher
operating voltages and larger conductors will allow transmission of
higher 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 have to be decreased or a
higher voltage level and/or larger conductor have to be chosen.
Construction and operating costs will limit operating voltages and
conductor sizes and poi nt to the most economi ca 1 1 eve 1 for any
particular case.
In Alaska, where small communities with low energy demands are
separated by great distances, conventional transmission lines are
known to be prohibition in cost. The Single Wire Ground Return
transmission scheme is an attempt to make tie lines possible where
conventional 3-phase lines would be too expensive to be built (see
Appendix B-1). If this scheme is utilized at a lower operating
frequency the load or transmission distance could be increased by
an amount that is inversely proportional to the new value for the
frequency.
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.
Interconnect ions 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 MVAloo. Static frequency/phase conversion
equipment is available, but presently not an "off the shelf" item
for small (1-2 MW) applications. It is however 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 characteristics.
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-23
Bethel -Appendix A
APA14/C
Transmission line transfer capacity is shown on Table A-3.1.
CONDUCTOR
SIZE
(AWG)
266.8 ACSR
397.5 ACSR
556.5 ACSR
266.8 ACSR
397.5 ACSR
556.5 ACSR
266.8 ACSR
397.5 ACSR
556.5 ACSR
TABLE A-3.1
THREE PHASE TRANSMISSION, 60 Hz
SINGLE WIRE GROUND RETURN, 60 Hz and 25 Hz
MEGAWATT MILES FOR 5% VOLTAGE DROP @ .9 P.F.
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
40 kV 66 kV 80 kV
110 300 440
135 360 540
150 410 600
See Appendix A-I and A-2 for method of calculation.
138 kV
1359
1535
133 kV
720
800
860
133 kV
1200
1440
1640
The construction cost of SWGR transmission are estimated at approx-
imately 30-40% of a three phase transmission line. For a rough
comparison the following cost can be used:
34.5 kV 3~ $ BO,OOO/mile (conductor to 556.5 ACSR)
69 kV 3~ $100,000/mile (conductor to 556.5 ACSR)
138 kV 3.0 $125,000/mile (conductor to 556.5 ACSR)
A-24
'"
...
..
..
iii·
• ..
.,
""
• ..
•
*' .. .. ..
Hi,'
•
• ..
/Ii.
III'
III· ..
III,
Bethel -Appendix A
APAI4/C
Transmission line cost for the following assumptions are then:
Power to be transmitted
Distance
3~ -69 kV, 397.5 ACSR
SWGR (60 Hz) -80 kV, 266.8 ACSR
SWGR (25 Hz) -66 kV, 266.8 ACSR
6 MW
50 Miles
$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
are anticipated to be between 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
will then show the possible savings.
A-25
Bethel -Appendix A
APA14/C
100
101
102
103
BIBLIOGRAPHY
liThe Largest Rotating Converters for Interconnecting the
Railway Power Supply with the Public Electricity System in
Kerzers and Seebach, Switzerlandll Brown Bover; Review, November
1978.
"Electrical Transmission and Distribution Reference Book ll
,
Westinghouse, 1964.
"Standard Handbook for Electrical Engineers", Fink and Carroll,
10th Edition.
IIElectrical Engineers' Handbook ll
, Pender, Delmar, 4th Edition
Electric Power.
A-26
..
•
•
..
..
Bethel -Appendix A
APA14/C
A-4 DETERMINATION OF "ECONOMIC" DISTANCE TO SUPPLY
CENTER FOR SWGR INTERTIES
A-27
Bethel -Appendix A
APA14/C
A-4 DETERMINATION OF "ECONOMIC" DISTANCE TO SUPPLY
CENTER FOR SWGR INTERTIES
It is investigated what distance between a supply center and a
community can be economically bridged with a tie-line if diesel
generation is assumed at both locations.
1. Basic Assumptions
a. Load:
The average small community load as established in the
energy requirements section is:
95 kWat .4 L.F. with 320,000 kWh per year
b. Power Supply:
Existing diesel generation at 8 kWh/gal. efficiency.
c. Fuel Cost:
$.8/gal. in supply center, 25% higher in small community.
d. Power Cost:
(at distribution bus without debt service, insurance,
distribution & administration costs).
Small Community
Fue 1 at $1. 00
Lube etc. at 10%
Maintenance
Operating (1 operator
at $25,000 per year
plus 30% benefits
and tax)
A-29
¢/kWh
12.5
1.2
1.0
10.2
24.9
Supply Center
Bu"lk prime rate
(Bethel 5/79)
+ Fuel subcharge
(60.4¢/gal base
& 12 kWh/gal) at
at $.8
8.0
1. 63
9.63
Bethel -Appendix A
APA14/C
e. Transmission/Distribution Line Cost
From Appendix B
for SWGR lines up to 40 kV
constructed with local labor
Conductor 7#8 Alumoweld
Conductor 4/0 ACSR
Terminal (2 required)
Annual Fixed Cost (Capital Recovery)
7#8
35 Year Loans Alumoweld 4/0 ACSR
Interest at Simile Simile
2% 760 1,140
5% 1,160 1,740
7% 1,467 2,201
9% 1,798 2,697
f. Performance Lim; tat ions for SWGR Lines
From Appendix A-2:
(without voltage drop
7#8 4/0
Voltage Alumoweld ACSR
KV L-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.
at terminal)
Load
MW
.1
.1
.1
.1
.1
A-30
miles
7#8
Alumw.
8
25
33
98
250
$19,000
$28,500
$35,000
Terminal
$/each
1,400
2,137
2,703
3,312
miles
4/0 ACSR
21
63
83
249
800
..
• ..
...
., ..
Iff
.. '
..
..
If
•
•
..
Bethel -Appendix A
APAI4/C
2. Economi c Di stance
a. Allowable annual payment for tie-line cost for local
generation
320,000 kWh x $.249 $79,680
minus
Cost for wholesale power
(320,000 kWh + 5% losses) x $(.963)
b. Distance from supply center:
32,356
$47,323
Miles = Allowable Annual Pa~ment Annual -Cost for Terminals(2)
Annual Cost for Tie-Line Per Mile
7#8
Interest Alumoweld 4/0 ACSR
Rate Miles Miles Remarks
2% 58 39 24.9 kV min for 7#8
12.5 kV min for 4/0
5% 37 25 24.9 kV min for 7#8
12.5 kV min for 4/0
7% 29 19 14.4 kV min for 7#8
9% 23 15 12.5 kV min for 7#8
3. Concl usions
With the assumptions and cost estimates stated above the
maximum economic distance is 58 miles for an interest rate of
2%. At a rate of 9%, 23 miles can be built. 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 "economical".
Figure A-4.1, "Line Mile Multiplier", may be used to determine
a corrections 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.
A-31
Bethel -Appendix A
APA14/C
Determine the local utility and central utility annual costs.
Divide these costs by the corresponding local utility and
central utility base costs. Use these utility base costs
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 = 1.10 79,680
Central Utility Base Cost Multiplier = ~~:§g~ = 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-32
.. .. ..
..
•
..
..
..
..
1.5 0.80
FIGURE A-4,1
LINE MILE MULTIPLIER
FOR 7 • 8 ALUMOWELD 0.90
1.4
LOCAL UTILITY ANNUAL cr::
BASE COST •• 79,680 w 0 ;:j
CENTRAL UTILITY ANNUAL a..
BASE COST • • 32,360 ~ 1.3
:J 1.10 2
W
J
i 1.20 1.2 w )::> Z I ;:j W
W
0.80 1.20
LOCAL UTILITY BASE COST MULTIPLIER
0.7'0
0.60
0.50
Bethel -Appendix A
APA14/C
A-5 CONTROLLED ELECTRIC HEAT -
A POTENTIAL MARKET FOR
UNUSED ENERGY FROM
HYDROELECTRIC POWER PROJECT
A-35
Bethel -Appendix A
APAI4/C
A-5 CONTROLLED ELECTRIC HEAT - A POTENTIAL MARKET FOR
UNUSED ENERGY FROM HYDROELECTRIC POWER PROJECT
A. THE CONCEPT
If the capacity of a hydroproject is relatively large compared to
the demand of the supplied area, the cost per kWh will be high
since the large investment has to be paid for whether its capacity
is used or not. Utilization of this surplus capacity in electric
home heating (at a rate comparable to cost for heating with other
systems) would be appropriate. The problem arises when -at a
later point in time -the area demand (minus the electric heat)
approaches the capacity of the hydroplant. At that t"ime the electric
heating load and its demand would require installation of additional
capacity -which if additional hydro potential cannot be found,
would have to be a diesel or other fossil fuel burning plants.
Another solution would be to ask all consumers with electric heat
to convert to some other heating system.
The following suggestion appears to provide for all the benefits
and avoids 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 plus
electric heat.
2. The utility pays for the installation of the electric heat and
its cont ro 1 .
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 "other" heating system supplies comfort heating
for the home. The other alternate home heating system thereby
provides peaking capacity to the utility.
B. ECONOMIC EVALUATION
Where are the benefits and to whom do they occur?
1. Investment Cost (Utility)
Installation of electric heating
system 20 kW @ $100/kW
Control equipment
Central station control equipment
(assumed Sangamo System 5)
A-37
1979 -$/Consumer
2,000
100
2,100
50,000
Bethel -Appendix A
APA14/C
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, since the alternate home heating system reduces
peaking effects of the electric heating.
2. Benefits
C.
1.
2.
Essentially all receipts for heating kWh sales (minus the
annual costs of the electric heating investment) are benefits
which can be used to lower the rates for electric energy from
the hydroplant until full utilization is achieved.
The following Tables A-5.l and A-5.2 illustrate this type of
electric heat utilization for the Bethel area with the Golden
Gate hydroelectric project.
SENSITIVITY TO CHANGES IN PARAMETERS
Load Growth
Accelerated growth will lead to an earlier exhaustion of
"surplus" energy and render the electric heating system useless
after a few years. (Until another hydroelectric power project
with excess energy becomes available). Table I shows though
that even as little as 5 to 6 years of full utilization will
make it economically feasible.
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 per gallon
in the year 2000.
NOTE: Analysis should 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 i nsu 1 at ion
etc.
c. Various heating systems, other than fuel oil.
d. Electric heat receipts at a lower cost than fuel displacement.
A-38
•
..
III'
•
.'
..
•
>
(..oj
\.0
Bethel -Appendix A-5
APA014/D1
TABLE A-5.1
II Normalll
Marketable
Hydro MWh s
Year MWh l (High)
1986 126,800 39,679
87 126,800 42,248
88 126,800 44,818
89 126,800 49,387
1990 126,800 49,957
91 126,800 56,739
92 126,800 63,520
93 126,800 70,302
94 126,800 77,084
1995 126,800 83,866
96 126,800 90,646
97 126,800 97,429
98 126,800 104,211
99 126,800 110,992
2000 126,800 117,774
Surplus Marketable Number of
Hydro Heating Residential
MWh MWh 2 Consumers
87,121 52,208 2,008
84,552 53,768 2,068
81,982 55,302 2,127
79,413 56,862 2,187
76,843 58,396 2,246
70,061 60,060 2,310
63,775 61,280 2,375
56,498 63,414 2,439
49,716 65,104 2,504
42,943 66,768 2,568
36,154 68,432 2,632
29,371 70,122 2,697
22,589 71,786 2,761
15,808 73,476 2,826
19,026 75,140 2,890
L Present Worth 1986 at 7% discount
1 Net -transmission losses 3.5%.
Evaluation of Electric Heat
for the Bethel Area
with Golden Gate Hydro, High Load Growth
Cost of Possible
Possible Heating Benefits
Receipts 4 I nstallation 3 To Normal
For Heating & Controls Busbar Cost
MWh ($1,000) ($1,000) ($1,000)
2,988 6,782 (3,794)
3,262 208 3,354
3,556 213 3,343
3,876 225 3,651
4,220 230 3,990
4,605 260 4,345
5,018 274 4,744
4,867 281 4,586
4,540 297 4,243
4,156 304 3,850
3,709 316 3,393
3,194 334 2,860
2,604 342 2,262
1,932 361 1,571
1,169 370 799
35,901 9,167 (Cash Flow at
beginning of year)
33,552 8,567 (Cash Flow at
year end)
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.
4 Fuel replacement equivalent: $/gal x 3413 x kWh . . 138,000 x .7 ; fuel cost escalated 2% above rnflatlon rate (1979 base = 89¢/gal)
5 Inc!. 10% system losses.
:r
.j:--
0
Bethel -Appendix A-5
APA014/D2
TABLE A-5.2
II Normal"
Marketable
Hydro MWh 5
Year MWh 1 --(Low)
1986 126,800 33,656
87 126,800 35,221
88 126,800 36,788
89 126,800 38,354
1990 126,800 39,920
91 126,800 42,039
92 126,800 44,159
93 126,800 46,278
94 126,800 48,397
1995 126,800 50,516
96 126,800 52,636
97 126,800 54,755
98 126,800 56,874
99 126,800 58,994
2000 126,800 61,113
1
Surplus Marketable
Hydro Heating
MWh MWh 2
93,144 52,208
91,579 53,768
90,012 55,302
88,446 56,862
86,880 58,396
84,761 60,060
82,641 61,750
80,522 63,414
78,403 65,104
76,284 66,768
74,164 68,432
72,045 70,122
69,926 71,786
67,806 73,476
65,687 75,140
Present Worths 1986 at
1 Net -transmission losses 3.5%.
Number of
Residential
Consumers
2,008
2,068
2,127
2,187
2,246
2,310
2,375
2,439
2,504
2,568
2,632
2,697
2,761
2,826
2,890
7% discount
Evaluation of Electric Heat
for the Bethel Area
with Golden Gate Hydro, Low Load Growth
Cost of Possible
Possible Heating Benefits
Receipts 4 I nstallation 3 To Normal
For Heating & Controls Busbar Cost
MWh ($1,000) ($1,000) ($1,000)
2,988 6,782 (3,794)
3,262 208 3,054
3,556 213 3,343
3,876 225 3,651
4,220 230 3,990
4,600 260 4,340
5,013 274 4,739
5,457 281 5,176
5,939 297 5,642
6,456 304 6,152
7,041 316 6,698
7,619 334 7,285
8,053 342 7,711
8,278 361 7,917
8,500 370 8,130
50,005 9,167 (Cash Flow at
beginning of year)
46,734 8,567 (Cash Flow at
year end)
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.
4 Fuel replacement equivalent: $/gal x 3413 x kWh .. . 138,000 x .7 ; fuel cost escalated 2% above inflation rate (1979 base = 89¢/gal)
5 Incl. 10% system losses.
'I ,. , I , , , • • , " ., ., ,. ., I • f , , , I If'
Bethel -Appendix A
APA12/Q
APPENDIX A-6
NULATO COAL FIELD RECONNAISSANCE REPORT
Prepared by
Marks Engineering
Anchorage, Alaska
for
Alaska Power Authority
A-41
Bethel -Appendix A
APA12/Q
NULATO COAL FIELD RECONNAISSANCE REPORT
A. COAL AND WOOD RESOURCES
1. Study Area
Within an area two miles each side of the Yukon River between
Galena and Kaltag the wood and coal fuel resources were briefly
examined with the following results.
a. Coal and Wood Resources Literature Summary:
(1) Coal resources: By far the greatest amount of literature
available on the coal resources of the study area ;s
that provided by the United States Geological Survey.
A list of available references from that source is
attached to this report (Item I). The coal resources
map available from the State of Alaska was prepared
recently by the Division of Geophysical and Geological
Survey by extrapolating from USGS data without the
benefit of additional on-site investigation so
should be used with great caution.
A summary of all the USGS data available leads to
the following description of the coal potential of
the study area:
The coal seams are found in the
Cretaceous Kaltag formation which is
composed of sandstone, silt-stone,
shale, and coal seams. The coal beds
are thin and usually included within
a carbonaceous bed that makes the
coal appear thicker than it is. Most
coal beds contain less than one foot
of clean coal and the carbonaceous
zones may approach three feet in
thickness.
There are four documented study area outcrops, as
follows:
(a) Ten miles above Nulato (Pickart Mine). Thickness
averaged 30" over 300 feet of adit. Strike = NE
and dip = 35°N. Also at least four additional
seams reported stratigraphically higher but
little is known of them.
A-43
Bethel -Appendix A
APA12/Q
(b) One mile above Nulato within 2~ feet of boney
coal, six inches of good coal in sandstone.
Very little development.
(c) Four miles below Nulato = Bush Mine. Seam was
probably less than two feet but contained areas
of crushed coal four to five feet thick.
Sandstone wall rocks.
(d) Nine miles below Nulato = Blatchford Mine.
Thickness was very irregular with masses of
coal up to eight feet in diameter (after adit
followed seam that pinched to less than one
inch). Mine was located below river level in
summer.
Average quality of seams from the various USGS
examinecd sources;
moisture = 2%
volitile matter = 25%
fixed carbon = 65%
ash = 7%
sulfur = 0.6%
heating value = 11,000 ± 10% BTU/lb.
b. Coal and Wood Resources Field Examination:
(1) Coal Resources: From September 22 through the 25th
all the sedimentary sequence exposures were examined
between Whiskey Creek (approximately 24 miles upstream
from Galena) and Kaltag. These exposures are limited
to the north and west bank of the Yukon between
these two locations, and clean exposures are limited.
Results follow:
Whiskey Creek to Galena
Only one coal seam was observed, and this was located
in the exposed hillside below VABM Lewis 709. The
exposure was poor but appeared to show a seam thickness
of less than one foot mixed with carbonaceous shale.
I assume this to be the coal location identified by
var; ous USGS pub 1 i cat ions as the Nahoc 1 at i 1 ten
deposit. The zone is very thin, the seam dip steep,
and the seam holds no promise for development from
the surface. Underground mining would not be feasible
under current conditions. (See summary comments.)
Quality information could not be estimated except to
conjecture that the seam would likely conform to the
specifications of the USGS (see above).
A-44
•
•
•
..
.'
..
..
Bethel -Appendix A
APA121Q
Galena to Negotsena Creek
No coal exposures noted.
Negotsena Creek to NUlato
I walked most of the di stance between these two
1 ocat ions and observed several small carbonaeous
shales, some containing very thin but obviously good
quality coal (less than six inches of coal thickness).
Normally such a traverse would not be possible,
however, due to the time of year, the water level of
the Yukon had fallen sufficiently to negotiate some
rather abrupt cl iffs. Much of the time it was
raining hard and the bluff exhibited very active
erosion (1 had to step quickly to avoid falling rock
on several occasions). The most interesting seam
sequence was located between Negotsena Creek and a
point perhaps 2~ miles down stream. This sequence
contained three feet of carbonaceous shale including
six to nine inches of clean, hard coal. I had
directions from several natives for the location of
the old Pickart Mine portal but was unable to actually
locate thi s dri ft but assume the seam mentioned
above to be the same as that mined at the Pickart
Mine.
It is not unusual that the old prospects were not
obvious when one considers the time lapse (77 years)
and the act i ve hill side eros i on in evi dence. The
Pickart seam appeared to strike northeast and dip
approximately 30 o N. No surface mining potential
exists at this location and underground mining would
not be feasible under current conditions (see summary
comments). Quality is assumed by field examination
to approximate that assigned by USGS (page A-44).
The Nulato coal bed described by the USGS as being
located a mile upstream from Nulato could not be
found during this visit, but I feel confident that
it does exist as described by the USGS.
Nulato to Kaltag
Only one area of interest was noted along this
stretch of the Yukon River. In an abrupt bluff
approximately 2~ miles downstream from Benedum
landing are located several carbonaceous shale seams
that make thin and often intermittent bands of coal.
I was able to uncover one chunk of coal for my
campfire that measured roughly l~ feet by one foot
A-45
Bethel -Appendix A
APA12/Q
but it was not all clean coal. I am sure that this
is also the site of the Blatchford Mine described by
the USGS. The river level was not yet low enough to
expose the portal and there was no evidence of any
prior development. The coal bearing sequence available
for examination did not in any way show any probability
for surface development and underground mining would
not be feasible under current conditions (see summary
comments). Quality;s assumed by field examination
to approximate that assigned by the USGS (page A-44).
The USGS describes one additional coal seam upstream
from the Blatchford Mine. four miles downstream from
Nulato. known as the Bush Mine. Considerable time
was spent examining the area for this old prospect
and also for an old oil seep mentioned in literature
comprising the Nulato No.1 oil exploration hole
report and corroborated by two elderly natives in
Nulato. Neither the mine nor the seep was located.
Additional miscellaneous information and summary.
The well logs for the Nulato No.1 oil exploration
hole (approximately 15 miles southwest of Nulato)
are not very complete for the interval from the
surface to 400 feet. but there are some indications
that several coal beari ng zones were penetrated.
It is possible that three separate seams located
between 300 and 400 feet from the surface coul d
amount to something of value. This was the only
encouraging evidence that I could uncover for the
entire study area. It is my opinion that the Kaltag
Cretaceous sequence does not at thi s time show
economic viability but that sufficient evicence
exi sts to encourage further exp 1 orat ion. Such
exploration effort would be most fruitful if expanded
north of Nulato between the North fork of the Nulato
River. and the Yukon (or along either bank of Mukluk
Creek to a point five miles north of its source).
Because the coal seams are so thin, the topography
so steep. and the seam di p adverse to hi 11 5 i de
exposure, I can only conclude that no surface mining
potential currently exists in the study area.
Primarily because of lack of seam thickness I also
must concl ude that underground mi ni ng woul d be
prohibitively expensive under the best of conditions
(experienced labor force, equipment availability.
etc. all of which do not exist to any degree ;n the
A-46
.'
..
till'
..
•
..
•
Bethel -Appendix A
APA12/Q
study area). To attempt underground mining with an
inexperienced crew would ask for certain problems
with the federal Department of Labor mine safety
enforcement branch in addition to prohibitive
operational problems. There is not current possibi-
lity for commerical coal production from the study
area.
A-47
Bethel -Appendix A
APA12lQ
APPENDIX A-7
LISTINGS OF
BIOMASS ENERGY CONVERSION PROCESSES
A-49
State of the Art
Biomass energy conversion processes for use of coal and wood for power and
heat.
Project
Name
Shasta
Mi 11 ~
Anderson,
Ca 1 if.
Oak Ridge
National
Laboratory,
Tennessee
IECO Hybrid
Wood Waste
P1 ant for
GeoProducts
EWEB*
Cogeneration
P1 an t,
Eugene,
Oregon
General
Descri ption
Wood bu rn i ng gas
turbine-combined
cycle p1 ant with
waste heat
Fluidized bed
coal fired gas
turbine p1 ant
Wood waste -
geothermal
combined plant
cycle
Wood waste -
cogeneration
plant provides
central space
/
' heating, burns
coa 1 + wood
waste
Mi chi gan-'I -E~~n~miC S~-~dy
Northern I of proposed
Peninsula I wood fired
Proposal I Michigan
~--"I ~:::m::a::UdY
.-.-
Input
175 tons
day
/
wood
wastes
..
NA
. -
1050
tons/day
wood
wastes
920 tons
day
/
1340
tons/day
wood
9B13
tons/day
coal
--
.~----.----..... --
Output
.. ----
4000 kW
generation
+
68000 1 bs/hr
steam
200 kW
initially
plus process
heat
55 MW
33.B MW
I--~----.--
50 MW
----.--
BOO t1W
Capital Costs
$/kW or
Output
. -1--------_.-
$4 $lOOO/kW
mi 11 ion
+----
$1.B $9000/kW
mi 11 ion
i
I
i -.
I $45 $818/kW
mi 11 ion I
r
-.. -----
i , NA Power i , produced at
9.75 mills/
kW-hr in
1977
--
$47 $934/kW.
mill ion
1--'---.. .--_ .....
$485 $61O/kW.
mi 11 ion
Ref:
f-~--
( 1)
I
r (2)
( 3)
( 4)
(5)
(5) l ___ . ______ 1~ ~~i~~~l~f!~d
~---------. ----'~ . -------
* This is the only existing commercial installation on this page.
A-51
State of the Art (Cont'd)
Proj ect
Nane
OtJens-
Ill; noi s
.-~~~~~-~~;on----I~ ~~t---r-O·u-t·-p-u-t---.------c-.a-p-it-a-l--~~::~-or----Re-;~
Output
---r---.-------f------+-------+------+----I
Existing wood-
coal fired
power plant in
: Tomahawk, Wis.
360 + : 9.2 MW
tons/day
wood
NA NA (18)
....
Consumers Proposed wood
Power Co. fired power
and Wolverine plant
Cooperat i ve
950 + ! 25 t·1W
tons/day j
wood I
$30]
mi 11 ion
--,-,. -.,-·_--·-·--i--------+---
$1228/kTi6l-~
.'-. ---------_._---
Washington
Water Power
Wood-fi red
power plant
under
construction
1700 + 40 MW : $46.7
tons/day ! million
$1l67/kW (7) \C"
wood I ,
I
t Co.,
Col vi lle,
I Washington i _ .. ------.---+-----------+------.-.-----I------\----j
Un; vers ity
of Calif.,
Downdraft
Gas
Producer
Union
Electric
Agr; cul tural
waste-gas
producer
tested at
Da vi s, Ca 1 if.
50 to 81
pounds
per hour
walnut
shells
and tree
I
I
! prunings :
10 kW
from an
interna 1
comb us ti on I
engine I
: Municipal --r 600 tonsIl Saves I
refuse used day of 300 tons/ I.
Co. , as suppl e-refuse day of
Meremac nental fuel coal
Pl an t , in coa 1 I I i
NA NA (8)
NA (9)
St. Louis, I Boilers I:
::~ust;on r~;f~se ~;~ed-r 58-toos--'-II 1 MW gas--tj--N-A---Ir--N-A -+(~~i-
Power Co. -: fluidized bed I per day I turbine ' I tJ
EPA Demon-I gas turbi ne ; refuse I output ' I
stration generator: I I'
Pl ant, Me n 1 0 I i _. ___ .. I f::~ CA, CO'~;;'~-CYC11-197 tons/ 1 3.5 MW 0;:-+--$3.5 $1000lk-W'--r-(--1-1-)--t
International! gas turbine day/wood: 1.5 MW I million
Proposed I wood-coa 1 I and 32000
Plant , fired cycle I : lbs/hr i
L-...-_____ . ___ .---.--_ ._ ... ___ L_ _: ~;~~~n~or I
A-52
•
•
..
.'
State of the Art (Cont'd)
Project
Na~
Nevada
Power Co. ~
Gardner
Plant
General
Description
Smallest size
coal fi red
pl ant recently
bui It
Input
9904
BTU/
kW-hr
-.-
A-53
-. ~.--. ,-
Output
.---, .. -
125 r1w
,-----,~,-,~-~-
Capita 1 Costs Ref:
$/kW or
$/BTU
t--------
NA NA (12)
State of the Art
Biomass energy conversion process for wood and coal fuels (Gasifiers and
Alternate Fuels).
-_.--------,.---------------,---
Project
Name
Well man-
Ga 1 usha
I Coal
Gasifier I
r
I "
Curtiss-
Wright
Pressuri zed
Fl ui d Bed
Gasifier
f Erie
j Mining Co.
I Hoyt Lakes. I Mi nn.
I r~~~~:de. I Errrnett.
I Idaho
Plant
General
[)esc ri pt ion
Oravo proposed
small coal
gasi fier-two
compartment
type
II
Experi mental
pilot plant
with coal
gasifier to
fuel a gas
turbine
generator
with waste
heat
recovery
Two stage
fi xed bed
Woodall-
Ouckham
deroonstration
coal gasifier
Wood waste
gasifier to
fuel a
boiler and
veneer dryer
Input
78 ton
day/co
at $30
ton
156 to
day/co
at $30
ton
120 to
day/co
550 to
day/co
204 to
day/ba
~~--.
Output Capi tal
Cost -r------
s/ 1.5 billion $3.5
al BTU/day of million
/ gas at 150
BTU/cubic
foot 1---------_._-------
nsf 3.2 billion $5.3
al BTU/day of million
/ gas at 150
BTU/cubic
foot
.~ ~----
nsl 7000 kW + NA
al 20.5
mi 11 ion
BTU/hr
waste heat
nsf 7 A bill ion $45
al BTU/day mi 11 ion
of gas at
I 175 BTU/CF
---------------
nsf 1.4 bill ion $1.4
rk BTU/day mill ion
of gas
L __ ._
.. --~"'----_._----------
A-54
$/kW or
$/BTU
----
$3.5/
mill ion
BTU
--.~-
$3.3/
mi 11 ion
BTU
NA
NA
NA
Ref:
( 13)
( 13)
I
( 14)
(15)
(16 )
1
Ill-
I
.l
III,
I
! .'
State of the Art (Cont'd)
Project
Name
Forest
Fuels
Wood
Gasifier
Forest
Fuels
Wood
Gas ifier
General
[)esc ri pt ion
Fl ue gas heated
wood gasifier
Fl ue gas heated
wood gasifier
Input
2.3 tons/
day/wood
Output
$36
mi 11 ion
BTU/day
Capital $/kW or
Cost $/BTU
$16,000
----------r----------f----------
I
--
Ref:
( 17)
18 tons/ I $288 $65,000 (17)
day /wood l' mi 11 ion BTU/day
-_.---~------
A-55
-
Bethel -Appendix A
APA15/A
APPENDIX A-8
KISARALIK HYDROELECTRIC PROJECT
HYDROLOGICAL ANALYSIS
A-57
Bethel -Appendix A
APAIS/A
A. SUMMARY AND CONCLUSIONS
Even with the absence of any gaging data for the Kisaralik River a
fair estimate of the power and energy available from a hydroelectric
project can be made.
A dam co ns t ructed with a sp ill way e 1 evat ion 1110 would prov ide
716.000 acre-feet of live storage. The power and energy which can
be provided by the project are summarized as follows:
Installed Capacity
Firm Capacity
Average Firm Generation
Average Annual Secondary Generation
Average Annual Total Generation
30,000 kW
IS ,000 kW
131. 4xl0 6 kWh
5S.5xl0 6 kWh
186.9xl06 kWh
In order to pass the probable maximum flood a spillway 375 feet
long would be required. Water depth during the peak flow through
the spillway would be 15 feet.
B. METHOD OF ANALYSIS
As there are no hydrologic data available for the Kisaralik drainage
basin, two basic methods of analysis were used to derive an estimate
of the capacity and energy potentially available from the development
of the Kisaralik Hydroelectric Project.
1. Method 1:
A conservative mean annual runoff at the Kisaralik damsite of
20 inches was chosen based on NOAA Techni ca 1 Memorandum
NWS AR-I0 Mean Monthly and Annual Precipitation, Alaska by
Gordan D. Kilday. This bulletin shows a mean annual precipita-
tion of 20 inches for Bethel, 40 inches for the mountainous
region near the Kisaralik River damsite and 80 inches along
the ridge dividing the Kuskokwim and Wood River Basins.
2. Method 2:
Twenty years of precipitation data for Bethel were correlated,
on a month-by-month basis, to the Kisaralik damsite drainage
basin by the use of monthly mean precipitation data provided
in the above described NOAA Technical Memorandum NWS AR-I0. A
probab 1 e 20-year preci pitat i on record and total volume of
precipitation estimate was then made.
A-59
Bethel -Appendix A
APA15/A
Mean temperature data for Bethel was then correlated to the
Kisaralik area to estimate the probable monthly distribution
of runoff into the Kisaralik River, i.e. the water available
for power generation. A probable set of monthly flow data was
then derived, assuming a ten percent loss due to infiltration
and evaporation. (Table 1)
Using the monthly flow data a mass hydrograph was constructed,
and in conjunction with the area-capacity curves, the minimum
and average streamflows were determined.
C. CLIMATE
While there are no weather stations in the immediate Kisaralik
area, it was assumed that the mountainous region near the Kisaralik
River damsite acts as a weather barrier which causes the area to
receive approximately twice as much precipitation as that recorded
at the Bethel station. As the damsite is also farther away from
the moderating influence of the Bering Sea, it can also be assumed
that temperature extremes will be considerably greater.
D. SOILS AND VEGETATION
The Kisaralik area is comprised of maturely dissected uplands
separated by broad, sloping valleys.
The vegetation is primarily tundra, but a few small stands of
stunted white spruce occupy several valleys that are protected from
strong winds. Occasional black spruce grow on low foot slopes.
Solifluction lobes are common on long slopes, and a few frost-scarred
areas occur on ridges.
The dominant soils ;n valleys and on foot slopes formed in thick
deposits of loamy colluvium, but a few of the soils on river terraces
consist of very gravelly alluvial material. On ridges and hills,
most of the soils formed in very gravelly residual material over
weathered bedrock.
Much of the lower areas consist of poorly drained soils with a
shallow permafrost table that occupy broad valleys and long foot
slopes. They formed in thick deposits of loamy colluvial sediment.
The dominant vegetation is sedges, mosses, low shrubs, and in a few
places, stunted black spruce. Beneath a thick peaty surface mat,
the soils consist of mottled, dark gray silt loam that contains
black streaks of frost-churned organic matter.
The hilly to steep areas consist of well drained soils with
permafrost on rounded hills and ridges. They formed in very gravelly
and stony residual material that is moderately deep over weathered
A-60
..
..
..
..
..
..
Bethel -Appendix A
APAI5/A
bedrock. The vegetation is tundra, made up of grasses, patches of
alder and willow brush, mosses, lichens, dwarf birch, and other
shrubs and forbs. Beneath a thin mat of organic matter, the soils
have a very dark grayish brown to dark brown very gravelly silt
loam layer that is about 8 to 16 inches thick and is acid in reaction.
The subsoil and substratum generally consist of olive gray, very
gravelly and stony silt loam or loam. Although the soils have a
mean annual temperature below freezing, the very gravelly material
seldom retains enough moisture in the upper 40 inches to form ice
rich permafrost.
E. POWER POTENTIAL
Using Method I, as described in Section 1.1, the 544 square miles
or 348,160 acres with 20 inches of runoff (1.67 feet) calculates to
580,270 acre-feet of runoff per year. The total runoff of
580,270 acre-feet per year equates to an average annual flow of
800 cfs.
Using the equation, kW; 0.07 (Q) (MEH) , assuming that 800 cfs (Q)
average would flow during the driest year with a mean effective
head (MEH) of 265 feet, the project would develop 15,000 kW
continuously or 131,400 MWh of firm energy per year.
Using Method 2, as described in Section 1.1, it was determined that
an annual flow of 1000 cfs could be maintained during the driest
year. Us i ng the above equation, wi th a mean effective head of
265 feet and a flowrate of 1000 cfs, the project would develop
18,600 kW continuously or 162,900 MWh of firm energy per year.
The average flowrate over the 20-year period of record was calculated
as 1150 cfs. Using this flowrate, and the above cited equation,
the average annual secondary energy would be 55,500 MWh.
Due to the lack of streamflow information, it was deemed conservative
to use the firm power estimate computed using Method 1. The available
secondary energy was estimated using Method 2. The results of the
power potential analysis are as follows:
Installed Capacity
Firm Capacity
Average Annual Firm Generation
Average Annual Secondary Generation
Average Annual Total Generation·
A-61
30,000 kW
15,000 kW
131. 4xl0 6 kWh
55.5xl06 kWh
186.9xl06 kWh
Bethel -Appendix A
APAI5/A
F. PROBABLE MAXIMUM FLOOD
L
2.
3.
Probable Maximum Precipitation
Probable maximum precipitation amounts for the Kisaralik
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 14.0 and
9.0 inches, respectively. In accordance with methods outlined
in this source, these precipitation amounts were adjusted to
reflect the size of the Kisaralik drainage basin. The 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.
Inflow Design Flood
Following 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 480,000 cfs.
Spillway Size
For the purpose of preliminary slzlng 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 water depth (h) of 15 feet, using an attenuation factor
(AF) of 25% and a downstream hazard factor (DHF) of 60%, it
was determined that the following length (b) would be required
to pass the inflow design flood:
b = (AF) (DHF) (Peak Inflow Rate)
3.33 (Hl.5)
b = (0.25) (0.60) (480,000) = 372 feet
3.33 (151.5)
A 375 foot-long spillway would be adequate to pass the inflow
design flood.
A-62
..
..
..
..
•
..
Bethel -Appendix A
APA15/A
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. IIMean Streamflow from Discharge
Measurements, IIBulletin 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 Max'imum Precipitation -
Northwest States, Hydrometeorological Report No. 43.
A-63
APA014/J1
TABLE 1
KISARALI K 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
1959 4.7 7.5 18.7 64.5 115.1 152.5 161.8 154.3 131.0 83.3 38.4 3.7 935.5
1960 5.5 8.9 22.1 76.3 136.0 180.2 191.3 182.4 154.8 98.4 45.3 4.4 1,105.6
1961 5.2 8.4 20.9 72.2 128.7 170.6 181.0 172.7 146.5 93.1 42.9 4.2 1,046.4
1962 3.7 5.9 14.9 51.2 91.3 121.0 128.4 122.5 103.9 66.1 30.4 3.0 742.3
1963 6.2 10.0 25.0 86.1 153.4 203.4 215.9 205.9 174.7 111 . 1 51.2 5.0 1,248.0
1964 3.0 4.8 12.0 41.4 73.7 97.7 103.7 98.9 83.9 53.4 24.6 2.4 599.5
1965 4.2 6.7 16.9 58.1 103.6 137.3 145.7 139.0 117.9 75.0 34.5 3.4 842.3
1966 3.4 5.5 13.7 47.2 84.1 111.5 118.4 112.9 95.8 60.9 28.0 2.7 684.1
1967 4.4 7.1 17.7 60.9 108.6 143.9 152.7 145.7 123.6 78.6 36.2 3.5 882.9
1968 2.8 4.4 11 .1 38.2 68.1 90.3 95.8 91.4 77.5 49.3 22.7 2.2 553.8 > 1969 3.0 4.8 12.1 41.8 74.4 98.6 104.7 99.9 84.7 53.9 24.8 2.4 605.1 I
0\ 1970 4.8 7.6 19.0 65.6 116.9 154.9 164.4 156.8 133.0 84.6 39.0 3.8 950.4 +:-
1971 4.6 7.3 18.2 62.9 112.2 148.6 157.8 150.5 127.7 81.2 37.4 3.6 912.0
1972 3.7 5.9 14.6 50.4 89.9 119.1 126.4 120.6 102.3 65.0 30.0 2.9 730.8
1973 3.7 6.0 14.9 51.4 91.6 121.4 128.8 122.9 104.3 66.3 30.5 3.0 744.8
1974 4.3 6.9 17 .4 59.9 106.7 141.4 150.1 143.1 121.4 77.2 35.6 3.5 867.5
1975 3.9 6.3 15.7 54.3 96.8 128.3 136.1 129.8 110.2 70.0 32.3 3.1 786.8
1976 2.2 3.5 8.6 29.8 53.1 70.3 74.6 71.2 60.4 38.4 17.7 1.7 431.5
1977 4.5 7.2 18.0 61.9 110.4 146.3 155.2 148.1 125.6 79.9 36.8 3.6 897.5
1978 5.4 8.6 21.5 74.1 132.1 175.1 185.8 177.2 150.4 95.6 44.0 4.3 1,074.1
Average 4.2 6.7 16.6 57.4 102.3 135.6 143.9 137.3 116.5 74.1 34.1 3.3 832.0
% of Average
Annual 0.5 0.8 2.0 6.9 12.3 16.3 17.3 16.5 14.0 8.9 4.1 0.4 100.0
, ,
APPENDIX B
COST ESTIMATES
Bethel -Appendix B
APA012/J
APPENDIX B
COST ESTIMATES
1. Transmission Systems
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: Ri ght-of-Way is not i ncl uded.
b. Transmission/Distribution Substation
Transformer 12/16/20 MVA
Switchgear
Bus Structure & Hardware
Freight
Labor 1500 man hours @ $50
Eng; neeri ng 10%
Real Estate
For 40 "'IVA Transformer Add
B-1
Use
1979 $/mile
$ 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)
$125,000.00
1979 -$
$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)
~,OOO.OO
$150,000.00
Bethel -Appendix B
APA012/J
c. Single Wire Ground Return Up To 40 kV
2 Pole Structures, 800' Spans
d.
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
add it i ona 1 guys
labor in difficult terrain add
Use
NOTE: Right-of-Way is not included.
Terminal for Sinrle Wire Ground Return
Transmission Up 0 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 Mil e
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)
$15,000.00
$ 2,860.00
1,320.00
5,000.00
$ 9,180.00
9,500.00
$ 4,OOq.OQ
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
•
..
•
•
Bethel -Appendix B
APA012/J
2. Wind Generating Equipment
a. 1.5 kW windplant with induction generator
and control (Enertech 1500)
Tower including 60-3 pole, pole top adapter
guy wires and anchors (4)
Control anemometer wire, 400 1
Freight 4000 lbs. @ $17/100 lbs.
Installation 100 manhours @ $50
b. 15 kW windplant with induction-generator
(Grumman WS-33)
Tower 40', steel
Control Anemometer wire 400'
Freight 8,000 lbs at $17/100 lbs
Installation 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
$ 35,000.00
2,000.00
60.00
1,360.00
10,000.00
$(48,420.00)
50,000.00
a. Single Wire Ground Return Low Frequency Transmission Up To 80 kV
2 Pole Structures, 500 1 Spans
Structures, 11 @ $300 (imported timber)
Conductor 266.8 ACSR, 5,300 1 @ $750/1000 1
Line Hardware
Survey
Clearing 20%/mile $700/1000 1
Freight
Labor 250 manhours @ $50 (contract labor)
Engi neeri ng 10%
to account for river crossings, bog shoes etc.
Use
B-3
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,OOO.00
Bethel -Appendix B
APA012/J
b. Phase and Frequency Conversion Equipment
(i) Low frequency (25 Hz) to high frequency
(60 Hz) and Ie to 3e for 1 to 2 MW
per terminal (manufacturer's data:
ASEA, Sweden)
Plus freight & engineering, contingencies
(ii) Phase conversion equipment Ie to 3e
estimate
8-4
$
$
$
1979 $
Per kW
200.00
100.00
300.00
150.00
III'
.,..
...
•
..
•
•
..
II< ..
APPENDIX C
ECONOMIC EVALUATION DETAIL SHEETS
Bethel -Appendix C
APAI2/K
APPENDIX C
ECONOMIC EVALUATION DETAIL SHEETS
I. LIST OF ALTERNATIVES
Description
Bethel, Low Diesel, Load
Small Village Communities Low Diesel, Load
Intertied System
Low Load, Diesel
Golden Gate Hydro, Low Load
Golden Gate Hydro, High Load
Golden Gate Hydro, Load Load + Heat
Golden Gate Hydro, High Load + Heat
II. PARAMETERS USED FOR ECONOMIC EVALUATION
A. POWER DEMAND AND ENERGY REQUIREMENTS
Alternative #
I-A
2-A
3-A
4-A
4-B
5-A
5-B
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 demand, although it is expected that
an intertied system would have a coincident demand of .98 or .99 of
the listed demand.
B. ENERGY SOURCES AND SUPPLIES
System firm capacity is assured by assuming the largest unit in the
system is non-operational.
For the alternatives investigating intertied system, firm capacity
is also maintained in each of the individual communities.
Hydroelectric development alternatives with a single transmission
line assume failure of this line, which requires reserve capacity
equal to the hydroplant plus small communities.
C-1
Bethel -Appendix C
APA12lK
C. SWGR LINE LOSSES
Line losses incurred on the SWGR Intertie System have been ignored
as they represent less than one percent of the system's annual
energy requirements.
D. BASE YEAR
All cost data is for the base year of 1979.
E. EXISTING PLANT VALUES
Bethel -Taken from December 1978 annual and financial statement.
Village Plant -Estimated at $870 per installed kW.
F.
1.
ESCALATION RATES
Fuel Costs
An inflation rate of ten percent per year is used through
1984. The inflation rate ;s then decreased to six percent per
year for the remainder of the study.
2. All Other Costs
G.
An inflation rate of eight percent year is used through 1984
for all other costs (i. e. 1 abor I construction t rna; ntenance
etc.) The rate is then decreased to four precent per year for
the remainder of the study.
FUEL COSTS
The fuel costs as of November 1979 were:
1. Bethel -$O.89/gallon
2. Villages -$1.60/gallon (Average)
These prices are inflated as previously mentioned. Escalated fuel
prices by year are shown in Table C~l.l.
H. GENERATION FUEL EFFICIENCIES
The following assumptions are made in regard to fuel cost calculations
and usage:
C-2
'til)
•
•
• ..
•
Bethel -Appendix C
APA12/K
1. Heat content of 138,000 BTU/gal. of diesel fuel.
2. A generating efficiency of 8.0 kWh/gal. in the villages.
3. A generating efficiency of 13.0 kWh/gal. in Bethel.
I. LUBE OIL, GREASE AND OPERATING SUPPLIES
Calculated as 10% of fuel cost.
J. DIESEL MAINTENANCE MATERIALS (REPAIR MATERIALS)
Estimated at $6.77/MWh generated in Bethel and $10.16/MWh in the
villages. These estimates are based on utility records. Inflation
rates are applied as listed.
K. HYDRO MAINTENANCE MATERIALS
Estimated at $0.60/MWh generated. Estimates are based on Alaskan
utility records.
L. INSURANCE
A single insurance rate of $3.00/$1,000 invested is applied to all
investments. This rate is inflated as stated above.
M. LABOR
The present production plant 1 abor costs were determi ned from
utility records for the community of Bethel, and were estimated at
$20,000 per year for the remainder of the communities in the study.
Taxes, insurance and all fringe benefits are included. For each
4,000 kW diesel plant addition an additional plant operator salaried
at $40,OOO/yr. (including benefits, etc.) is assumed. Additional
plant operators will not be required for Golden Gate Hydro project
as ; t wi 11 be des i gned for remote contra 1 ope rat i on and it; s
assumed that the crew size will be sufficient, with the diesel
plants mostly in standby service.
N. DIESEL PLANT COST
Cost of install ing diesel generation is estimated at $870 per
installed kW. These costs represent installation costs as recently
experi enced inA 1 as ka. I nfl at i on rate has been app 1 i ed to future
installation.
C-3
• FUEL COST Tables
APA012/N1 iIOt'
• ..
II!"
TABLE C-1.1 ...
FUEL COST ..
for BETHEL AREA
in dollars/gallon
Year Bethel Villages ..
.."
1979 .89 1.60
1980 .98 1.76 .,
1981 1.08 1.94
1982 1.19 2.13
1983 1.31 2.34 •
1984 1.44 2.58 .,
1985 1.53 2.73
1986 1.62 2.89 ..
1987 1.72 3.06 ..
1988 1.82 3.25 .,
1989 1.93 3.44
1990 2.05 3.65 .'
1991 2.17 3.87
1992 2.30 4.10 •
1993 2.44 4.35 ..
1994 2.59 4.61 •
1995 2.75 4.88 • 1996 2.92 5.18
1997 3.10 5.49 til'
1998 3.29 5.82
lilt;
1999 3.49 6.16
2000 3.70 6.53 .. ..
inflated 10% through 1984 ..
6% thereafter ••
• .. ..
.,
.-.. ..
...
C-4 ., ..
Bethel -Appendix C
APA12/K
O. HYDRO PLANT COST
See Section III.
P. DEBT SERVICE
Debt service on new investments has been calculated using 2, 5, 7
and 9 percent cost of money. An amortization period of 35 years is
used in all alternatives.
Q. DISCOUNT RATE
A 7% discount rate has been used in all alternatives for present
worth calculations.
R. TAXES
Taxes are assumed as one percent of the taxable investment.
C-5
Bethel -Appendix C
APA12/K
III. EXPLANATION OF COMPUTER PRINTOUTS
The following is a line by line explanation of the enclosed computer
printouts.
1.
2.
DESCRIPTION
Load Demand
Demand -kW
Energy -MWh
Sources -kW
A. Existing Diesel
Location or Unit 1-12
B.
C.
D.
Additional Diesel
Unit 1-6
Existing Hydro
Unit 1-6
Additional Hydro
Unit 1-3
Total Capacity -kW
Largest Unit
Firm Capacity
Surplus or (Deficit) -kW
Net Hydro Capacity -MWh
Net Diesel Capacity -MWh
Diesel Generation -MWh
C-6
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 (See
page C-2 for definition)
Total capacity less largest unit
Surplus or deficit in existing generation
capacity
Net annual MWh available from hydro
generation
Net annual MWh available from diesel
generation and is calculated by
multiplying firm capacity in MW by
8760 hrs./yr.
Diesel Generation in MWh required to
supply load enegy. Calculated as
Load energy (MWh) less net hydro
capacity (MWh), with diesel providing
peaking energy where required.
..
•
•
..
•
•
•
..
Bethel -Appendix C
APA12/K
DESCRIPTION
Surplus or (Deficit) -
MWh
3. Investment Cost ($1000)
1979 Dollars
A. Existing Diesel
B. Additional Diesel
Units 1-6
C. Existing Hydro
D. Add it i ona 1 Hydro
Units I-B
E. Transmission Plant
Unit 1-2
F. Taxes Prod. P~ant
Inflated Values
Total ($1000) 1979 Dollars
Inflated values
4. Fixed cost ($1,000)
Inflated values
A.
B.
Debt Service
L Existing
2. Additions
Subtotal 2%-9%
Insurance
Total Fixed Cost ($1000)
2% -9%
C-7
EXPLANATION
Surplus or deficit in existing energy
capacity.
Cost of existing diesel units in 1979
dollars.
Cost of additional diesel units in 1979
dollars
Cost of existing hydro units in 1979
dollars
Cost of additional hydro units in 1979
dollars
Cost of transmission plant additions in
1979 dollars
Estimated taxes on private utilities'
investments and income
Sum of lines A through E above
Sum of Lines A through E 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
Bethel -Appendix C
APA12/K
DESCRIPTION
5. Production Costs ($1000)
Inflated value
A. Operation and Maint.
1. Di ese 1
2. Hydro
B. 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
Mills/kWh 2%-9%
C-8
EXPLANATION
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
Sum of fuel oil and lube oil cost.
Lube oil cost ;s assumed as 10% of
fuel oil cost. Fuel oil cost ;s
calculated by dividing Diesel Genera-
tion (MWh) by 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%
•
..
• ..
•
•
•
I-A
Pi)WER t:O";T '; TIJOV
ALTERSME 1·,\ BETHEL DIESEL -LOW LOAD
\97'"' 1980 1'"'81 lq:3~ 1"'83 1984 1ge:s 1<>86 1997 1'!'>88 1"':39
I. LOAD DEMAND
OEMAND -1"1.1 4.397 4.6b6 4~93:' 5.2.,1 5,46:9 '5.735 6.0.,:) 6.270 6,'537 6.904 7.07':!.
f:NE"'GV -MWH 19.317 21,2'57 :?:?,/:.67 24,077 2'5,436 26.998 28.309 29.719 31,128 32.'5:39 ,)3,94?
., SOURr:E-3 -~:W
A. EXISTING DIESEL
L!JCAT ION OR IJNIT I :::.400 e.4')0 $,400 3.400 9.40t) 3,4(;0 9,400 9.400 $.400 $.40t) 3,400
2
'3
4
'5
",
7
'" <;>
10
II
12
B. ADDITIONAL DIE"·EL
tJNIT 1 2,100 :;, lor) 2. lOt) 2,100 2, tOO 2.100 2.100 2,100 2.100 2, to.)
2
'3
" ':.
(,
C. ExtSTINO HY[lRI)
tJNl T I
:2
[I. AOOITIONAL HVORO
UNIT I
:::
·3
TOTAL CAPACITV -1'\.1 S .. 4;"If) It)~ 50r) t t) s 5 1)f) 10 .. ')1)(\ 10, ~i)O 10,5f)!) Ij)~ ':-0') 10,50" 10,5t)0 11),'500 10~~OO
LAROEST l)NIT :,100 ~~ lOt) :-. 1 (li) :: 't 10() "2. 1 (H) ~t 100 2.100 ~, 100 :.l()O 2' J 1 (10 :.1<)0
F"IRM CAP':KITV 6, ?('1.) 8",4tH) :3.400 :3,4"0 '3" 4(H) :3.40') 8,400 8,4t'0 :~. 4<)0 $,4(H) "'.4<)1)
';:URPl.US OR (OEFICnJ -,:\.1 1, Q(\3 3. 7~:4 3.4/;.7 J. 1 .:)"} : ... ~~.2' Z~b6~ :::, :3'''7 Z. 1 ?!) 1.8·<') 1, -::~.:~ 1 .. J'::3
NET HYDRO CAPACITy -MWH
~'CT DIC'?EL CAPAC lTV -MWH !--:;, 1~:~ 71, :':34 1'3~,)S4 7~.C:::;:4 9 ~"~4 73,~e4 73.'5B4 73. 5:~4 7'3,5:34 7'3 .. :':34 73~ '5:34
D! f"~.rL r·O:IJEPATIJ)N -MI'H 1"'.817 :1. ~:C::7 "~:.1.·,1>7 :4.('77 ~ 4'~,:" :6~ :;Y'B 2!3, "11):3; ~.:). 71:3 31.1':::" '32. '5.::::.:) ~;l. ':)4'~
';I}RF"'Ltl'; !)r~ r DCF Ie IT) -M'-IH 3'5 .. ')71 52, :;:::'7 o:.n. 'J17 4'1. C::07 ~ t)9::: 46. I...,"?':. 45. Z7/;. 43! :?':,./~ 4~, 45~ ... 41.045 :~'~.I) ::-:5
l-A
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000
1. LOAO DEMAND
DEI1Ar,m -I(I.J 7.339 7.730 8.121 9.512 9.903 9,294 9.b85 10.076 10.467 10,l!~59 11.249
ENE~'GY -MI.JH '35.359 37.243 39,127 41.011 41.1395 44.779 46.662 49.546 50.430 '52.314 '54.198
2. SOIJRCES -KW
A. EX ISTINO DIESEL
LOCATION OR UNIT 1 8.400 8.400 3.400 8.400 9.400 8.400 8.400 9.400 9.400 9.400 8.400
2
'3
4
'5
6
7
9
9
10
11
12
B. ADDITIONAL DIESEL
LINlT 1 2.100 2.100 2.100 2.100 2.100 2.100 2.100 2.100 2.100 2.100 2.100
:2 ~t 100 :2.100 2.100 2.100 2.100 2,100 2, 100 2.100 2.100
'3 2,100 2.100 2,100
4
'5
b
C. EXISTING HYDRO
UNIT I
:2
O. ADDITIONAL HYDRO
UNIT
:2
'3
TOTAL CAPACITy -1<101 10.'500 10.500 12.600 12.600 12.600 12.600 12.600 12.600 14.700 14.700 14.700
LARGEST IJN IT Z.100 2.100 2.100 2.100 2,100 2,100 2.100 2,100 2.100 2.100 2.100
FIRM CAPACITy 3.400 8.400 10.'500 to. 500 10.'500 10.500 10.500 10.500 12.600 12.600 12.600
SURPLUS OR <DEFICIT) -KW 1.061 670 2t37~ 1.988 1.597 I.,Z06 81'5 424 ::.133 1,742 1.351
NET HVORO CAPACITY -MI.JH
NET DIESEL CAPACITy -MI.JH 73.584 73.584 91.9130 91.980 91.980 91,990 91.980 91.980 110.376 110,376 ! 10.376
DIESEL GENERATION -MWH 3'5.3'59 37.243 39.127 41.011 41.895 44.779 46.662 48.546 '50.430 52.314 '54. lOS
'3URPLUS OR (DEFICIT) -MWH 3S.22~ 36.341 '52.853 50.969 50.095 47.201 4'5.318 43.434 59.946 S8.062 56.173
fI , ~. , ! I . , , . I , , . , . , , , , , , , I • " , *, .•
I-A
1979 1980 1991 1<>82 1993 1984 198~ 1996 1997 1988 1999
3. INVESTMENT COSTS ($1000)
1979 DOLLARS
A. EX ISTING DIESEL 2.~4~ 2.~4S 2.~4~ 2.!54~ 2.54'5 2.~45 2,545 2.54'5 2~~45 2.~4S 2.545
B. AODITIONAL DIESEL
UNIT 1 1.827 1.927 1.827 1.327 1.327 1.927 1.927 1.927 1.927 t .,827
:::
3
4
5
6
C. EX ISTINO HYDRO
D. ADDI TIONAL HYDRO
UNIT 1
:2
3
E. TRANSMISSION PLANT 1'1001 HONS
UNIT 1
2
F. TAXES PROD. PLANT
INFLATED VALUES 25 46 SO 54 59 63 66 69 71 74 77
TOTAL (111000)
1"'79 DOLLARS ::-.~4-S 4."372 4.37::: 4.372 4,')72 4.372 4,372 4.372 4,")72 4.372 4.372
INFLATED VAL'.'ES 2~ ~.45 4,518 4.518 4.'519 4,")18 4.519 4.'518 4.518 4,51'3 4,518 4.518
4. FIXED COST (111000)
INFLATED VALLIES
A. DEBT SERVICE
1. EXISTING 183 IS3 183 183 183 183 183 183 183 183 183
2. ADDITIONS
SUBTOTAL 21. 7<> 70 79 79 79 79 79 79 7° 79
'S:z 120 120 120 120 120 1::::0 1:0 120 120 L~O
7f. 152 t'5~ 152 152 152 152 152 15~ I~~ -'-1~2
91. IS7 IS7 197 187 IS7 187 IS7 187 IS7 187
S. INSURANCE 8 15 16 17 IS :::0 21 22 22 ::::3 ;;:4
f I
TOTAL FIXED COST ('IOOOl
2%
5%
7%
9%
5. PRODUCTION COST <'1000l
INFLATED VALUES
A. OPERATION AND MAINT
1. DIESEL
2. HYDRO
B. FUEL AND LUBE OIL
TOTAL PRODUCTION COST ('1000)
TOTAL ANNUAL COST ('1000)
2%
57.
7%
9%
ENERGY REQUIREMENTS -M~H
MILLS/KI..IH
2'X
'5%
7%
97.
C. PRESENT WORTH
ANNUAL COST ('1000)
2%
'5'Y.
7%
9%
O. ACCLIMUL. ANN. COST (f1000)
5Y.
7%.
<>"t.
E. ACCUMULATED PRESENT WORTH
ANNUAL COST (SIOOO)
, I . ,
1979
216
216
2!6
216
478
1.493
1.971
2.187
2.197
2.1137
2.197
110
110
110
110
2.1137
::.187
::.1137
2,187
2,187
2.187
~.le7
2,187
.187
.IS7
• t87
.187
1980
323
364
396
431
'516
1.761
2,277
2,6QO
2.1.:t41
2,673
2.708
21.257
122
124
126
127
2.430
2,468
2.49:.3
2.'5'31
4.797
4.928
4.660
4.89 '5
4.617
4.6'5'5
4.685
4.718
1981
3213
369
401
436
'5'58
2.066
2.9~2
2.<>93
3.02'5
3.060
22,667
130
132
133
135
2~~7S
21614
2.642
::.1:;.73
7.739
7,821
7.89'5
7~~55
7.19'5
7.::69
7.327
7.391
1982
333
374
406
441
602
3.346
3.389
3.421
3.4'56
24.077
139
141
142
144
2,733
;;?71:;.6
2~79'3
~.3~1
11.087
11.210
11.306
1I.4lt
(),q:s
10.03':5
10.120
10.Z12
1983
339
380
412
447
6~0
2,$10
3.460
3.799
3.840
3.97Z
3.907
2'5.496
149
151
lSZ
1'53
2,89$
2~930
2,954
2.9 91
14.886
15.050
1:5.179
1~;, 318
12,82'6
12.Q6"5
t3.~)'74
13.193
't , . , , II , , ,
1984
34'5
386
418
453
702
4.308
4.349
4.381
4,416
11:;.0
162
163
164
3,072
3,101
3.124
3,149
19.194
19.399
19.'559
19.734
1'5.896
t6,Ob6
16.199
16.342
1985
34<>
390
422
457
730
3.639
4.369
4.718
4 .. 759
4.791
4,:326
29.308
167
168
169
170
3.144
:). 171
3.192
3.2:16
2:),912
24.159
24.350
~4,560
19.04::
19.237
19,3"0
1"'.'558
-~
19$6
352
393
425
460
760
4.051
4.811
~t 163
5'1'204
5.236
5.271
174
17'5
176
177
:3 .. 21~
3.241
3.261
3,;::-83
29,075
2:9,,362
29 .. 536
~9.S31
2Z .. 2'57
~2.479
~:,b51
2~.841
1987
355
396
42$
4b3
790
5.641
'5,682
5.714
5.749
31.1 29
181
183
184
185
3,2:33
3.307
').3"26
3.346
34.716
35.044
35.300
"J'5.580
2:5.':540
:::'5.78'5
25.<>77
::6.187
'357
400
432
467
822
4.993
'5.805
6.164
6.205
6.237
6.272
32.539
189
191
192
193
3.3'53
3.37'5
3.3"':)
3.41:::
40.880
41,249
41.'537
41.85:
28,$9')
29.160
29~370
2~.'5Q~
363
404
436
471
sss
'5.'510
6.7:"9
6.769
6.801
0,836
33.949
198
I"''''
200
:::01
3~4:('t
3.44\
3.4'57
31147":.
47.609
48.018
49.:)38
4",b:,l:i3
3:::.313
32,1:;.01
3:::,827
33.074
I-A
,
I-A
197? 19!J1) 1?31 1?3::? 1<:>8') 1904 196'5 1986 19 87 19:30 1 "':'l.~
F. AC(UI1 PRES WORTH OF ENERGV
I1ILL'3/I"WH
2% 110 224 ')38 4'5t '56'5 1:>79 790 9?8 I. DO') I. 106 1.207
'5% 110 221:> ')41 4'51:> '571 687 7?"J 90S 1 .01'5 1.11 9 1,;220
7% 110 228 ')44 460 '576 692 130'5 91'5 1,022 1,126 1.2:'3
9% ItO 229 347 46'5 532 699 812 922 1.030 I • 13'5 1.2')7
I-A
1990 1991 1992 1 9 93 1994 1995 1996 1997 1998 1999 2000
3. INVE~TMENT COSTS ('11000)
1979 DOLLARS
A. EX ISTING DIESEL 2,S4~ 2,545 2.545 2.545 2.~45 2.'545 2,545 2,~4S 2.545 2.545 2.545
B. ADOlTIONAL DIESEL
UNIT 1 1.827 1.$27 1.927 1,3:::.!7 1.1327 1. :327 1.927 1,827 1.927 1.927 1.827
:2 1.821 1 t 827 1.927 1.927 1,827 1.927 1.827 1.9:27 1,827
3 1.827 1.927 1.827
4
~ .'
6
C. EXISTING HYDRO
D. ADDITIONAL HYDRO
UNIT 1
:2
:)
E. TRANSMISSION PLANT ADDITIONS
UNIT 1
2
F. TAXES PROD. PLANT
INFLATED VALUES 90 83 123 129 133 138 144 ISS 201 209 218
TOTAL ('51000)
1979 DOLLARS 4.:'372 4.372 6.199 6.199 6.1<><;> 6.199 6.19<;> 6.199 9.026 8,026 StO:=!6
INFLATED VALUES 4.518 4.'518 3.192 8.192 St 192 9, 1 '92 9.192 8,192 12.841 12.941 12.841
4. FIXED COST 1'11000 )
INFLATED vALUES
A. DEBT SERvICE
1. EXISTINO IS3 193 133 193 193 193 193 183 183 183 183
2. ADDITIONS
SllE<TOTAL 2~ 79 79 226 :?26 226 2:?6 226 226 412 412 412
SY. 120 120 344 34.4 344 344 344 344 623 628 6::3
7Y. 152 1S2 436 436 436 436 43i:-436 795 795 7"'5
<;>x 187 197 535 53S 53'5 '53'5 535 53S 975 "'75 975
B. I NSlIRANCe: 2'5 26 49 SI 53 Si:-S8 60 99 102 106
, f , . , , . « , , , , . , , ,
I-A
1990 1991 1992 1993 1994 1995 19<)6 1997 1999 199'" 2000
TOTAL FIXED COST ($1000)
2% 367 371 591 'SS9 59'S 603 611 624 994 906 919
~4 408 412 699 706 713 721 729 742 1.110 1,122 1.135
7Yo 440 444 791 799 80'5 813 921 834 1.277 1.299 1.302
9'/' 47'5 479 .990 897 904 912 920 933 1.4'57 1.469 1,482
'5. PRODUCTION COST ($1000)
INFLATED VALUES
A. OPERATION AND MAl NT
I . DIESEL SS9 924 1.042 I.OS3 t.127 1.172 1.219 1.267 1.318 1.371 1.426
2. HYDRO
S. FllEL AND LUBE OIL 6.0S4 6.793 7.'564 8.404 9.318 10.311 11.339 12.560 13.830 1'S.204 16.696
TOTAL PRODUCTION COST ($1000) 6.973 7.717 9.606 9.4S7 10.44~ 11.433 12.609 13.927 15.148 11;..'57'5 19.12:2
TOTAL ANN'JAL COST ($1000)
2~. 7.340 8.088 9.187 10.07'5 11.040 12.086 t'3.Z1 Q 14.451 16.042 17.481 19.041
'5% 7.381 8.12Q 9.305 10.193 11.158 12~204 13.337 14.'569 10.2'5:3 \7.697 19.::::'57
7% 7.413 8.161 9.397 10.28'5 11.2'50 12.296 13.429 14.661 16.425 17. :';1<:>4 19,4:'4
9% 7.449 8.196 9.496 10.384 11.349 12.395 13.528 14.760 16.605 18.044 19.604
ENERGY REQUIREMENTS -MI.IH 3~:s. 359 37.243 39.127 41.011 42.895 44.779 46.662 48.546 50.430 52.314 '54.198
MILLS/KWH
:y. zoe· 217 23"5 246 2-S7 270 2'3:) 2<';)(; 3t:J TJII -'~.I
~/. 209 21B 238 ~49 260 ::::7J ;:n6 30') 3~2 J)n )lIry'~
7% 210 219 ~4f) 251 :!62 ~7"5 2BB 302 3::::6 341 J~.8
'"'7. : 11 220 ~43 :53 265 :77 290 304 329 34~ }/>:
C. PRESENT WORTH
ANNUAL COST 11110(0)
2% 3.487 3.591 31812 3."'07 4.001 4.0<>4 4.IS5 4.:276 4,436 4.517 4.'599 .,., 3.507 3,609 3,$61 3,953 4.044 4.134 4~Z~: 4. :310 4~4~S 4.573 4,651 " .
7" 3,522 3 .. o~4 3.899 ~ .. -:)89 4.078 4.165 4.2'51 4,;33S 4.54'1 4.616 4.b91
""I. 3,11)3:3 3.639 3.941 4.027 4.113 4,l QQ 4,'::9:3 4.267 4.'591 4.663 4,735
D. ACC'UMLIL. ANN. COST (S 1000)
Z% 54.948 63.036 72.2~3 92,::98 9'),339 10:; .. 424 118.643 133.0"'4 149.130 166.617 lSS .. b5S
5% 55.399 63.52S 72.S33 83.026 94. 134 106·389 119,725 134,294 150,552 168,249 1$7.'506
77. !!>5.751 63.912 73.309 83,'594 94.844 107.140 1:0,!-69 t35~~::;:O 151.655 1/_~Q,51\") 198."'43
9% '56.130 64,332 73.82$ 84 .. =1~ 95. '!·61 107.<>56 IZ1.484 t::?-6o,244 1 '52. :34'? 170.893 191).4<>7
E. ACCUMULATED PRESENT WORTH
ANNI)AL COST (SIOOO) :x 35.800 3 9 .1"1 43.203 47.110 "51 • I I 1 5'3t~OS '5<>.39Q 63.666 6S.102 7~t61Q 77. :::!8
os'%. 36.108 39.717 43.'573 47.'531 51.'57'3 ~S.7()q '50;>.931 .!>4. ::::41 63.736 73. 30'> -:''':'.''::,1)
7~-! 36.~4<> Y'.<>7) 43.37: 47.3101 '51.9 39 '56,104 61).355 64.{'<>,) 1:;.9. ~'::'5 73.8'51 7:).-:":
9% 36.612 40.::51 44.1"'2 4:3. :::19 52.":' 56.'5:11 60.814 65. lSI 6'~, 77'2 74.4J'5 7".170
l-A
19<:>0 1""1 1992 1993 1994 19'?'5 199 .... 1997 19913 199';> 2000
F. ACCUM PRES WORTH OF ENEI':OY
MILLS/KWH
2Y. 1.306 1.402 1.500 1.595 1.6S3 1.779 1.3b9 1.957 2,045 • 131 2.21b
~% 1.31 <:> 1.41 .... 1,515 I. b12 1.70b \.7"'8 1.889 l.'ns 2.0b7 -. 1~4 2.240
71-1,323 1,42'5 1 ,5~5 1 ~6Z2 1.717 1.1310 1.901 1.990 2.080 .163 2.2'54
9'Y,. 1.337 1.43'5 1.536 1.634 1.730 1,924 1.916 2,006 2.097 .IS6 2.273
f , , , , , I , , I , , f-, ,
1>('1./[11 r:r.l' :T o;flJOV
VILLAGES At THNAl[ 2·,\ -DIESEL -LOW LOAD
1971 1980 \981 1'482 1983 1994 l?a~ 1ge1, 1937 1988 1 9 '39
I. LOA[) DEMAND
[)EI'IAND -1<'.101 7Q(l 913 836 860 883 906 0;130 9'53 'n6 1.000 1.023
ENERGY -HWH 2,9'23 '3yOO~ 3.160 3.316 "3,472 3,627 3.78'3 3.933 4.0<>4 4.-:'50 4.4(>'5
2. SOURCES -KW
A. EX ISTING [)IESEL
LOCATION OR UNIT 1 330 330 no 330 330 :310 330 3'30 :no 3'30 330
'2 4~O 4~O 4S0 4~0 4'50 4'50 45') 4~O 4'50 4 a:': 0 4':'0
3 206 206 206 206 206 206 :06 Z06 206 Z06 206
4 I~" ~., 1:-~ 125 12'5 12'5 12'5 lZ5 1~~ ~J 12S 12'5 12'5
'5 ISO l~O 1'50 150 1 '50. 150 150 1'50 I~'O 1'50 1 ':,l)
6 ~O(t ::::00 ~00 200 200 200 :00 200 :00 200 ~oo
7 :00 2 t)(I :f)Q 200 200 200 200 200 200 200 200 a
<>
10
I I
\2
B. ADO rT IONAL DIE~·EL
UNIT I ZOO 200 200 200 200 200 200 200 200 200
:: ~()O 20() 200 200 ZOO 200 :?oo ::::00 ·:00
3
4
'5
(,
c .. Exr."nNG HYDRO
UNIT 1
~
('. A(10ITlO:-lAL HYDRO
UNIT 1 .... ..
TOTAL CAF'ACITY -J I.j 1.661 I. '~61 :!" 1)/;. t :; .. f)61 2,061 2,061 :.061 :" ('l61 ::!'"Obl ::,1)61 2,O61
LAR'~Esr I)NIT \')0 100 1 {)(l 14'0 10" 10<) 100 1<)<) 100 10.' 1 {)('
F IRI1 CAF'ACrTY 1, ~~ .. 1 1.7(,1 I • '>·,·1 1. "'61 1.961 1.961 1 • ~/> 1 1. ~1.."1 I ,"',,! 1. "'61 I • ·~"'1
';IJG.F'l.fJ'i ')R (DEFICIT! -1(\.1 771 "'48 1 ~ 1::'5 I • !" 1 1.073 1 • 0'5'5 I. O~I 1.0')8 ':;':~5 <>61 ~':?'3
r1f,T HYt'RO CA"'AC!TY -I'IWH
p<Er [I!E',EL CAPACITY -I'II-IH 13.674 1'5.4:6 17.178 17.178 17.178 17.178 17.179 17.17$ 17 f 178 17. 7:~ 17. 17:3
(11 E·:.fL C,ENEr-AT ION -MW'" ~ .. ':'):3 3~OO5 3. 160 3.11/;· "),47': 3,(·27 3.7'33 39 Q 38 4.1)94 4. 50 4,4 1):'
,:,I'F'I='LI r; OR «'EFlCrT) -MI-IH lr),7~1 1~.4:1 14.01',: IJ~$(~':: D.70·~ 1"3, ~S l 1'3 .. 3-''5 1:3. :::4.) 1:3. ()S4 1'~ -' -,' -':;' 1,2.77J
2-A
1990 1991 1992 1993 1994 1995 199o!> 1997 1998 1999 2000
1. LOAD DEMAND
DEMAND -KW 1.047 1.100 1.1~3 1.206 1.260 1.313 1.366 1.419 1.472 1. '526 1. '579
ENERGY -MWH 4.'561 4.796 5.032 '5.267 5.503 5.738 5.973 6.209 6.444 6.680 6.916
2. SOI.lRCES -KW
A. EXISTING DIESEL
LOCATION OR UNIT 1 330 330 ")30 330 330 330 330 330 330 330 330
2 4!·0 4'50 450 450 450 450 4~O 450 450 450 450
3 206 206 20o!> 206 206 206 206 206 206 206 206
4 125 125 125 125 125 125 125 125 12'5 125 12*5
'3 150 lSI) 150 150 150 150 150 150 150 150 1S0
6 200 200 200 200 200 200 200 200 200 200 200
7 200 200 200 200 200 200 200 200 200 200 200
e
9
10
11
12
B. ADDITIONAL DIESEL
UNIT I 200 200 200 200 200 200 200 200 200 200 200
2 200 200 200 200 200 200 200 200 200 200 200
3
4
'5
6
C. EXISTING HYDRO
UNIT 1
2
D. ADDITIONAL HYDRO
IJNIT 1
:2
:3
TOTAL CAPACITY -KW 2.061 2.061 2.061 2.061 2.061 2.061 2.061 2.06\ 2.061 2,061 ::,061
LARGEST UNIT 100 100 100 100 100 100 100 100 100 100 100
FIRM CAPACITY 1.961 1.961 1.961 1.961 1.961 1.961 1,961 1,961 1,961 1.961 1,961
SURPLUS OR (DEFICIT> -KW 914 861 SOI3 7'55 • 701 048 595 542 489 435 382
NET HYDRO CAPACITY -MWH
NET OIESEL CAPACITY -MWH 17.178 17.178 17.178 17.178 17.178 17.173 17.178 17.179 17.179 17.179 17.178
DIESEL GENERATION -MWH 4.561 4.796 5.0:32 5.267 5.503 5.739 5.973 6,;209 6.444 6.680 6.9\0
'3l1RPLUS OR <DEF ICIT> -MWH 12.617 12,3B~ 12,146 11.911 1\.675 11.440 11.20'5 10.909 10.734 10.499 10,262
I I , , 1 • • • , , • 1. , ,
2-A
1979 19S0 1991 1992 1993 19S4 19S~ 199b 19$7 19S9 1989
3. INVESTMENT COSTS (SI0I')O)
1979 DOLLARS
A. EXISTING DIESEL 1. 44~ 1.44'5 1.44'5 1.44~ 1.44'5 1.44, 1.44~ 1.44~ 1.44'3 1.44~ 1.44'5
B. ADOITIONAL OIESEL
UNIT 1 174 174 174 174 174 174 174 174 174 174
2 174 174 174 174 174 174 174 174 174
3
4 ,
6
C. EX ISTING HYDRO
O. ADDITIONAL HYDRO
UNIT 1
2
3
E. TRANSMISSION PLANT ADDITIONS
LIN IT 1
2
F. TAXES P~OD. PLANT
INFLATE!) VALUES
TOTAL ("1000)
1979 !)OLLARS 1.445 1.619 1.793 1.793 1,793 1.79" 1.7"'3 1.793 1.7"'13 1.7"'3 1.70 3
INFLATED VALUES 1.445 1.633 1. a::::6 1.936 1.836 1.8'3b 1.836 1.836 1.836 1.836 1 ~S36
4. FIXED COST 1$1000)
INFLATED VALUES
A. !)EST SERVICE
1. EX ISTINO '59 59 ~S . 59 59 '9 59 '39 59 59 59
2. ADDITIONS
SUBTOTAL 2'X 9 Ib 16 16 16 16 16 16 16 Ib
5% 11 23 23 23 23 23 :3 23 23 23
77-15 31 31 31 31 31 31 31 31 31
97-19 37 37 37 37 37 37 37 37 37
B. INSURANCE 4 '5 7 7 9 <> 10
2-A
1979 1980 I?SI 1ge2 1?83 1<>84 198!; 1996 1997 1983 1989
TOTAL FIXED COST ('1000)
21. 62 71 SO 81 81 82 82 83 83 83 84
57.. 62 74 87 S8 8S 89 89 90 90 90 91
n: 62 78 95 96 96 97 97 98 9'3 98 99
9% 62 81 101 102 102 103 103 104 104 104 lOSS
5. PRODUCTION COST ('1000)
INFLATED VALUES
A. OPERATION AND MAINT
t. DIESEL 13S 179 230 249 271 2?4 307 321 336 352 368
2. HYDRO
e. FUEL AND LlIBE OIL 644 727 929 944 1.076 1.222 1.337 1.461 1,595 1.742 1.1399
TOTAL PRODUCTION COST ($1000) 779 906 1.0'59 1.193 1.347 1.'516 1.644 1.782 1.931 2.094 2,267
TOTAL ANNUAL COST ($1000 )
27.. 941 977 1.139 1 t 274 1.429 1.599 1,726 1.965 2.014 2.177 2,351
~"I. 841 990 1.146 1 .. 281 1.435 1.605 1.733 1.872 2,021 2,194 2.3'59 n. 941 984 1.154 1,289 1.443 1.6013 1.741 I.S80 2,029 2.192 2.366
9% 841 997 1.160 1,295 1.449 1.619 1.747 I.S86 2,03'5 2,198 2.372
ENERGY REQUIREMENTS -MWH 2,923 3.005 3.116 3.:227 3.339 3.449 3.560 3.671 3.782 3.893 4.00'5
HILLS/KYH
2~ 288 325 366 395 428 463 48'5 50a 533 559 587
'57-2SS 326 368 397 430 465 487 510 534 561 589
7X 288 327 370 399 432 468 489 512 536 563 '591
9% ~8S 328 372 401 434 469 491 '514 539 '565 '592
C. PRESENT I.JORTH
ANNUAL COST ($1000)
2% 841 <>13 9<>5 1.040 1.099 1.139 10150 1.161 1.172 1.184 1.195
57-841 916 \.001 1.046 1.095 1.144 1.1'55 1.166 1.176 1.198 1.199
7~ 341 Q20 1.00a 1.052 1.101 10150 1.160 1.171 1. 131 1.192 1.203
9% 841 922 1.013 1.0'57 1.105 1.1'54 1.164 1.175 1.184 1.196 1.2Q6
O. ACCLIMLIL. ANN. COST (SI000)
27-841 1.818 2.9'57 4.231 '5.659 7,257 8.983 10.848 12,962 15.039 17.390
5Y. 941 1.821 2.967 4.:248 S.683 7,289 9.021 10.993 12.914 1'5.09$ 17.4'56
7Y. 841 1.82'5 2.979 4.268 5.711 7,3~4 9.065 10,945 1:2.974 15.166 17.'532
97-841 1,828 2,Q8S 4.283 '5.732 7,3'51 9.098 10.984 13.019 15.217 17,'589
E. ACCUMULATED PRESENT YORTH
ANNLIAL COST ('1000)
2Y. 841 1.754 2.749 3.789 4,818 6.017 7.167 8.328 ~,~oo 10.684 11,97<>
5% 841 1.757 2.758 3.904 4.899 6.043 7.198 8.364 9,~40 10.728 tl.~::::7
7% 9'41 1.761 2.769 3,821 4,~22 6.072 7 .. 232 9.403 9.,!;84 10.776 11.97<>
9:<: 841 1.71>3 2,776 3.833 4.939 6.09:2 7.2'56 El. 431 9,615 10.811 12,017
" , , , , , , . . , , . , II f I , I , II , .. , , , ,
2-A
1979 1980 1931 1982 1983 19'3'1 198'5 1996 1937 1908 19,,9
F. ACCUM PRES WORTH OF ENERGV
MILLS/KWH
27-299 592 912 t .234 1.'561 1.891 2,214 2.'530 2.840 3.144 3.442
'57. 298 '593 914 1.239 1.'561;> 1.898 2.223 2.'541 2.8'52 3.1'57 3.456
77-2aa '594 917 1.243 1.573 1.907 2.233 2.552 2.964 3.170 '3.470
97-2a8 595 920 1,241 1.579 1.912 2.239 2,~59 2,972 3.179 '3.480
2-A
1990 1991 1992 1993 1994 199'5 1996 1997 1993 1999 2000
3. INVESTMENT COSTS (SI000)
1979 DOLLARS
A. EXISTING DIESEL 1.445 1.445 1.445 1.44'5 t.445 1.445 1.445 1.44'5 1.445 1.44'5 1.44'5
B. ADDITIONAL DIESEL
UNIT 1 174 174 174 174 174 174 174 174 174 174 174
:2 174 174 174 174 174 174 174 174 174 174 174
3
4
'5
6
C. EXISTING HYDRO
D. ADDITIONAL HYDRO
UNIT 1
:2
3
E. TRANSMISSION PLANT ADO IT IONS
UNIT 1
2
F. TAXES PROD. PLANT
INFLATED VALUES
TOTAL (SI000)
1979 DOLLARS 1.793 1.793 1.793 1.793 1.793 1.793 1.793 1.793 1.793 1.793 1.7"'3
INFLATED VALUES 1.936 1.936 1.$36 1.936 1.836 1.936 1,836 1,936 1,336 1,836 1.836
4. FIXED COST (111000)
INFLATED VALUES
A. DEBT SERVICE
1. EXISTING 58 '58 'Sa 59 '58 sa S9 59 59 59 '59
2. ADDITIONS
SUBTOTAL 27-16 16 16 16 16 16 16 16 16 16 16
57-23 23 23 23 23 23 23 23 23 23 23
7% 31 31 31 31 31 31 31 31 31 31 31
9Y. 37 37 37 37 37 37 37 37 37 37 37
B. INSURANCE 10 11 11 12 12 12 13 13 14 1'5 1'5
\I: • f • If 11 If .. , 111 " , , . I , I •
2-A
1990 1991 1992 1993 1994 199'5 1990. 1997 1998 1999 2000
TOTAL FIXED COST ($1000)
27-84 8'5 8'5 86 86 So. 87 87 SS 89 89
'5% 91 92 92 93 93 93 94 94 9'5 96 96
7Y. 99 100 100 101 101 101 102 102 103 104 104
9% 10'5 106 lOb 107 107 107 108 108 109 110 110
'5. PRODUCTION COST, ( $10(0)
INFLATED VALUES
A. OPERATION AND I'IAINT
I. DIESEL 38'5 404 424 44'5 468 489 '513 '538 565 '593 622
2. HYDRO
B. FUEL AND LUBE OIL 2.068 2)294 2,533 2,804 3,093 3.407 3,747 4.119 4,51S 4.950 '5.418
TOTAL PRODUCTION COST ( $10(0) 2,4'53 2,699 2,962 3,249 3,'561 3,896 4,260 4,657 5.083 5.543 6.040
TOTAL ANNUAL COST ('111000)
2~ 2t~37 2.,793 3.047 3.33'5 3.647 3.982 4,347 ' 4.744 '5.171 5.,632 6.,12C;>
5Y. 2.544 2.790 3.054 3.342 3.6'54 3.989 4.,354 4.751 '5,178 '5.639 6.136-
77. 2.552 2.798 3,062 3.3'50 3,662 3,997 4.362 4.7'59 5,186 5.647 6.144
9Y. 2.5'58 2.804 3.068 3.356 3.668 4.003 4.369 4.765 5.192 5.6'53 6. 1 SO
ENERGY REQUIREMENTS -I'IWH 4.11'5 4.30'5 4.496 4.686 4.877 5,00.7 '5,257 '5.448 5.638 5.829 6.019
M!LLS/I(WH
~y. 617 646 678 712 748 786 '327 871 917 966 1.01$
5% 618 648 679 713 749 787 828 872 918 '''67 1.01'"
77-620 650 681 715 7'51 789 830 874 920 ".'>9 1.021
97-622 651 682 716 752 790 S':'11 87'5 q:l 970 1.0.:'2
C. PRESENT WORTH
ANNUAL COST ('£1000)
27-1,20'5 1.,236 1,264 1 t 293 1.322 1.349 1.376 1,404 1.430 1.4'55 1.480
SY. 1.209 1.,239 1, ~67 1.296 1.324 1 • 351 1.378 1.406 1.432 1,4'57 I. 'IS::?
77-1,212 1 .. 242 1.271 1, ::::9~ 1. ~::?7 1.3'54 1.391 1.40:3 1,434 1.45'" 1.484
"'r. 1. Z15 1.24'5 1. :::73 1,302 1.3:9 1,356 1.383 1.410 1.43b 1.461 1.4:35
O. ACCUMlIL. ANN. COST ($1000)
2r. 19.927 22.710 25.7'57 29,t)9::? 32.739 36.721 41.066 45.812 50.983 56.615 62.744
5Y. 20,000 22,790 2'5.844 29.186 3:2.840 30,829 41.1S3 45,934 5101 12 56,751 62.997
7r. 20.094 22.882 2~,944 ~9,2~4 32.9~6 36.953 41.315 46.074 51,260 56.<>07 63.0'51
97-20.147 22.951 26.019 29.375 33.043 37.046 41,414 46.179 51,371 57.024 63.174
E. ACCUMULATED PRESENT \.IORTH
ANNUAL COST !'JI(00)
2X 13,084 14,::;l::?G 15,584 16.8n IS. 1"'9 19.'548 20,~:-4 ~2,,3::::a 'Z3,1~9 ~5.Z13 ::?6.6"'3
57-13.136 14.375 1'5.642 16.938 18.::::b2 19.613 20.991 :=!2,397 23.S29 25.28b ::::6.768
7% 13.1"'1 14.433 15.704 17.003 18.330 19.684 21.1.165 22,473 23.907 25.366 ~6,8~O
97-13.232 14,477 15,,7'50 17.052 18.381 19.737 21. 120 22.530 23.966 ::5,4:7 :6.Q 12
2-A
1990 1991 1992 199'3 1994 199'5 1996 1997 1998 1999 2000
F. ACCUM PRES WORTH OF ENERGY
MILLS/KWH
2"-3.7315 4.022 4.303 4.579 4,850 5.116 5,378 5.636 '5.890 6.140 6.386
S~ 3.750 4.039 4~320 4.597 4.868 S. 13~ 5.397 5.655 5,909 b,159 6.40"5
7'l. 3.765 4.054 4.337 4.614 4.886 '5.153 'S.416 5.675 5.929 6.179 6.426
9X 3.776 4.065 4.348 4.626 4,899 '5.167 5,430 '!h689 5,944 6.195 1,:.,442
, I If , • I f .. , " " I I • f • " , " I '" . I "
PClIJER (,O"=.T '3TI.lDV
INTERTIED SYSTEM -DIESEL -LOW LOAD ALTER~lJ\TIVE J-A
197" 19~0 1981 1982 1';1133 1984 1985 1980 1987 1938 1999
1. LOAD DEMANO
DEMAN!) -KIJ "3. lea ~,479 -5,.77(} 0.060 6.351 6.642 6,,9'32 7.223 7,"313 7.S04 9JO~~
ENERGY -I'1I./H :!2.740 24, ;2/:.1 2~,S'27 27.393 2$,958 30,52'5 3:!.090 33,6'56 "~t221 36.78:3 3:3.3"34
2. SC1l!RCE'S -r~W
A. EXISTING DIESEL
LOCATION OR lINIT 1 3.400 8.400 8.400 8.400 8.400 :;:.400 8.400 3 .. 400 $.400 St400 S,40(l
2 1,661 1,661 1.661 1.6/>1 1.661 1. c.bl 1. (;,61 1.661 1,661 1.6&1 1.6(;,1
:)
4
"3
6
7
'3
<;>
10
1 1
I:!
11. ADDITIONAL DIESEL
'-'NIT 1 2,300 2.300 2,300 2,,300 2,300 2,300 2,300 2,')00 2.300 :'1 '3(u)
:! 200 200 :::00 zoo 200 ~oo ::00 20., :O()
3
" '5
6
C. ExrST INO HYDRO
l1NIT I
:::
D. ADO I TI (INAL HYDRO
','NIT 1
:: :l
TOTAL CAPACITY -,'1./ 10.1)':'1 1~. 36 t 1:::.'561 1:.5,l,,1 1::.'561 1:.~61 1:.5/;-1 12,561 l'::~ ':.61 1~.5,';.1 t:=.St-.t
LAR';.E3T I.lNIT 3.761 3.761 -3 7 761 '3,761 3.761 3.761 3·761 3.71,1 3.761 .).761 3,761
F"tRM CAPACITY 6.3('0 8 .. 61)r) 8. :30t) :3. :31)0 $.800 $,800 S,SQO :3,800 :)., 8(\1) ;::,,80<) ;~ ~ :300
::·IJRPLU·; OR (DEFr I: I T) -KIJ 1. II:::: 3" 1~1 3:. O'?t) 2,74,) ::::. 44'~ -, 1 ~.:::: 1.81.>8 1,577 1· '::-'S7 ·~'i.'-.. 7(1C:;
NF:T HYORO CAPACITY -MWH
r;ET DIE"·EL I~Ar-'ACITY -r'!\.JH 55,18B 1'5,3-J6 77. f)8:~ 77,0':>:3 77,08:3 77.1):="3 77,t):?:::t 77.0S:, 77 .I):J:~ 77, OS::; 77.0:;-'3
!HE'SEL I~ENERAT ION -NWH Z~t140 24, ;:.~ I :!5. :327 :1.3'::»3 2$.':)'58 30,,5::!5 8:,O,?t) ~~3~l;,~6 35,1::1 36,1:::::3 ;:8 .. :{54
".I:RPLU'3 I)R (DEFICIT ) -MWH J;? 44:3 :51,015 51, ~.~·1 4':),6'~5 48.t 3') 46. '5·~·3 44,<><>'3 43" 43'~ 41. S·C,7 4('l, ~('l('\ 3:3~ i::4
3-A
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000
1. LOAD DEMAND
DEMAND -1<'14 8.386 8.S30 9,274 9.719 10.1-!>3 10.607 11.0'51 11.49'3 11.940 12.384 12.928
ENER"V -MWH 39.920 42.039 44.159 46.278 48.397 50.516 '52.63-!> ~4t755 56.874 58.994 -!>l.t 13
2. SOURCES -KW
A. EX {STING DIESEL
LOCATION OR UNIT 1 8.400 8.400 8.400 8.400 8.400 8.400 8.400 8.400 8.400 8.400 8.400
2 1.661 1.661 1.661 1.661 1.661 1.661 1.661 1. b61 1.661 1.661 1.661
3
4
5
6
7 a
$'
10
11
12
B. ADDITIONAL DIESEL
·UNIT 1 2.300 2 .. 3:00 2.300 2.300 2.300 2.300 2.300 2.300 2.300 2.300 2.300
2 200 200 200 200 200 200 200 200 200 200 200
'3 2.100 2.100 2.100 2.100 2.100 2,100 2.100 2.100 2.100 2.100 2,100
4 2.100 2.100 2.100 2.100 2,100 21100
5 2, tOO 2.100
b
C. EXISTtNG HVDRO
UNIT 1 .
2
O. ADDITIONAL HVDRO
,'NIT 1
:2
3
TOTAL CAPACITY -KW 14.661 14.661 14.661 14.661 14.661 16.761 16.761 16.761 16.761 18.861 19.961
LARGEST 'JNIT 3.761 3.761 3.761 3.761 3.761 3.761 3.761 3.761 3.761 3.761 3.761
FIRM CAPACITV 10.900 10.900 10,900 10.900 10.900 13.000 13.000 13.000 13.000 15.100 15.100
Sl'RPLUS OR (DEFICIT) -KW 2.514 2.070 1,626 1.181· 737 2,393 1.949 1.505 1.060 2.716 ~1272
NET HVDRO CAPACITY -MWH
NET DIESEL CAPACITY -MWH 95.494 95.484 "''5.494 "''5.494 95.484 113,990 113. SSO 113.S90 113.SS0 132,276 1:32.276
DIESEL GENERATION -MWH 39.920 42.039 44.159 46.'Z7S 48.3<>7 50.516 52.636 54.755 56.874 58,994 61.113
SURPLUS OR (DEFICIT) -MWH 55.564 53.445 51.325 49,2l'lb 47.087 63.3b4 61 t 244 59.,125-57.006 73t~82 71.163
., , J , . , , .. " I , " p, .. . " .. . , r , !f • , . I ,
3-A
1979 1980 1981 1982 1993 1984 1985 1986 1987 1989 1999
3. INVESTMENT COSTS ('HOOO)
1979 DOLLARS
A. EX ISTING DIESEL 3.990 3.990 3.990 3.990 3,,990 3.990 3.990 3.990 3.990 3.990 3.990
B. ADDITIONAL DIESEL
UNIT 2.001 2.001 2.001 2.001 2.001 2.001 2.001 2.001 2.001 2.001
2 174 174 174 174 174 174 174 174 174
3
4
5
6
C. EX ISTING HYDRO
D. ADDITIONAL HYDRO
'.'NIT 1
2
3
E. TRANSN1SSION PLANT ADDn IONS
UNIT 1 3,100 3.100 3.100 3.100 3.100 3.100 3.100 3.100 3,100
:2
F. TAXES PROD. PLANT
INFLATEO VALUES 25 46 '50 54 59 63 66 68 71 74 77
TOTAL ('51000)
1'">79 DOLLARS 3.9<>0 5.991 9.26'5 9.26'5 9.265 9.265 9.265 9,2b~ 9,26'5 9~~65 ~,:::65
INFLATED VALUES 3.990 6.151 9.970 9,Q70 9.970 9,970 9.970 <>,970 9,970 9.970 9,-no
4. FIXED COST <'510(0)
INFLATED VALUES
A. DEBT SERVICE
1. EXISTING Z41 ~41 241 241 241 241 :41 241 241 241 241
2. ADDITIONS
SUBTOTAL 2~ Sf> 23<> 23~ 239 239 239 239 239 239 ::!3()
S% 132 365 365 365 365 365 365 36'5 365 365
7% 11>7 462 462 462 462 462 462 462 462 46::::
9% ~04 565 565 565 56S 565 565 565 565 565
9. IN$'JRANCE I: 20 3'5 38 41 44 46 48 49 51 53
TOTAL FIXED COST (~1000)
2%
'5%
7%
9%
5. PRODUCTION COST (~1000)
INFLATED VALUES
A. OPERATION AND MAINT
1. DIESEL
2. HYDRO
B. FUEL AND LLIBE OIL
TOTAL PRODLICTION COST (~1000)
TOTAL ANNUAL COST (~1000)
2'l.
5%
7%
91.
ENERGY REOUIREMENTS -MWH
MILLS/KWH
2Y.
5%
7Y.
9%
C. PRESENT WORTH
ANNLIAL COST (UOOO)
5%
7%
9%
D. ACCUMUL. ANN. COST (~1000)
2%
51.
7%
91.
E. ACCLIMULATED PRESENT WORTH
ANNUAL COST ('1000)
'51.
7%
91.
, ,
1979
278
279
278
279
583
2.071
2.654
2.932
2,932
2.932
2.932
22.740 .
129
129
129
129
2,932
2.932
2.932
2.932
2.932
2.932
2.932
2.932
2,Q3::!
2,932
2.9 32
1980
393
439
474
S11
662
2.430
3.092
3.485
3,531
3.'566
3.603
24.261
144
146
147
149
3,:~7
3.300
3.333
3.367
6.417
6.463
6.499
6.535
6.199
6.232
6.26'5
6.299
, .
1981
'56'5
691
788
891
192
2.353
3.110
3.236
3.333
3.436
25.827
120
12'3
129
133
2.716
2,92b
2.911
3.001
9.527
9.699
9.831
9.971
9.90'5
9.059
9.176
9.300
1982
572
698
79'5
898
20S
2.74'5
2.9'53
3.525
3.651
3.748
3.851
27.393
1:9
133
137
141
2,877
2.980
3.0'39
3.144
13.052
13.3'50
13.'579
13.922
11,792
12.039
12'f23~
12.444
1983
S80
706
803
906
224
3.194
3.418
3.999
4.124
4 • .221
4.324
28.958
138
142
146
14';>
3.0'50
3.146
3,220
3.299
17.050
17.474
17.800
19.146
14.93:
15.194
15.4'3'5
15.743
.. .
1994
587
713
810
913
242
3.703
~t945
4.532
4.658
4.755
4.8'59
30.525
148
153
156
159
3.231
3.321
3.390
3.464
21, ~92
22.132
22.5'55
23.004
18.063
19.505
19.84'5
19.207
1985
592
718
815
919
4,126
4.378
4.970
5.096
5.193
5.296
32.090
155
159
162
16'5
3.312
3.396
3.460
3 .. ~29
26.552
27.229
27.749
29.300
21.375
21.901
2Z,305
2:,736
" ,
1986
~96
722
819
922
262
4.596
4.948
'5.444
5.'570
5.667
'3.770
33.656
162
16'5
168
171
3.390
3.469
3.529
3.593
31.996
32.799
33.415
34.070
24.76'5
25.370
25.934
26.329
f ..
1987
600
726
823
926
273
5.087
'5.360
'5.960
6.086
6.183
6,286
35.221
169
173
176
179
3.469
3.542
3.'599
3.65'"
37.956
39.884
39.598
40.3'56
':9,234
28.912
29.433
29,QSS
, ,
1999
605
731
828
931
284
5.634
5.919
6.5:?3
6.64"
6.746
6.949
36.799
177
181
193
186
3.'548
3.617
3.669
3,725
44.479
4'5.533
46.344
47.205
31.782
3:.5:9
33.102
33.713
19'3'~
610
736
833
936
6,.226
6.521
7. 131
7.~51
7,354
7.457
39.3'54
186
189
192
1"4
3,6:~
3.699
3.738
3.7"1
51.610
52.790
'53.699
54.61,2
3'5.407
36.219
36.8-l0
37.504
, ,
3-A
, .
3-A
1"'7'" 1 ?~(. 11");~ 1 1"'/:~:: t -:.:::) 1';'~'4 t ?r{'5 1 <';;'>1;) I '~87 t ·:j.~?:3 t'1:'71'-'
F. ACCt.'M PRES WORTH e'F ENERC.,(
MILL'S/trI.lH
2Y. 129 :!64 3'/.,.9 474 ~79 68'3 783 as? 9S7 1.0:31 1.1 7 8
~y. IZ? 26'5 314 433 '5 9 1 700 30/> 90';-1.010 I. lOS 1 ~ ~(l4
7"1. 129 266 37'" 4"'1 602 713 :321 ?~~ t 10~:3 1.1::8 t ~ ::-:-6
9Y. 1:!:'" :-6.8 384 499 613 721.> :?36 942 1.046-1.147 1 .. 246·
3-A
1 '~"<) 1".,1 l'?*:l~ 1 "'''3 1"''''4 1"'>'4':, 1 ""~I, 1.,':>7 19<>9 1 ",~" :;000
3. I~NESTMENT COSTS ('1:1000)
1~7~ r'OLLAR':>
A. EXISTING DH"~EL 3.990 3.990 3.9"0 3.9';>0 :'3.9-:>0 3.""'0 3.9';>0 3.9"0 3.990 3,I!)9'O 3.9":'0
S. ADDITIONAL DIE":·EL
UNIT 1 ~.OOl 2d)<) 1 2,')01 2.001 2, f)(tl 2,Of)1 2.001 2.001 2,Qf)1 2.001 2,001
2 174 174 174 174 174 174 174 174 174 174 174
3 1.'327 1 ,~:27 1.827 I.B27 1. 3~7 1.3:7 1, :327 1.827 1,327 1 f 8:!7 1,8::7
4 1.827 t .,:3~7 1.827 1.827 1.327 1, :327
'5 1,827 1,827
0
C. EXISTING HYDRO
D. ADDITIONAL HYDRO
UNIT I
~
E. TRANSMISSION PLANT ADDITIONS
UNIT 1 ~.1(1) 3.1')0 3tlOO '3.100 '3, If)O 3.100 3.100 3.100 3,100 3.10<' '3.100
~
~
F. TAXES PROD. PLANT
INFLATED VALUE'; eo 3'3 I'"''"' 1~8 1]3 133 144 1':.5 :01 ::t)·:) ~13
TOTAL (' 1')')0)
1~;'0 01JLLARS 11 ~,)9~ 11 ~ 0'7i: 11., O,:)~ 11 ,O·~: 11. t)'"')2 12, '.'1'> L~f'~l<!) l~t':;>l"? 1~. ':')1 0 ·14.741;, 14.741,
INFLATED VALUES \3, 3,~.7 13. '31)7 13,367 1'3.367 1'3" '1~7 17,5')() 17*500 l'.5f:"O 17 .. 5(lO 2:2.335 ..... -, ........ c:-........ ,-.;.,.;._.
4. Ft XED COST ( '10<)<')
INFLATED VALUE',
A. ['lEST $ERVI'~E
1-nISTlN(' :41 ;:'41 :41 :41 :41 ;:41 -;::41 :41 :41 ;Coli :41
~ A [tD IT ! ,)NS
SUBTOTAL :Y.. ::;l7'5 37'5 37'5 '?-7'5 ::;l7'5 '540 '540 54" 540 T"n 733
5'%. ,)7:: 57: ~-.~ ~" -'5"'~ "5,7~ 7?-::4 8:4 6:':4 ~~·~4 1 • I I'" 1 • I I'"
7" '. 7::4 7::4 :-:: '\ -:':~ 7:4 1 "~';) 1 ,043 1 ,t~43 I, "4'3 1.416 1.41",
"'% 8gl.~ 8:~~\ :3~~·~.., S:'3·~ ::::~6 \. ::77 1 ~ :'77 1,277 1, :77 1,735 1, ,',,:.
B. I>"".'RAN':E 7'5 73 '31 ' 84 :37 lI'~ 1:4 1 ~~ _0 IJ4 177 1'34
, I , \\I If • " .. . , , .. 11ft , t I • f., • I
3-A
1990 \991 1992 199'3 1994 1995 1996 1997 1999 1999 ;1000
TOTAL FIXED COST (UOOO)
2% 771 777 920 929 936 1,039 1,049 1.064 1, 116 1,360 1,376
!iY.. 969 974 1 • .,17 1,025 1,033 1.322 1,333 1,348 1,400 1.746 1.762
n; 1.120 1,126 1,169 1.177 t,la~ 1.541 1.552 1.567 1.619 2.043 2.059
n 1.282 1.289 1.331 1.339 1.347 1.77'3 1.796 l.eOI 1.853 2.362 2.37S
5. PRODUCTION COST ( .. 10001
INFLATED VALUES
A. OPERATION AND MAtNT
1. DIESEL 307 31';1 412 429 446 464 482 '302 '322 '342 564
2. HYDRO
B. FUEL AND LUBE OIL 6.969 7.666 9.'336 9,492 10,511 11.629 12.947 14,166 15,597 17.149 18.930
TOTAL PRODUCTION COST ("10(0) 7.175 7.985 9.949 9.911 10.957 12.093 13.329 14.669 160119 17.690 19.394
TOTAL ANNUAL COST (SI000)
27. 7.946 8,762 9.769 10.739 11.793 13.131 14,379 1'3.732 17.235 19.050 2t),770
57. 9.143 e.<;),~9 9.965 10.936 11.99" 13.415 14,662 16,016 17.519 19.436 21.15t. n 8 .. 295 9.111 10,117 11 ,098 12.142 13.634 14.891 16.23'3 17.7'38 19.733 21,4'5'3
97. 8.457 9,273 10.279 11.25., 12.304 13.968 1'5.11'3 16.469 17.972 20,052 21,772
ENERGY REQUIREMENTS -MWH 39.920 42.039 44.159 46.278 48.397 '50.'316 '52.636 54,755 56.974 58.994 61,113
MILLS/KWH
21-199 20S 2:?1 232 244 260 273 287 303 323 340
'51-204' 213 ~26 236 248 266 279 293 303 'J2? '346
77. 209 217 2:?? 240 ::tt 270 283 :97 312 :334 3'51
9'X. 212 Z21 233 243 :'54 275 287 301 316 340 3'56
C. PRESENT WORTH
ANNUAL COST ($1000)
2~ 3.77'5 3.$90 4.0'53 4.16'5 4,274 4,449 4,!'552 4,b~~ 4,766 4,923 5,016
5% 3.869 3.978 4.1:315 4.241 4,346 4,S44 4,642 4.739 4.844 ~,O2:3 '5.10"
7Y. 3.941 4,04'5· 4.198 4.300 4.401 4.618 4.711 4.903 4,90'5 5.099 '5. lSI
9% 4.016 4.1 17 4.~65 4.363 4.460 4.698 4.73'5 4.913 4.969 5,IS2 S.~5S
D, ACC\.IMUL. ANN. COST ($1000 )
2X 59.556 68.318 78.096 S8.82'5 100.618 113,749 128 .. 127 143.859 161.094 180.144 200."14
5% 60.933 69.892 79.857 90.793 102.783 116.1 Q e 130.960 146.876 164.395 193.1331 204.997
7'l. 61.993 71.104 81, :21 92.309 104.4'51 119.085 132.966 149.201 166.939 196.672 209 .. 12'5
97-63.119 72.39~ 82.671 93,'9: 1 106.225 1:0.09:) 13'5.208 151,677 169.649 199.701 211.473
E. ACCUMULATED PRESENT WORTH
ANNUAL COST ( 'SIOOO)
Z'l. 39.182 43.072 47.125 51 .. 290 '55. '364 60.012 64.564 69.219 73."85 79.908 6'3,924
5Y. 40.087 44.065 48.~OO 52.441 '56.787 61.331 65,973 70.712 7'3.'556 80.'579 85.689 n. 40.791 44,826 49.0Z4 '53.324 57.7::::5 62.343 67.0'54 71.857 76.762 81.961 97.042
97-41.522 45.639 49.904 54.267 '58.727 63.425 68.210 73.083 78.0:5::1 83.234 8S.492
3-A
1990 1991 1992 199'3 1994 19Q5 1996 1997 1993 1999 2000
F. ACCUM PRES WORTH OF ENERGV
MILLS/KWH
2% 1.273 1,365 1.457 I, '547 1.63'5 1,723 1.809 1.894 1.978 2,061 2,143
57. 1.301 1. '396 1.490 I, '582 1,672 1.762 I.S~O 1.937 2.022 2,10? 2.1 91
7Y. 1.325 1.421 1.516 1.609 1.700 1.791 1.881 1,969 2,OSS 2.141 ::? .. 2:?6
9Y. 1.347 1.44'5 1, :;42 1.636 1.729 1.821 1 •. 912 2.001 2.088 2,176 2,262
.. . '" . r • , . • • , , III , II , , , , , It· I , , , , , , I •
P01,.!ER CO':;T '::TUOY
INTERTIEP SYSTEM HYDRO LOW LOAD AL TERlIATlVE 4-,'\
1"'79 1 9 80 1931 1ge2 19:33 1"':34 1)1:3~ 1986 1987 t?S!3 1 '>:,,<>
1 • LelAO Oe:MAr~o
OEMAr;o -n" ~.laf:l :;,47? ~.770 6.0(,0 6.351 6.642 6.932 7.22'3 7.~13 7.:304 3.09'5
ENERGY -MWH 22.740 :?4.261 Z-S~ :327 27 .. 31!)3 2:3.?59 31).52'5 32.090 3,3.6'5/> 35.2Z1 36.738 33,3~4
2. '3(!URCES -trY
A. EXISTING OIESEL
lOCAT I(lN QR UNIT 1 8,4(')0 :3.400 8,41)1) 3,4(H) 3,40(\ S,4I),) $.400 $.400 3.400 $.400 3.400
2 1.1,1,1 1.661 1.661 1.661 1.6/,1 1 t 661 1.661 1.661 1 .1,61 I .61, 1 1.661
:3
4
'!\
6
7 --
:3
Q
10
11
12
B. ACtO 1 TI ONAL OIESEl
LIN IT 1 2,:)00 2.300 2.3')0 2t3()() 2,300 ~l' :300 2,300 :,300 2,300 :2,:300
2 200 ::00 ZOO ~f)O 200 200 200 200 200
';1
4
'5
b
C. EX ISTING HYOf\')
UNIT 1
2
O. ADC'l T rONAL HYDRO
UNIT 1 .,. 30,.0(1) 30·0(10 30.00t) 30. t)O(\
::
'3
TOTAL CAPACITY -KW 10.061 12.31>1 12, -:;.~ 1 t:,5t,,1 12.'561 lZ$5~1 1:,561 4~,S61 4;:. '5,~1 42,5bl 4:,5(,,1
LARC·EST ','N! T ~~7/')1 3.7(;,1 3.7/,1 3,.761 3.761 '?7'61 3.761 ')1. ~,61 31.6(;,1 31. t,,~1 '31 ,t<~61
FIRM '::>'.P-'lCITY 6.300 8,000 :3 ~ 8(H) t3,. SOl) S.8f )1) $.8(,H, S~ :~('O 10, ,)()O 10. "<)(1 1(\,,900 to. '::)fH)
',:URPlU?, I)R ([IEF letT) -1<14 1.1 12 '3. 121 J~ f) '::c) -:. 7 ~(~ ~.44·;j 2,1'5:3 1,$(.:;: 3 .. ,,77 3,387 3.0''''6 :,~0':1
NET HV[·RO .... APACITY -I1WY 1 ~6. ;300 1':.~. :;'0l) 1 :1,. :,00 126. ::::00
~:ET [1!E';;EL CAPt\CITy -MWH ':5~t88 7C:;~ 3?1.." 77.08:3 7 7 , (1:3":3 77.0;,:3 ;7.08:3 77, ()88 ?5 • ..1;34 "'-''5, 4;~;4 '~'5. 4:34 ':)';,4::;:ol
r.'IE".El ,:",r,ERA T I ')N -MWH ':?2.741) ::4 ~ ::?h 1 :::5, :~27 17, ,)'::'?-::3" QS:3 30tS:C:: 3~, o·-:)t)
';URPt-I)S I)R ( DEFICIT! -M\.i;~ 32.H1 51,1)7'5 51. :c·1 4':), (.95 48. 13E) 46,!o6"3 441";)?8 <?5~ 4:34 ~5, 4:::t4 -:")5~ol84 .~'5. 4:34
4-A
1990 1991 1992 1993 1994 1995 1996 1997 1999 1999 2000
1 • LOAD DEMAND
DEMAND -KW 9.396 9.930 9.274 9.719 10.163 10.607 11.0'51 11.495 11,940 12,394 12.828
ENERGY -MWH 39,920 42.039 44.1'59 46,278 48.397 '50.516 ~2.636 ~4.755 56.974 59.994 61.113
2. SOLIRCES -KW
A. EXISTING DIESEL
LOCATION OR lINIT 1 9.400 9.400 8,400 9.400 9.400 9.400 9.400 8.400 8.400 8.400 8,400
2 1.661 1.661 1.661 1.661 1.661 1.661 1.661 1.661 1.661 1.661 1.661
'3
4
5
6
7
$
9
10
11
12
9r ADDITIONAL DIE'SEL
UNIT 1 2.300 2.300 2,300 2.300 2,300 2.300 2.300 2.300 2.300 2.300 2.300
2 ZOO 200 200 200 200 2QO 200 200 200 200 200
3 2.100 2.100 2.100 2.100 2.100 2.100
4 2.100
5
b
C. EX ISTINO HYDRO
LINIT 1
2
D. ADDITIONAL HYDRO
tiN IT 1 30.000 30.000 30.000 30.000 30.000 30,000 30·000 30.000 30.000 30.000 30.000 :::
'3
TOTAL CAPACITY .-KW 4~,~61 42.;561 42.5bl 4Z.Sbl 42.561 44.661 44,661 44.661 44,661 44.661 46.761
LARGEST UNIT 31.661 31.1>61 31.661 31.661 31.661 31. bOl 31·661 31.661 31.661 31.661 31,661
FIRM CAPACITY 10.9l10 10.9 00 10.900 10.900 10.900 13.000 13.000 13.000 13.000 13.000 IS.!OO
StIRPLLr, OR (DEFICIT ) -KW 2.514 2.070 1.626 IdSI 737 2.393 1.949 I.SOS 1.060 616 2,272
NET HYDRO CAPACITY -MWH 126,$00 126.800 1:::6.800 126.$00 126,900 126.;900 126.900 126.800 126.900 126.900 126.900
'~ET OIESEL CAPACITY -MWH 95.484 9'!!. 4134 95.484 95.484 95.484
DIESEL GENERATION -MWH
I 13.1l80 113,880 113.1390 ,113. S80 113.980 132,276
SlIRPLL'3 OR WEF IC I Tl -MWH 95.494 95.494 Q5.484 9!:".494 95.494 113.890 113.890 113.990 113.980 113.S90 13Z.276
, , If 'I . , .. , • I , , " , . , If , , ,
4-A
1979 1980 1981 1982 1983 1984 19135 1991.> 1987 19sa 1999
3. INVESTMENT COSTS (SI000)
1979 DOLLAR';
A. EXISTING DIESEL 3.990 3.990 3.990 3.990 3.990 3.990 3.990 3.990 3.990 3.990 3.990
9. ADOITIONAL DIESEL
UNIT 1 2.001 2.001 2.001 2.001 2.001 2.001 2.001 2.001 2.001 2.001
'2 174 174 174 174 174 174 174 174 174
3
4
5
I.>
C. EXISTING HYDRO
D. ADDITIONAL HVORO
UNIT 1 99.1.>57 99.657 99.657 -;:>9,6~7
'2
3
E. TRANSMISSION PLANT ADDITIONS
UNIT 1 3.100 3.100 3.100 3.tOO 3.100 3.100 3.100 3.100 3.100
2
F. TAXES PROD. PLANT
INFLATEO VALUES 25 46 50 '54 '59 63 66 68 71 74 77
TOTAL (SI000)
1979 DOLLARS 3,990 '5.991 9.265 9.265 9,26,!5 9.265 9,26'5 10S .. 9~:: 108,92~ 108.9 22 10:3,922
INFLATED VALUES 3.990 6.151 9.970 9,'no 9,970 9."70 9.970 168.347 168.347 168.347 168.347
4. FIXED COST (SI000)
INFLATEO VALUES
A. OEBT SERVICE
1 • EXISTING 241 241 241 241 241 ~41 241 241 241 241 241
2. ADDITIONS
"239 SUBTOTAL Z% S6 239 239 239 239 6.574 6.574 6.574 6.574
5'l. 132 365 36' 365 365 365 9,S'?S 9.S95 Q,3O~ 9l8Q~
7% 167 462 462 462 462 462 12.693 12.693 12.6<>3 12.69 3
9'l. 204 56S ~6S S65 565 565 1'5.'552 IS.5S:? 15.5'52 15t~S2
B. INSURANCE 12 20 35 38 41 44 46 803 835 863 903
4-A
1979 1990 1981 1982 1983 1984 198:5 1986 1987 19 83 1989
TOTAL FIXED COST (SI000)
2% 278 393 :56:5 572 :580 587 592 7.686 7.72i 7,757 7.795
5Y. 278 439 691 698 706 713 718 11.007 11.042 11.078 11.116
n. 278 474 788 795 803 810 81'5 13.805 13.840 13.876 13.914
9Y. 278 511 891 898 906 913 918 16.664 16.699 16.735 16.773
:So PRODUCTION COST ("1000)
INFLATED VALUES
A. OPERATION AND MAINT
1 • DIESEL :583 662 192 208 224 242 2~2 262 273 234 29'5
2. HYDRO 362 393 428 46'5
B. FUEL AND LUeE OIL 2.071 2.430 2.353 2.74~ 3.194 3.703 4.126
TOTAL PRODUCTION COST ('fIOOO) 2.OS4 3.092 2.'545 2.953 3.418 3.945 4.378 624 666 712 760
TOTAL ANNUAL COST ( 'I;tOOO)
2X 2.932 3.485 3.110 3.525 3.998 41~32 4.970 8.310 8.387 8.40',> SySS~
5% 2.932 3.531 3.,236 3.651 4.124 4.653 5.096 11.631 11.708 11.790 11.876
7Y. 2.932 3.560 3.333 3.748 4.221 4.755 5.193 14,429 14.506 14.538 14,674
9Y. 2.932 3.603 3.436 3.851 4~324 4.858 5.296 17,289 17.305 17.447 17.533
ENERGY REOUIREMENTS -MWH 22.740 24,261 25.827 27.393 28.958 30.525 32.090 33.656 35,221 36.788 38,:)54
MILLS/KWH
Z%. 129 144 120 129 138 148 155 247 233 230 2:?3
5'l. 129 146 125 133 142 153 159 '346 332 320· 310
7Y. 129 147 129 137 146 156 162 429 41:: 397 383
9Y. 129 149 133 141 149 159 105 514 493 474 457
C. PRESENT WORTH
ANNUAL COST (StOOO)
2Y. 2.932 3 .. 257 2 .. 716 2.677 3.050 3.231 3.312 5.175 4.881 4.607 4.349
SY. 2"Q~2 3.300 2.626 2.990 3.146 3.321 3.396 7.243 6.814 6.413 1.>.037
7Y. 2.932 3·333 2.911 3.05<:> 3.220 3.390 3.460 8·986 3.443 1,,935 /,460
9Y. 2.Q 32 :).367 3.001 3.144 3.299 3,464 3.529 10.766 10.107 9,490 8.913
D. ACCUMUL, ANN. COST ($1000)
2Y. 2,932 6.417 9,~27 13.0::"2 17,050 21.582 26,,~52 34.862 43.249 51.718 60.273
5Y. 2.932 6.463 9.699 13.350 17.474 22.132 27,2:!S 38.859 50.567 62.357 74.23'3
7Y. 2.932 6.498 9.831 13.579 17.800 22,,5~5 :7.748 42.177 56.683 71.271 S5.Q 4'5
9Y. 2.9 32 6.535 9.971 13.922 16,146 23.004 :8.300 45.5$8 62.Q 53 80.400 <'17.933
E. ACCllMlILATEO PRESENT IJORTH
ANNUAL COST ("1000)
2Y. 2,932 6.189 8.905 11.792 14.9'32 18.063 :1.375 26.550 31.4'31 36.033 40.387
5Y.. 2.932 6.232 9.0~8 12.038 15.184 18,505 21.901 29,144 35.9'38 42,371 48,408
n 2 .. 932 6.~o!5 9·176 1~'i235 15.455 Hl.845 2= .. 305 31,Z~1 39.734 47.669 55,12<>
9Y. 2.932 6.299 9.300 12.444 15.743 19.207 ~2,73o 33.502 43.609 53,099 02.012
9: • , , , , , II , . , I • • " Ii , . , • II , , ,. f • , " . ,
4-A
1979 1990 1981 19a~ 1983 1984 19!J5 198~ 1987 1988 1989
F. ACCUM PRES WORTH OF ENEROV
MILLS/KWH
27-129 2~4 3~9 474 579 ~95 7SS 942 1.081 1.20~ 1.319
57-129 2~5 374 433 591 700 80~ 1.021 1.214 1.398 1,546
77. 129 26~ 379 491 ~02 713 S21 1.089 1.329 1 ,~44 1.739
9Y. 129 2~8 394 499 ~13 72~ 936 1.156 1.443 1 .701 1.933
4-A
1990 1991 1992 1993 1994 199'5 1996 1997 1998 1999 2000
3. INVESTMENT COSTS (UOOO)
1979 DOLLARS
A. EXISTING DIESEL 3.990 3.990 3.990 3.990 3.990 3.990 3.990 3.990 3.990 3.990 3.990
B. ADIHTIONAL DIESEL
UNIT 1 2.001 2.001 2.001 2.001 2,001 2.001 2.001 2.001 2.001 2.001 2.001
2 174 174 174 174 174 174 174 174 174 174 174
3 1.827 1.827 1.827 1.827 1,927 1.927
4 1.327
~
6
C. EXISTING HYDRO
D. ADDITIONAL HYDRO
UNIT 1 99.6~7 99.657 99.657 99.657 99.657 99.6'57 99.657 99.6'57 <>9.657 'l>9.657 9Q,,6~7
2
3
E. TRANSMISSION PLANT ADDITIONS
UNIT 1 3.100 3.100 3.100 3.100 3.100 3.100 3.100 3.100 3.100 3.100 3.100
:2
F. TAXES PROD. PLANT
INFLATED VALUES 80 83 123 128 133 138 144 155 201 209 219
TOTAL ("1000)
1979 DOLLARS 108.,922 108.922 10e,1. 922 10S,,92:! 109,922 110.749 110.749 110.749 110.749 110.749 112.57b
INFLATED VALUES 168.347 168.347 168.347 165.347 168.347 172.480 172.430 172.480 172.480 172.480 177.50S
4. FIXED COST (.1000)
INFLATED VALLIES
A. DEBT SERVICE
1. EXISTING 241 241 241 241 241 241 :41 241 241 241 241
2. ADDITIONS
SUBTOTAL 2X 6.~74 6.574 6.574 6.574. 6.574 6.739 6.739 6.739 6.739 6.739 6.940
57-9.89'5 9.89'!i 9.895 9,SQ~ 9.$95 10.147 10.147 10.147 10.147 10.147 10.454
7"1. 12.693 12.693 12.693 12.693 12.693 13.(112 13.012 13.012 13.012 13.012 13.400
91-15.552 15,5~·:2 15,552 1~,5~2 15.5'52 15.943 15.943 15.943 15.943 15.943 16.419
B. INSURANCE 939 977 1.011, 1.056 1.098 1.170 1.217 1.266 1.317 1.369 1.466
'" , * • • J , I , ¥ , " , , I , . , • 11 " ..
4-A
1990 1991 1992 1993 199 4 1995 1996 1997 1999 1999 2000
TOTAL FIXEO COST ('$1000)
2Y. 7.834 7.875 7.954 7.999 8.046 8.2aS 8.341 8.401 8.498 8.5~8 8.96'5
'5y. 11.155 11.196 11.27'5 11.320 11.367 11.696 11.749 11.809 11.906 11.966 12.':n9
7Y. 13.953 13.994 14.073 14.118 '14.16'5 14.561 14.614 14.674 14.771 14.831 1:;.325
9Y. 16.812 16.853 16.932 16.977 17.024 17.492 17.545 17.605 17.702 17.762 18.344
'5. PRODf)CT I ON COST (SI000)
INFLATED VALUES
A. OPERATION ANO MAINT
I. DIESEL 307 319 412 429 446 464 482 502 :522 ~42 564
2. HYDRO S02 '551 601 655 713 774 837 909 980 1.0'56 1.139
B. FUEL ANO LUBE OIL
TOTAL PRODUCTION COST ($1000) 809 970 1.013 1.084 1.159 1.238 1.319 1.410 1.502 1.598 1.703
TOTAL ANNUAL COST (SI000)
2Y. 8.643 8.745 8.967 9.083 9 .. 20!5 9~~26 9.660 9.811 10.000 10.156 10.*5':,8
57-11.964 12.066 12.288 12.404 12.:526 12.934 13.068 13.219 13.4013 13.'564 14.082
7Y. 14.762 14.864 15.086 15.202 15.324 15.799 15.933 16.084 16.273 160.429 17.028
9Y. 17.621 17.723 17.945 18.061 18.183 18.730 18.864 19.015 19.204 19.360 20.047
ENERGY REOUIREMENTS -MWH 39.920 42.039 44.159 46.278 48.397 50.516 52.636 54.755 56.874 58.99 4 61.113
MILLS/KWH
2Y. 217. 208 ~O'3 196 190 189 184 179 176 172 173
'5y. 300 287 278 269 2'59 25~ 248 241 :::!:)6 230 ::30
77-370 354 342 328 317 313 303 ZQ 4 286 278 27q
9Y. 441 4'"''' 406 390 :)76 :)71 3~8 347 338 3::?S 328
C .. PRESENT WORTH
ANNUAL COST ( SlOOO)
2Y. 4.106 3.883 3.721 3.S23 3.336 3.227 3.058 2.903 2.765 2.62'5 2.~5Z
57. '5.684 ~.357 5.099 4.810 4.540 4.381 4.137 3.911 3.707 3.505 3.4')1
7Yo 7.013 ~.600 6.260 5.891> ~.5!:4 5.352 5.044 4~7'59 4.500 4.246 4.112
9Y. 9.372 7.S69 7.447 7.004 6,590 6.344 '5.97-;: 5.626 $.310 5.003 4.84~
O. ACCL'ML'L. ANN. CO'ST ($1000)
2% 0.8.916 77.661 96.628 95.711 104.916 114.442 124.102 1:<3.913 143.913 1'54.069 164.637
5Y. 86.197 98.263 110.551 122.9'55 135.481 148.415 161.483 174.702 188.110 201.674 215.7'56
77-100.707 115.571 130.6'57 145.859 161.183 176.982 192.915 208.999 225 .. 272 241.701 2~e,7:9
9,.. 115.554 13~.277 151,222 169:283 187.466 206.196 225.,060 244.075 26<')~279 292 .. 639 ::102.686
E. ACCUMULATED PRESENT WORTH
ANNUAL COST ('S1000)
2X 44,49~ 48.376 52.097 55.620 58.956 62.183 .<;5.:'41 68.144 70.909 73.534 76.l'86
'5y. 54.0<:>2 59.449 64.548 6 9 .3'53 73.893 7$.279 82.410. 96.32i 90.034 93.539 "b,'94r)
n:. 62.142 68.742 75.002 90.898 96.452 91.804 96.948 101.607 106.107 110.3'53 114.465
9% 70.384 7!h :'53 85.700 Q2.704 99.294 105.638 111.610 117.23.<; 122.546 1:"7.549 132.3"'1
4-A
199(1 1991 1992 1993 1994 199~ 1996 1997 1998 1999 2000
F. ACCUM PRES WORTH OF ENEROV
MILLS/KWH
2'Y. 1.422 1.'514 1. '598 1.674 1.743 1.807 1. $65 1.918 1.967 2.011 2.053
57-1.689 1.816 1.931 2,03'5 2,129 2.216 2,2'9-3 2.366 2.431 2.490 2.~46
77-1,91'5 2.072 2.214 2,341 2.456 2,562 2.658 2.745 2.824 2.896 2,963
97. 2.143 2,330 2'.,498 2,649 2.785 2.911 3.,024 3.127 3.220 3.30~ 3.334
, . , . • • II , ,
I "
, . lfi • i •
P()W!':f'l CQ'3T ""rUDY
INTERTIED SYSTEM AL TER~AT!VE 4-B HYDRO HIGH LOAD
1979 1930 1981 1';>92 193:) 1934 1'>35 1936 1 9 87 1~$3 198~
1. LOAD DEMAND
DEMA~~[I -YW 5, ISS 5.47"?J 5,Qe2 6,435 6,938 7,492 7.9~'5 3,4<>:3 ~,O(ll 9.504 10.007
ENERGY -MWH 22,740 Z4,2bl Z~., 8?:t) Z9.400 31,970 34,540 37,109 3<>,67'9 4~,24:1 44.313 47,387
~ SOURCES -I<W
A. EX I'>TlN(l DIESEL
LOCATION OR UNIT 1 9.400 8.400 8.400 8,400 3.400 3,400 9.400 8.400 3.400 8.400 3.400
:2 1. 6~,1 1.661 1.,661 1 • 661 1.661 1.661 1.661 1.661 1.661 1.661 1.661
'3
4
'5
'-'
7
8
.~
10
11
12
B. ADDITIONAL OIE'3EL
UNIT I 2,51)0 2t~I){) 2,50(l .2.~OQ 2.~OO 2.'500 2,500 2,500 2,'500 2 I '5(')()
::?
'3
4
':l
(,
Co ex ISTlN I3 HY(1R')
UNIT I
~
D. A[lDITIONAL HY['RO
UNIT 1 JC),I)Of) 3t..) .. 000 '30, f)(H) :30 .. (100
:.'
3
TOTAL CAPA':;ITY -KW 1 ,). <)61 t~,S61 1:::.5'<:·1 12,561 1=::,~61 12,561 1::.,.5(.,1 4:.'.561 4:-,561 42, '5,: .. 1 42.561
LAR'~E<:T I)NIT 3,761 3.761 3.761 3.761 3.761 3, 7~'1 3.71:>1 :31 ,i::,!,d 31.661 '31,661 31,661
F"lRM CAPACITY 6., ')1)0 :3 I ;3.)() 8,$00 8' • ;3(')1) :3, Sf)f) 3.:300 :3, :30" 10,'~OO 1 () • .:.t(H) 10, <)c)O 10 • .,")f)f)
':·Uf.:PLU'3 OR (oEF' len) -KW 1. 11 ~ 3.3:::1 ::.BI:e> =.315 1.81~ 1.31):3 80S :., 40'Z 1 , :3,?? 1,3"(-:~'~3
NET HYDFlO CAPACITY -M~H 1 :'?~t Sf)t) 1":6,800 126,SO!) 1 ::'6, S'1)i)
IIET o IE'3EL CAF'AC ITY -I1WH -SS,11:;6 77 t I):~:?: 77.0:?8 77, r)f3:,3 77.083 77,0;38 77.08!3 95,4:34 ..:)5.484 '4'5,4:"34 '?IS, 4:)4
[lIE-;,EL GENERf'TtQN -MWH ::::::.7~0 :::4,:::61 ':~.:33r) :':>,4(,H) 31,t.;);'t) 34.540 '37. Ii)'~
':I,'RPLI.I'; OR ( OEFl':ITl MWH ~::,44:3 ~2,!?!~7 !SI) l '~'5:;! 47,6:~;'3 45,11:3 4~.548 :-;." '~!7''J ,"¥lc:.~ 4~34 9'5, 4:::4 "')5.4:)4 <::IS,. ..l!3~
4-B
1"90 1991 1<192 1993 1994 199'5 1996 1997 1999 1999 2000
1. LOAD OEM AND
DEMAND -KW 10.511 11.948 13.336 14.823 16.261 17.699 19.136 20.574 22.012 23.449 24.997
ENERGY -MWH 49.957 56.739 63.'520 70,302 77.084 93.966 90.647 97 .. 429 104.211 110.992 117.774
2. SOLIRCES -KW
A. EX rSTINO DIESEL
LOCATION OR UNIT 1 9.400 9.400 9.40c) 9.400 9.400 9.400 9.400 9.400 9.400 9.400 9.400
2 1.661 1.6bt 1.661 1.661 1.0.0.1 1.60.1 1.661 1.0.61 1.0.61 1.661 1.661
3
4
5
6
7
3
9
10
11
12
B.' ADDITIONAL DIESEL
UNIT 2.500 2.500 2.500 2.500 2.500 2.500 2.500 2.500 2.500 2,'500 2.'500
:2 2.000 2.0.00 2.600 2.600 2.600 2.600 2.600 2.600 2.600 2,600 2.600
3 5,')00 5.000 5.000 5.000 5.000 5.000 ~:;.OOO '5,000 5.000
4 5.000 5.000 5.000 5.000 5.000 5.000
5 5.000 5.000
b
C. EX ISTINO HYDRO
UNIT 1
2
O. ADDlTIONAL HYDRO
LIN IT 1 30.000 30.000 30.000 30.000 30.000 30.000 30.000 30.000 30.000 :;10.000 :;10.000
:2
3
TOTAL CAPACITY -KW 45.10.1 45.161 '!>0.161 50.161 50.161 55.161 55.161 '55.161 '55.161 60.161 60,161
LARGEST UNIT 31,661 31.661 31.661 31.661 31.661 31.661 31.661 31.661 31,661 31.661 31.0.61
FIRM CAPACITY 13.500 1:;1.500 1S.'500 H10500 19.500 23.,~OO 23.500 23.500 2:;1.500 29,'500 28.500
SURPLUS OR (DEFICIT) -KW 2.98-" 1 .. ~5: 5.114 3.677 2.2:;1<1 '5.901 4.364 2.,~2b 1.499 5.0'Sf 3.613
NET HYORO CAPACITY -MWH 126.800 126.600 126.900 126.800 126.900 126.S00 126.900 126,900 126.800 1260.900 126.900
NET OIESEL CAPACITY -MWH 119.260 119.260 162.060 162.060 162.000 205.960 20:5.960 20:5.960 205.960 249.660 249.660
OIESEL DENERATION -MWH
SURPLUS OR !DEFICIT) -MWH 118.260 118.260 162.060 162.00.0 1b2.060 205.960 ~OS,BbO 205.860 205.960 249.660 249.660
Ii: • , . , . I 11 , . , , , , lI\. , , .. . , , . I , , , , . , . , ,
4-B
1979 1990 1981 1982 19133 1984 1995 1996 1997 1998 1999
3. INVESTMENT COSTS ('10001
1979 DOLLARS
A. EXISTING DIESEL 3,990 3.990 3.990 3.990 3.990 3.990 3.990 3.990 3.990 3.990 3.990
S. ADDITIONAL DIESEL
UNIT 1 2.175 2,175 2.175 2.175 2,175 2. 175 2.175 2.175 2.175 2.175
2
3
4
5
6
C. EXISTING HVDRO
D. ADDITIONAL HVDRO
UNIT 1 99.657 99.657 99.657 99t~~1
:2
3
E. TRANSMISSION PLANT ADDITIONS
UNIT 1 3.100 3.100 '3.100 3.100 3.100 3.100 3.100 '3.1(1) 3.100
~
F. TAXES PROD. P.LANT
INFLATED VALLIES Z5 '51 '5'5 ~9 64 69 7":! 15 79 1 ::t' 1:''5
TOTAL ('111000)
1979 DOLLARS 3.9<;>0 6. t.~5 Qt26~ "'.::65 9,;::65 9.265 '9,;:?6'5 10:3,922 109,,9::2 10$.92: lOS,>:)::?::!
INFLATED VAUJES 3.990 6.33<) 9,955 '1,955 9.955 9.955 ~.\'?~5 169,332 168.332 le·g, 3'3:',2 Ib8 .. JJ2
4. FIXED COST ($1000)
INFLATED VALUES
A. DEBT SERVICE
1. EXISTING 241 241 241 241 241 241 241 241 ~41 241 :'41
2. ADDITIONS
SUBTOTAL :X 94 23'> 239 ~39 239 :3'~ 6.'574 6.574 b~574 6.574
'5Y-143 364 364 364 364 364 9.8"'4 9.894 Q,9"4 <>,gQ4
7Y-181 460 4,~0 460 460 460 lZ.691 12,691 12.69 1 12.6"1
Qy' :Z2 564 ':.64 504 564 564 15.!oSl 15.551 15.551 1-;'.~51
B. INSURANCE 12 21 35 38 41 44 46 803 835 869 Q03
TOTAL FIXED COST ($1000)
~y.
~y.
~. PRODUCTION COST ($1000)
INFLATED VALUES
A. OPERATION AND MAINT
1. DIESEL
2. HYDRO
9. FIJEl AND LUBE OIL
TOTAL PRODllCT ION COST ($ 1 (00)
TOTAL ANNUAL COST ($1000)
Z~
57-
7'7.
9'7.
ENERGY REOI.! I REI1ENTS -MI-IH
MILLS/KI-IH
C. PRESENT WORTH
ANNIJAL COST ( $ 1000 )
2%
5'7.
7'7.
9'7.
D. ACCUI1Ul. ANN. COST (SI000)
:;:)(
7'Y.
9'7.
E. ACCUI'1L1LATED PRESENT WORTH
ANNUAL COST (SIOOO)
27.
'5'7.
7)(
9)(
, . f ,
1979 1980
593
2,071
2,{<''54
2.93~
2,932
2,932
2.932
22.740
, "
2.93Z
2.93:::
2.9':?
2.932
2,93:2
2.932
2.9'3~
2.93:::
2,93~
2.93:2
2,o3Z
2.932
, ,
407
456
494
5')5
662
2.430
3.092
3.4<>9
3.'548
3.596
3.627
144
146
14"
149
~.270
3.316
3.3'51
3.3<>0
6,431
6.480
6.'518
~h~59
6.20:.:'
6,248
6.283
6.322
570
69'5
791
995
192
2.445
2.637
3.207
3.332
3,428
3,~32
26,S30
120
1:'4
128
132
2.$01
::~.~ 1 (\
Z .. ?':)4
3.0:35
<>,638
<>.812
0.946
10.091
9.003
9.158
9.217
9.407
, ,
577
702
798
902
208
2.947
3.1'5'5
3,732
3.957
3.953
4.057
2<l'.400
1:17
131
134
138
3 .. :!Z7
3,312
13.370
13.669
13.S<l'0
14.148
.04<l'
.306
.504
.719
1<l'83
~a'3
710
SOl:.
910
224
3.749
4.334
4.459
4,5'55
4.659
31.970
"
136
I 'J'T
142
146
3.306
3.402
3.475
3.'554
17.704
18.1:'9
19.454
13.807
1'5.35'5
15.708
15.0 79
16.273
1984
'393
718
814
918
242
4.432
S,025
5.150
5.246
5.350
34.'540
14'3
14<l'
15~
155
3.672
3.740
,3,814
22,7~9
~3.278
23.700
24.157
19.9 38
19.380
19.71<l'
20.087
198'5
598
723
819
923
2'52
4,772
'5.024
5~622
5.747
'3.843
5.947
37.109
1'51
1'55
1'57
100
;:).746
3.829
3.80 '3
3.<l'63
213.3'51
~9.,O~'5
:9.,~43
30.104
2:!.694
234209
:13.612
24.0'50
f. , , I
1996
7,693
11.013
13.810
16.1:.70
262
428
690
8.383
11.703
14.~00
17.360
39.679
'5.
7.
211
295
365
438
9.030
10.911
36,734
41),1:9
44.043
47.464
27"'1<jlO~
30,49 7
32.,642
34.361
1997
7.729
11.048
13.84'5
16.705
273
473
746
8.474
11.70 4
14.'5<l'1
17.451
42.,243
4,'9'3=
6,864
9.4':)~
10,157
4'5.208
5:,~:-2
58.634
64.91'5
32,837
37,361
410134
4'5.019
I
1988
7.803
11.123
13.920
16.780
284
521
805
8.608
11.<l'28
14.7:!'5
17.'585
44.918
198<l'
7.843
11.163
13.<l'60
16.820
295
574
8.71::?
I::! ",.)2
14.829
17.6:39
47.387
IEJ4
2~4
313
373
4.68:: 4.42<l'
6.488 od 16
8.009 7.538
9,56'5 S,'~Q2
53.,916 62,529
64.4'50 76.482
73.3'5<l' 88.199
82.500 100.189
37,519
43.84<:1
49.143
'54.583
41.<l'48
49,96'3
56.681
63.'57'5
, .
4-B
, .. , .
4-B
1979 1980 1 9 81 1982 1983 19134 1,;)85 198"" 1987 1989 1<;13<;1
F. ACCUM PRES WORTH OF ENERGV
MfLLS/¥I-lH
2Y. 129 264 369 473 *!J77 680 781 91:2 1.029 1.133 1.227
5Y. 129 265 373 480 5Sb 692 795 979 1. 141 1.2136 1~41~
n. 129 267 379 4S8 596 704 809 1,031.> 1.237 1,416 1.57'5
9Y. 129 268 383 496 "'07 718 925 1,098 1.339 t ,551 1.741
4-B
1990 1991 1992 1993 1994 199'3 1996 1997 1999 1999 2000
3. INVESTMENT COSTS (101000)
1979 DOLLARS
A. EX ISTING DIESEL 3.990 3.970 3.990 3.990 3.9 90 3.990 3.990 3.990 3.990 3.990 3.99 0
B. ADDITIONAL DIESEL
UNIT 1 2.17'3 2, 17~ 2.17'3 :2. 17'5 2.17'5 2 .. 175 2'.175 2.175 2017'3 2. 17'3 2.175
2 2.262 2.~62 ~t262 2,262 2t262 2.262 2,=62 2,262 :,262 2,262 2.262
3 4.3'50 4.350 4.3'50' 4t3~O 4,350 4.350 4.350 4.,350 4.3'30
4 4.350 4.350 4.3-:;0 4.350 4.3'50 4,350
'3 4,350 4,350
6 2.262 2 .. 26::!
C. EXISTING HYDRO
D. ADDITIONAL HYDRO
lIN IT 1 99,657 99.6'57 99.657 99.6'57 99.6'37 9 9 .6'37 99.657 99.657 99.657 99.6'57 99.657
2
3
E. TRANSMISSION PLANT ADDITIONS
UNIT 1 3.100 3.100 3.100 3.100 3.100 3.100 3.100 3.100 3.100 3.100 3.100
Z
r:. TAXES PROD. PLANT
INFLATED VALUES 130 178 18'3 241 Z~O 260 270 280 292 34'3 3'59
TOTAL (UOOO)
1979 DOLLARS 111.184 111.194 115.'334 115.534 11'3.534 119.884 119.884 119.884 119.884 126.4Q 6 126,4"'6
INFLATED VALUES 172.537 172.537 181.284 lSI,284 181,:::84 191. 124 191-124 1°1,124 191,124 208~6~1 2<)8.621
4. FIXED COST (101000)
INFLATED VALllES
A. DEBT SERVICE
1. EXISTING 241 241 241 241 241 :=:41 241 241 241 241 241
2. ADDITIONS
SUBTOTAL ~4 6.742 6.742 7.0QZ 7,0<;>2 7.092 7.4$6 7.486 7.486 7,,486 $.186 $.186
5Y. 10.1'51 10.151 10.685 10.&85 10.6'35 11.:::96 11.286 11.286 11.286 12.3'5'5 t:.3SS n 13.016 13.016 13.692 13.6<;>2 13.692 14.4~: 14.452 14.452 14,4~2 1 S, 8<.1:3 15.S03
9y' 15.949 15.949 16,777 16.777 16.777 17.709 17. 70S 17.708 17.708 19.364 19.364
B. I NSI.IRANCE 962 1,001 1.094 10137 1.183 1.2Q7 1.349 1.403 1.4'59 1.6S6 1. i'~~
, , , r , '" I , . II • I , , . , ..
4-8
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000
TOTAL FIXED COST (.1000)
2% 9.07'5 S.162 9.612 S.711 9.766 9.284 9.346 9.410 9.478 10.429 10.~OS
'5% 11.494 11.571 12.205 12.304 12.359 13.084 1').146 13.210 13.278 14.597 14.677
7Y. 14.349 14.,436 15.212 1'5.311 15.366 16,250 16,312 16.376 16.444 18.045 18,125
9)(. 17.282 17.369 19.297 18.396 19.451 19.506 19.569 19.632 19.700 21.606 21.696
5. PRODUCTION COST (.1000)
INFLATED VALlIES
A. OPERATION AND MAINT
1. DIESEL 307 396 412 429 446 464 '576 ~99 623 649 674 .., HYDRO 628 742 96'3 995 1.13'5 1. 29'S 1.444 1.61'5 1.796 1.987 20193
B. FUEL AND LUBE OIL
TOTAL PRODUCTION COST (.1000) 935 1.138 t,27' 1,424 1. '381 1.749 2.020 2,214 2.419 2'.0'3'5 2,867
TOTAL ANNUAL COST (ttOOO)
2Y. 9.010 9.300 9.899 10.13'3 H'I.347 11.033 11.366 11,624 11.897 13.063 13.37'5
S% 12.419 12.709 13.482 13.n8 13.940 14.833 1'3.166 1'5.424 15.697 17~23.2 17.~,44
n. 15.284 15.574 16.499 16.735 16.947 17.999 18.332 18.590 18.863 20.680 20,992
9% 18.217 19.'507 19,574 19.920 20.032 21.25'5 21 ;SSS 21.946 2Z.t 19 241241 24.553
ENERGY REQlI IREMENTS -MWH 49.9'57 ~b,,73? 63.'320 70.302 77.094 83.866 90,647 97.429 104.211 110.992 117.774
MILL':::II<WH
2% 190 164 1'56 144 134 132 125 119 114 US I 14
5':( 249 224 21:2 175 lSI 177 167 1'38 151 15'5 149
7% 301> 274 260 2'38 220 21'5 202 191 181 186 17$
9'Y. 365 326 308 .282 260 253 238 224 212 218 208
C. PRESENT \.IORTH
ANNI)AL COST ('1>1000)
24 4,2S1 4.12<> 4.104 3.<>31 3,750 3.737 3.59 9 3.439 '3~Z~O 3.376 3 .. 2~O
'S'/' 5.900 5,043 5.SQS 5,3~4 5~O~:! 5.024 4. '301 4.%3 4.340 4.4'53 4.237
77. 7~:~1 6.915 6 .. 842 6.490 6,142 6.097 ~ .. S03 '5.'S00 '5.216 5,344 5.070
9% 8,655 9,217 8.123 7,637 7.261 7.200 6,834 6 .. 463 6.116 6,264 '5.930
O. ACClIMlIL. ANN. COST al0(0)
2% 71.:na 80.933 ~t), 727 100.?62 111.209 lZ:?,~42 133.603 145.232 157,129 170.1"'2 193,'567
S?. 98.901 101.610 115.092 128,9:0 142.760 157,5'?3 172.759 193.133 203.380 221,112 ::39.656
7"1. 103.472 119.046 135.535 1'52.;:70 169.217 187.216 205,'549 2:;'4,133 ::43.001 263.631 284,673
9'Y. 11S.406 136.913 1'56.437 171:0.307 196.339 '=17,594 239.1$2 261,029 283.147 307.38B 331."'41
E. ACClIM!)l.ATEO PRESENT \.IORTH
ANNl'AL COST ($1000)
2% 46.229 50.358 '54.462 '59 .. 30;>3 62.143 6'5.$30 69.473 72.917 76.207 79,583 92.S13
'5'1. 55.S65 61 ,~O8 67,103 72.427 77.479 82.503 97.304 91.967 96.207 100.660 104.$'>7
7% 1>3.942 70,$57 77.0"9 84.189 90.331 96.428 102.231 107.731 112.947 118.291 1:3.361
9% 72.230 80,447 88.570 9th:51 103.513 110.713 117. '552 124.015 130.131 136·39'3 142.32'5
4-8
1990 1991 1992 1993 1994 1995 1996 1997 1993 1999 2000
F. ACCIJ/1 PRES WORtH OF ENERGY
MfLLS/YWH
27.-1,313 1.386 1 • 451 1,S07 1,556 1,601 1,641 1,676 1,708 .7'33 1,766
5'7. 1,533 1,632 1.120 1.796 1.862 1,922 1,975 2.022 2.06.4 .104 2.140
7Y. 1.720 1.842 1,950 2.042 2 .. 122 2.195 2.259 2.316 2.366 .414 2.,457
9'7. 1,914 2.059 2,187 2,~9b 2.390 2.476 2,551 2.617 2.676 ,732 2,7S2
I , If , , . , , , . , . , . , , , , I • f I f , , t , .
I "
PI)WEA CI)'3T ~T'JOY
INTERTIED ' SYSTEM -HYDRO -tow LOAD &.ELECTRIC HEAT ALTERNATIVE' 5-A
1979 t"O. t981 1982 1983 l"C t98'S 1986 1987 19$$ 1~
1. 1.01'0 DEMAND
tHiI'lA"O -I"W S.tes 15.479 ".770 6.060 6.3S1 6.642 6.9'32 7.223' 7.1513 7.e04 8.0<11'5
F.NEROV -rn.'H 22.140 24.:61 2'.821 27.393 28.9SS 30.$2' 32.090 a'.e64 es.989 92.090 ')1'5.214
2. SOIJRCn -KW
A. tUSTlNO DIESEl.
LOr.ATION OR UNIT 1 8.400 8.400 8.400 8.400 ..400 8.COO 8.400 8.400 e.400 8.400 8.400
2 1.661 1.661 1.661 1.661 10661 1.661 1.661 1.661 10661 1.661 1.661
3
4 ,
6 -7 ..
S
!t
10
U
12 .... -
8. ADDITIONAl. DIE'S!1.
UNIT 1 2.~ :2.300 2.300 2.300 2.300 2.300 2.300 2.300 2.300 2.300
:! 200 200 200 200 200 200 :00 ::00 :"" ::I
4
~
6
c. tUSTlNO HVtlRO
'JIll IT I
2'
O. AO!)tT10NAL HYDRO
IJNIT t 30.000 30.(100 30.000 ,0.OOQ
2
:l!
TOTAL CAPACITY -KW to.061 12.':61 t2.~~t J~ .. ~6t 12.'!!61 12.~61 12,'61 42.561 42.'61 42. !o61 4:,561
I.':\Rr..E~T I.IN I T 3.161 3.761 3.761 3.761 3.1~1 3.761 3,161 31.661 31.661 31.661 '31oM1
F IRl'I CAPACITY 6.300 • '3.60" 8.'300 e.soo 8.'300 $.soo $,,$00 10.900 10.900 10.900 10,"'00
'SI..IRF'Ut-; OR !!)EFICn) -)0.1 10 11: 3,1:1 3.0~·' : .. 740 ~.44~· 2.2'5:9 1.86$ 3.677 3.337 3.0<>6 :,9(';'
NET HYDRO CAPACITY -~WH ,. t~6.S0(! 1~6.S(lO \~6.$OO 1:6,$1,"1(\
NET Pt£SEL ~APACITY -M~H '5~.t$O "'.31t. ?:i".(I~S 77.('1$19 77,(113:3 "".O~$ "7,0013 9'5.4"'4 ~!:.4$.q 9'5 .. ~H~4 Q,,!:,,4$4
II f(';EL C.e:Ne:~ATtON -m./H ~2.740 ~4,,::61 :5.:;t~7 :T.~·:l3 ::~,<:)!:s 3(\ .. ~:S 3~.('I'·O
$lIl'lPLt.t1 I.~R tOE!" IC IT) -I'Iwl'/ 'l~.44a '5t, "7~ '1. :':(.1 4 .... 6-¢'S 4$: 1:::f.I 4( •• ', .. '3 4 4 ,?>6$ ?,.4$~ 05.4\$4 <:)'5,40.:1 <)".$,4301
5-A
1990 1991 1992 1993 1994 199~ 1996 1997 1999 1999 2000
1. LOAD DEMAND
DEMAND -1<\01 9.396 3.930 9.274 9.719 10.163 10.607 11. 0~1 11.49~ 11 .940 129384 12.929
ENERGY -MWH 99.316 102.099 10~.909 109.692 113.501 117.284 121.068 124.877 126.800 126.800 126.800
2. SOURCES -K\oI
A. EX ISTINO DIESEL
LOCA T I ON OR UN IT 1 8.400 9.400 8.400 8.400 8.400 9.400 8.400 9.400 9.400 9.400 9.400
2 1.661 1.661 1,661 1.661 1.661 1.661 1.661 1.6.61 1.661 1.661 1,6.61
:3
4
5
6
7
9
9
10
11
12
B. ADDITIONAL DIESEL
UNIT 1 2.300 2.300 2.300 2.300 2.300 2.300 2.300 2.300 2.300 2.300 2,,$00
2 200 200 200 200 200 200 200 200 200 200 200
:3 2,100 2.100 2,100 2.100 2,100 2.100
4 2,100
:5
6
C. EXISTING HYDRO
LIN IT 1
2
D. ADDITIONAL HYDRO
LIN IT 30.000 30.000 30.000 30.000 :30.000 30.000 30.000 30,000 30.000 30,000 30.000
2
3
TOTAL CAPACITY -K\oI 42.'561 42. '561 4::,~61 42.'561 42.561 44.661 44.661 44.661 44.661 44.661 4b.7bl
LARGEST UNIT 31.661 31.661 31.661 31.661 31.661 31,661 31.6601 31.6601 310661 31,661 31.661
FIRM CAPAC ITV 11).900 10.900 10.9 00 10.900 10.900 13.000 13.000 13.000 13.000 13,000 15.100
SURPLUS OR (OEFICIT ) -KW 2.:514 2,070 1.626 1. 181 737 2.393 1.949 1.:505 1.060 616 2 .. 272
NET HYDRO CAPAC lTV -MWH 126d:lOO 126.900 126.800 126.900 126.800 126,900 126.800 126.900 126,$00 126.800 126.800
NET DIESEL CAPACITV -MWH 95.484 95.484 9'5.494 95.494 95.484 113.990 113.990 113.390 113,830 113dS90 132.276
DIESEL GENERATION -MWH
~.lIRPLUS OR (DEFICIT) -MWH <>'5.484 9'5.484 9'5.494 95.494 9:5.484 113.890 113.880 113.990 113.980 113.880 132,Z76
t .. " , , , . , , ! , 1 'I!' , t , " . ,
" I , .. • •
5-A
1979 1990 1991 1992 1993 1984 1995 1996 1987 1988 1999
3. INVESTMENT COSTS ($1000)
1979 DOLLARS
A. EXISTING DIESEL 3.990 3.990 3.990 3.990 3.990 3.990 3.990 3.990 3.990 3.990 3.990
B. ADDITIONAL DIESEL
UNIT 1 2.001 2.001 2.001 2.001 2.001 2.001 2.001 2.001 2.001 2.001
2 174 174 174 174 174 174 174 174 174
3 -
4
'5
6
C. EX ISTING HYORO
O. ADDITIONAL HYDRO
UNtT 1 99.657 qq.6~7 99.657 99,6'!>7
2
:3
E. TRANSMISSION PLANT ADDITIONS
UNIT 1 3.100 3.100 3.100 3.100 '3.100 3.100 3.100 '3.100 J.I0.)
2 4. '::t.7 126 1'24 12~
F. TAXES PROD. PLANT
lNFLATED VALLIE'; '::5 46 50 !<4 59 63 "6 68 71 74 77
TOTAL ($1000)
1979 DOLLARS 3,99 0 5.9<>1 9,~65 9.26'5 9.265 9.265 q.2b~ 1 D. 189 109.04$ 109.046 10"',049
INFLATED VALLIES 3.990 6.1'51 9,970 9,970 9.970 9.970 9.970 17'5, 1 ~9 169.::!S'S 168.008 167.7'::'6
4. FIXED COST ($1000)
INFLATED VALUES
A. DEBT SERVICE
1. EXISTING 241 241 241 241 241 241 241 241 241 241 Z4t
" ADDITIONS L.
SUBTOTAL 2X 86 239 239 23q 2'39 239 6.345 6.571 6.560 6.'549
57-132 ::t65 365 ::t65 365 365 10.309 9.891 9.$74 9.857
7Y-167 462 462 462 462 462 13.217 12,688 12.667 12.64'5
97-204 '56'5 565 56S 565 56'5 11:>.194 15.546 15.5::0 1'5.4<>3
B. lNSliRANCE 12 20 35 38 41 44 46 835 834 966 90"
5-A
1979 1980 1981 1982 1983 1984 1985 1986 1987 1999 1999
TOTAL FtXED COST ($1 """)
2'Y. 278 393 'S6'S '572 'S90 587 '592 7.989 7.717 7.741 7.767
'57-278 439 691 699 706 713 718 11.453 11.037 11.055 11.075
77-278 474 789 79'S 803 810 91'5 14.361 13.934 13.848 13.863
97-278 511 991 99S 906 913 918 17.338 16.692 16.71)1 16.711
:5. PRODUCTION COST ('S1000)
INFLATED VALUES
A. OPERATION AND MAINT
1 • DIESEL 583 662 192 208 224 242 2'52 262 273 294 295
2. HYDRO 923 99'5 1.071 1.1'53
B. FUEL AND LUBE OIL 2.071 2.430 2.3~3 2. 74'S 3.194 3.703 4.126
TOTAL PRODUCTION COST (UOOO) 2.b54 :J.Q9Z 2.'54:5 2.953 3.419 3.94'5 4.378 1.18'5 1,268 1, 3'5~ 1.448
TOTAL ANNUAL COST ($1000)
2% 2.932 3.48'5 3.11Q 3.'52:5 3.998 4.'532 4.9'70 9.174 8.985 9.0"'6 9.215
57. 2 .. 932 3,'531 3.236 3.6'51 4.124 4.6:58 '5.096 lZ,63a 12.305 12.410 12'.5:3
77. 2.932 3.566 3.333 3.749 4.221 4.755 5. 193 15.546 1'5.102 15,203 15,311
97-2.932 3.603. 3.436 3.951 4.324 4.958 :5.296 18.'523 17.960 19.056 19.159
ENERGY REQUIREMENTS -MWH 22.740 24.261 2~,a27 27.393 29.959 30.525 32.090 95.864 98.999 92.090 Q5,216
MtLLS/KIJH
2% 129 144 120 129 139 148 155 107 101 99 97
'57-129 146 125 133 142 153 1'59 147 138 135 132
77-129 147 120 137 146 156 162 181 170 165 101
9Y. 129 149 133 141 149 159 165 216 :02 196 191
C. PRESENT \.IORTH
ANNUAL COST (SI000)
24 2,C;-;::::: 3 .. 257 2.716 2.877 3.050 3.231 3.312 '5.713 5.2:9 4,<>48 4.694
'57-2.Q32 3.800 2.926 2.990 3.146 3.321 3.396 7.S70 7.1~2 6.750 6.366
77-2 .. ~32 3.333 ~.911 3.0S9 372~O 3.390 3.460 9.681 8.7"'0 S~:b9 7t783
9y. :?,.932 3 .. 367 3.001 3.144 3 .. Z~9 3.464 3,529 11 .. 535 10.453 9.S:::1 0.231
O. ACCLIMUL. ANN. COST (UOOO)
2Y. 2,932 6.417 9.527 13.0S2 17,OSO 21.582 26,'552 3'5.726 44.711 53.907 63.022
SY. 2,932 6,463 9,699 13,3'50 17.474 22.132 27,229 39,366 52,171 64.531 77.104
7'1. 2,93~ 6.49 8 9.931 13. '579 17.800 22.555 27.748 43,294 58.3"'6 73.'599 99.910
97-2,932 6,'385 9.971 13.822 19.146 23.004 29.300 46.823 64.783 92,939 100,90 9
E. ACCUMULATED PRESENT \.IORTfol
ANNUAL COST (~1000)
2Y. 2,932 6.199 9.0 05 11.782 14.932 19.063 21,375 27.098 32,317 37.265 41.0 4'"
5Y. 2 .. 93:? 6~~'3Z 9.058 12.038 15.194 19.505 21.901 29.771 36.933 43,693 ~O,O49
77-2 .. Q3~ 6.26'3 9.176 12.235 15.455 19.945 22.:)05 31.986 40.776 49.045 56,8~9
97-2 .. 93:2 6,299 9.300 12.444 15.743 19.207 22.736 34.271 44, 7:~4 '54.'545 63.776
, t f , ¥ • f I f • 'I I , , '! , , . , , , • I l I
5-A
1979 19130 191'31 1982 1993 1904 190'5 198'; 1997 1900 198')
~. ACCUM PRES WORTH OF ENERGY
MILLsn:WH
27-129 264 '369 474 '579 6e'5 798 8'55 914 96S 1.017
'57-129 265 '374 493 591 700 806 99S 979 1.0'51 1. liS
71-129 266 379 491 602 713 921 934 1.033 1,123 I. 20'S
9% 129 268 384 499 613 726 936 971 1.099 \.196 1.293
5-A
1990 1991 1"'92 1993 \??4 19<>5 1996 1997 1998 1?99 2000
3. INVESTMENT COSTS (SI000)
1979 DOLLARS
A. EX ISTING DIESEL 3.990 3.990 3.990 3.990 3.990 3.990 3.990 3.990 3.990 3.990 3.990
B. ADDITIONAL DIESEL
UNIT 1 2.001 2.001 2.001 2.001 2.001 2.001 2.001 2.001 2.001 2.001 2.001
2 174 174 174 174 174 174 174 174 174 174 174
3 t .927 1,921 1.927 1.827 1.827 1,927
4 1.827
5
6
C. EX ISitNO HYDRO
D. ADDITIONAL HYDRO
LIN IT 1 99.657 99.657 99.6'57 9<>.657 99.6!1c7 99.657 99.657 99.657 99.657 99.657 q9.6~7
2
3
. E. TRANSMISSION PLANT ADDITIONS
UNlT 1 3.100 3.100 3.100 3.100 3.100 3.100 3.100 3.100 3.100 3.100 3.100
2 124 134 136 134 136 134 134 136 1::;14 136 134
F. TAXE'S PROD. PLANT
INFLATED VALUES 90 93 123 128 133 138 144 1~~ 201 209 218
TOTAL (SIOOO)
1979 DOLLARS 109.046 109.056 109.059 109.056 109.0'58 110.833 110.883 110.885 110.883 110,985 112.710
INFLATED VAL,-IES 167.426 167.138 16b,S2:::! 166.486 166.144 169.913 169.704 169.4"'2 169,262 169.032 17'3.811
4. FIXED COST (.,1000)
INFLATED VALUES
A. DEBT SERVICE
I. EXISTINO 241 241 Z41 :;.':41 241 ::::41 241 241 241 241 ::;41
2. ADDITIONS
SUBTOTAL 27, 6.:537 6.52:5 6.512 6.499 6.485 6.6::;16 6.629 6.620 6.611 6.602 6.793
57-9.839 9'1921 9 .. $02 9.781 9.760 9.990 9.977 9.964 9.950 9,936 10t~29
77-12.622 12, bO('I 1::::,576 12.550 12,524 12.81~ 12,799 12.783 12.765 12.747 13.116
97-15.465 15.439 15.408 15.376 15.344 15.701 15.6S1 15,661 15.639 1~;,617 16.069
B. INSURANCe: 934 970 1.006 1,045 1.094 1.153 1.198 1,~44 1.292 1.342 1.43'5
• , , " , t 11 f I f .. f , , I 1
5-A
1990 1991 1992 1993 1994 1995 1996 1997 1999 1999 :2000
TOTAL FIXEO COST (UOOO 1
2Y. 7.7<)2 7.!H9 7.992 7.913 7.943 9.169 8.211 l'!.260 8.34'5 8.394 e.687
5Y. 11.094 11.115 11.172 11. 19'5 11.218 11,522 11.560 11.604 11.694 11.729 t 2,122
7% 13.a77 13.894 13.946 13.964 13.982 14.347 14.392 14.423 14.499 14.'539 1'5,010
9Y. 16.720 16.732 16.778 16.790 16.802 17.233 17.264 17.301 17.373 17.409 17.963
5. PRODUCTION COST ($1000)
INFLATED VALUES
A. OPERATION AND MAINT
I • DIESEL 307 319 412 429 446 464 492 502 522 . 542 564
2. HYDRO 1.239 1.336 1,442 1.554 1.670 1.796 1.929 2.067 2.193 2.270 2.361
B. FOEL AND LUElE OIL
TOTAL PRODUCTION COST ("1000) 1.545 1, b'3~ 1.854 1.993 2.116 2,260 2.411 2.'569 2.705 2.S1:! 2t9~S
TOTAL ANNUAL COST ($10001
2Y. 9.337 9.474 9.736 9.996 10.059 10.429 10.622 10,929 11.050 11.200 11.612
~y. 12.639 12.770 13.026 13.179 13.334 13.792 13.971 14.\73 14.389 14.'540 15.047 n. 1'5.422 15.'549 15,800 15.947 16. ~)99 16,607 16,793 16.992 17.204 17.3'51 17,93'5
9'Y. 18,26'5 18.387 19.632 18.773 18.919 19.493 19.675 19.570 20.079 20,221 '20.899
ENERGY REClUIREMENTS -MWH 98.316 102.099 105.909 109.692 113.'501 117.284 121.0613 124.877 126.900 126.900 126.8(10
MiLLS/KWH
2Y.. 95 93 92 90 99 99 a7 87 S8 9:-
51.. 129 125 123 120 117 118 11 ' 113 113 115 II"
n 157 152 149 145 142 142 1'3" 136 136 137 141
9'Y. 186 ISO 176 171 167 166 163 159 15S 159 165
C. PRESENT WORTH
ANNUAL COST ('SIOOO)
2% 4.436 4,207 4.040 3.939 3.646 3.532 3.363 3,204 3.055 2.896 2.'904
SX 6.005 '5.670 5.40'5 5, 111 4.833 4,668 4,423 4.193 3.979 3,7'57 3.634
7"1. 7,327 6,9')4 6.556 6.185 5,835 S,62S 5,316 5,027 4,757 4.484 4~ 332
9"1. 8.67$ 8.164 7,7:'32 1,290 6,857 6,603 6,229 5~879 C' e'C"'" -" ",,'-'~ 5,::'5 ~.O45
O. ACCUMLIL. ANN. COST ('101000)
2~ 72,359 81.8'33 91,569 101.465 111,524 121,~52 132,574 143,403 154,4'53 165,659 1779271
5% 89,743 102.513 115,539 128,717 142.0'51 1'55,8:33 169.804 183.977 19S,366 212.906 2:!7,95J
77.. 104.332 119,8SI 135.681 1'51.628 167,726 184.333 201.126 21S,118 235~32:2 ~S2.673 270.608
97-119.263 137,650 156.:82 17'3.0'!'5 193,973 213.466 233.141 253,011 273.089 293,310 314.1"8
E. ACCI)MULATED ?RESENT WORTH
ANNUAL COST (~10~)0 )
Z% 46.:385 50,5"'2 54.632 58.470 62,116 6'5.648 69.011 72.2t5 7'5,"270 79.166 80.'770
57. :;0,054 61,724 67.129 72.240 77,073 81,741 86,164 90.357 94.336 "S,0<>3 1 01.7:7
71. 64. 1'5'5 71.059 77.615 9:3.800 89,635 "'5.260 100.576 10'5.603 110,360 114.844 119.176
9Y. 12,454 80.618 88,3'50 9'5.630 102,487 109.090 115.319 121·198 126.750 131.975 137.020
5-A
1990 1-;)'r) 1 1":,,92 1'7"3 1 ':'''4 l~':t-:. 1""'6 19';>7 1 '?';/!3 199';> :'i)(ll)
F. ACCI.lM PRE'; f,J(!I"TH ('F ENERGY
MILL';/'WH
21.. t,062 1,103 1.141 1.176 1.2t:'18 1.~38 1.266 1. 29~ 1. :316 1 ~ 339 1 • ·3·~· t
5:~ 1.179 1,235 1.Z86 I. '313 1.375 1.41'5 1.45\ 1.494 1 t 515 1.545 1.574
7" " 1.280 1.347 1.409 1,,41:.'5 1.516 1,"564 111 60!3 1'164$ 1,686 1.721 1,75i1)
9~~ 1.381 1. 4L, 1 1.'534 1.60('1 1.6,(:,1 1.717 1.769 1.316 1.860 1, "01 1.9 41
f , . , , , , , , , .. , , .. , , , , , . , .. I I
PQWER CO';T ,)l"uoy
INTERTIED SYSTEM -HYDRO -HIGH LOAD & ELECTRIC HEAT ALTERNf,TI'lE 5-B
1979 19BO 1991 1'?S2 1993 19134 1<;1:3'5 1936 1997 19'5'3 1"'39
1 • LOAD DEMAND
DEMAND -I<I.l '5.1138 '5.479 'S.9~2 6.4a~ !:..9BS 79492 7,~95 S.4~S 9.001 9,S04 10.007
ENERGY -I1I.lH 22.740 24.2!:.1 26,:330 29,40Q 31.970 34.'340 37.109 91.987 96.016 100.120 1(>4.:::49
z. SOURCES -KI.l
A. F.:XISTINO DIESEL
Lr)CATlON OR UNIT 9.400 13.400 9.400 13.41)0 '3.4<)0 8.400 13.400 3.400 8.400 13.400 9.400
Z 1.661 1.661 1.661 1.661 1.661 1.661 1.661 1 • o!:>6 1 1.661 1.6(,·1 1.661
3
4
'5
6
7
S
<;I
10
11
12
B. AOlHTIONAL DIESEL
UNIT 1 2,500 2.'500 2.500 2.500 2~~OO 2.500 2.5"0 2.5(1) 2,500 2.'51)1)
2
3
4 .--' 6
Cw EX 1ST I N() HYDRO
UNIT 1
2
D. ADDITIONAL HV[)RO
',IN I T 1 -)Ot ('u)!) '30,O(H) 30, l)(lO 30,t:'lOO
:2
:3
TOTAL CAPACITY -~:I.l 10.01.>1 1~,S61 1'::.'561 1~,5!.:d 1:.5/.·1 12,4)61 12.'561 4~,561 42.'561 4:? .. '561 42.':.61
LAR(·EST UNIT 3.7/,1 3.761 3.761 3.761 3.761 3.761 3.7(·1 31.661 31,61:01 :) 1.6'·1 -31" ,~~ ... 1
FIRM CAPAI:ITY 6,3(\(' 5,8(H) S·81)1) S~ 800 13. :3<:11) 8.800 ~:t" 3(H) lO",-==>()('! 10,900 10, '?(H) 10, ~I)O
';URPLUS OR (DEFICIT) -KI.l 1.112 3.3:::1 2·818 :2."315 1., 81:-1,3(')$ SO'S ~, 4(l2' 1, sqQ 1, ]"':>·S e':='J
NET HYDRO CAPAI= I TV -MWH 1 :( ... , ;?00 1':6, :301) 1 ~·S, :J(H) 1:6 ~ snl)
N~T DIESEL (APACITV -~WH 55. IS::: 77,088 77.0'=::3 77. ('1'3:~ 77.088-77. O:3:~ 77.0,38 '''5.4'".; .':)~. 4~::4 °5.4."::4 ':J'5~ 4"34
[l!E'?EL (·ENEPAT ION -M~H ~::,14t) 24. :~'1 :.~. ~3:,O ::;Q~4(j() 31., '"'}7t) 34. -:,.~(1 2:7.1(1';:'
:?,'-'f'; PL' J'~ r)R ([lEF !I~! Tl -HWH ~·~.448: 52 .. !::'27 ~·O 1 ::-'5:j 47.1_,8:3 45, t 1':.: 4~,':.4~3 :'">. '4;"") '7J5.4:34 '''/5,4:?4 ·':)5 ~ 4;~4 -:.'5" 4::<4
5-B
1990 1991 1992 1993 1994 199'5 1996 1997 1993 1999 2000
1. LOAD DEMAND
DEMAND -KW 10. '511 11.949 13.396 14.923 16.261 17.699 19.136 20.574 22,012 23.449 24,:337
ENERGV -M\.JH 108.3'53 116.799 125,270 126,900 126.900 126.800 126.600 126.900 126,900 126.900 126.900
2. SOURCES -KW
A. EX ISTING DIESEL
LOCATION OR UNIT 8.400 8.400 9.400 9.400 8.400 9.400 8.400 9.400 9.400 9.400 9.400
2 1.661 1.661 1.661 1.661. 1.661 1.661 1.661 1.661 1.661 1.6';1 1.661
3
4
5
6
7
9
9'
10
11
12
9. ADDITIONAL DIESEL
UNIT 1 2.500 2.500 2.'500 2.500 2.500 2.500 2.'500 2.'500 2.500 2,~OO 2,500
2 2.600 2.600 2.600 2.600 2,600 2.600 2.600 2.600 2.600 2.600 2,600
3 5.000 5.000 5.000 5.000 5.000 5.000 5.000 5.000 5.000
4 5.000 5.000 5.000 5.000 5.000 '5.000
5 5.000 '5.000
6
C. EXISTING HVDRO
UNIT 1
2
D. ADDITIONAL HVDRO
UNIT 1 30.000 30.000 30.000 30.000 30.000 30.000 30.000 30.000 30.000 30.000 30.000
2
3
TOTAL CAPACITY -KW 45.161 45.161 50.161 50.161 '50.161 '5'5.161 '5'5. 161 '5'5.161 '5'5.161 60.161 60.161
LARGEST UNIT 31.661 31.661 31.661 31.661 31.661 31.661 31.661 31.661 31.661 31.661 31.661
FIRM CAPACITY 13.'500 13.'500 18,'500 18.'500 18.'500 23,~OO 23.'500 23.500 23,~OO 29.500 29.'500
SVRPLUS OR (DEFICIT ) -KW 2.989 1.552 5.114 3.677 2.239 5.601 4.364 2,926 1.499 5,O~1 3.613
NET HVDRO CAPACITY -MWH 126.900 126.800 126.600 126.800 126.900 126.900 126.800 126.800 126.800 126.800 126,900
NET DIESEL CAPACITY -MWH 119.260 119.260 162.060 162.060 162.060 20'5.960 205.960 205.860 205.$60 249.660 249.660
DIESEL GENERATION -MWH
SURPLUS OR (DEFICIT) -MWH 119.260 119.260 162.060 162.060 162.060 205,860 20'5.960 205.860 205.860 249,660 249,660
I I
5-B
1979 1980 1991 1982 1993 1984 198'5 1986 1997 1989 1989
3. INVESTMENT COSTS (UOOO)
1979 DOLLARS
A,' EX ISTING DIESEL 3.990 3.990 3.990 3.990 3.990 3.990 3.990 3.990 3.990 3.990 3.<>90
9. ADDITIONAL DIESEL
UNIT 2.17!5 2.175 2.17~ 2.173 2.175 2.173 2.175 2.175 2.175 2.17'3
:2
3
4
5
b
C. EXISTING HVDRO
D. ADDITIONAL HYDRO
UNIT 1 99.b57 99.b'S7 <)9.657 99t6~7
2
3
E. TRANSMISSION PLANT ADDITIONS
UNIT 1 3.100 3.100 3.100 3.100 3.100 3.100 3.100 3.100 3.100
2 4,'267 126 124 126
F. TAXES PROD. PLANT
INFLATED VALl'ES 2'3 '31 5'3 59 64 b9 -., ,-75 79 1'::0 12'3
TOTAL ($1000)
1979 DOLLARS 3,9~O 6.16'.5 ~.26'5 9.265 9.26'5 9,26~ 9t26~ 113.189 109.048 109 .046 !OQ,04:3
I NFLATED VALUE'; 3.990 6.3:"-' 9,955 9.9'55 9. ','5'5 9,,955 9.955 17'5.114 169.270 167,9'~3 167.711
4. FIXED COST ($1000)
INFLATED VALUES
A. DEST SERVICE
1-EX ISTINQ 241 241 241 241 241 241 :;:':41 241 241 241 241
2. ADDITIONS
SUBTOTAL 2h 94 239 239 239 239 23~ 6.845 6.':171 6.560 6,~4~
'5'): 143 364 364 364 364 364 10.308 9.890 9.973 Q,S~6
7"!. 181 460 460 460 460 460 13.215 12.696 12.665 1:.643
9'): ...... ., "'--'564 564 '564 564 564 16.193 15.545 lS,~19 15 .. 4 Q :::!
B. INSURANCE 12 21 35 38 41 44 46 835 834 866 9"'9
,
TOTAL FIXED COST ($10001
2Y.
~y.
7Y.
9Y.
~. PRODUCTION COST (SI000)
INFLATED VALUES
A. OPERATION AND MA!NT
1. DIESEL
2. HYDRO
B. FUEL AND LUBE OIL
TOTAL PRODUCTION COST (SI000)
TOTAL ANNLIAL COST (SI000)
2Y.
~y.
7Y.
9%
ENERGY REQI.HREMENTS -M\.IH
M!LLS/Jo:\.IH
2%
5Y.
7'Y.
9Y.
C. PRESENT \.IORTH
ANNLIAL COST (SlOOO)
2};'
5Y.
7Yo
9:>:'
D. ACCUMLIL. ANN. CO'3:T (s1000)
2"-
'5%
7Yo
9%
Eo ACCUMULATEO PRESENT \.IORTH
ANNUAL COST (S10001
~4
'5Y..
7:1.
97.
f • "
1979
278
279
279
2713
'5133
2.6'54
2.932
2.932
2.932
2.932
129
129
1:?9
12~
2.932
2.932
2.932
2.93:
2,932
2,932
2.932
2,,932
2.932
2,932
2.932
2.932
, .
1990
407
456
494
53S
662
3,092
3.499
3.'543
3.'536
3.627
144
141.>
148
149
3.270
3.:316
3.3'51
3.39(1
6.431
6.490
6.'518
6.'5'59
6.202
6.248
6,,283
6 .. 322
, ,
19131
'570
69'5
791
9<;>5
192
2.637
3.207
3.332
3.428
3.~32
26.830
120
124
128
132
2.801
~.910
2.994
3.085
9.639
9.$12
9.946
10.091
9.0t13
9.1'59
9.277
9.407
I •
1982
'577
702
79$
902
208
2,947
3. 15'3
3.732
3.9'57
3.9~3
4.057
29.400
127
131
134
138
3.046
3.148
3.227
3.312
13.370
13.669
13.999
14. 148
12.049
12.306
12.504
12.719
, .
19133
~8~
710
SOl,
910
224
3.749
4.334
4.4'59
4.5~'5
4.6'59
31.970
136
139
142
146
3,306
3.402
3.47'5
3.554
17.704
113.12$
18.4'54
IS.807
1'5.3'55
15.708
1'5.979
16.273
" ,
1984
59'3
719
314
919
242
4.190
4.432
5.025
5.150
~.246
~.3'50
34.'540
14~
149
1~2
155
3.5S3
3,672
3.740
3.814
22 .. 729
23.278
23.700
24.1:57
19.933
19.3(10
19.719
20.097
, .
193'5
599
723
819
923
4.772
5 .. 024
5 .. 622
'5.747
5.1343
'5.947
37.109
151
155
157
160
3.74b
3·829
3.893
3.963
::8.351
29.0::-S
':9.543
30.104
:::2,684
23.209
23,612
24.0'50
" ,
1986
7.996
11.4~9
14.31,6
17.344
262
988
~,24b
12.709
15.616
18.594
91.897
101
13:3
170
202
5.7~S
7.915
9.725
11.579
~7,S97
41.734
4'5.159
49.699
29 .. 442
31.124
33.337
3'5.629
1997
7.7'24
11.043
13,339
16.699
273
1,074
1,347
9.071
12.390
1'5,196
19,045
94
129
159
199
5.,279
7 .. ~11
8.838
10.502
46.668
54,1:4
60.345
66.743
33.721
39.335
42.175
46,131
1988
7.797
11.100
13,892
16.746
294
1-165
1.449
9.236
12,,549
15.341
19.19'5
100.120
92
125
153
192
5,,024
6.926
9.344
9.997
'55.904
66.673
75.68b
84.933
39,74'5
4'5.161
'50.:519
'56.023
1989
7.814
11.121
13.909
16.757
29'5
1'1'262
1.557
9.371
12.678
15.46'5
19.314
104.249
90
148
176
4.764
6.445
7.862
9.310
b5 .. 275
79,351
91! 1'51
103 .. 25.::
43,509
'51.606
59.391
65.339
, .
5-B
I , If 1
5-B
1979 1990 1991 1?S2 1983 1?84 198:5 1984 1997 1999 1989
F. ACCUM PRES WORTH OF ENERGY
MILLS/KWH
2~ 129 2604 369 473 :577 690 7131 844 899 949 99:5
:!Iy. 129 26:5 373 480 584 692 79:5 SSt 9:56 1.024 1.096
7Z 129 267 379 483 596 704 e09 915 1.007 1.090 1.165
97-129 2608 393 4960 607 718 S2:!1 9:51 1.060 1.159 1.248
5-B
1990 1991 1992 199:3 1994 199~ 1996 1997 1999 1999 2000
3. INVESTMENT COSTS (S 1000)
1979 DOLLARS
A. EXISTING DIESEL 3.990 3.990 3.990 3.990 3.990 3.990 3.990 3.990 3.990 3.990 3.990
9. ADDITIONAL DIESEL
UNIT 1 2.175 2.17~ 2~115 2.175 2.175 2,175 2.175 2.175 2.175 2.17~ 2.17~
2 2.262 2~Z62 2.262 2.262 2.262 2,262 2,262 2.262 2.262 2.262 2,262
3 4.3~0 4,35t) 4.350 4.3:50 4.350 4.350 4.350 4.3'50 4,3~O
4 4.3~0 4.3'50 4.350 4.350 4.3~0 4.350
5 4.3'50 4,350
6
C. EXISTING HYDRO
D. ADDITIONAL HYDRO
UNIT 1 99.6'57 99.6'57 99.657 99.657 99.657 99.6'57 99.657 99.6'57 99.6'57 99.657 99.657
2
3
E. TRANSMISSION PLANT ADDITIONS
UNIT 1 3.100 3.100 3.100 3.100 3.100 3.100 3.100 3.100 3.100 3.100 3.100
2 124 134 136 134 136 134 134 136 134 136 134
F. TAXES PROD. PLANT
INFLATED VALUES 130 178 lS5 Z41 250 260 270 280 292 345 3'59
TOTAL ('11000)
1979 DOLLARS 111.308 111.318 115.670 11'5.669 115.670 120.019 I::W.019 120.020 120.018 124. :370 124.368
INFLATED VALUES 171.617 171.49~ ISO. 103 180.0'?9 lS0.103 189.938 199.938 189.943 189.938 201 t 454 201.448
4. FIXED COST (101000)
INFLATED VALUES
A. DEBT SERVICE
1-EXISTING 241 Z41 ::::41 241 241 241 241 241 241 241 241
2. ADDITIONS
SUBTOTAL 2Y. 6.705 ~" 700 7.044 7.044 7.044 7.437 7.437 7,437 7.437 7.898 7.898
5X 10.09~ 10.083 10.614 10.614 10.614 11.215 11.21~ 11.21'5 11.21~ 11.918 11.918
7X 12.945 12.931> 13.601 13.601 13.601 14.361 14.361 14.361 14,361 1'5.2~0 1'5.250
91. 15.862 15.8'51 16.665 16.66~ 16.665 17.596 17,5'?6 17.596 17.596 18.686 18.685
B. INSURANCE 9:57 995 1.096 1,130 1. 175 1.299 1.340 1.3<:14 1. 'ISO 1,59'" 1.663
, I .. . , , , . r •
5-B
1990 1991 1992 1993 1994 1995 1990. 1997 1999 1999 2000
TOTAL FIXED COST ("1000)
27-8.033 8.114 8.550. a~b~6 8.710 9,227 9.288 9.352 9.420 10.083 10.10.1
57-11.423 11.502 12.120. 12,226 12.280 13.00'5 13.066 13.130 13.198 14.103 14.181
77-14.273 14.350 15.113 15.213 15.267 16.1'S1 16.212 16.276 16.344 17.435 17.513
97-17.190 17.265 180177 18.277 18.331 19.380. 19.447 19.511 19.'579 20.871 20.948
5. PRODUCTl ON COST ( .. tOOO)
INFLATED VALUES
A. OPERATION AND MAINT
1. DIESEL 307 396 412 429 446 .464 576 599 623 b4S 0.74
2. HYDRO 1.365 1.529 1.705 1.794 1.866 1.941 2.018 2,099 2.183 2.270 2.361
B. FUEL AND LUBE OIL
TOTAL PRODUCTION COST ($1000) 1.672 1.925 2.117 2~223 2,312 2.405 2,594 2.698 2.806 2.918 3.035
TOTAL ANNUAL COST (stOOO)
27-9.705 10.039 10.673 10.879 11.022 11.632 11.882 12.050 12,,226 13.001 13.196
5~ 13.095 13.427 14.243 14.449 14.592 IS.410 15.660 15.828 16.004 17.021 17.216
77-15.945 16.275 17.230 17.436 17.579 18.556 18.806 18.974 19.150 20.353 20.548
97-18.862 19.190 20.294 20.500 20.643 21.791 22.041 22.209 22.385 23.789 23.983
ENERGY REQUIREMENTS -Mt..IH 108.353 116.799 125.270 126.800 126.800 126.600 126.800 126.800 126.800 126.800 126.800
MILLS/KWH
2Y. 90 86 85 86 87 92 94 95 96 103 104
Sr. 121 115 114 114 115 1~'" 124 125 126 134 136
7''1.. 147 139 138 138 139 146 148 1'50 1'51 161 lc-2 on. 174 164 lc-2 162 163 172 174 175 177 IS8 189
C. PRESENT t..IORTH
ANNUAL COST (SlOOO)
2r. 4.611 4,457 4,429 4,21"? 3.99~ 3.940 3,762 3,~6S 3.381 3.360 3.187
5% 6,221 '5.962 ~J910 '5.604 ~,:S9 5.220 4.9'58 4.683 4,425 4,,3,?Q 4.158
7'f. 7.'575 7,::6 7.1'5<) 6.762 6.371 b.~36 5.?53 5,614 '5,2'?5 5,2¢O 4.9c-3
9)(. 8.961 8.521 8,421 7.950 7.482 7.381 6.978 6.'571 6.190 6.148 5,792
O. ACCLIMlIL. ANN. COST (stOOO)
::2% 74.980 85.019 95.692 106.'571 117.593 129,,225 141.107 153.157 165.393 179.384 191.580
51-92.446 105.873 I~~" 116 134.'56'5 149.157 164.567 180.227 196.05S 212.059 229 .. 080 246.296
7Y. 107.096 123.371 140.601 158.<)37 175,616 194.172 21:";,,978 231.952 251,102 27104'55 292.003
<:>"t, 122.114 141.304 161.599 182.09:3 .202.741 2::::4,532 246.573 268,792 291.167 314.956 338.9J9
E. ACCUMULATED PRESENT \.IORTH
ANNUAL COST ($1000)
2% 48.120 52,577 57.006 61.2::::5 o~.2'~O 69.160 72,9~2 76.487 79.868 83.2~8 96.415
5:1. 57.827 c-3.789 69.699 75.303 SO. 592 8'5.612 90.770 -~5.4S3 99,878 104.277 108.43'5
7~ 65.956 73.182 80.332 97.094 9').46.5 99.7'51 10'5.704 111.318 116.613 121.873 1:26,$36
'04 74.299 82.820 9!. Z41 99.191 106·673 114.0'54 121.032 127.603 133.793 139.941 14'5,733
5-B
1990 1991 1992 1993 1994 1995 1996 1997 1999 1999 2000
F'. ACCUI1 PRES WORTH OF' EN ERG V
HILLS/KWH
2% 1.038 1.076 1.1 11 1.144 1.176 1.207 1.237 1.26'5 1.292 1.319 1.344
SY. 1.143 1.194 1.241 1.295 1.327 1.368 1.407 1.444 1.479 1.'514 1 f '547
n 1.235 1.297 1.3'54 1.408 1.4'5S 1.507 1,554 1,,598 1.640 1.682 1.721
9% 1.331 1.404 1.471 1. '534 1. '593 1.651 1.706 1,758 1.807 1 .. 856 1.902
l I . , , I I I , , , . , . , . " •• J • , f· ,
APPENDIX D
ENVIRONMENTAL AND OTHER COMMENTS
Appendix 0 -Bethel
APA012/S3
APPENDIX 0-1
LETTER FROM STATE OF ALASKA
DEPARTMENT OF FISH AND GAME
January 23, 1980
Robert W. Retherford Associates
P. O. Box 6410
Anchorage, Alaska 99502
Attention Dora L. Gropp, P.E.
Gentlemen:
3D RASPBERRY ROAD
ANCHORAGE 1f1512
Re: Assessment of Fish and Wildlife Impacts -Kisaralik Hydroelectric Development
A hydroelectric dam at the Kisaralik River Lower Falls (Golden Gate
Falls) would exclude forty-five to fifty (45-50) miles of mainstem
spawning habitat from use by king, chum, and silver salmon. Another
thirty (30) miles of spawning habitat in tributaries would be excluded
from use by chum salmon. Approximately 10,000 chums, 500 kings, and
unknown numbers of silver salmon spawn in the Kisaralik River and its
tributaries above the lower falls annually.
Lake trout, rainbow trout, Dolly Varden, and grayling are also present
and spawning and rearing habitats for these fishes would also be impacted.
In addition, the impoundment would inundate caribou, moose, wolf, wolverine,
grizzly bear, and black bear habitats. Numerous raptor nesting sites
along the Kisaralik River would probably be lost.
Of course, you understand that this assessment of impacts is only general
in nature. To precisely quantify numbers of fish and wildlife affected
would take additional studies as well as more specific design information.
In addition, the Fish and Wildlife Coordination Act requires that the
U.S. Fish and Wildlife Service be consulted along with the Alaska Department
of Fish and Game for the purpose of identifying and minimizing fish
and/or wildlife losses and providing for mitigation of losses.
In order to propose studies, make assessments, etc., the Department
requires ample lead time and the cooperation of the consultant or design
parties to supply us with ample background information. We expect that
you will furnish us with copies of your feasibility studies as they are
completed as well as any plans or specifications. We would also appreciate
a description of the schedule you are following in the process of development
of these sites.
Retherford Associates - 2 -
January 23, 1980
We expect to have cursory assessments for the rest of these sites prepared
shortly and will transmit them to you as they become available.
If you have any questions or comments, please feel free to contact us
(telephone 344-0541).
~J
Thomas J. Arminski
Habitat Biologist
Habitat Protection Section
..
..
..
.' ..
..
II!
..
•
U oited States Department of the Interior
BUREAU OF LAND MANAGEMENT
Anchorage District Offic~
Ms. Dora L. Gropp
Project Engineer
4700 East 72ud Avenue .
Anchorage, Alaska· 99507
Robert W. Retherford Associates
Arctic District of International
Engineering Co., Inc.
P.O. Box 6410
Anchorage, Alaska 99502
Dear Ms. Gropp:
--"'~
... ....-----"_.
IN REPL Y RE.:FER 1'0
1275/8351. 2
Your Reference:
9703-104
UJO
We offer the following comments on land status in response to your letter
of January 7, 1980, concerning the reconnaissance study for potential
hydroelectric power on the Kisaralik River.
The proposed location of the dam is on Federal land presently managed by
the Bureau of Land Management (BLM). Currently, this land is under with-
drawal under Section 204(e) of the Federal Land Policy and Management Act
(FLPMA). This is an emergency withdrawal invoked by Public Land Order
(PLO) 5654 on November 17, 1978, for a three year period to be included as
part of the proposed Yukon Delta National Wildlife Refuge. The Secretary
of the Interior, after determining an emergency existed, withdrew these
lands to protect resource values that would otherwise be lost with the
intent of preserving all options to the Congress pending the lands final
classification. The order withdrew all lands, subject to valid existing
rights, from settlement, sale, entry or selection under the operation of
the public land laws, withdrew all lands from the mining laws and from
selection under the Alaska Statehood Act. Although the withdrawal does
not specifically prohibit water resource development projects such as
hydroelectric dams, we feel that with the stated intent of the withdrawal,
environmental considerations and restrictions could possibly be prohibi-
tive. It is also our understanding that the Kisaralik River, among others,
is currently being considered for a Section 204(c) withdrawal under FLPMA.
This is a 20-year withdrawal and undoubtedly would be more restrictive and
would probably preclude a hydroelectric project. Further, the Kisaralik
River has been proposed in legislation in both the U.S. House of Represen-
tatives (HR-39) and the U.S. Senate (S-9) to be included into the Wild and
Scenic River system. If either bill would pass, the Kisaralik River would
be designated a Wild and Scenic River and the dam would be precluded. In
the event that neither of these bills would pass, and the Kisaralik River
should ultimately not be designated a Wild and Scenic River, and the
hydroelectric project became a bona fide proposal, it would still require
2
development of an environmental statement assessing potential wilderness,
threatened and endangered species, flood plains, wetlands, cultural re-
sources and other environmental criteria. Our personal knowledge of the
area indicates the Kisaralik River would probably meet the criteria for
wilderness designation.
The powerline from the dam to Bethel, Alaska, would be in the same situa-
tion as the dam as far as land status is concerned. About 32 miles north-
west (approximately the west boundary of T. 6 N., R. 66 W., Seward Meridian)
along the proposed line from the dam to Bethel, the land status changes to
a complex situation of Native selected and interim conveyed Native lands
interspersed with Native allotments.
We hope this provides you with the information you wanted concerning land
status and the compatibility of the project with this land status. We
would ask that you keep us informed of, and send us a copy of the recon-
naissance study you are preparing for the Alaska Power Authority on the
Kisaralik River.
Land status and other comments concerning the Lake Tazimina hydroelectric
development project will be provided by the Peninsula Resource Area under
a separate cover, since that is in their area of jurisdiction.
Sincerely yours,
Lou Waller
Area Manager
McGrath Resource Area
..
..
Ii<: ..
•
•
•
•
•
Appendix 0 -Bethel
APA012/S7
APPENDIX 0-2
LETTER FROM
UNITED STATES DEPARTMENT OF THE INTERTIOR
BUREAU OF LAND MANAGEMENT
,
Appendix 0 -Bethel
APA012/S9
APPENDIX D-3
LETTER FROM
CONGRESS OF THE UNITED STATES
HOUSE OF REPRESENTATIVES
DON YOUNG
CONCReSSMAN FOR ALL ALASKA
COMMITTEES:
INTERIOR AND INSULAR
AFFAIRS
MERCHANT MARINE AND
FISHERIES
QCongres£) of tbe ~lniteb ~tateS)
;FJOU~t of l\epusentatibes
m~binnton, ~.(t. 20515
February 19, 1980
.Hr. Art Kennedy
P.O. Box 3576 ECS
Anchorage, AK 9950J
Dcar Art:
WASHINGTON OFFICE
1210 LO~G¥,()IlTH eUIUlUiG
TELEPHONE 2Ql/22,·576S
DISTRICT OFFICES
F[O!Jl4L IlUJLOIHG 1\/10
u.s. COURT HOUSE
7!l1 C STIIEET:OOX l
ANtHOMC£. AlASI(" 99513
TUEfIlON[ SQ1,UI·~978
F[DERAL aUILOIHG. ROO!.! 212
10112111 "VENUE. 80x 10
f'''lml.~NKS. AUS!(A 99701
Tn [PHO'IE S\)7:4SG-69<19
'l'hank you for your letter regarding the ~:'!'();Josed
Kisaralik River power project. I hope that tl'.c followin~J
will be of help to you.
Currently, all of the Alaska lands bills pending
before the Congress include all or part of the Kisaralik
River in wildlife refuge status. Under 5.9, the upper
Kisaralik is included as part of the Bristol SAY study
ar~a. Under the Refuge Administration Act l construction
of power projects is allow~d at the discretion of the
secretary of the Inter ior. .~J:!.:~9h_t~~j~s dis.s:-.;_~t~ . .2~._
has not been used in th~ast, it appears that the pre-cea6·n-t-·wrrl-S9Q'ri-be setJut:..tL°·the apDrQY-ul Qr-t~LQr-_
L~k~·_.J2f:Q~ct:...._.:i~2'0diak. This can form the basis for
-rn-vestiga ting the-Rlsaralik proj ect.
Due to the uncertain status of the Alaska lands bills,
l/ I cannot predict whether this issue vlill be covered in
conference. Please keep in mind, however, that some
reservations about the Kisaralik project have been
expressed by fisheries managers due to the potential
impact on commercial fishing.
Please continue to keep me informed of your concerns
on this and other matters.
UY:rhm