HomeMy WebLinkAboutPreliminary Power Study Volume 1 1966ROBERT W. RETHERFORD ASSOCIATES
CONSULTING ENGINEERS
P. O. BOX 3008. EASTCHESTER BRANCH
TELEPHONE BR 8·4201
ANCHORAGE. ALASKA IIIIDOI
12 February 1966
Mr. Larry Famen, Manager
Homer Electric Association
Box 255
Homer, Alaska
Dear Sir:
Transmitted herewith are fifteen copies of the Preliminary Power Study with
recommendations concerning the solution of your problem of keeping pace
with the rapidly increasing demands for electrical energy throughout the
power system of the Homer Electric Association.
This report contains an extensive review and analysis of several Alternate
Plans. A large portion of the work has been spent in carefully reviewing
the Bradley Lake Hydro-electric Project which appears to offer the best
solution. The proposals for development of this project contained herein
are within the easy reach of the Homer Electric AssociationJs own needs.
The startling fact is, that by proceeding immediately with the engineering
work on such a project and following through with applications for permits,
licenses, construction funds, design and construction, the first section of
the project could be built barely in time to meet the need. Within 3 more
years a second 25,000 KW unit would be needed~
( would like to thank you and Jack Lunden for providing office space, maps,
transportation and encouragement for carrying forward the work of this re-
port. [have never encountered a more interesting or demanding set of pro-
jects that refused to be left uncounted. The intriguing possibilities for de-
velopment of the many sites studied were almost exasperating because of the
time each required to make sure noth ing important was bei'ng missed •.
I am now reasonably sure that the Kenai Peninsula area, contiguous to o(wrthin
your system boundary, has been well looked at and "found out" regarding
potential hydro sites. There are no doubt some possible projects that have
been missed or passed by as not worthy which may yet require further attention.
I believe this report is timely in spite of its long-time a-borning, and [
earnestly hope it provides the sound basis you need to move forward for addi-
tional power supply.
Sincere ly,
-a~,~
ROBERT W. RETHERFORD
dh
INTRODUCTION
This Preliminary Power Study was undertaken as a result of an agreement between the
Homer Electric Association and the Engineer dated November 10, 1964. The specific
purpose was to carry out an "investigation and study of the various possible methods of
power supply to serve the present and future requirements of the Owner most adequately
and economica Ily ••••. II It was further be I ieved by the Eng ineer that no broad study of
the possible power supply resources on the Kenai Peninsula had been made, and that one
must be made as a starting point for more definitely oriented studies of specific cases.
It was hoped that this study might provide something of that nature.
The existence of some hydro-sites was known and the gas, oil and coal fuels were re-
cognized, but no thorough review of possibiHties had been made. The time necessary
to do this 'NO rk was not certain --mostly because of intangible elements associated with
load growth and hydro-electric sHes-which m(ght warrant more than superficial review.
In 1965 developments on the Kenai Peninsula pointed to startling load growth possibilities
associated with the Cook Inlet Basin oil search and the Japanese interest in wood chips.
These possibilities combined and a new power requirements study was completed by REA
in August, 1965 which recognized the potential growth and provided the basis for a new
look at wholesale power requirements of a different magnitude. One project in particular
seemed worthy of another look --the Bradley Lake Hydro-electric Project. A field re-
connaissance and review of older cost estimates provided a boost in interest on the project
which deserved more careful consideration. The results of this somewhat deeper prelimi-
nary re-evaluation are included herein. This took quite a bit of time. In addition, 23
more potential hydro-electric sites were investigated --several of which had never been
listed in any accounting of sites with which the Engineer is acquainted.
Fuel generated energy has progressed through substantial changes in a very few years in
this area and now is a major challenger for the lion's share of all energy consumed in the
Cook Inlet Basin. Fuel prices are still in a state of difficult predictability and seem to
demand bargaining for their establishment.
This report then compares a variety of fuel generating plants and plans with the gravity-
powered, solar-energized hydro projects of the Kenai Peninsula.
-i-
TABLE OF CONTENTS
Volu~e No.1
ITEM PAGE NO.
Letter of Transmittal •..•••••••••••••••••••.•••••••..••••••••••.••••••••. frontispiece
Introduction . II ................ ., ................ ., ................ ., .. It .. go .......................................... ..
Table of Contents ••••.• 0 • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • i i
Index of Plates, Figures, Tables .. "" .... It .............. II 0 ............ II .................. .,................... iii
Summary and Recommendatio!1s u ............................ ,.., .. u .. .. .. .. .. .. .. .. .. .. .. .. • .. .. .. .. .. .. .. .. .. .. 1
Key Map --Power Study, Plate ~ .. III .......................... ., .. III .. ., ................ ., .... II .......... " .. .. 2
Part I Present System .... " ....... <6 ................ ., III '" .. " .... " .... ., .............. ., .... ., .. ell II ., II .. .. .. 1-1
Present Investment in Generation and Transmission •••.••• 0........ 1-2
Part II --System Electric Loads
Present and Future System •..•.••••••••. 0 • • • • • • • • • • • • • • • • • • • •• '11-1
Historical [)cJtc 0 eo ............................ II" ........ 0 .... .. .. .... ...... .... ............ ........ 11-2
Load Trends, Load Factor, etc .•••.•••.••.••••...•.•••••..•...• 1J ... 8
Part III --Wholesale Power Situation
Part IY --
Present Sources of Supply ••.•••••.• 0 •••••••••••••••••••••••••• III'-l
Kenai Peninsula Generation --Existing ••••••.•.•••••••••••.•••• 111-2
Cost of Purchased Power ••••••••••• 0 ••••••••••••••••••••••••• 111-3
Generation Requi remen ts Forecast 0 ••••••••••••••••••••••••••••• 111-4
Fuel Investigations
Coal "'., .. .,., ........ ., ...... Co ................ 0 .. &> ........ ., III ............................................ ..
Oi I •.••.••...•••.•••••••.•••••.•••••.•.••.•••••••.•••••••
Gas
Costs 0 •• " •••••••• " •••••••••• C> •••• " •• III • II •••••••••••••••••••
IY:"'l
IY-1
IY-2
IY-3
Part Y --Hydro-electric Potential of Area.............................. Y-l
Hydro-electric Sites --Kenai Peninsula, Plate II Y-4
Part YI --Alternate Plans
Unit Costs --Alternates Table 9 .••.•.••.• 0 ••••••••••••••••••• YI-2
Unit Costs --AI temates Table 9A ..•.•••••••.••••••••••••••••• YI-3
Demand-Capability Curves, Figure 14 •...•.••..••..•••••••.... YI-6
One Line Diagram!;, Alternates A, B, and C, Figure 15 •••••••... YI-7
14-Year Cost Projections, Alternate A •.••••••••••.•••.•••••••• YI-8
14-Year Cost Projections, Alternate B ••••••••••.•.•••••.•••••• YI-9
14-Year Cost Projections, Alternate C .••••••••••••••••••••••.. YI-10
14-Year Cash -C05~ Forecast ••••..•••••• 0 • • • • • • • • • • • • • • • • • • • •• YI-13
Appendix--A
Appendix --B
Appendix --C
Appendix --D
Appendix --E
Appendix --F
Appendix --G
Appendix --H
Appendix --I
Appendix --J
Yolume No.2
Agreement for Sale of Electric Power, etc. .•••••••••••••.• A
Month Iy Financial & Statistical Report, Year End 1964 •••••• B
Power Requirements Study, REA, August, 1965 ••••••••••••• C
Letter from Jujo Paper Company.......................... D
Existing Rates~ Natural Gas Fuel... •• . •• •••••••.••• ••••.• E
Construction & Operating Costs, Gas-Fired Generating Units. F
Characteristics, Costs, Selected Hydro Sites, Kenai Peninsula G
Alternate Schemes, Bradley Lake Project....... •• • •• •• • •• • H
Construction & Operating Costs, Substa. & Trans. Lines..... I
Depreciation Rates & Annual Depr. & Int. Costs, Gen. & Trans. J
Investments
-11-
ITEM
Plate I
Plate"
Plate III
Plate IV
Figure 1
Figure 2
Figure 3
Figure 4
Figure 5
Figure 6
Figure 7
Figure 8
Figure 9
Figure 10
Figure 11
Figure 12
Figure 13
Figure 14
Figure 15
Table 1
Table 2
Table 3
Table 4
Table 5
Table 6
Table 7
Table 8
Table 9
Table 9A
Table 10
Table 11
Table 12
Table 13
Table 14
INDEX OF PLATES, FIGURES, TABLES
Key Map, Power Study ••••••••••
Key Map, Hydro-electric Sites ••• 0 0
Key Map, Bradley Lake Project 0 0 •• 0
Alternate Schemes, Bradley Lake Project
. . . . .
o • 0
PAGE NO.
2
V-4
H-i
H-8
Kilowatthour Requirements Recorded and Projected II -3
Kilowatt Demand Recorded and Projected 0 • 0 ••• 0 • 0 • 0 0 " -4
Energy Distribution by Months 1962 and 1964 • 0 II -6
Energy Distribution by Months 1970 and 1975 ". " -7
Demand Projections HEA and CEA ••••• 00 ••• 0 II -9
Energy Projections HEA and CEA ••••• 0 • 0 11-10
Annua I Load Factor •••••••••••••• • 0 • • 11 -12
Swanson River Oil Field Production --Load Pattern. 1/ -14
Energy-Load and Load-Duration Curves, 66% L.F. • 11-15
Energy-Load and Load-Duration Curves, 72.5% L.F. • • • • • • /1-16
Energy-Load and Load-Duration Curves, 80% L.F •••• 0 • • • "-17
Refi nery Load Pattern. • • • • • • • • • • • • • 0 • • 0 II -18
Estimated KW Demand, Oil Drilling Platform • •• II -21
Demand-Capability Curves, Alternate Plans •• VI-6
Substation & Trans. Line, One Line Diagrams • VI-7
Historical Load Data 1950 --1964
Historical Load Data 1950 --1964
Maximum and Minimum Load Forecasts
Est. Demand for Oil Drilling Platform
. . . .
Est. Energy Requirements Oil Drilling Platform
Kenai Peninsula Generation --Existing .• 0 ••
• 0 •
Generation Requirements Forecast --Kenai Peninsula·
Hydro-e lectric Sites --Kenai Peninsula •• 0 ••••••
Unit Costs --Generating Plant Alternates --Kenai Peninsula· ••
Unit Costs --Generating Plant Alternates --Kenai Peninsula 0 ••
Alternate A --Bradley Lake Project 14-year Cost Projection
Supplement to Table 10-Effect of Interest Rates •.•.••.
Alternate B --Gas Turbines, 14-year Cost Projection
Alternate C --Gas Engines, 14-year Cost Projection
Supplement to Table 12 -Effect of Interest Rates· ••••
Investment & Production Costs Existing Generation --Kenai
Peninsula •••••••••••••••••.•••• -.
Alternate A --Bradley Lake plus Existing --14-year Cash
Cost Pro iection ••••••.•••••••••••• ill • •
-iii-
11-2
11-5
/I -8
/I -19
11-20
III -2
111-4
V-5
VI-2
VI-3
VI-8
VI-8
VI-9
VI-10
VI-lO
VI-12
VI-13
SUMMARY AND RECOMMENDATION
The Kenai Peninsula of Alaska is a fast-developing, wonderfully diverse land mass with
amazing qualities to draw the interest of many people. The petroleum development has
been the primary spur for industrial expansion. The famous hunting and fish ing has drawn
outdoorsmen for many years. The commercial fishery has long been active and is expanding
again. The beautiful scenery and milder climate of parts of the Peninsula are bringing men
from great distances to build homes for living and enjoying the country. It all adds up to a
good growth potential which will keep the "Kenai" rolling along on the amazing course it
has a I ready drawn.
The forecast of power requirements in this study incl udes an optimum and a minimum fore-
cast. The optimum prediction comes quite close to the average growth rate since 1950 which
is 40.30/0 for increases of energy usage and 36.2% for increasing demands. The minimum
forecast is one which is conservative and considered appropriate as a basis for considering the
expenditures of large sums of money.
The projects reviewed in this study include a group of thermal generating units and a large,
more diverse group of hydro-electric projects. Approximately 24 hydro sites were reviewed --
with interesting results. Part V of this report contains the data found. Projects reviewed
vary in size from about 1,500 KW to 125,000 KW --a broad range but necessary for proper
evaluation of hydro possibilities. These hydro-electric projects total 679,500 KW of potential
installed capacity which could produce 1,983,050,000 KWH of prime energy plus 553,637,000
KWH of secondary energy. The bus bar (at site) costs of this energy are estimated to range from
a high of 21.3 mills/KWH for prime energy to a low of 2.9 mills/KWH. It is further estimated
that of the total, about 597;000 KW would deliver an overall amount of 2,180,820,000 KWH
at bus bar for 6 or less mills/KWH, and about 190,000 KW would deliver an overall amount of
674,500,000 KWH at bus bar for about 3 or less mills per KWH. These estimates are based on
2% money and 5D-year project life and should be increased by about 16% for each 1% increase
InTnterest rates. Transmission cos ts to Kenai Peninsula load centers are about 1 mill/KWH or
less with minor exceptions. These figures show that the Kenai Peninsula could supply itself with
dependable, low cost hydro-electric energy for many years to come.
The most interesting project of all --the Bradley Lake Project --has been reviewed before but
the circumstances of much smaller loads on the Kenai at that time required that the feasibility
depended on the Anchorage area. Today this is not so --the Bradley Lake Project is within
reach of the Homer Electric Association~ The minimum load forecast shows a need for an in-
crease in ~nerating capacity avai lable to the Kenai Peninsula of about 46,000 KW in the
next 14 years. Almost 20,000 KW of new capacity (beyond all that is available on the
Peninsula) is needed in about 7 years.--.ne magnitude of needs has changed and a well-
balanced development based on !he largest hydro project of the Peninsula is a practicality~
Three Alternate Plans were considered in detail in Part VI of the report. The Bradley Lake
Project stands out clearly above all the alternates.
I
J
LEGEND
EXISTING GENERATING PLANT
PLANNED GENERATING PLANl
PROPOSED GENERATING PLANT
EXISTING SUBSTATION
PLANNED SUBSTATION
PROPOSED SUBSTATION
EXISTING 69 KV LINE
EXISTING 115 KV LINE
- - -PLANNED 69 KV TRANSMISSION LINE
_ _ _ PLANNED 138 KV TRANSMISSION LINE
•.••••••.••• _--PLANNED 25 KV DISTRIBUTION LINE
_ _ _ PROPOSEDt36 KV TRANSMISSION
- - -PROPOSED 69 KV TRANSMISSION LINE
••••••••• PROPOSED 34.5 KV SUBMARINE CABLE
............... _... FUTURE 25KV SUBMARINE CABLE
COOK INLET OIL FIELD PLATFORMS
HOMER ELECTRIC ASSOCIATION, INC.
HOMER, ALASKA
KEY MAP
POWER STUDY
CONSULTING ENGINEERS
ROBERT W. RETHERFORD ASSOC PLATE
ANCHORAGE, ALASKA .1
. by Date __
14-year investments considered for the various plans are:
ALternate A (Bradley Lake)
Alternate B (Gas Turbines)
Alternate C (Gas Engines)
GENERATION
$ 26, 308, 363
9,612,359
10, 151, 100
TRANSMISSION
$ 3,808,738
1,811,250
1,811,250
14-year charges for depreciation and interest and insurance and replacement are:
Alternate A (Bradley Lake)
Alternate B (Gas Turbine)
Alternate C (Gas Engines)
GENERATION
6,684,530
3,500, 182
2,657,581
14-year operationand maintenance costs compare as follows:
GENERATION
Alternate A $ 1,471,401
Alternate B 3,022,750
Alternate C 2,5(JJ,296
14-year average cost of power delivered:
Alternate A
Alternate B
Alternate C
5 J mi lis/KWH
8.9 mills/KWH
7.5 mills/KWH
TRANSMISSION
$ 367,515
300,027
300,027
TRANSMISSION
1,271,068
626,298
6261.298
FUEL COSTS
$ 344,230
4,899,570
4,207,594
Selecting Alternate A as the best solution and combining it with the existing facilities on
the Kenai Peninsula and analyzing the costs on a casll basis the following results derive:
14-year operation and maintenance costs are:
Existing Faci I ities
Alternate A
GENERATION
$12,359,000
7,585,000
TRANSMISSION
$ 3,027,000
1,505,000
14-year average cost of power generated by both:
Existing Facilities
Alternate A
Total
16.4 mills/KWH
5.3 mills/KWH
9.2 mills/KWH Ave. combined
The Bradley Lake Project is clearly the most beneficial of the alternates studied.
3
~
In order that a reasonably accurate picture of the effect of increased interest rates might be
obtained, supplements to Tables 10 and 12 (Alternates A and C, 14-year cost projections)
have been prepared showing the effect oTincreased interest rates. From these supplements,
the graphs below have been prepared to show the effect over the 14-year period.
30
25
~ -!--
.L
I
I
I \,---
\
.-\ .-;.!~ I;.
..J 1-yt
i
70
30
25 -
10
5
70
AVERAGE POWER COST
with
2% INTEREST
;> -
30 I---+--~
25 1---+--+-
I 20 1----'-+--1---1-
3=
~
~ 15 I----;---'+---I-~
-l
AVERAGE POWER COST
with
3% INTEREST
___ __ t:;
72 74 76 78
YEAR
AVERAGE POWER COST
with
4% INTEREST
12 74 76 78
YEAR
___ oJ
80 70
30
25 I--+r---+
80
:c 20
3=
~
::;, 15
--l _J
~
lC
70
72 74 76 78
YEAR
AVERAGE POWER COST
with
72
5% INTEREST
74 76
YEAR
78
80
80
The graphs show that increased interest rates favor Alternate C and that at 5% interest the
14-year average cost of AlternateA and C are equal. It should be noted, however, that
the costs of Alternate A are decreasing somewhat faster than Alternate C which has almost
"leveled out." Over a longer period the costs of Alternate A would be less --even at 5%
interest.
The Chugach Electric Association is now proceeding with the Beluga Project and it is pro-
bable that they will have some surplus power available at thjs site. It could be beneficial
to the future planning for and supplying of power to both parties if a conference were held
with a view towards coordinating the possible developments on the Kenai Peninsula with
thoseon the opposite sides of Cook Inlet. It is believed that by the use of the trarn;mission
interconnection, reduction in reserve~ required on both sides of Cook Inlet could be accom-
pi ished as well as improving feasibi lity at both ends of such interconnection. For example,
at some future date, pumped-storage on the Kenai Peninsula could be supplied pumping energy
by the low-cost fuel in theBeluga area and the Kenai Peninsula pumped-storage unit could
then supply peaking energy to the Anchorage area.
Recommendati ons:
(1) It is strongly recommended that the HEA review the Bradley Lake Project as presented
here with the Corps of Engineers who made the original study with a view towards the
accomplishment of the project either as a cooperative financed project or as a Corps
of Engineer Project.
(2) It is recommended that you confer with the Chugach Electric Association with a view
towards establishing mutual benefits regarding a project development as reported herein
and in particular, with regard to the immediate needs of the Homer Electric Association.
(3) It is recommended further that as quickly' as is feasible to your operation that more in-
formation be secured regarding the better of the 24 hydro sites discussed in<the report,
such as, High Valley and Twin Lakes.
5
PART I
PRESENT SYSTEM
PART I
(A) AREA SERVE D.
The Homer Electric Association (HEA) service area boundary encloses approxi-
mately 6,500 square mi les of the Kenai Peninsula and the eastern half of Cook
Inlet in South Central Alaska. The service area is outlined on Plate I. Other
utilities operating within this service area include the City of Kenar,-
Consolidated Utilities (a privately financed generation entity), and the Chugach
Electric Association. The City of Kenai purchases power from Consolidated
Utilities for resale to its own municipal consumers. Consolidated Utilities gener-
ates with internal combustion engines using natural gas as a fuel. The Chugach
Electric Association (CEA) owns and operates the Bernice Lake Plant which gener-
ates electric energy and steam from a gas turbine-waste heater boiler combination
using a distillate oil from the Standard Oil Company Refinery as a fuel. CEA sells
wholesale power to HEA, process steam to the Standard Oil Company Refinery and
transmits the remaining energy via HEA and CEA transmission lines to Anchorage.
The Seldovia electric system on the southside of Kachemak Bay was purchased by
HEA in 1964. It is presently supplied energy from a small diesel-electric plant
in Seldovia. Surveys have been made and construction plans prepared for a line
extension from Seldovia northeast to Halibut Cove along Kachemak Bay. It is
probable that the Seldovia area load wi II eventually be served from Homer by
means of a submarine cable.
(B) DESCRIPTION OF EXISTING PHYSICAL PLANT.
(1) Generation: HEA has two generating plants both of which utilize
diesel engines as prime movers. One plant located in Homer is
used for standby purposes to pick up a part of the load if there
should be planned or emergency outages of the wholesale power
source supplied by CEA. The Homer plant has 1450 kilowatts of
generating capacity consisting of 2 --600 KW and 2 --125 KW
machines. The other generating plant which is in Seldovia has a
total nameplate capacity of 1300 KW made up of 1 --600 KW,
1 --300 KW, 1 --250 KW and 1 --150 KW machines. This
latter plant is the sole power source for the Seldovia area at this
time. In the future a probable interconnection with the main
HEA supply system will allow the Seldovia plant to go on standby
duty as backup protection for such interconnection.
(2) Transmission: The transmission system includes 60.5 miles of 69
RV line connecting CEAls Quartz Creek substation to HEAls
Kasilof substation. Another 24.5 miles of 69 KV line connects
the Bernice Lake generating plant to the system ata point 15.6
mi les north of Kasi lof. The town of Homer and the surrounding
load area is supplied from the Kasilof substation over a 24.9 KV
line which is about 63 miles long and serves consumers along the
way. This line will soon be used for distribution only since plans
are underway to extend the 69 KV system from Kasilof to Homer
and the Homer Spit.
1-1
(C) PRESENT INVESTMENT IN GEI'-IERATION AI'-ID TRANSMISSION FACILITIES.
The Homer generating plant and 69 KV transmission facilities are leased to Chugach
Electric Association who in turn is charged with their operation and maintenance in
accordance with the terms of the contract attached as Exh ibit A.
The total transmission and generation investment is $2,264,747 which includes the
facilities as listed below I "
HEA PRESENT GENERATION & TRANSMISSION INVESTM~NT
Homer Plant
land and land Rights
Structures and Improvements
Generation Equipment
Seldovia Plant
land and land Rights
Structures and Improvements
Generation Equipment
Quartz Creek -Kasilof Transmission Line
Bernice Lake Transmission Line
Kasilof Substation
Total
1-2
$ 8,032
74,528
458,822
$ 6,250
30,862
352,628
$ 541,382
389,740
860,916
378, 133
94,576
$ 2,264,747
PART II
SYSTEM ELECTRIC LOADS
PART II
SYSTEM ELECTRIC LOADS
(A) PRESENT SYSTEM.
HEA Electric System energy requirements from 1950 to 1964 inclusive are plotted
on Figure 1. A least squares curve of the exponential form y = ab x fitted to the
historicalsection of the curve indicates an average annual compounded increase
of 40.3 percent in energy requirements. HEA Electric System power demands from
1950 to 1964 are plotted on Figure 2. A similar rate of growth curve plotted to
fit the historical kilowatt demand Indicates an average of 36.2 percent annual
growth rate. (The two curves are plotted from the data contained in Table 1 and
Table 3 following). Both of these are high growth rates and are not used inthis
long range forecast. The expanding service area has been responsible for much
of the past growth and although much of the service area is still not served,
however, it appears that the remaining area will not repeat the unusual record
of the present system.
Kilowatthour sales by consumer type for the last calendar year of record (1964)
are included in the December, 1964 Monthly Financial and Statistical Report
included herewith as Appendix.!:
The existing mix of consumers with their respective energy requirements is likely
to undergo a drastic change within the next five years with the probability that
Homer Electric Association will become industry oriented rather than consumer
oriented. This situation is being brought about by the active expansion of
projects related to the oil industry.
Monthly kilowatt demand and energy requirements are listed in Table 2 beginning
with May, 1961 at which time Cooper Lake power became available-.-
Typical energy distribution data by months as a percentage of annual usage are
plotted from historical data of Figure 3 and are forecast for 1970 and 1975 on
Figure 4. This estimate of future energy usages will be used in evaluating
alternate generation schemes --particularly hydro-electric projects where storage
requirements are affected materially by the system energy use as well as run-off
from the watershed.
(B) FUTURE SYSTEM.
Energy and demand projections through 1975 have been included in Figures 1
and 2 along with the data of record beginning in 1950 for comparative purposes.
rhe major contribution to load growth in the immediate future wi II come from
the oil industry, and particularly from the drilling platforms which will be
located in Cook Inlet.
Two load projections are included in each of the above two Figures. The upper
one (optimum forecast) was made by Mr. Frank Coover of the REA Power
Requirements Branch in August, 1965; the lower one (minimum forecast) was
made by R. W. Retherford Associates. The latter projection was made for the
purpose of establishing a lower limit for consideration in the power study.
Supporting data for the higher projection is included in Appendix C, Power
Requirements Study, August, 1965. Table 2-compares the two prOjections.
11-1
TABLE I
HISTORICAL LOAD DATA -AI'.INUAL
Ki lowatthours Annual
Year Demand KW Generated Purchased Total Load Factor
1950 55
1951 1.10 232,830 232,830 0.242
1952 172 597,600 597,600 0.397
1953 200 797,400 797,400 0.455
1954 240 833,400 833,400 0.396
1955 305 1,325,797 1,325,797 0.496
1956 440 1,907,550 1,907,550 0.495
1957 875 3,292,500 3,292,500 0.430
1958 1280 5,372,940 5,372,940 0.480
1959 1400 6,711,200 6,711,200 0.547
1960 1740 7,902,781 7,902,781 0.519
1961 2232 3,618,840 7,467,600 11,085,440 0.567
1962 3072 13,072,873 13,072,873 0.485
1963 3858 18,682,000 18,682,000 0.553
1964 4292 21, 187, 120 21, 187, 120 0.564
11-2
1950
KILDWATrHOUR REQUIREMENTS ;;1
RECORDED 8 PROJECTED
1965 POWER STUDY
HOM ER ELECTRIC ASSOCIATION
by ROBERT W. RETHERFORD Assoc.
October 1, 1965
- - -Least Squares Appro<i mation 1950 -1964
-----0 Historical 1950 -1964 CSce Table 1)
~ _____ ~ REA PRS August 1965 lOptunum For,£ca~;tl-~-l
EJ------e Minimum F«ecast RW.REl);ERFORD ASSOC.
::::> z z
<{
2
2
1980
FIGURE 2
TABLE 2
HISTORICAL LOAD DATA BY MONTHS
HOMER
1961 1962 1963 1964 1965
KWHR KW KWHR KW KWHR KW KWHR KW KWHR KW --
Jan. 1,175,256 2400 1,596,960 3072 2, 115,360 3798 2,083,840 3867
Feb. 1,032, 165 2544 1,412,400 2794 1,702,960 4292 2,048,080 3720
Mar. 1,015,215 2064 1,514,160 2688 1,942,000 3460 1,879,040 3358
Apr. 1,023,683 1968 1,350, 160 2544 1,540,560 2902 1,799,280 3245
May 672,795 1464 1,008, 137 1848 1,222,240 2498* 1,643,440 2617
June 629,647 1296 971,011 1824 1,245,600 2360 T, 391,760 2514
July 716,779 1296 932,783 1848 1,292,640 2274 1,568,640 2686
Aug. 736,892 1368 991,626 1872 1,562,480 2916 1,715,440 2956
Sept. 791,880 1488 1,072,026 2184 1,756,640 3268 1,613,360 3088
Oct. 872,213 1656 1,175,923 2544 1,738,880 3334 1,751,440 3369
Nov. 1,075,250 1920 1,248,711 2928 1,926,000 3858 1,896,720 3458
Dec. 1, 146,247 2232 1,426,337 3072 2, 131,040 3727 2,305,440 4093
-
I 13,072,873 18,642,000 21, 187, 120 \TJ *Bernice Lake connected
SELDOVIA
KWHR KW KWHR KW
Jan. 118,581 270
Feb. 132,969 2.40
Mar. 106,421 250
Apr. 250
May 91,360 273
June 115,000 280
July 176,894 480
Aug. 138,542 450
Sept. 100,382 .r85-
Oct. 107, 154 200
Nov. 73,470 250
Dec. 108,374 285
911,176
6,
II
(j)
C
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12
10
II) 8
D::
J o
I
~ ~ o
--I 6
~
--I «
J z z « u. o 4
t-
Z
W
U
a:: w a..
2
1970 0/0
JAN 9.5
FEB 7.95
MAR 8.5
APR 7.55
MAY 7,75
JUN 7.00
JUL 725
AUG 7.85
SEP 7.9
OCT 8.65
NOV 9.3
DEC 10.8
total 100.0
o 0 1962 Without refinery
A A 1964 With ref1nery
-.: ______ Average of two years
FIGURE 3
ENERGY DISTRIBUTION BY MONTHS
AS A PERCENTAGE of TOTAL ANNUAL
,FOR 1962 a 1964 6THEIR AVERAGE
1965 POWER STUDY
HOM ER ELECTRIC ASSOCIATION
by ROBERT W. RETHERFORD Assoc.
October 1,1965
O~----~----+-----~---+-----+----~----~----+-----r---~~--~----~
JAN FEB MAR APR MAY I JUN JUL AUG SEP OCT NOV DEC
MONTH
NOTE: For background information only.
~
...J
"T1 -G> c
::0
ITI
~
~ 8
8
i ~ - 6 :.::
~
Z
Z
~
~ .. .-
Z
tj
~
2
1m2 ~
JAN ;.5
FEB B..2
MAR 8.8
APR 7.8
MAY 7.8 JUN 72.
JUl 7.5
AUG 7B SEP 7.;
OCT 8.7
NOV ;.0 DEC 9.8
total 100.0
1970 «l
1975 .. • •
FIGURE 4
ENERGY DJSTRJBUTIONBYMONTHS
AS A PERCENTAGE of TOTAL ANNUAL
FOR 1970 a 1975
1965 POWER STUDY
. HOMER ELECTRIC ASSOCIATION-
by ROBERT W RETHERFORD Assoc:.
October 1.1965
0~----~--~----+----+----4---~~--~----+----4----~----~--~
NOTE: Use the 1970 curve throughout, the difference is negJigable compared toprobableaccur.a~
(C)
TABLE 3
OPTIMUM & MINIMUM LOAD FORECASTS
KW Demand KWHR x 10 3
..QE!.. Min • Opt. Min.
1967 11,000 58,000
1970 29,800 17,500 186, 147 99,700
1975 44,200 33,700 280,846 197,600
Since HEA & CEA combined loads are presently supplied from power plants operated
by.C~A, there is i.ncluded information on these loads --,individually and combined.
This IS shown on Figures 5 and 6 where the forecasts have been extended another 10
years to 1985. The HEAminimum forecast was extended beyond 1975 by assuming
a 10 percent annual growth rate; the optimum forecast was projected by extending
the 1970-75 rate to 1985. The difference between the optimum and minimum HEA
forecasts is !argeLywashed out in the combined total because of the CEA requirements
which are substanfially the larger part of the total.
CEA's existing generating capability is indicated on Figure 5; this includes the
second gas turbine recently instal led at the International substation, which has a
maximum capability of 16,100 KW @ 400 F and 17,500 KW @ 200 F (limit). Addi-
tion of this second turbine gives a firm capability of 71,700 KW. Figure 5 shows
that approximately 100,000 kilowatts of generation must be added to the combined
HEA-CEA systems within the next 10 years.
DISCUSSION OF LOAD TREND~ LOAD FACTOR, DIVERSITY FACTOR, AND
SPEciAL LoAD cHARACTERlsTI S.
(1) Load Trends: It appears at the time of this writing that the future
growth pattern will reflect a definite trend towards industrialization
through expanded development of the oil industry. lhe discoveryof
oil in the Middle Ground Shoal area has led to planning and con-
struction by several oil companies of permanent drilling platforms
for recovering the oil. The power requirements for serving one of
these platforms can be considerable ~ince it is possible to drill 32
wells from one platform. The cost of providing space on such plat-
forms for generating power is one factor that has led to consider-
ation by the oil companies of purchasing power rather than using
self-generation. lhe economics of providing power by submarine
cable from the Kenai Peninsula has been analyzed in a preliminary
report which is now being considered by the oil companies. It
appears completely feasible for the amount of power presently esti-
mated.
The number of these platforms to be served ultimately depends on
how many new fields are discovered, which in turn is related to
! 1-8
4
1965 70
Bu.Rec.
K.A.P.P.
Cooper Lk..
~rnJce Lk.
Int. Sub.
NAMEPLATE
~,OOO KW Hydro
14,500 KW Stea m
15JOOO KW Hydro
7, 500 KW Gas TurbIne
28,000 KW GasTurbs.(2)
Total 74,OOOKW
ExIsting FIrm CapabIlity
1005 VgAR
10,200 KW
17,000 KW
18,000 KW
9,000 KW
35,000 KW
89,200 KW
17J SOO KW
71~ 700 KW ""II, "-' .
FIGURE 5
·g
~
o o o .....
x
. i 0
I or-
)(
..;
I
FIGURE 6
(2)
the exploration effort. The amount and location of land being
leased by the State of Alaska combined with the favorable
settlement of the "Tallman Case" will stimulate exploration
within the HEA service area.
The natural gas resource on the Kenai Peninsula could form the
basis for a natural gas liquefaction plant directed toward the
Japanese market. One of the major 01 I companies is presently
engaged in negotiations with Japanese interests for such a
plant.
The petrochemical industry wi II probably enter the picture with
the economics and marketing position becoming more favorable.
The Jujo Paper Company of Japan has been discussing and
negotiating for the establishment of a wood chip and lumber
mill in the Homer area.
The future load trend is toward industrialization on the Kenai
Peninsula.
Load Factor: The annual load factor for the system from 1951
to· "964 inclusive is plotted in Figure 70 There was a general
uptrend from 1951 to 1959. This increase in load factor to a
certain extent reflects the increase in diversity due to the
growth in number of consumers. The effect of diversity between
consumers decreases as the number of consumers increases;
consequently, its effect on load factor will be minimized as the
system grows. Industrial type loads with a high load factor will
have a noticeable effect at the present level of development.
Examples of th is type are the Standard Oi I Refinery and the
Swanson River 011 field loads. (The refinery had a 65.6 percent
load factor in 1964, the oil field load 71 percent). The growth
of these two loads contributed to the increase in system load factor
from 4805 percent in 1962 to 5604 percent in 19640
Future load growth related to the oi I industry wi II tend to increase
the sytem load factor above its present level. The chip mill
proposed by the Japanese for installation at Homer will have a
low load factor for the first year or two be'Cause of a single shift
operation. The load factor will increase proportionately as two
and three shift op~ration is adopted. Considering the nature of
the potential loads, which for the most part will be on for 24
hours a day, and their size compared to the existing demands,
it is expected that the load factor will continue to rise for the
next ten years. This is estimated as shown on Figure 2:
(3) Diversity: There would probably be no significant diversity
be"tWee"ri -fhe potential industrial loads during the peak load
period; consequently, the additional system capacity required
would very nearly match the sum of the individual demands.
(4) Special Load Characteristics: Since most of the future load
growth will be associated with the oil industry, a more detailed
" G> c
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"'-J
100
~
Z 80 w o
a:: w70
A.
a: GO g
u
: 50
a
§ «>
o
1950 1955 1960
YEAR
m MinImum FOrecast RWR Assoc.
~ REA PRS August 1Q65
FIGURE 7
-ANNUAL LOAD FACTOR
RECORDED & PROJECTED
1965 POWER STUDY
HOMER ELECTRIC ASSOCIATION
by ROBERT W. RETHERFORD ASSOCIATES
October 1, 1065
1965 1S>75
look' at the characteristics of that load type is included here.
Figure 8 is a plot of the month Iy energy, demand, and load
factor tor the Swanson River oi I field production. rhe average
month Iy load factor for 1964 was 82.5 percent compared to 71
percent for the annual. The annual load factor is lower than
the monthly load factor because of load growth. Two load
factor projections are incl uded on Figure 7, a maximum and a
minimum. As long as the 011 industry demand is increasing,
the lower projection would probably be the appropriate one
to use. If the growth should level off, the maximum pro-
jection would probably prevai I.
Approximate load duration curves have been prepared wh ich
would be applicable to the two conditions. Figure 9 assumes
an annual load factor of 66 percent and would be appropriate
for use with the minimum projections. The load factor for
Figure lOis 72.5 percent which would be appropriate for use
with the optimum pro jections. Figure 11 is designed for use
with an 80 percent load factor and woUld be applicable for
use with a monthly load curve.
Figure 12 shows the monthly characteristics of the Standard
Oil Company Refinery load including kilowatt demand, kilo-
watthours and load factor. The load pattern is more erratic
than is that for oil production; however, it also is charac-
terized by a high monthly load factor which has reached 98
percent on two occasions. The electrical requirements of
the refinery will remain static until the local market can
justify an expansion in either the quantity of present refined
products or the number of products being refined.
The oil platforms are expected to have a load characteristic
similar to that of the Swamon River load. The productive
I ife of a platform has been aSiumed to be 30 years with a
minimum of 8 platforms estimated for completion by 1975,
A schedule of the demand and energy requirements for these
8 platforms is listed by year from 1966 to 2004 in Table 4
and 5 respectively. Table 5 contai ns two energy estimates,
one on the basis of a 71% annual load foetor and one assuming
80% annual load factor. These energy projections were de-
rived from power requirements data obtained from one of the
major oil companies that is in the process of installing a plat-
form. The demand pattern followed is that shown in Figure 11.
Characteristics of the proposed Japanese ch ip mi II at Homer
are included in Appendix D which is a transmittal from the
Juio Paper Manufacturing Company, the sponsoring organi-
zation.
R
~
11
Q
c
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8
.111 0 '
00-........
I I
'01»
cOl
00 E~
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00:::'
J:.
:?::?:
~~
FIGUREi8 i ,
L
'-y----, .. -------r--------j :/11'1
, I
I
--t--~----,----,.(!" j
SWANSON' RIVER OIL FI.ELD
PRODUCTION",·LOAD PATT;ERN i
61
CD KW Demand
® KWH Usage
". t
I
I
I
! ® Monthly Load Factor
, , -•. ___ ~ __ .. ____ ----.J.-___ ~~ _______ . ___ ~_
~~~~;;:;;~~~~~:;,.:,~~~~~:;::~ -
---, ...L ~ Cl 2' -, ......, -< 1.'1 Co Z (J -, ;.. 7 0« :». ""-,-,
~'-' '; ~
!
I
I
,-.:, -
z " --.... ---. '''''1'-------. r-'--'-'-'---.. -.---.------.--,--.----.-..... -.-,_.--.... , .... ----1
I 19 6 3__ i 19 .. Q.~_ I 1'.:'9 5 .. J
.. -.. ___ ,,; .... __ ...... _. ____ .. _______ . ___ L. .. , ... ___ .... ___ ..... __ .. __ . _____ .... _---L_, ______ .. _______ ... __ . " ' .. -,-____ __
DATE
.,::,~"
.. Q.. 10
, ; ...
: .. 1"
L .!.
! ; , :
NOTE; This curve assumes that the' oil industry related loads will have an
annual load factor of 71·/.. It is applicable to both 1970-1975. ,_. , 1'''-:-''-' '1' ...... _-,'.--
........
-. ..•... ~ .. ;.
.. ; ....... ~~~' .. ~ .. ~,
"1" .. ,. ,
t ."' , ..... ~ . ~.. . •
··1·,-I: .,
:::"""'-_-,-i "'--j ,
.... ~ ., ... ~ ...... _ ... ,. ~ f'"
... : ... " ., .. , .. ~ .. : .......... . .... ,,:, .. J:': .
1965 POWER STUDY
HOMER ELECTRIC ASSOCIATION
by ROBERT W. RETHERFORD AsSOCIATES
October, 1965
.. ? .'
t ... --.~-.. -,
,~·t· r ..
li-JS FlGURE 9
1965 POWER STUDY
HOMER ELECTRIC ASSOCIATION
by ROBERT W. RETHERFORD ASSOCIATES t
October, 1965
n-I& FIGURE 10
70
;·················~6 . . ~
W
Q.
'050
.~
l1J U . -_·0:····4
lIJ a..
NOTE:
USE FOR MONTHLY
LOAD DURATION
10 2.0 30 40 50 60 70 80 90 100
PERCENT of ENERGY or TIME
FIGURE 11
ENERGY LOAD & LOAD DURATION CURVES
80 % LOAD FACTOR
HOMER ELECTRIC ASSOC.
1965 POWER STUDY
by ROBERT W. RETHERFORD ASSOCIATES
1 October 1965
J[-Il
FIGURE 11
0
~
-t
111
GL 3~n81~ 91-lI -\0 Ie
-\0
I~
-ID
KW Demand -10'5 KWHR Usage -10.000'5 DEC ~ ~ ~ ~ ~ ~ ~ ~ ~ :~! ,~---~ JAN.I· •... , • " ••• 1 . . . . t-t· ..... ~: . I' ... ' .... c 1 • .... . . Ie ........ t .'. .. . ." I ~-.'.',~." '1 ." ' H " .... I' ~, ..• ,-.. t FEB.'····· .. , .. ~. 7".j. -.-•• .:.-., t • MAR'I . ---......... -.+. , .-; -~ •. T-'-' -+ .-. -, d ... APR. -,-, .-.... --t-i :-~"1'-c··_·· .. T MAY JUN. JUL ., .1 .. ~--r---' .-:....-,
AUG.
SEP. .--~ ~ -~ -• t-+--
OCT.
NOV'" ..... '." • . . --, ~..:.
DEC.
JAN. t--•• -.-.... ,-. --.... _ .•
FEB.
MARl APR. , •.••. r'-' •
' ,
MAy .. • .. • .. •· , •.
JUN.
JUL'r .~.~ • .,.." c-
, ..
AUG. -'-~: , .. "'·r.l
I· I: I
SEP.
OCT.
NOV.
DEC.
JAN.
FEB.
IlAR'
1
APR.
I~I'" AUG
-ID
I
-ID
I
5EP.
OCT.
NOV.
DEC.
JAN.
FEB.
liAR.
IAPR.
NOV
DEC.
JAN.
FU.
liAR
APR.
III
JUII.
JUL.
AUG.
UP.
. ,
I ; I ' I 11'
_.-4.J r' + "'.' I'" III "I iitt,· + .,.;-+ .. ", • liT, 'I r, ,I .. ,
tJT~R=~T
-+-.~-+.+_I+ ! I ' I 1fT I
I I I!: '"
t: ; i 1 i ; I I I~r-;
4-1.i.t+h~+
+' Ii! I~ l~: .TTI',t .
'I' I I I -t--t-t-~+-tt+-;.
I:! I f I I'! -1-------.-+--....... 1 . , , I
. , .. '}" .. '~'1 t I I Ii' t OCT ........ -.-__ +;. _____ •••• --* ........ r-+t ~ +-1--.-••••• 'T ....--., ... ~···-+1-· -.-.~~--'~' ·":'t
IIOvl.,--++;>-I . .j. ~-~-.~ •• ~''':l-t''ll ",-",-_.J..~....... . .. I .~~+~-+ 'I~-I--t~·'-r ~---<tt""-f";-' rl ::~l-t--t.+-.:-~-+.tt-:..
-tv , "'I'''' '" 9 ' ~ . 00 . "~. . 8
DEC.' ~ ,., 9 '2 9' 5>
MONTHLY lOAD FACTOR -(./.)
TABLE 4
ESTIMATED KILOWATT DEMAND FOR
PERMANENT TYPE OIL DRILLING PLATFORMS
TOTAL
Year Platforms Installed KW KILOWATTS
1966 2 1,000 1,000
1967 1 1,720 500 2,220
1968 1 2,440 860 500 3,800
1969 1 3, 160 1,220 860 500 5,740
1970 0 3,880 1,580 1,220 860 7,540
1971 1 4,600 1,940 1,580 1,220 500 9,840
1972 0 5,320 2,300 1,940 1,580 860 12,000
1973 1 6,040 2,660 2,300 1,940 1,220 500 14,660
1974 0 6,760 3,020 2,660 2,300 1,580 860 17,J 80
1975 1 7,500 3,380 3,020 2,660 1,940 1,220 500 20,220
1976 7,500 3,750 3,380 3,020 2,300 1,580 860 22,390
1977 7,500 3,750 3,750 ~,380 2,660 1,940 1,220 24,200
1978 7,500 3,750 3,750 3,750 3,020 2,300 1,580 25,650
I 1979 7,500 3,750 3,750 3,750 3,380 2,660 1,940 26,730 ----'
I.f) 1980 7,500 3,750 3,750 3,750 3,750 3,020 2,300 27,820
1981 7,500 3,750 3,750 3,750 3,750 3,380 2,660 28,540
1982 7,500 3,750 3,750 3,750 3,750 3,750 3,020 29,270
1983 7,500 3,750 3,750 3,750 3,750 3,750 3,380 29,630
1984 7,500 3,750 3,750 3,750 3,750 3,750 3,750 30,000
1985 7,500 3,750 3,750 3,750 3,750 3,750 3,750 30,000
1986 7, 150 3,750 3,750 3,750 3,750 3,750 3,750 29,650
1987 6,800 3,575 3,750 3,750 3,750 3,750 3,750 29, 125
1988 6,450 3,400 3,575 3,750 3,750 3,750 3,750 28,425
1'989 6, 100 3,225 3,400 3,575 3,750 3,750 3,750 Tl,550
1990 5,750 3,050 3,225 3,400 3,750 3,750 3,750 26,675
1991 5,400 2,875 3,050 3,225 3,575 3,750 3,750 25,625
1992 5,050 2,700 2,875 3,050 3,400 3,750 3,750 24,575
1993 4,700 2,525 2,700 2,875 3,225 3,575 3,750 23,350
1994 4,350 2,350 2,525 2,700 3,050 3,400 3,750 22,125
1995 4,000 2,175 2,350 2,525 2,875 3,225 3,575 20,725
1996 2,000 2, 175 2,350 2,700 3,050 3,400 15,675
1997 2,000 2, 175 2,525 2,875 3,225 12,800
1998 2,000 2,350 2,700 3,050 10, 100
1999 2, 175 2,525 2,875 7,575
2000 2,000 2,350 2,700 7,050
2001 2, 175 2,525 4,700
2002 2,000 2,350 4,350
2003 2, 175 2, 175
2004 2,·000 2,000
2005
TABLE 5
ESTIMATED ENERGY REQUIREMENTS FOR
PERMANENT TYPE OIL DRILLING PLATFORMS
TOTAL MWHR
Year Platforms Installed KWHR 71% L.F. 80% L.F.
1966 2 6,257 6,257 7,070
1967 1 10,762 3,128 13,890 15,696
1968 1 15,268 5,381 3, 128 23,777 26,868
1969 1 19,772 7,634 5,381 3,128 35,915 40,584
1970 ° 24,278 9,886 7,634 5,381 47, 179 53,312
1971 1 28,782 12,139 9,886 7,634 3,128 61,569 69,573
1972 ° 33,288 14,391 12,139 9,886 5,381 75,085 84,864
1973 1 37,792 16,644 14,391 12,139 7,634 3,128 91,728 103,653
1974 ° 42,298 18,896 16,644 14,391 9,886 5,381 107,496 121,470
1975 1 46,928 21,149 18,896 16,644 12,139 7,634 3,128 126,518 142,965
1976 46,928 23,464 21,149 18,896 14,391 9,886 5,381 140,095 158,307
1977 46,928 23,464 23,464 21,149 16,644 12,139 7,634 151,422 171,107
1978 46,928 23,464 23,464 23,464 18,896 14,391 9,886 160,493 1'31,357
1979 46,928 23,464 23,464 23,464 21,149 16,644 12,139 167,252 188,995
1980 46,928 23,464 23,464 23,464 23,464 18,896 14,391 174,071 196,700
rv 1981 46,928 23,464 23,464 23,464 23,464 21,149 16,644 178,577 201,792
1982 46,928 23,464 23,464 23,464 23,464 13,464 18,896 183,144 206,953 0 1983 46,928 23,464 23,464 23,464 23,464 23,464 21,149 185,397 209,499
1984 46,928 23,464 23,464 23,464 23,464 23,464 23,464 187,712 212,115
1985 46,928 23,464 23,464 23,464 23,464 23,464 23,464 187,712 212,115
1986 44,738 23,464 23,464 23,464 23,464 23,464 23,464 185,522 209,640
1987 42,548 22,369 23,464 23,464 23,464 23,464 23,464 182,237 205,928
1988 40,358 21,274 22,369 23,464 23,464 23,464 23,464 177,857 200,978
1989 38,168 20, 179 21,274 22,369 23,464 23,464 23,464 172,382 194,792
1990 35,978 19,084 20,179 21,274 23,464 23,464 23,464 166,907 188,605
1991 33,788 17,989 19,084 20,179 22,369 23,464 23,464 160,337 181,181
1992 31,598 16,894 17,989 19,084 21,274 23,464 23,464 153,767 173,757
1993 29,408 15,799 16,894 17,989 20, 179 22,369 23,464 146,102 165,095
1994 27,218 14,704 15,799 16,894 19,084 21,274 23,464 138,437 156,434
1995 25,028 13,600 14,704 15,799 17,989 20,179 22,369 129,677 146,535
1996 12,514 13,609 14,704 16,894 19,084 21,274 9P,,079 110,829
1997 12,514 13,609 15,799 17,989 20,179 80,090 90,502
1998 12,514 14,704 16,894 19,084 63,196 71,411
1999 13,609 15,799 17,989 47,397 53,559
2000 12,514 14,704 16,894 44,112 49,847
2001 13,609 15,799 29,408 33,231
2002 12,514 14,704 27,218 30,756
2003 13,609 13,609 15,378
2004 12,514 12,514 14,141
2005
411000
3000
FIGURE 13
ESTI MATED KI LOWAlT DEMAN 0
tooo for
OIL DRILLING PLATFORM
~ O~----------~----------~-----------+ (i)
C
:0 rn
" 10 20 30
YEARS
PART "'
WHOLESALE POWER SITUATION
PART III
WHOLESALE POWER SITUATION
~A) PRESENT SOURCES OF SUPPLY.
( 1 )
(2)
( 3)
Present Power Supplier: Homer Electric Association purchases all of its
power requirements, except those for the Seldovia division, from Chugach
Electric Association under the terms of the agreement included in APpendix
A herein. Until a physical connection is made to Homer, the Seldovia
requirements will be supplied by the HEA owned and operated diesel-
electric plant in Seldovia.
Availabilit , Ade uac , and Nature of Present Service: Generation on
enal enmsu a mc u es t e, y roe ectrlc plant at Cooper
Lake and a 7500 KW gas turbine driven unit at Bernice Lake. These two
plants are tied into the Anchorage area generation by a 115 KV trans-
mission I ine originating at the Quartz Creek substation. At the present
time this line cannot be considered as a dependable tie because of
earthquake damagei however, this is a temporary situation which should
be remedied in the near future. The Bernice Lake plant was available
for approximately 6000 hours in 1964. It is hoped<that this record can
be improved in the future. The Cooper Lake plant has two 7500 KW
units and has had a good record of availability. Table 6 lists all gener-
ation on the Kenai Peninsula. -
In the Anchorage area, the several entities who generate power (Chugach
Electric Association, City of Anchorage, Bureau of Reclamation,
Elmendorf Air Force Base and Fort Richardson) are interconnected --
mostly at one point, the Bureau of Reclamation Anchorage Substation.
rhis interconnection provides the opportunity for improved reliabnity
and best use of economy energy interchanges, but also requires a well
coordinated operating arrangement for best results. To date, it is
generally agreed that t+Te coordination of operation of the interconnected
system is not the best. This continues to be a challenge to the syst~m
operators. It is believed that progress is being made and that there exists
today a pooling system (however weak) that places each entity in a some-
what beuer position than without it.
Future additions to the systems will require muchmore coordination of
effort, particularly regarding the relaying and dispatching of the several
individual systems.
Anticipated Deficiencies: The existing contract with Chugach provides
for supplying all of Homer Electric Association's power and energy re-
quirements not in excess of 8,000 kilowatts unless the excess is available
to Chugach and requested by Homer. It is anticipated that the system
demand will reach 8,000 KW during the 1966-67 peak season. The esti-
mated deficiencies for HEA and CEA combined are indicated by Figure
5. The existing firm capability (listed on Figure 5) includes the second
gas turbine recently installed at the CEA InternOITonal substation. The
fi rm capabi I ity is now 71,700 KW. . As previously pointed out in '
Section I'-B,' approxi.mately lOO.,OOO KW of.odditi:onal installed firm
I J 1-1
HOMER ELECTRIC ASSOCIATION, INC.
POWER STUDY
TA~LE~
KENAI PENINSULA GENERATION -EXISTING
Nameplate Generator Net Energy
Item Plant Descti:Rtj:on Ca~acit~ Caeabilifl Available
(A) Cooper Lake Hydro-Project
2 -7500 KW Units 15,000 18,000 41,000,000
(B) Seward Electric System
2 -1500 KW Diesel Unit (Standby
750 rpm packages 3,000 3,300 Un i ts)
(C) Bernice Lake Plant
1 -7500 KW Gas Turbine 7,500 8,000** 40,000,000*
(D) Homer Electric Association
2 -600 KW Diesel) (Standby
2 -125 KW Diesel )-Homer 1,450 1,450 Units)
1 -600 KW Diesel)
1 -300 KW Diesel) . 1,300 1,300 6,200,000 1 -250 KW Diesel )-Seldovia
1 -150 KW Diesel) (@' 55%L. F.)
Future Standby
(E) Strandberg (Kenai Plant)
1 -1500 KW Dual Fuel Engine
1 -700 KW Dual Fuel Engine
1 -600 KW Dual Fuel Engine 2,800 2,800 13,400,000
(@' 55%L.F.)
31,050 35,700 100,600,000
REA Financed 25,250 28,750 87,200,000
REA Commitments (A), (B), (C), & (D) 28,250 32,050
*Estimated Min. output required under contract. This is 57% L.F. on 8000 KW or 61%
on 7500 KW.
**Based on CEA experience; it is believed that this capability could be increased to
9,000 KW by a change to Gas-Fired operation.
111-2
(4)
capacity is indicated by 1975. CEA is presently planning additional
generating capacity in the Bel uga gas field on the north side of Cook
Inlet west of Anchorage. Power from th is proposed plant would be
delivered to Anchorage over a 60-mi Ie transmission I ine and could be
delivered to HEA over the existing Kenai Peninsula-Anchorage trans-
mission tie assuming that the latter can and will be maintained in re-
I iable condition.
There is presently under serious consideration a submarine cable sys-
tem to serve the Cook Inlet oil field platforms. This system could
also provide a tie across Cook Inlet between the HEA transmission
system and the CEA Beluga Project. This cable system could provide
additional reliability and capacity to the HEA systems. If this
connection were not made and the Turnagain Arm I ine was out of
service, the generating capacity available to serve the HEA load
(assuming the necessary contractual agreements had been made)
would be the combined capacities of Cooper Lake, Bernice Lake
and the Homer diesel plant or a total of 23,950 KW. If the Bernice
Lake gas turbine or one of the Cooper Lake generators were out of
service simultaneously with the line, the available capacity would
be 16,450 which would be adequate to serve the HEA load until
1969 or 1970 depending on whether the minimum of optimum fore-
cast is used. This ignores the commitment to Seward and the CEA
load at Kenai Lake which are served out of the Dave's Creek sub-
station. With the transmission line out and all generation available
during the peak load period, the Kenai Peninsula REA financed
generation resources would serve the load unti I 1970 with the
optimum forecast or 1973 using the minimum forecast. If the Cook
Inlet submarine cable tie were completed, the reliability and re-
serve capacity would improve in amounts depending on the actual
cable system installed.
If it is assumed that CEA may continue to serve all of HEAlS re-
quirements, it must be concluded that (1) Transmission ties to the
Kenai Peninsula must be made adequate and reliable or (2) Addi-
tional generation must be added on the Peninsula in amounts
commensurate with the H EA anticipated load growth. For the
purpose of this study it is assumed that the future requirements
of HEA will be served by generation on the Kenai Peninsula
(present and future) and that the existing transmission tie to
Anchorage would be used to provide for reserve capacity and
economy energy interchange.
rhe following Table 7 shows the Generation Requirement Forecast
for estimated optimum and minim/Jm expectati.ons on the Kenai
Peninsula.
Cost of Purchased Power: Purchased power costs cannot be pre-
cisely determined in advance since they are based on a cost sharing
formula under the agreement attached herein as Appendix A. The
actual cost to HEA since the inception of the purchasing and lease
agreement has been:
Year
1961
1962
1963
1964
111-3
Mi IIs/kwhr.
21. 72
18. 11
13.88
14.50
TABLE...L
GENERATION RE~UIREMENTS FORECAST --KENAI PENINSULA LOADS
'91>7 191)8 191>9 12Z 0 1:171 I:1Z 2 1~7~ I:1ZIi Il!Z~ 1:171) I:1ZZ I:1ZI! I:1Z2 i2Bli
m Groll Gen. Required, Optimum Forecast --KW 11,000 15,300 21,300 29,600 32,100 34,700 37,600 40,700 1tIt,200 47,700 51,600 55,900 60,500 65,000
Gro •• Gen. Required, Minimum Forecast --KW 11.000 12.800 ~ .IZ..:i.QQ .. ~ ~ l2...JQQ 29,600 .ll.JQQ lZ...!.QQ 40,800 1tIt,800 ~ ~
(3) MIX, Clp'Y AVllllble, CEA Agreement --KW S,OOO 8,000 8,000 8,000 8,000 8,000 8,000 8,000 8,000 8,000 8,000 8,000 8,000 8,000
~4) Net Clply. Required, Optimum Forecast -KW 3,000 7,300 13,300 21,600 24,100 26,700 29,600 32,700 36,200 39,700 43,600 47,900 52,500 57,000
5) Net Clply. Required, Minimum Forecast -KW ...l...QQQ 4.800 ..L.Q.QQ ~ ..!..L..lli ~ ..!..Z"jQQ 21,600 12....ZQQ ~ 32,800 36,800 .!iLlQ.Q 46,300
~~~ Groll Energy Required, Optimum Forecast -MWH 58,000 85,600 126,300 186,147 202,000 219,000 239,000 259,000 280,846 306,000 331,000 360,000 391,000 425,000
Gro •• Energy Required, Minimum Forecast -MWH 58,000 ~~ ~ .l..ll.alQ.Q 128,700 146,200 166,100 .!.iWQ2 l!l...2QQ ~ ~ 290,000 318,000
(8) Energy AVllllble, CEA Agreement -MWH 46,300 46,300 46,300 46,300 46,300 46,300 46,300 46,3'00 46,300 46,300 46,300 46,300 46,300 46,300
(9) Net Energy Required, Optimum Forecast -MWH 11,700 39,300 80,000 139,847 155,700 172,700 192,700 212,700 234,546 259,700 284,700 313,700 31t1t,700 378,700
(10) Net Energy Required, Minimum Forecast -MWH 11,700 23,200 36,900 53,400 67,000 82,400 99,900 119,800 151,300 171,200 192,700 217,200 243,700 271,700
CAP 'V. AND ENERGY AYAILABLE ON.kENA! PE~INSULA
~ !II~ From ill REA-flnlnced Generatlon--KW* 22,5 00 22,500 22,500 22,500 22,50 0 22,500 22,500 22,500 22,500 22,500 22,500 22,500 22,500 22,500
12 ,MWH** 93,000 93,000 93,000 .9) ,000 93,000 93,000 93,000 93,000 93,000 93,000 93,000 93,000 93,000 93,000
PRESENT PENINSULA COMMITMENTS FOR (II) ABOVE
!13 l Homer Electric A.soclatlon --kW 8,000 8,000 8,000 S,OOO S,OOO S,OOO S,OOO S,OOO S,OOO 8,000 8,000 8,000 8,000 8,000
14 Kenll Like Ar .. , Sewlrd .. _-KW -HW ..l....!Q2 ~ 4,000 ,~:~gg ,i'tgg ,i':gg li:ro ~ ~ ~ ;t.Wo f,ggo "Wag 15 . Total --kW ,5 10,100 11,000 12,000 , , 13,20 13, 5 13,7 a I , a 1 ,30
PRESENT PENINSULA COMMITMENTS FOR (12) ABOVE
(16l Homer Electric ASSOCiation --MWH 46,300 46,300 46,300 46,300 46,300 46,300 46,300 46,300 46,300 46,300 46,300 46,300 46,300 46,300
!17 Kenll Like Arel 'Seward --MWH ~ ...l.1QQ ~ iH§g ~ t!:i~g ~~'l£g ~O,9~~ l~'sgo l2,rog ~ 2"Ogg st:~gg ~ 18 Total --MWH 52, 00 55,500 59, 00 3.300 ,7 a , 7,2 ,1 0 9, 7 ,3 7 ,
NEW CAP'Y. RE~UIRED BEYOND (II) --(15) ABOVE
!19~ Optimum Forecl.t (II) --(IS) --(4) --KW none none 1,800 11,100 13,800 16,600 19,700 23,000 26,700 30,400 34,550 39,100 1tIt,000 48,800
20 Minimum Forecut (11) --(15) --(5) --KW nOne none nOne none 1,600 4,600 8,000 11,900 16,200 19,800 23,750 28,000 32,800 38,100
NEW ENERGY RE~IRED BEYOND (12) --(18) ABOVE
(21) Optimum Forecast (12) (18) (9) --HWH none 1,800 46,400 110,147 126,400 1ItIt,300 166, lao 186,900 209,646 235,800 261,900 292,000 324,200 359,500
(22) Minimum Forecut (12) --(18) --(10)--MWH none none 3,300 23,700 37,700 54,000 73,300 94,000 126,400 147,300 169,900 195,500 223,200 252,500
oIIOoe. ~ Include Homer Diesel Plant which will be considered only for standby reserve capacity and l!.2£ for blilc power supp.Jy.
**Inclu e. 12,000,000 KWH which can be readily added by diversion of water from Stetson Creek Into Cooper Lake.
(5)
The increased cost in 1964 was due to non-recurring expenses resulting
from the March earthquake. Future estimated costs under the agreement
are expected to be less than 11 mills with in two to three years.
Contnxt Provisions: A copy of the existing sale and lease agreement
with Chugach Electric Association is attached as Appendix A. Article
III, Section 3.1 of this agreement is most pertinent with respect to this
study since it can limit Chugach's commitment to HEA to 8,000 KW.
This study will provide various power supply alternates whereby the
Homer Electric Association could plan for future power requirements
beyond the present commitment in the contract with CEA.
(B) SOURCES OF SUPPLY.
(1)
(2)
Presently Available: There are no adequate additional sources of
supply available on the Kenai Peninsula at this time. It is possible
that arrangements could be made with either the City of Kenai or
directly with Consolidated Utilities for the future purchase of whole-
sale energy; however, this could not be done without their undertaking
a generation expansion program. It is difficult to envision a situation
wherein either ofthese entities could supply the needs of HEA at a
reasonable price. It is assumed herein that they cannot. It is con-
ceivable that joint efforts by these utilities with HEA to accomplish
a generating faci I ity similar to these suggested in Part VI following
might be done with mutual benefit.
Future Availabilit of Government Plants and Transmission Lines: The
orps 0 ngrneers as stu Ie t e ra ey a e prolect on ac emak
Bay and recommended an installation of 64,000 kilowatts. The bus
bar energy costs were estimated to be 7 mills per kilowatthour for
280,000,000 kilowatthours. This project has been dormant since the
report was published in 1960. It has been reviewed as part of this
Power Study on the basis of better water records and a different scheme
of development. This review has shown some interesting possibilities
as will be indicated in Part V of the report. It is possible that this
project might be activated on the basis of a new benefit/cost ratio
as developed in th is report.
rhere are no government transmission faci I ities existing or proposed
in the area at the present time for the purpose of marketing Federal
energy.
I! !-5
PART IV
FUEL INVESTIGATIONS
PART IV
FUEL INVESTIGATIONS
(A) PRESENT SOURCES OF SUPPLY.
( 1 ) Present Suppliers: The only requirement that the Association has for fuel
at the present time is for the Seldovia generating plant wh ich uses diesel
oil. The oil is being purchased at 17 cents per gallon.
(B) PROPOSED SOURCES OF SUPPLY.
( 1 ) Availability, Adequacy, and Other Characteristics: Three fuels are or
could be made available on the Kenai Peninsula. These are (a) coal,
(b) oil and (c) gas.
(a)
(b)
Coal: Much of the Kenai Peninsula is underlain with coal
deposits. rhe extent of the deposits is not well defined due
to lack of exploratory work. Geological Survey Bulletin
1058-F, "Geology and Coal Resources of the Homer District
Kenai Coal Field, Alaska" states:
"Indicated coal reserves in the Homer district are
estimated to total about 400 mill ion tons in beds
2 feet or more in thickness."
It is also suggested that, "the potential reserves of the district
may amount to several billion tons."
The classification of the coal varies from lignite to sub-
bituminous B, with the greater part being subbituminous C
which has a moist BTU content of more than 8300 but less
than 9500. The ash content of the coal varies from 3.2
to 22.6 percen t as rece i ved.
Some of the coal could be strip mined, but how much is
undetermined. The formation is cut by at least 35 faults
with the displacements varying from a few inches to nearly
80 feet.
There are no active commercial coal mining operations of
any consequence at the present time since there is no market
other than home heating use. It is doubtful whether a com-
petitive development could be supported by the amount of
fuel that would be burned in a generating plant to supply the
Kenai Peninsula.
Oil: Disti lIate fuel is available from the Standard Oil
Company Refinery at Bernice Lake. The cost should be
related to the quantity and competitive pressures from the
other refinery products. CEA is paying approximately 62
IV-l
*
(c)
cents per 10 6 BTU at Bernice Lake, Th is, however, is based
on a contract involving process steam supplied by CEA to the
refinery. Heavy fuels shipped into Alaska have been quoted
at about 45 cents per 10 6 BTU in large quantities .
.Na.t~ural_C;;a_s: The estimated reserves are a closely held secret
by the wen owners, but severa1 presumably qual ified sources
have made some rough estimates of what the proved reserves
might be. More important than the existence of proved re-
serves is their avoilahility as a fuel supply for electric
generating plant use. This availability in turn is dependent
upon other existing or future competitive uses for the fuel.
Existing competitive uses include pipeline sales and oil
field repressurization. Future competitive uses include
liquefaction and petrochemical production.
There were three producing gas fields on the Kenai Peninsula
in 1964 -Kenai, Swanson River and Sterl ing. The Kenai
f,ie:ld, operated by the Union Oil Co" has been estimated*
to contain from more than a trillion to over three trillion
cubic feet of gas. Total production from this field to July I,
1965 was 11,953,161 Mcf. Total production from the field
in 1964 was 4,502,836 Me[ (12, 300 Mcfd. ave .. ) practically
all of which was sold to the Alaska Pipeline Company for
transmission to the Anchorage market. Production during 1965
should conside rably exceed that of 1964 since the Union Oi I
Company has contracted to deliver more than 100,000 Mcf.
per day to the Standard Oil Company for pressure maintenance
in the Swanson River Field. Pressurization is not a consumptive
use of the gas; it does delay the availability for other purposes.
The gas liquefaction plant being discussed would require an
estimated 30-35,000 Mcfd. A 100,000 KW generating plant
would require an average of 20,000 Mcfd. Alrowing 50,000
Mcfd. for Alaska Pipeline, four times the existing sales, the
Kenai Field would serve the above consumptive uses for 25
years assuming the lower reserve estimate of one trillion cubic
feet.
The gas from the Swanson River Field is being injected or re-
injected, depending on the source, for pressurization, Since
Standard is purchasing additional gas for the same purpose,
there would be no gas avai lab Ie from this field for electric
generation purposes unti I 011 production ceases.
"Mineral and Water Resources of Alaska" -Report prepared by the U. S. Geological Survey
in cooperation with State of Alaska Dept. of Natural Resources, 1964.
IV-2
The Sterling Gas Field has two wells, one of which is pro-
ducing for Consolidated Utilities. Total sales from 1962
through 1964 were 128,108 Mcf. The 1964 sales were
57,680 Mcf. rhe field has not been developed further
due to the lack of a market --no reserve estimates are
available.
The West Fork and Falls Creek Gas Fields are both shut-
in. The Standard Oil Company recently struck gas in the
Birch Hill area. No reserve estimates are available for
these units. Also, a very recent announcement indicates
a gas well of undetermined reserves is undergoing tests
about 20 miles north of Homer.
(2) Cost: Since there are no commercial coal operation:) of any consequence on
the Peninsula at this time, any cost estimate is highly speculative. It would
be influenced by the scale of the mining operation which in turn would be de-
pendent almost entirely on the generating plant for a market. The risk in-
volved in being dependent on such a mining venture is high even if it were
operated by HEA because of sparse knowledge of the underground conditions
and prob lems.
Diesel oil would probably not be available for much less than the 17 cents a
gallon price now in effect. It is probable that heavy fuels useful in a steam
plant might be purchased for about 45 cents per 10 6 BTU.
The price of natural gas is in a state of flux. Consolidated Utilities re-
portedli is paying 25 cents per mill ion BTU at the well-head, with a pro-
vision for escalation of 2.5 cents per million BTU each five years. The
Chugach Electric Association has signed a 20-year contract with the Standard
Oil Company for delivery of gas in the Beluga area beginning in 1967. The
contract pri ce is 15 cents per mill ion BTU for the first 5 years with a one-cent
escalation in five-year increments thereafter so that the gas price for the last
five years of the contract will be 18 cents per million BTU. The contract also
provides that CEA will pay all taxes on gas taken grom this field. This has
been estimated by CEA to add about 0.3 cents/l 0 BTU to the price. Published
rates for gas on the Kinai Peninsula indicate that large quantities would sell
for about 45 cents/l0 BTU today. For the purpose of evaluating this resource
in this report, a figure of 25 cents per million BTU has been used for well-
head delivery. Since construction of the gas line from the Union Oil Company,
Kalifonsky Field to Bernice Lake for delivery to Standard Oil Company for
pressurizing the Swanson River Field, it is believed that gas probably would be
available at the Bernice Lake Plant site for about 26 cents/l0 6 BTU. This
figure will be used in estimating Bernice Lake Future Operating Costs. To
these figures will be addei an escalation charge equivalent to the CEA-Beluga
contract 6-1.63 cents/l 0 BTU each five years for 25-cent gas and 1.73
cents/10 BTU each for five years for 26-cent gas.
~V-3
PART V
HYDRO-£LECTR1C POTENTIAL OF AREA
PART V
HYDRO-ELECTRIC POTENTIAL OF AREA
The area reviewed for potentia I hydro-electric projects includes all the Kenai Peninsula.
The present HEA service area as shown on Plate I does not encompass the same area;
however, for purposes of potential wholesale power supply, the additional area was studied
since the sites involved are adjacent and within reasonable transmission distance of HEA
load centers.
The preliminary investigations carried out by the Engineer for this report have been partly
based on the "Summary of Potential Hydro-electric Power in Alaska, II published by the
Corps of Engineers, U.S. Army Engineer District --Alaska, as revised September, 1961
and the original "Interim Report No.2 on Survey of Harbors and Rivers in Alaska --Cook
Inlet Area, II dated January, 1950 with subsequent revisions also published by the Alaska
District of the Corps of Engineers.
The Engineer made use of all information available from the U.S. Geological Survey who
maintain water records at various points throughout the Kenai Peninsula. U.S.G.S. has
also published Water Supply Papers and Plan and Profile Maps of selected Rivers and Dam
Sites. All this data was reviewed in developing this report. The base maps for study and
eventual use in the report came from the original mapping published by the U.S.
Geological Survey.
The Engineer made additional brief field trips into areas of the Kenai Peninsula which
appeared potentia Ily interesting based on studies of the U 0 S. G. S. Quadrang les of the
general area. Reports of persons acquainted in various regions were also followed up.
There are undoubtedly more hydro sites on the Kenai Peninsula which are yet unidentified,
but it is believed that those most promising within reasonable reach of the HEA service
area have been noted. Much more could be done toward a better evaluation of most of
the sites, but for this report the writer has used his best judgement based on preliminary
findings to reduce the number of sites for further study. For Jack of time, some interesting
sites noted recently have not been visited yet. Those I isted are so noted.
In viewing potential hydro-electric developments, the Engineer has endeavored to be
aware of other uses of the areas and waters involved and has incl uded some comments re-
garding these on the "Capsule" I istings in Appendix G.
In reviewing work already done on potential hydro sites, it appeared that the Bradley Lake
Project (reported on by the U. S. Geological Survey in January, 1956 and the Alaska
District of the Corps of Engineers in November, 1960) deserved another look. Rapid de-
velopment of the Kenai Peninsula indicated that the total output of the project could be
used locally and longer water records provided a sounder basis for evaluating the project.
Alternate plans for project development similar to those suggested by the U.S. Geological
Survey were reviewed and the two-step development provided an interesting alternate to
better match investments with local load growth. Bus bar power costs appear most attrac-
tive and are estimated at about 2.9 mi lis/Kwh for alternate insta Ilations of 50 MW and
125 MW. Appendix H contains the Preliminary estimates of the Engineer for several
alternate schemes of development •
There are some hydro'sites on the Kenai Peninsula which could be adapted to pumped-
storage arrangements, but it is believed that these are more likely to become interesting
as future developments. The most intriguing of these are the run-of-the-river projects
V-l
whose large capacity installations must be used normally during the high run-off season,
and which could be converted to pumped-storage at small cost for use as peaking plants
during the remaining winter season. Numerous lakes along the west shore of the Kenai
Peninsula might be suitable for pumped-storage. These have not been studied in this
report.
The following tabulation (Table 8) of potential hydro 'sites and their estimated charac-
teristics are the result of prelimmary findings based in most cases on very rough estimates
of topographic features and construction costs. Where actual water records do not exist,
water supply estimates are based on knowledge of the area and its relationship to nearby
areas where water records are available. This tabulation is intended to indicate the re-
lative characteristics~ and pin-point the most interesting sites which might be worth more
detailed investigation. Plate I! shows the general location of each of the sites listed.
A capsule listing of the characteristics of each project listed in Table 8 IS included in
Appendix G. Each such "capsule II I isting includes a code letter ratingof the Basic Data
used in estimating the project. "rhese ratings vary from Good to Poor and indicate that
the data presented must be used with caution. Repeating --these listings are primarily
for pin-pointing interesting sites for further stu~.
The cost estimates included in Appendix G are based on the basic data of the project and
are no better than that data. Cost levels are today's (1966) and the annual costs are de-
veloped using 50-year life and 2% interest for annual costs of interest and depreciation;
0.2% for an allowance for insurance and interim replacements; and, for operation and
maintenance the costs included are based on experience and the assumption that these
projects will be an integral part of a larger system with the project operating costs re-
flecting the importance of the project to the overall system. Estimated taxes have not
been included since the present tax applied to non-profit cooperatives in Alaska is based
on energy sales and not investment. This tax would be the same for any type of power
production and would not affect the relative merits of one method over another.
Transmission distances and costs included in the Table are the Engineerls estimate of the
costs properly chargeable to the particular project based on its locatiorl I size and relation
to an assumed basic transmission grid which would be required for a power system regardless
of the power source, Some of the sites are naturally associated with one another and arbi-
trary assignments of transmission costs have been made.
It is believed that this listing of sites presents an interesting --even astonishing --por-
trayal of the hydro-electric potential on the Kenai Peninsula. The summary of Table 8
(at bottom) shows that the total capacity listed is nearly 680,000 kilowatts. Of this -
680,000 it appears that 352,000 KW would produce energy at an overall average bus bar
cost of 4 mills per KWH or less. With transmission costs of about 1 mill or less per KWH
to Kenai Peninsula load centers, it would appear that such projects bear more investi-
gation since these costs are highly competitive with the presently estimated thermal power
generating costs of 5.8 mills per KWH at bus bar plus some lesser transmission costs of
about 1/2 mill per KWH. Several additional projects capable of producing energy at an
overalTCiVerage bus bar cost of 5 mi II:5/KWH or less are located advantageously to reduce
transmission costs and thereby become c.ompetitive with fuel generation
The lowest cost prime energy source listed is the Bradley Lake Project. Its distance from
Kenai Peninsula load centers is greater than some of the other sites but its estimated bus
bar costs are lower. Transmission costs to the Soldotna area (a proposed bulk power supply
v-' ?
point) are about 1 mi II/KWH. This project can be developed in steps wh ich are low cost
and will better match the estimated load growth. More details on this project are in-
cluded in Appendix H of this report. The lower power plant of the proposed two-step de-
velopment could contain a pump-turbine unit for pumped storage use at some future time.
This would be very economical here because of the added capacity available in this power-
house which is normally required for run-of-river power from the lower watersheds.
Some of the projects listed would affect the commercial fishery of Alaska. The projects on
the Kenai River and the Kasilof River are the major ones. These projects are low head (45
to 85 feet) and it is probable that fish passage facilities are feasible and workable. More
information is needed on possible effects on the spawning grounds.
Several sites to the south of Kachemak Bay would affect the development of certain re-
creational areas and cabin site locations (Seldovia Lake, Hazell Lake and Cronin Lake).
There are possibly fish problems at some of these sites and also the sites at Halibut Creek
and Portlock Creek.
There may be fishery problems in the Sheep Creek and Fox River areas. These possibilities
should be investigated further. A prel'iminary meeting with the State Department of Fish
and Game and the U. S. Fish & Wildlife Commercial Fisheries personnel was held to brief
everyone on the sites being studied.
One particular site reviewed would appear to be of particular interest to the Seward area.
This is the Lost Lake site which reportedly has been given some thought in the past, but
has not been followed up. Based on the data available to the Engineer, it is recommended
that this project be given further study immediately. It is urged that water records of some
kind be accumulated as a first step.
The Snow River and Nellie Juan projects appear quite low cost and should be investigated
more carefully although their location is not near the presently fast-growing loads on the
Kenai Peninsula.
The Twin Lakes site above the Ski lak Lake area is a low-cost, high -head development of
interest. The cost estimate for this project is based on very rough data and no field in-
vestigation. It appears interesting enough to Investigate further. Water supply is of first
importance and means to help establish the watershed quantities should be placed at work
at an early date if further checking of the project bears out the present appearance.
V-3
\ ,
VA-
Of
~
LEGEND
• EXISTING SUBSTATION
-TRANSMISSION LINE
CERES LAKE
SELDOVIA LAKE
BARABARA CREEK
HAZELL LAKE
HIGH VALLEY
CRONIN LAKE
HAU BUT CREEK
PORTLOCK GLACIER
BRADLEY LAKE
SHEEP CREEK
FOX RIVER
INDIAN CREEK
FUNNY R!VER
MOOSEHORN
TWIN LAKES
STELTER
17 JUNEAU LAKES
COOPER LAKE
CRESCENT LAKE
2 GRANT LAKE
21 PTARMIGAN LAKE
22 SNOW RIVER
~ NELUE J. UAN LAKE ~ LOST LAKE
HOMER ELECTRIC ASSOCIATION, INC.
HOMER, ALASKA
KEY MAP
HYDRO-ELECTRIC SITES
ROBERT W. RETHERFORD ASSOC.
CONSULTING ENGINEERS
ANCHORAGE,ALASKA
PLATEn
<
I
(Jl
NO. NAME
I Ceres Like
~ Se IdOV a Like
Se I dov I I LI ke wfd vers Ion
3 Barlbera Creek
'+ Haze Lake
~ HIQn VII ley &~_ .Jfon I n Lake
, -Cron I n Ike wi th givers ions f.+ ... !llil but Creek
Portlock
9 Bradley Lake (blslc)
9a Bradley Lake (w/dlvers ions)
dr' ' .. Sheep Creek
Fox River
II, Upper Fox River
~-Tustumena ProJ. (Kas Ilof)
120 Tustumena Pro • Indian Cr.
Kesflof ~ Indian combined
11 Funny River
lit Moosehorn
15 Twl n Lakes
16 Stel ter
4t Juneau Creek
Cooper Lake
laa w/Stetson Creek
19 Crescent Lake
20 Grant Lake '-' 21 Ptarmigan Lake
-21a .-w/FI11 S (;reek
22
...
Snow River
23 Nellie Juan
24 Lost Leke
24a wid Ivers Ions
ORA INAGE
AREA
(Sq. III.)
3.65
H.40
12.90
19.20
2f;i.'IO
6.10
~L 88.1
20.3
26.2
5'1.0
117.2
96.3
103.0
[4Z.t:!-"7.5
738.0
bo.9
'38.0
1 890.0
I 510.0
28.5
634.0
62.0
31.0
40.3
29.6
'12, 7
29.4
31. f
99.8
36.0
5.7
!:I.O
RUN-OFF AVE. ANNUAL
1,000'5 FLOW-C.F.S.
ACRE FEET REG .!EXCESS
21 28/1
31 34/H
'Ib S'lno
56 24/53;'-
169 95t '4
2 29/'
63 78/
_~O .-440/'5 ss-53/ ;9
123 80/90
274 m9~0 Upper
1379/0 Lower
59'+ ,61!:1/47 Upper
716/47 Lower
454 325/301
373 488/27
217--35 o 240 0/39
I 722 2,380/0
2'1J u/JJ5
TABLE 8
HYDRO ELECTRIC SITES -:-KENAI PENINSULA
ALASKA
MEAN ESTIMATED POWER BUS ~:h~NERGV EFFECTIVE KILOWATTS
~EAD(ft.) PRIME INSTALLED PRIME SECONOARV
505 I 030 2 000 8 850 _ 3J:L
275 680 1,500 5 830 1.370
2 !:IS I 130 20;00 'L 700 .800
325 5' 0 3 000 4.900 10 800
203 1.460 5 000 12.600 q.!5Q
I 120 2.160 5 000 _2~t ~ ~.070
19.0 __ --1.,980 2.~00 CUOO .080
340 10.900 30 000 95. SOD 16.300
330 I ~O .500 I 000 14 200
140 815 5 000 7,000 7,800
518 29,500 50,000 253,000 -0-
548
51~
548 52.500 125 000 450 000 31 400
365 8,650 40 000 74. 000 69.000
200 OC 15 000 61 000 a
500--900 -0-40 000 . '-O~' 97 000
85 14,400 30,000 126 000 -0-
tlOU -u-~o.Ooo -0-I~; ,000
----------------SEE ABOVE -----._-------. 60 000 230 000 2H.400
4,11+0 3 720/1,980 45 12 200 45 000 105 000 55 800
;,5]0 J 720/1 200 70 19000 60 000 163 000 .5..2,~~
92.5 95/29.5 I 950 13,600 30 000 117 000 35! 2.2.0
EST I MATED BUS BAR COST TRANSMISSION
CONST. COST MIL ,S/KWH DISTAl :E , COST
(Dolllrs) PRIME OVERALL MILES MILLS/KWH
I . 7~n nnn R.a R. 17 .~ 2.0
3 033 125 19.7 16 0 6., a 1.0
4.44' .8;0 16.7 L~..a .I'1 7~
3.281.750 21.3 _8...0 Cl. 't O.li
3.422,000 8,!L _6.JL ~ . I 1.5
2.77' .62~ <;.4 4.7 .2. 1.2.5
.q8a.7_~o. 8,6 7.Q -.0...5. O. 7;--2.~
23.995. ISO ft:· 7 4 8, I 1.0
2. j8It.55o. 4.1 O. '5
3.363.750 15.2 BJ 11 .0 1.25
17,127,044 2.9 2.9 56.0 0.9
34 87,841 2.9 2.9 53.5 1.0
15 131,500 6.6 _3 ... 4. M 1·CJ.
18. 06,250 .6 7.4 3.0 .0
11 63, '50 ---5.1 2.8 .0
19 165 625 5.9 5·9" 0,6 0.5
10 ID~~~~ f--:':'--. 2,9 0 u.~
32 oc. 00 __ -t.k 4. a 0.5
2~1125,000 S. IS. 0.5 0.5
_ 2~,250.g~ !-. 4.9 I!.·l 9.5 ,0
I 39l...2.QQ._ . __ 2..~ -~. 37--20 .0--0.75
2 320 70/2,030 65 5 570 40 000 47 700 53 000 NOT ESTIMATED --BELIEVED HIGH
93 !:ISS 000 1'1,000 60 000 -o-Ne ESJ IMATED --BELIEVED HIGH
65 90/0 734 ,80 0 Ii 000 41 000 -o-J j88 QSl L.i...~I~_ 7.5 9--'17--90 !
85 115/0 734 170 Ii 000 5.;_ 000 -0-5.338.657 6.2 6,2
54 15/0 I 000 ,4HO 10 000 46.900 -0-8.44£.000 _ . 3±t-j~-2 -'1.,--\).2= ~r :2..:.22 __
136 Itl!:1/0 2'10 3 190 7,500 27,500 -0-3,5 000 --H-:-"-1±-0.75 .5
50,4 111/0
_.
350 2,840 5 000 24,400 -0-4,482,685 '-~~ .25~
110.4 .~~~u1ppe I'li~ 6,630 15,000 56,900 -0-7,611,238 5.6 5.6
144 a owe _ .... _-2.!~O~-~iT.C ~6-:'g-'-'Ii I 650/0 693 31.900 60 000 214 000 -0-~!-5i.Jl5·-=-. ~~ ... _ 3 .• !L __
20g 255/0 900 21 000 2 000 181 000 -0-17,840 000 _.3.oL., 32--17 1.0
33 '16/0 1,400 4,650 10 000 39.800 -0-3 315 000 3.2 3.2 1.0. 0.5
'lId 52/12 1,'100 5,300 15,000 'I5,[)00 10,500 .4,223,125 3'.2-' 3-:0" ·----1--.. ~"'-T~~~~
SUMMARY
OVERALL INSTALLED PRIME SECONDARV
KW MWH MWH MWH
Total Installed KW (Largest A'-ternate~l. .~.-.~~~ ~~OO ~~53'~050'-553,'637' T5'3'6.6'B'7
:total Instolle~ KW w1JIi"0,;eriTr'Aye-:"'Cost ~'6-mlHs!KWH-ooL..J...9.~OQ .... 516:6_2.L..2. lBO...J!.2C
ota nsta e I<w wltfi !:iveraff Ave.Cost "'5 mT s KWH 4,4 "nn' "u~~'nn ~~!l..-4.i.C.. LM "'0.
ota nsta e<l..~ w th_ vera Ave. ost 5<'+ m S'KwtI 1~,nnn LLiJ I;nn .281 •. LOO J.2J.JillL
t!.:>tal Inst.lled KW wi th Overall Ave. Cost t 3 mills/KWH Igo,OOO 495,600 178,900 674.~QQ
PART VI
AL TERNATE PLANS
PART VI
POWER STUDY
ALTERNATE PLANS FOR ADDITIONAL POWER SUPPLY
A review of the foregoing Generation Requirements Forecast, Part III, Table 7, shows
that in the next 15 years an added capacity of 40 to 50 Megawatts capable oTproducing
250,000 to 360,000 Megawatthours of energy is required.
In this forecast of Table 7 , the assumption was made that all existing REA-financed
generation on the Kenanreninsula would be used to serve the requirements of the REA-
financed utilities on the Kenai Peninsula. The following plans also assume that arrange-
ments can be made for the integrated operation of these existing facilities with any new
addit ions proposed.
The forecast shows an energt shortage developing first (1969 --1970). This assumes that
construction of the Stetson reek diversion project to increase the energy available from
the Cooper Lake Project has been accomplished by 1968. This project has been engi-
neered and bid on previous occasions providing a sound basis for estimating costs. It is
a project which can be complete in a summer construction season. In view of certain re-
pair work required at the Cooper Lake Dam, it would seem logical to accomplish both
projects together. This addition would provide the 12,000,000 KWH of energy noted in
Table 7. Additional energy and capacity can be provided by alternate methods as follows:
(I) Addition of Gas-Fired,Engine Driven Generating Units.
(2) Addition of Gas-Fired, Gas'Turbine "Driven Generating Units.
(3) Addition of Gas-Fired, 'Steam Turbine Driven Generating.Units.
(4) Addition of Hydro-electric Power Units.
(5) Combinations of (I), (2), (3) and (4).
To reduce these alternatives for further more detailed comparisons, estimates of con-
struction and operating costs have been developed and included in Appendix F, G and
H. The applicable unit costs for these several alternates are tabulated for easy com-
parison on the following Table.9 and 9A. Table 9 includes straight gas-fired engines
whereas Table 9A includes CluCtr-fueJecrengines:-5tudy of the two Tables shows clearly
that dual-fuel operation fuel costs are considerably more expensive than those for straight
gas-fired units. The present cost of pilot fuel (Arctic Diesel) is comparatively high. If
a lower cost pilot fuel were available,. the dual-fuel operation would be preferred. En-
gines could be purchased for "tri"-fuel operation to give maximum flexibility and re-
liability. Construction cost estimates have provided for this probability by including a
diesel fuel system. (See Appendix F).
VI-l
TABLE 9
UNIT COSTS
GENERATING PLANT ALTERNATES
KENAI PENINSULA
ESTIMATED PLANT BUS BAR COSTS
(Straight Gas-Fired Engines)
UNIT COSTS --~ PER KILOWATT ENERGY COSTS --HILLS/KWHR
FUEL & L,t). TOTAL ANNUAL COSTS
INVEST-DEPR.& INSURANCE L.F.
ITEH DESCRIPTION HENT INT. 0 & H & REPL. 0.66/0.8~ L.F. 0.66 L.F. 0.8!!
BASE LOAD PLANTS
4.00% 0.9% * ** * ** * ** 1(a) 8,500 KW Gas Engine, 1st Unit 179 T.I6 12.50 1.61 2.9 5.1 6.6 8.8 5.7 7.8
8,500 KW Gas Engine, 2nd Unit 159 6.36 5.00 1.43 5.1 7.3 4.5 6.6
Two-Unit Plant 169 6.76 8.75 1.52 2.8 4.9 5·9 8.1 5.1 7·2
4.00% 0.9%
2 (a) 14,400 KW, G.T.,S.C.,I--Shaft, 1st Unit 126 5.04 7.00 I. 13 4.6 8.3 6.9 10.6 6.0 9.4
14,400 KW, G.T.,S.C.,I--Shaft, 2nd Unit 93 3.72 3.50 0.84 6.0 9.7 5.3 8.7
Two-Unit Plant 110 4.40 5.25 0.99 4.2 7.6 6.5 10.2 5.6 9·0
4.00% O'ff 2 (d) 19,000 KW, G.T., Regen. C, I-S, 1st Unit 161 6.44 7.00 t. 5 3.6 6.5 6.2 9.1 5.3 7.9
19,000 KW, G.T., Regen. C, I-S, 2nd Unit 133 5.32 3.50 1.20 5.3 8.2 4.7 7.3
Two-Unit Plant 148 5.92 5.25 1.33 3.3 5.9 5.8 8.7 5.0 7.6
4.00",(, 0.9%
3 22,000 KW, 850# Steam T., 1st Unit 290 1T:'60 9.50 2.61 3.2 5.8 7.3 9.9 6.3 8.8
22,000 KW, 850# Steam T., 2nd Unit 275 11.00 6.35 2.48 6.6 9.2 5.8 8.3
Two-Unit Plant 282 11.28 7.93 2.54 3.1 5.6 7.0 9.6 6.0 8.5
3.18'1. 0.2%
4 Bradley Lake, 25 HW,Lower Phse., 1st Unit 536 17.04 3.20 0.98 3·7 2.8 (mi n.)
Bradley Lake, 25 HW,Lower Phse •• 2nd Unit 68 2.16 0.80 0.16
Bradley Lake, 25 HW,Upper Phse., 1st Unit 296 9.41 2.00 0.59 2.1 1.9 (min.)
Three-Unit Plant 300 9.54 2.00 0.58 2 .8(m in.) 2.8 (min.)
PEAKING PLANTS -(Opera t i ng 1,000 hrs. ~ average loading of 87 1/2%)
5.12% 0.9",(, L.F. 0.10 l.F. 0.10
1 (b) 2,665 KW,"Package" Gas Engine, 1st Unit 143 7.32 6.25 1.29 3.2 20.2 22.5
2,665 KW,"Package" Gas Engine, 2nd Unit 105 5.38 2.50 0.95 13.3 15.6
Two-Unit Plant 124 6.35 4.38 1.12 5.5 16.8 19.1
4.00% 0.9%
I (c) 8,500 KW,Gas Engine, *** 1st Unit 179 7.16 4.00 1.61 2.8 17.4 19·5
8.500 KW.Gas Engine, ~k 2nd Unit 159 6.36 2.00 1.43 14.0 16.1
Two-Un it Plant 169 6.76 3.00 1.52 4.9 15.7 17.8
4.58% o .9"10
2 (b) 16,100 KW, G.T. ,S.C., I--Shaft, 1st Unit 113 5.T8 3·50 1.02 4.2 15.3 18.6
16,100 KW, G.T. ,S.C., I--Shaft, 2nd Unit 83 3.80 1.75 0.75 II .4 14.7
Two-tlnit Plant 98 4.49 2.63 0.88 7.6 13.3 16.6
4.97.4, 0.9"1,
2 (c) 14,400 KW, G.T. ,S.C. ,2-SpooIIJet,"lst Unit 118 5.86 3.00 1.06 3.8 15.1 18.1
14,400 KW, G.T. ,S.C. ,2-Spool"Jet,"ind Unit 95 4.72 1.50 0.86 11.9 14.9
Two-tlni t Plant 107 5.32 2.25 0·96 6.9 13 .6 16.6
3 . 18"1, 0.2%
4 Bradley Lake, 25 HW. Lower Phse. , 2nd. Uri It 68 2.16 0.80 0.16 3.6
6 *Gas Cost ~ 25cli0 BTU (HHV).
**Gas Cost ~ 45Cl10 6 BTU (HHV).
***Listed here to show 0 & H for Peaking and Standby use only.
VI-2
TABLE.....2L
UNIT COSTS
GENERATING PLANT ALTERNATES
KENAI PENINSULA
ESTIMATED PLANT BUS BAR COSTS
(Dual-Fuel Engine Units)
UNIT COSTS --$ PER KILOWATT
INVEST-DEPR.S. INSURANCE
ITEM DESCR I PTI ON MENT INT. g ',MS. REPL.
BASE LOAD PLANTS
4.00% ~ I (a) 8,500 KW Dual-Fuel Engine, 1st Unit 179 '].T6 12.$0 1.61
8,500 KW Duel-Fuel Engine, 2nd Unit 159-6.36 5.00 1.43
Two-Unit Plant 169 6.76 8.75 1.52
4.00% 0.9"10
2 (a) 14,400 KW, G.T.,S.C., I--Shaft, 1st Unit 126 s:oz;-7.00 I. 13
14,400 KW, G. T. ,S.C., I--Shaft, 2nd Unit 93 3.72 3.50 0.84
Two-Unit Plant 110 4.40 5.25 0.99
4.00% 0.9%
2 (d) 19,000 KW, G. T., Regen. C, I-S, 1st Unit 161 6.Ii4 7.00 T:'4s
19,000 KW, G. T., Regen. C, I-S, 2nd Unit 133 5.32 3.50 1.20
Two-Unit Plant 148 5.92 5.25 1.33
4.00% 0.9%
3 22,000 KW, 850# Steam T., 1st Unit 290 TT:'6O 9.50 2.61
22,000 KW, 850# Steam T., 2nd Unit 275 11.00 6.35 2.48
Two-Unit Plant 282 11.28 7.93 2.54
3 • 18"10 0.2%
4 Bradley Lake, Lowe r Phse., 1st 25 MW 536 17.04 3.20 0.98
Bradley Lake, Lower Phse., 2nd 25 MW 68 2.16 0.80 0.16
Bradley Lake, Upper Phse., 1st 25 MW 296 9.41 2.00 0.59
Three-Unit Ave. 300 9.54 2.00 0.58
PEAKING PLANTS -(Operat ing 1,000 hours @ average loading of 87 1/2%)
5.12% 0.9"10
I (b) 2,665 KW, "Paekage"Dua l-Fue 1 Engine, 1st Unit 143 7.32 6.25 1.29
2,665 KW, "Paekage"Due I-Fue 1 Engine,2nd Unit 105 5.38 2.50 0.95
Two-Unit Plant 124 6.35 4.38 I. 12
4.00% 0'9%
J(e) 8,500 KW, Dual-Fuel Engine*** 1st Unit 179 7.16 4.00 1.61
8,500 KW, Dual-Fuel Engine*** 2nd Unit 159 6.36 2.00 1.43
Two-Unit Plant 169 6.76 3.00 1.52
4.5F 0.9%
2 (b) 16,100 KW, G.T.,S.C. , 1-~Shaft,lst Unit 113 5.1 3.50 1.02
16,100 KW, G.L,S.C., I--Shaft,2nd Unit 83 3.80 1.75 0.75
Two-Unit Plant 98 4.49 2.63 0.88
4.97% 0.9%
2(e) 14,400 KW,G.T.,S.C.2-Spool"Jet".lst Unit 118 s:B6 3.00 1.06
14,400 KW.G.T.,S.C.2-Spool"Jet",2nd Unit 95 4.72 1.50 0.86
Two-Unit Plant 107 5.32 2.25 0.96
3.18% 0.2%
4 Bradley Lake. 25 HW. LONer Phse., 2nd Unit 68 2':"ib 0.80 D:16
6 6 *Gas Cost @ 25c/106 BTU, Pilot Fuel @ 124c/10 BTU in 94/6% Ratio.
**Gas Cost @ 45c/10 BTU, Pilot Fuel @ 124cl106 BTU in 94/6% Ratio.
**Listed here to show 0 & " for Peaking and Standby use only.
VI - 3
ENERGY COSTS --MILLS/KWH,
FUEL s. L.O. TOTAL ANNUAL COSTS
L.F.
0.66/0.8~ L.F. 0.66 L.F. O.8~
* ** * ** * ** 3.6 5.7 7.3 9.4 6.3 8.3
5.8 7.9 5. I 7.1
3.4 5.4 6.6 8.7 5.7 7.7
4.6 8.3 6.9 10.6 6.0 9.4
6.0 9.7 5.3 8.7
4.2 7.6 6.5 10.2 5.6 9.0
3.6 6.5 6.2 9.1 5.3 7.9
5.3 8.2 4.7 7.3
3.3 5.9 5.8 8.7 5.0 7.6
3.2 5.8 7.3 9.9 6.3 8.8
6.6 9.2 5.8 8.3
3. I 5.6 7.0 9.6 6.0 8.5
3.7 2.8 (min. )
2.1 1.9 (mi n.)
2 .8(mi n.) 2.8 (min.)
L.F. 0.10 L.F. ,0.10
3.7 20.7 22.9
* ** 14.2 16.4
5.9 17.3 19.5
3.4 18.0 20.0
* ** 14.6 16.6
5.4 16.3 18.3
4.15 15.3 18.6
* ** 11.4 14.7
7.45 13.3 16.6
3.82 15. I 18.1
* ** 11.9 14.9
6.86 13.6 16.6
3.6
/
The figures of Table 9 and 9A in the last col umns show average annual costs for particular
load factors. These ligures indicate that the Steam Plant Alternate is not competitive 0
The .steam plant has lower costs only for a case where the simple-cycle gas turbine has
fuel costs o-f 45 cents/106 BTU. Both gas engines and regenerative cycle gas furbines
are lower cost than the steam p'lant for all conditions. The Steam Plant Alternate will
not be considered further. Further inspection of the Table shows that the~egenerative
cycre gas turbine betters slightly the straight gas-fired engine for the average costs
of a 2-unit base load plant using 25-cent gas. It will also be noted, however, that for
added units of gas engines the average cost is less. For dua I-fuel operation using the
high-priced pilot fuel presently available, the simple-cycle gas turbine also betters the
average cost of the two-unit dual-fueled, base load engine plant. Additional units of
dual-fueled engines are better than the simple-cycle gas turbine on 25-cent gas. The
regenerative cycle gas turbine betters the engine for added units on 25-cent gas but not
on the higher pri ced gas.
The Tables also clearly show that for peaking power, the addition of a unit at Bradley
Lake is least expensive and that for thermal units, the gas turbines have the edge. This
assumes that the units are used as indicated (1,000 hours per year at an average loading
of 87--1/2%). There may be advantages in using a heavy duty unit for peaking on a
temporary basis during a systems growth, so unit costs for such operation have been de-
veloped. It also follows that for standby operation only (reserve capacity) the lower
cost E kilowatt units are favored.
The Table indicates the lowest average costs are provided by the Bradley Lake hydro-
electric project. This average cost assumes that the generating units are used to their
capacity under the load factors Tridicated. To determine the relative merits of alternate
generating plans, it is necessary to review these plans more carefully on a step-by-step
basis which recognizes the fact that a growing electrical load is to be served and it will
not be possible to load all generating units in the manner which will produce the
"average" costs indicated in the Tables 9 and 9A. No substation or transmission costs
are included in the figures of the TableSCi"nd these costs must be compared for the various
alternate plans.
Based on the review of the Tables 9 and 9A (see comments of preceding paragraphs)
three alternate plans (including transmisSIOn costs) will be compared on a step-by-step
basis to provide a more useful guide in the selection of a preferred generation scheme.
These are;
(A) Bradley Lake Hydro-electric Project 0
(B) Gas-Fired, Regenerative Cycle, Gas Turbine, Base Load Plant.
(C) Gas-Fired, Base Load Engine Plant 0
For the, purpose of comparing these alternate generation plans, a year-by-year com-
parison on an accrual basis is made in the following Tables for the additional facilities
required under each plan to serve the minimum loads forecast. The best of these plans
will then be combined on a cash basis with the cash costs for the existing Kenai
Peninsula power system to provide a forecast for the estimated overall delivered cost
of wholesale power to the Homer Electric Association, Inc.
VI-4
It will be further assumed that all presently installed, REA-financed generation on the
Kenai Peninsula will be used in the best manner practicable and that further, the
Bernice Lake Plant will be converted to gas-fired operation using 26-cent gas and can
be placed on standby service no later than 1972 if desirable.
All plans considered will contain the following escalations of cost through the years
compared beginning with 1967:
Operation and Maintenance Costs @' 3% per year
Thermal Plant Investment Costs @' 3.75 % per year
Hydro-electric Investment Costs @ 2. 0% per year
Substation Investment Costs @: 3.75% per year
simple accumulation
simple accumulation
simple accumulation
simple accumulation
These escalations are based on long-term indexes of the Bureau of Reclamation,
Engineering News-Record and local operating experience.
It is assumed further that the Seldovia loads will be served from the Kenai Peninsula
Electric System and that the generation capacity in Seldovia will be useful as standby
capacity only and not for prime energy supply.
All plans will include provision for reserrve capacity In an amount not less than
supplying 100 per cent of the deficiency that exists on the Kenai Peninsula with the
largest unit out of service. This is considered reasonable based on the existence of the
Transmission Tie to Anchorage and the fact that the total reserve requirements of the
two areas can be shared as a resulto (See Part inff Table 6 for Firm capability of the
existing interconnected Kenai Peninsula system). -
Gas well-head power plants are assumed to require about 7 miles of transmission line
to the Soldotna Substation which is used as the load center for comparative purposes.
The Bradley Lake Project will require 56 miles of line to this :same load center. This
load center is that one generally proposed In the Long Range Plan completed in 1962.
Unit costs for investment, operation and maintenance, annua I charges for depreciation
and interest, insurance and inter'im replacements and cost of losses are taken from the
estimates included in Appendices F, H, I and J.
Figures 14 and 15 show the demand-capability characteristics and one-line diagrams of
each alternate analyzed on the following Tables la, II, and 12.
V~-5
10
bO
-f'G-U~E 14-
. AtrEtz.}-JlXrE.-~~"
aEADl.E¥:-U~-R.O~?JaOJ seT
. ~~Aatt:q:"'r'~CUfO.le
-.EXl'S.il UJG'~-~-~.e'5 ~ILJpt=.: .:=-
' .... 'T'E~
...... (1 ..... P''''$=4--Io ... -:'' f>"
. 2BI~e~
CU5lN&
'0 ''2 , --'1'E,6..IO:.
A TE.J2 NAT:;: "C" '-
Q,~ "F\ R.Et:> = ~GllJE-:' PE~~~ -,..~j;,ell.~;T"'t' c.ul2.ve
, ___.-a:1:I'V't -unr--:.~.~~.-
19~ca.
~9&i9
~~7~
~91~
~~18 ~9a
'1'6
''16 'eo
FIGUlGE: \5
ALTEg~A\E-PLANS
6U~~rA.rIO~8 rRA~~MI.r&6\ON LI~e~
0...., e Llt-J = DIA..GTr2A.M6
.~~ (VI --~---'.
:&.R.WIC5 ~EA -t I . I
LAIGW 2~ 1lV I DI~T~.. r'2)
. PUTUlta Lt"'Ol P--
,g~ "Ze tWIt.
I to
-TO ~~I LOfll -.... ..;;;.;:;;;~~:..,......-+-I +--+--4 t HOMER.
~ L T t; f2. t--J A.T E: " e"
~Ge\J, CVCU::, Q-A6 TU~Blt-.lE. pL~NT
~
~.
:-<0 FIR.~r ~f&P -l'3b9
t'2J~r:coNt)&j TEP ~ {97 ~
\.3) TH1£t) ~rep -197"
Q)(I'STI~G IO~."'"
'!>\\'I~~ '2T~rlotiJ (E=lJTU~ ~UIY.tTp..lION)
TABLE 10
ALTERNATE A --BRADLEY LAKE HYDRO-PROJECT POWER SUPPLY --14 YEAR COST PROJECTION (ADDED PLANT ONLY)
Item Description 1967 1968 1969 1970 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980
Existing Intertied Gen. Plants
(1) Total Capability KW 32,050 32,050 32,050 32,050 32,050 32,050 32,050 32,050 32,050 32,050 32,050 32,050 32,050 32,050
(2) Fi rm Capabi Ii ty KW 23,050 23,050 23,050 23,050 23,050 23,050 23,050 23,050 23,050 23,050 23,050 23,050 23,050 23,050
(3) Norrrol Capacity KW 22,500 22,500 22,500 22,500 22,500 22,500 22,500 22,500 22,500 22,500 22,500 22,500 22,500 22,500
(4) Available Energy MWH 93,000 93,000 93,000 93,000 93,000 93,000 53,000 ** 53,000 53,000 53,000 53,000 53,000 53,000 53,000
HEA, KL, & Seward
Requi rements
(5) Capacity KW 12,500 14,900 18,000 21,500 24,100 27,100 30,500 34,400 38,700 42,300 46, ?50 50,500 55,300 60,600
(6) Energy MWH 64,500 78,700 96,300 116,700 130,700 147,000 166,300 187,000 219,400 240,300 262,900 288,500 316,200 345,500
Net HEA Requirements
(7) Capacity KW None None None None 1,600 4,600 S,OOl' 11,900 16,200 19,800 23,750 28,000 32,800 38,100
(8) Energy MWH None None 3,300 23,700 37,700 54,000 113,300 134,000 166,400 187,300 209,900 235,500 263,200 292,500
Proposed Added Generation
8,500 (See Remarks) (9) New Capacity, this year KW 25,000 25,000
(10) Accum. Cap'y., prior years KW 8,500 8,500 8,500 8,500 33,500 33,500 33,500 58,500 58,500 58,500 58,500
(11 ) New Substa. this year Kva 10,000 25,000 25,000
( 12) Accum. Cap'y., prioryears Kva 10,000 10,000 10,000 10,000 35,000 35,000 35,000 60,000 60,000 60,000 60,000
* Remarks: First unit added in last quarter of 1969 at Bemice Lake. Operated briefly for energy only in 1969. Costs for this unit are "added uni til (See Appendix F.) because of Berni ce Lake. Existing facilities
and staff. Figure 14 and 15 show unit scheduling and capability. Ber ni ce Lake PI ant can go on standby in 1973.
Investments, New Gen.
( 13) New Capacity, this year $ 1,505,000 15,252,000 8,899,000
(14) New Capacity, prior years $ 1,505,000 1,505,000 1,505,000 1,505,000 16,757,000 16,757,000 16,757,000 25,656,000 25,656,000 25,656,000 25,656,000
( 15) New Substa. this year $ 168,800 260,100 223,463
(16) New Substa. prior years $ 168,800 168,800 168,800 168,800 428,900 428,900 428,900 652,363 652,363 652,363 652,363
( 17) Total Gen. Invest. to Date $ 1,505,000 1,505,000 1,505,000 1,505,000 16,757,000 16,757,000 16,757,000 25,656,000 25,656,000 25,656,000 25,656,000 25,656,000
(18) Total Sub. Invest. to Date $ 168,800 168,800 168,800 168,800 428,900 428,900 428,900 652,363 652,363 652,363 652,363 652,363
Annual "Fixed" Costs--New Gen.
( 19) O&M (Gen.) added this yr. $ None 96,800 65,000
(20) O&M (Gen.) from prior yrs. $ 47,600 48,875 50,150 None** 99,200 101,600 104,000 172,900 176,800 180,700 184,600
(21) O&M (Sub.) added this yr. $ None 7,563 8,125
(22) O&M (Sub.) from prior yrs. $ 2,800 2,875 2,950 3,025 10,850 11, 113 11,375 19,950 20,400 20,850 21,300
(23) Depr. & Int. 4/3.18% of (17) $ 15,050 60,200 60,200 60,200 545,214 545,214 545,214 828,202 828,202 828,202 828,202 828,202
(24) Depr. & Int. 3.85% of (18) $ 1,625 6,500 6,500 6,500 16,513 16,513 16,513 25, 116 25, 116 25,116 25,116 25,116
(25) Ins. & Repl. 0.9/0.2% of(17)$ 3,386 13,545 13,545 13,545 44,049 44,049 44,049 61,847 61, 847 61,847 61,847 61,847
(26) Ins. & Repl. 0.6% of (18) $ 253 1,013 1,013 1,013 2,573 2,573 2,573 3,914 3,914 3,914 3,914 3,914
Annual Variable Costs--New Gen.
(27) Fuel & Lube @ 2.9 mi II s/kwh" $ 9,5'''0 8,730 109,230 156,600 ( 78,288)** ( 78, 28~** ( 78,288) ** (78,288) ** (78,288) ** ( 78,288) ** ( 78,288)**( 78,288) **
(28) Losses (Substa.) $ 527 1,600 3,000 3,500 5,000 6,000 7,500 8,000 9,500 10,000 12,000 13,200
Total Annual Costs--New Gen.
(29) "Fixed" Costs --Total $ 20,314 131,658 133,008 134,358 715,737 718,399 721,062 1,107,579 1, 111,929 1, 116,279 1,120,629 1,124,979
(30) Variable Costs --Total $ 10,097 70,330 112,330 16J,100 ( 73,288) ( 72,288) ( 70,788) ( 70,188) ( 68,788) ( 68,288) ( 66,2@8) ( 65,088)
(31) TOTAL --New Gen. $ 30,411 201,988 245,338 294,458 642,449 646,111 650~294 1,037,291 1,043, 141 1,047,991 1,054,341 1,059,891
Transmission Costs --New
(32) Investment 25/56 mi .69/138kv$ 2,661,900 2,661,900 2,661,900 2,661,900 2,661,900 2,661,900 2,661,900 2,661,900
(33) Step-down Substa. $ 223,463 223,463 223,463 466,838 466,838 466,838 466,838 466,838
(34) Circuit Interruption $ 267,000 267,000 267,000 267,000 570,000 570,000 570,000 680,000 680,000 680,000 680,000 680,000
(35) TOTAL $
Annual Costs Trans. --New
267,000 267,000 267,000 267,000 3,455,363 3,455,363 3,455,363 3,808,738 3,808,738 3,808,738 3,808,738 3,808,738
g~ O&M Lines t 28,254 28,954 29,655 30,355 31,056 31,756 32,457 33, 157
O&M Step-down Substa. 3,270 3,360 3,450 3,540 7,563 7,750 7,938 16,250 16,625 17,000 17,375 17,750
(38) Depr. & Int. @ 3.85% (35) $ 10,280 10,280 10,280 10,280 133,032 133,032 133,032 146,636 146,636 146,636 146,636 146,636
(39) Ins. & Replace., 0.2%(32) $ 5,322 5,322 5,322 5,322 5,322 5,322 5,322 5,322
(40) Ins. & Replace., 0.6%(33+34) 1,602 1,602 1,602 1,602 4,761 4,761 4,761 6,881 6,881 6,881 6,881 6,881
~1J~ Losses, Une $ 7, 100 10,900 16,]00 21,000 23,500 37,000 43,000 .57,800
Losses, Subs to. $ 4,800 5,500 6,500 8,000 9,600 10,000 11,000 12,000
(43) TOTAL --NEW TRANS $ 15,152 15,242 15,332 15,422 190,832 196,219 203,908 234,444 244,620 254,595 262,671 279 ,546
TOT AL ANNUAL COSTS--NEW G&T
(44) Yearly New G & T Cost $ 45,563 217,230 260,670 309,880 833,281 842,330 854, 182 1 ,?71, 735 1,287,761 1, 302~586 1,317,0)9 1,339,437
(45) Average Delivered--Mills/kwh 13.8 9.2 6.9 5.7 7.4 6.3 5.1 6.8 6. 1 5. 5.0 4.6
(46) Accum. Ave. Cost Del. Mills/kwh 13 8 9.7 8.1 7.0 7.2 6.9 6.3 6.4 6.4 6.2 6.0 5.7
* Unit installed at Bernice Lake with assumed gas price of 26 c /1O° B.T.U. and an escalation of 0.16 mills/kwh in 1972 and 0.36/kwh in 1977.
** The avai lable capacity and energy from the first unit of Bradley Lake can allow the Bern ice Lake Plant to go on standby service with a net fuel savi ng of about $ 78,288 annually.
Vl-8 TABLE 10
YEAR
MWH 3
x' 10
1969
(3.3)
3.3
1970
(27.0)
23.7
1971
(64.7)
37.7
1972
(118.7)
54.0
1973
(232.0)
113.3
1974
(366.0)
134.0
1975
(532.4)
166.4
1976
(719·1)
187.3
1977
·(929.6)
209.9
1978
(1,165.1)
235.5
1979
(1,428.3)
263.2
1980
(1,720.8)
292.5 .
SUPPLEMENT TO TABLE !Q (HYDRO)
EFFECT OF INTEREST RATE ON ENERGY COSTS
2% 3%
INVEST. D & I MI D & I MI
4%
D & I MI
$1.000Is $ lM'1 S KWH $ 1 M ~ s KWH~ $ 1 M'I;.S KWH*
1.505 15 18 20
169 2 2 3
267 10 (13. 8~ 12 (15.3) 14 (16.8)
T 1.941 27 13.8 32 15.3 37 16.8
60 I 70 tlO
7 I 8 9
10 (9.7)1 12 pO.4) 14 ( 11.0)
T 1.9Zj:l 77 9.2 90 I 9.8 103 10.3
,
-(8.1) -(8.6) -(9.1)
T 1 .941 77 6.9 90 7.2 103 7.6
I (] .4) -(] .0) -103
(].7)
T 1,941 77 5.7 90 I 5.9 6.2 !
H 15,252 485 592 I 708
D 1,505 60 70 I 80 I 429 17 19 1 22
3 z455 133 (] .2) 156 I (8.0) 180 (8.9)
T 20 641 695 7.4 837 fl..? 990 10.0
(6.9) (] .8) -(8.8)
T 20,641 695 6.3 837 7.4 990 8.5
(6.3) (] .2) -(8.1)
T 20.641 695 5. 1 837 6.0 990 6.9
24, 151 768 939 1 , 120
1,505 66 70 80
652 25 29 34
3 2 80 9 147 (6.4) 172 (] .3) 199 (8.4)
T 30, 117 1,006 6.8 1 ,210 7.9 1,433 9. 1
(6.4) (7.4): (8.4)
T 30,117 1,006 6. 1 1 ,210 7.1 1,433 8.3
(6.2) (].1) (8.1)
T 30.117 1.006 5.5 1 .210 6.4 1,433 7.3
(6.0) (6.9) (] .9)
T 30,117 1,006 5.0 1 ,210 5.8 1,433 6.6
(5.7 (6.6) (] .5)
T 30,117 1,006 4.6 1,210 5.3 1,433 6.1
( ) Figures in parenthesis are the accumulated totals and averages.
5%
D & I MI
$ 1 M"~s KWH *
23
3
16 (18.4)
42 18.4
92
10
16 '(11.3)
TI8 10.9
i (9.6)
liB ! 8.0
TI8
(8. 1)
6.5
836
92
26
207 (9.8)
1 , 161 I 11.5
(9.8)
1 , 161 9.8
(9.2)
1 , 161 7.9
1 ,323
92
39
228 (9.5)
1,682 10.4
(9.5)
1,682 9.3
(9.3)
1,682 8.4
(9.0)
1,682 7.6
(8.5)
1,682 6.9
.-
* HillslKWH are determ.ined by taking the difference between Depr. & Int. at 2% and the
new interest rate, dividing by HWH and adding to millslKWH @ 2%.
VI-8a
Item
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(9)
(10)
(11 )
(12)
( 13)
(14)
(15)
(16)
H~
( 19)
(20)
(21)
(22)
(23)
(24)
(25)
(26)
(27)
(28)
(29)
(30)
(31)
(32)
(33)
(34)
(35)
(36)
(37)
g~l (40
(41
(42)
(43)
~fs~
(46)
Description
Existing Intertied Gen. Plants
Total Capability KW
Firm Capabi lity KW
Normal Capaci ty KW
Available Energy MWH
HEA, KL, & Seward Requirements
CaPQcity KW
Ererw MWH
Net HEA Requi rements
Capacity KW
Energy MWH
Proposed Added Generation
1967
32,050
23,050
22,500
93,000
12,500
64,500
None
None
TABLE 11
ALTERNATE B --GAS TURBINE POWER SUPPLY --14 YEAR COST PROJECTION (ADDED PLANT ONLY)
1968
32,050
23,050
22,500
93,000
14,900
78,700
None
None
1969
32,050
23,050
22,500
93,000
18,000
96,300
None
3,300
1970
32,050
23,050
22,500
93,000
21,500
116,700
None
23,700
1971
32,050
23,050
22,500
93,000
24, 100
130,700
1,600
37,700
1972
32,050
23,050
22,500
93,000
27,100
147,000
4,600
54,000
1973
32,050
23,050
22,500
* 93,000
30,500
166,300
8,000
73,300
1974
32,050
23,050
22,500
93,000
34,400
187,000
11,900
94,000
1975
32,050
23,050
22,500
93,000
38,700
219,400
16,200
126,400
1976
32,050
23,050
22,500
93,000
42,300
240,300
19,800
147,300
1977
32,050
23,050
22,500
93,000
46,250
262,900
23,750
169,900
1978
32,050
23,050
22,500
93,000
50,500
288,500
28,000
195,500
1979
32,050
23,050
22,500
93,000
55,300
316,200
32,800
223,200
1980
32,050
23,050
22,500
93,000
60,600
345,500
38,100
252,500
New Capacity, this year KW 8,500* 19,000 19,000
Accum. Caply" prioryrs. KW 8,500 8,500 8,500 8,500 27,500 27,500 27,500 46,500 46,500 46,500 46,500
New Substa. this year Kva 10,000 25,000 25,000
Accum. Cap'y.,priorlrs. Kva 10,000 10,000 10,000 10,000 35,000 35,000 35,000 60,000 60,000 60,000 60,000
Rermrks:*First urit adde in last quarter of 1969. Operated briefly for energy only the first year. Beginning 1973 engine will produce 70,000 MWH annually, Figure 14 & 15 show scheduling and capabilities.
Capabilities are based on nameplate rating of ne.v machines and actual proven capabilities of existing plants,
Investments, New Gen.
New Capacity, this year $
New Capacity, prior years $
New Substa., this year $
New Substa., prior years $
Total Gen. Invest. to Date $
Total Sub. Invest. to Date $
Annual "Fixed" Costs--New Gen.
O&M(Gen.) added this yr. $
O&M(Gen.) from prior yrs. $
O&M(Sub.) added this yr. $
O&M(Sub.) from prior yrs. $
Depr. & Int. 4% of (17) $
Depr. & Int. 3.85% of (18) $
Ins. & Rep I. O. 9% of (I 7) $
Ins. & Repl. 0.6% of (18) $
Annual Variable Costs --New Gen.
Fuel & Lube Oil ** $
LQ.SslU (Substa.) $
Total Annual Costs -New Gen.
"Fixed" Costs --Total $
Variable Costs --Total $
TOTAL -NEW GEN. $
Transmission Costs -New
Investment 7/18 mi. 138/69kv$
Step-down Substa. $
Circuit Interruption $
TOTAL $
Annual Costs Trans. -New
O&M lines $
O&M Step-down Substa. $
Depr. & Int. @ 3,85%(35) $
Ins. & Replace.,0.2% (32) $
Ins. & Replace., 0.6%(33+34)
Losses, li ne $
Losses, Substa. $
TOT Al. -NEW TRAN S. $
TOTAL ANNUAL COSTS -NEW G&T
Yearly New G & T Cost $
Average Delivered-Mills/kwh
Accum. Ave. Del. -Mills/kwh
1,690,000
168,800
1,690,000
168,800
9,265
681
16,900
1,625
3,803
253
9,240
527
32,527
9,767
42,294
259,700
267,000
526,700
2,726
4,450
20,278
519
1,602
100
29/675-
71,969
21.8
21.8
1,690,000
168,800
1,690,000
168,800
119,000
2,800
67,600
6,499
15,210
1,013
66,360
1,500
212, 122
67,860
279,982
259,700
267,000
526,700
2,818
4,600
20,278
519
1,602
210
30,027
310,009
13. 1
14. 1
1,690,000
168,800
1,690,000
168,800
122,200
2,875
67,600
6,499
15,210
1,013
105,560
3,000
215,397
108,560
323,957
259,700
267,000
526,700
2,909
4,750
20,278
519
1,602
600
30,658
354,615
9.4
11.4
1,690,000
168,800
1,690,000
168,800
125,400
2,950
67,600
6,499
15,210
1,013
159,840
3,500
218,672
163,340
382,012
259,700
267,000
526,700
3,001
4,900
20,278
519
1,602
1,300
31,600
413,612
7.7
9.7
3,856,934
1,690,000
202,000
168,800
5,546,93-4
370,800
167,913
59,969
7,891
3, 156
221,.877
14,276
49,922
2,225
219,740
6,000
5.27,229
225,740
752,969
567,500
570,000
1, 137,500
6,502
10,100
43,794
1,135
3,420
2,000
66,951
819,920
11.2
10.3
5,54G,934
370,800
~546,g34
370,800
234,650
11,375
221,877
14,276
49,922
2,225
298,400
6,500
534325
304;900
83~22~
567,500
570,000
1,137,500
6,695
10,400
43,794
I, 135
3,420
2,500
67,944
907,169
9.7
10.1
5,546,934
370,800
~546,934
370,800
241,419
11,703
221,877
14,276
49,922
2,225
421,520
8,500
3,474,625
5,546,934
220:000
370,800
9,021,559
590,800
91,438
248, 188
8,594
12,031
360,862
22,746
81,194
3,545
500,940
10,500
9,021,559
590,800
9,021,559
590,800
348,888
21, 188
36q862
22,746
81,194
3,545
618,000
12,000
541,422 828,598 838423
430,020 511,440 630',000
971,442 1,340p~ "',468,4'23
567,500 567,500 567,500
673,750 673, 750
570,000 570,000 570,000
I, 137,500 1,811,250 1,811,250
6,888
10,700
43,794
1, 135
3,420
3,500
69,437
7,081
34,375
69,733
I, 135
7,463
1,000
4,000
l24,787
7,274
35,313
69,733
1, 135
7,463
1,500
4,500
126,918
1,040.879 1,464,825 1,595,341
8.2 9.9 9.4
9.5 9.6 9.6
~021,559
590,800
9,021,559
590,800
358, 150
21,750
360,862
22,746
81,194-
3,545
720,400
13,700
8482 .. 7
734: 100
1582347 I ,
567,500
673,750
570,000
1,811 ,250
7,468
36,250
69,733
1, 135
7,463
2,000
5,000
129,049
9,021,559
590,800
9,021,559
590,800
367,413
831,200
16,000
858p73
847, 200
1705273 , .
567,500
673,750
570, 000
1,811,250
7,660
37,188
69,733
1, 135
7,463
2,500
5,500
131,179
1,711,396 1,836,452
8.B 8.2
9.4 9.2,
** @ 2.8 mills/kwh for engine and 3.6 mills/kwh for Gas Turbines with escalation of 0.16 and 0.20 mills/kwh in 1972 and 0.32 and 0.40 mills/kwh in 1977 for engine and turbine respectively.
9,021,559
590,800
~021,559
590,800
376,675
22,875
36-0 .. 862
22,746
81,194
3,545
948,400
16,500
867.897
964,900
1832797 . ,
567,500
673,750
570,000
1,811,250
7,854
38,125
69,733
1, 135
7,463
3,000
6,000
133,310
1,966,107
7.8
8.9
VI-9 VI-9 TABLE 11
TABLE 12
ALTERNATE C --GAS ENGINE POWER SUPPLY --14 YEAR COST PROJECTION (ADDED PLANT Cl'JLY)
Item Description 1967 1968 1969 1970 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980
Existing Intertied Gen. Plants
(1) Total Capability KW 32,050 32,050 32,050 32,050 32,050 32,050 32,050 32,050 32,050 32,050 32,050 32,050 32,050 32,050
g~ Firm Capabi lity KW 23,050 23,050 23,050 23,050 23,050 23,050 23,050 23,050 23,050 23,050 23,050 23,050 23,050 23,050
Normal Capacity KW 22,500 22,500 22,500 22,500 22,500 22,500 22,500 22,500 22,500 22,500 22,500 22,500 22,500 22,500
(4) Available Energy MWH 93,000 93,000 93,000 93,000 93,000 93,000 93,000 93,000 93,000 93,000 93,000 93,000 93,000 93,000
HEA, KL, & Seward
Requirements
(5) Capacity KW 12,500 14,900 18,000 21,500 24,100 27,100 30,500 34,400 38,700 42,300 46,250 50,500 55,300 60,600
(6) Energy MWH 64,500 78,700 96,300 116,700 130,700 147,000 166,300 187,000 219,400 240,300 262,900 288,500 316,200 345,500
Net HEA Requirements ?) Capacity KW None None None None 1,600 4,600 8,000 11,900 16,200 19,800 23,750 28,000 32,800 38, 100
8) Energy MWH None None 3,300 23,700 37,700 54,000 73,300 94,000 126,400 147,300 169,900 195,500 223,200 252,500
Proposed Added Generation
(9) New Capacity, this year KW 8,500* 8,500 8,500 8,500 8,500
g?~ Accum. Cap'y., prioryears KW 8,500 8,500 8,500 8,500 17,500 17,500 17,500 26,000 26,000 34,500 34,500
New Substa. th is year Kva 10,000 10,000 10,000 10,000 10,000
(12) Accum. Cap'y., prioryearsKva 10,000 10,000 10,000 10,000 20,000 20,000 20,000 30,000 30,000 40,000 40,000
* Remarks: First unit added in last quarter of 1969. Operated briefly for energy only the first year. See Figures 14 and 15 for scheduling of major faci lities and the establishment of firm capabi lity.
Capabilities are based on nameplate rating of new machines and actual proven capabi lity of existing plants.
Investments, New Gen.
(13) New Capacity, this year $ 1,690,000 1,708,000 1,860,000 1,961,000 2,063,000
(14) New Capacity, prior years $ 1,690,000 1,690,000 1,690,000 1,690,000 3,398,000 3,398,000 3,398,000 5,258,000 5,258,000 7,219,000 7,219,000
(15) New Substa. thi s year $ 168,800 157,500 171,600 180,900 190,300·
(16) New Substa. prior years $ 168,800 168,800 168,800 168,800 326,300 326,300 326,300 497,900 497,900 678,800 678,800
(17) Total Gen. Invest. to Date $ 1,690,000 1,690,000 1,690,000 1,690,000 3,398,000 3,398,000 3,398,000 5,258,000 5,258,000 7,219,000 7,219,000 9,282,000
(18) Total Sub. Invest. to Date $ 168,800 168,800 168,800 168,800 326,300 326,300 326,300 497,900 497,900 678,800 678,800 869,100
Annual "Fixed" Costs--New Gen.
(19) O&M (Gen.) added this yr. $ 9,265 51,400 55,300 57,800 60,350
(20) O&M (Gen.) from prior yrs. $ 119,000 122,200 125,400 128,600 184,500 188,900 193,400 254,400 260,100 324,900 331,900
(21) O&M (Sub.) added this yr. $ 681 3,025 3,250 3,400 3,550
(22) O&M (Sub.) from prior yrs. $ 2,800 2,875 2,950 3,025 6,200 6,350 6,500 9,975 10,200 13,900 14,200
g~~ Depr. & Int. 4o/00f (17) $ 16,900 67,600 67,600 67,600 135,920 135,920 135,920 210,320 210,320 288,760 288,760 371,280
Depr. & Int. 3.85% of (18) $ 1,625 6,499 6,499 6,499 12,563 12,563 12,563 19,169 19,169 26,134 26,134 33,460
(25) Ins. & Rep\. 0.9% of (17) $ 3,803 15,210 15,210 15,210 30,582 30,582 30,582 47,322 47,322 64,971 64.,971 83,538
(26) Ins. & Repl. 0.6% of (18) $ 253 1,013 1,013 1,013 . 1,958 1,958 1,958 2,987 2,987 4,073 4,073 5,215
Annual Variable Costs--New Gen.
a~ Fuel & Llhe @ 2.8 mills/1<wh·~ 9,240 66,360 105,560 159,840** 216,970 278,240 374,140 436,000 530,100 ** 609,960 696,384 787,800
Losses (Substa.) $ 527 1,500 3,000 3,500 6,000 6,600 7,700 10,500 11,100 14,000 15,000 17,500
Total Annual Costs-New Gen.
(29) "Fixed" Costs --Total $ 32,527 212,122 215,397 218,672 367,073 371,723 376,273 538,248 544,173 715,438 722,738 903,493
(30) Variable Costs --Total $ 9,767 67,860 108,560 163,340 222,970 284,840 381,840 446,500 541,200 623,960 711,384 805,300
(31) TOTAL --New Gen. $ 42,294 279,982 323,957 382,012 590,043 656,563 758,113 984,748 1,085,373 1,339,398 1,434,122 1,708,793
Transmission Costs --New
(32) Investment 7/18mi . 138/69kv $ 259,700 259,700 259,700 259,700 567,500 567,500 567,500 567,500 567,500 567,500 567,500 567,500
(33) Step -down Subs ta . $ 673,750 673,750 673,750 673,750 673,750
(34) Circuit Interruption $ 267,000 267,000 267,000 267,000 570,000 570,000 570,000 570,000 570,000 570,000 570,000 570,000
(35) TOTAL $ 526,700 526,700 526,700 526,700 1,137,500 1,137,500 1,137,500 1,811,250 1,811,250 1,811,250 1,811,250 1,811,250
Annual Costs Trans. --New
g~ O&M Lines $ 2,726 2,818 2,909 3,001 6,502 6,695 6,888 7,081 7,274 7,468 7,660 7,854
O&M Step-down Substa. "$ 4,450 4,600 4,750 4,900 10,100 10,400 10,700 34,375 35,313 36,250 37,188 38,125
(38) Depr. & rnt. 3.85%(35) $ 20,278 20,278 20,278 20,278 43,794 43,794 43,774 69,733 6v;7J3 6«1;733 6lT,733 69,733
(39) Ins. & Replace., 0.2%(32) $ 519 519 519 519 1,135 1,135 1,135 1, 135 1,135 1,135 1,135 1,135
~!?~ Ins. & Replace., 0.6%(33+34) $ 1,602 1,602 1,602 1,602 3,420 3,420 3,420 7,463 7,463 7,463 7,463 7,463 Losses, Line --$ 100 210 600 1,300 2,000 2,500 3,500 1,000 1,500 2,000 2,500 3,000 (42) Losses, Substa. $ 4,000 4,500 5,000 5,500 6,000 (43) TOTAL --New Trans. $ 29,675 30,027 30,658 31,600 66,951 67,944 69,437 124,787 126,918 129,049 131,179 133,310
TOTAL ANNUAL COSTS --NEW G&T
(44) Yearly New G&T Cost $ 71,969 310,009 354,615 413,612 656,994 724,507 827,550 1,109,535 1,212,291 1,468,447 1,565,301 1,8423103 ~45) Average Delivered--Mills/1<wh 21.8 13. 1 9.4 7.7 9.0 7.7 6.5 7.5 7. I 7.5 7.0 7.
46) Accum. Ave. Del. --Mills/1<wh 21.8 14. I 11.4 9.7 9.4 8.9 8~ 1 8.0 7.8 7.7 7.6 7.5
** With escalation of 0.16 mills/1<wh in 1972 & 0.32 mills/1<wh in 1977.
VI-1O Vl-1O TABLE 12
MWH
YEAR x 10 3
1969
(3.3)
3.3
1970
(27.0)
23.7
1971
(64.1)
37.7
1972
(118.7)
54.0
1973
(192.0)
73.3
1974
(286.0)
94.0
1975
(412.4)
126.4
1976
(559.7)
147.3
1977
(729.6)
169.9
1978
(925. 1)
195.5
1979
(1. 148.3)
223.2
1980
(1,400.8)
252.5
SUPPLEMENT TO TABLE 12 (GAS-ENGINES)
EFFECT OF INTEREST RATE ON ENERGY COSTS
2% 0 3%
INVEST. 0&1 M/ 0&1 M/
$I,OOO's $ 1M' s KWH $ lM's KWH*
1,690 17 20
169 2 2
0&1
$ lM's
23
3
527 20 (21. 6) 24 (23.9) -.ll T 2.386 39 21.8 46 23.9 53
68 79 90
6.5 8 9
20 ~ 14.1) 24 (15.0) 27
T 2.386 94.5 13.1 TIT 13 .8 126
~ 11.4) (12.0)
T 2,386 94.5 9.4 1 1 1 9.8 126
(9.7) (10.2)
T 2.386 94.5 ].7 TIT 8.0 126
3,398 136 158 182
326 13 15 17
1 z 138 44 (9.4) 51 (9.9) 59
T 4 862 193 9.0 224 9.4 258
-(8.9) (9.3)
T 4,-862 193 7.7 224 8.0 258
(8.1) -(8.5)
T 4,862 193 6.5 224 6.7 258
5.258 210 239 282
498 19 23 26
1 z 811 .-El (8.0) 82 (8.3) 95
T 7.567 299 7.5 344 7.8 403
-(7.8) -(8.1)
T 7,567 299 7. 1 344 7.4 403
7,219 289 335 388
679 26 31 35
.L.M! 70 (7.7) 82 (8.0) 95
T 9 709 385 7.5 448 7.8 518
(7.6) (7.9)
T 9.709 385 7.0 448 7.3 518
9.282 371 451 499
869 33 39 45
1 z 811 70 (7.5) 82 (7.8) 95
T 11.962 474 7.3 572 7.7 639
4%
M/
KWH*
~26. 0)
26.0
15.8)
14.4
12.6)
10.2
10.6)
8.3
10.3)
9.9
(9.7)
8.4
(8.8)
7.0
(8.7)
8.2
(8.5)
7.7
(8.4)
8.2
(8.3)
7.6
(8.2)
8.0
( ) Figures in parenthesis are the accumulated total and averages.
5%
0&1 M/
$ 1M's KWH *
26
3
32 ~28.5)
6f 28.5
103
10
32 16.8)
145 15.3
13 .3)
145 10.8
11.2)
145 8.6
207
20
68 (10.8)
295 10.4
10.2) -295 8.8
-I (9.3)
295 7·3
321
30
108 (9.1)
459 8.6
(8.9)
459 8.0
440
41
108 (8.8)
589 8.5
(8.7)
589 7.9
567
52
108 (8.5)
727 8.3
* Mills/KWH are determined by taking the difference between Depr. & Int. @ 2% and the
new interest rate. divided by MWH and adding to mills/KWH @ 2%.
VI-lOa
The results of comparing Alternate Plans A, B, and C on Tables 10, 11 and 12 show clearly
how they differ in costs year by year over the 14-year period anTaccumulaTIVely. The total
differences in costs between the Alternates is shown below:
Alternate A
Alternate B
Alternate C
14-YR.ACCUM.COST
9,881,674
12,492,294
10,556,933
TOTAL MWH DELIVERED & AVERAGE COST
DIFFERENCE FROM A
2,610,620
675,259
Alternate A --1,720,800 MWH @ 5.7424 mills/KWH
Alternate B --1,400,800 MWH @ 8.917 mills/KWH
Alternate C ---1,400,800 MWH @ 7.5363 mills/KWH
Alternate A not only shows a substantially lower total cost but also delivers about 320,000
MWH more energy than the other plans. This happens because the hydro project has suffi-
cient energy to allow placing Bernice Lake on standby service with the resulting saving in
fuel cost.
Alternate A is studied on a cash basis combined with the existing facilities on the Kenai
Peninsula. This study (see Table 14) shows the results of absorbing all costs on the Kenai
Peninsula. The investments considered of the existing faci lities aretnose shown on Table
]1 and include the transmission system to Turnagain Arm.
No credit was taken for possible power sales through this tie line --either firm or secondary.
No credit was taken for reserve capacity which it might provide.
With all this facility charged to the project and using cash costing the cost per KWH reaches
a low of 7.4 mills and averages 9.2 mills for the 14-year period. This is a pessimistic
approach and represents the worst probable circumstances.
Figures on Alternate A for Table 14 were taken from Table 10 and converted to a cash basis
as follows: --
DEBT SERVICE INT. & REPLACEMENT
Gas Engines 2% Int. only --3 yrs. 0.9%
4.24% after 1st 3 yrs. 0.9%
Substation 2% Int. only --3yrs. 0.6%
4.24% after 1st 3 yrs. 0.6%
Hydro-Plant 2% Int. only --5 yrs. 0.2%
4.44% after 5 yrs. 0.2%
Trans. Plant 2% Int. only --3 yrs. 0.2%
4.24% after 3 yrs. 0.2%
VI-ll
YEAR
1967
1967
1967
1967
1967
1968
1968
1968
1968
1968
1969
1969
1969
1969
1969
1970
1970
1970
1970
1970
1971
1971
1971
1971
1971
1972
1972
1972
1972
1972
1973
1973
1973
1973
1973
TABLE Jl
INVESTMENT AND PRODUCT~ON (CASH)COSTS
EXiSTING GENERATION --KENA! PENINSULA
AVE. KW~ ANNUAL COSTS(G&T)--$1 ,0001S
xl0 0 & M DEBT FUEL~'(";'~ $
DEVO. AOM~N. ~NS. & Loss@.·003 TOTAL
GRAND COST
TOTAL M I LLS/KWH
Cooper Lake Plant* 25
Bernice Lake Plant* 40
Homer & Seldovia (Standby)*
Transmission & Sub. 115* 7
Transmission & Sub. 69* 58
Cooper Lake Plant 39
Bernice Lake Plant 40
Homer & Seldovia (Standby)
Transmission & Sub. 115 9
Transmission & Sub. 69 70
Cooper Lake Plant 53
Bernice Lake Plant 40
Homer & Seldovia (Standby)
Transmission & Sub. 115 13
Transmission & Sub. 69 80
Cooper Lake Plant 53
Bernice Lake Plant 40
Homer & Seldovia (Standby)
Transmission & Sub. 115 17
Transmission & Sub. 69 76
Cooper Lake Plant
Bernice Lake Plant
Homer & Seldovia (Standby)
Transmission & Sub. li5 17
Transmission & Sub. 69 76
Cooper Lake Plant
Bernice Lake Plant
Homer & Seldovia (Standby)
Transmission & Sub. liS 19
Transmission & Sub. 69 74
Cooper Lake Plant 53
Bernice Lake Plant 0
Homer & Seldovia (Standby)
Transmission & Sub. 115 20
Transmission & Sub. 69 33
55
185
8
27
16
57
189
8
28
16
58
193
8
29
17
60
197
9
30
17
61
201
9
31
18
63
205
9
32
18
64
209
10
33
19
368
129
48
102
59
368
129
48
102
59
379
129
48
102
59
379
129
48
102
59
379
129
48
102
59
390
129
48
102
59
390
129
48
102
59
78
1
78
o
78
I
78
o
78
1
78
o
o
I
424
393
57
1 130
3 78
426
397
56
I 131
5 80
438
401
57
I 132
6 82
440
405
57
I 133
6 82
441
409
58
I 134
6 83
454
413
57
1 135
6 83
0 .. _._ .. 455
0""" .339
60
0 .. _._ .. 136
0'''''' 84
1,082
1 ,090
1 , 110
1 , 117
1 , 125
1 , 142
1,074
~':Cooper Lake -Investment. ....... $7,926,203 (aJ 4.44 + 0.2 = 4.64
16.6
13.8
11.9
12.0
12. I
12.3
20.2
Add Stetson Creek (1969)..... 500,000 @ 4.24 + 0.2 = 4.44 (3 yrs. int.only)
Bernice Lake Investment o.oo~o •• 29500~OOO @ 4.24 + Oe9 = 5814
Homer and Seldovia ....... " .... 931,122 @4.24+0.9 5.14
Trans. & Sub., 115 K\I (45n;,).~ 2,200,000 @ 4.44 + 0.2 = 4.64
Trans. & Sub., 69 KV (86 mi.), •• 1,333,625 @ 4.24 + 0.2 = 4.44
id(cU 26¢/l0 6 BTU and Steam Credit until 1973 when plant goes standby.
i(";~*Loss costs are zero when excess hydro energy is available.
V!=12
TABLE 14
KENAI PENINSULA EXISTING SYSTEM, PLUS ALTERNATE A --NEW
14 --YEAR CASH COST PROJECTION
KWH 6 ANNUAL COSTS {GEN.) --~1,000's ANNUAL COSTS {TRANS.) --~ 1,000' 5 AVE.
x 10 o &. M DEBT* o &. M DEBT'" GRAND COST
YEAR DEL'D. ADMIN. INS. &. FUEL LOSSES TOTAL ADMIN. INS. &. LOSSES TOTAL TOTAL MILLS/KWH
1967 E 65 248 545 79 2 874 43 161 4 208 1,082 16.7
1967 N ------1967 T 65 ill m 79 '2 m 1i3 m 1+ 20S T:OB2 T6."7
'9(;8 E 79 254 545 78 2 879 44 161 6 211 1,090 13.8
1968 N --
1968 T 7"9 m m 78 '2 879 1+1+ m r TIT 1,090 T3"T
1969 E 93 259 556 79 2 896 46 161 .7 214 1,110 11.9
1969 N 3 0 12 -fa 1 22 i-rri 0 10 1,ll~ 10.6
1969 T ~ 259 ~ 3 m T Wi Ti':'9
1970 E 93 266 556 78 2 902 47 161 7 215 1,117 12.0
1970 N 24 ~ 48 ~ 1 168 -.L rri 0 10 ~ ..l:!!... 1970 T m 601+ 3 1,070 50 T 225 1,295 11.1
1971 E 93 271 556 79 2 908 49 161 7 217 1,125 12.1
1971 N 38 .....2! 48 i; 1.. 212 4 rri 0 11 -ria ...2..:L 1971 T TIT 323 604 5 1,IZO 53 T m 1,3 10.3
1972 E 93 277 567 78 2 924 50 161 7 218 1,142 12.3
< 1972 N ~ ..2l 86 ill 4 ~ 4 '* 0 ili l,l~~ ...2..:L 1972 T 330 m 235 r 1,2Z 5I+ T 9.9
1973 E 53 283 567 1 0 851 52 161 0 213 1,064 20.1 ..... 1973 N lli ill 428 0 0 ~ • ~ 0 121 .....ill * W 1973 T 390 995 -, 0'"'" 0 m 1,720 10.
1974 E 53 289 567 I 0 857 53 161 0 214 1,071 20.1
1974 N * 110 428 0 0 ~ J.L ~ 0 122 660 ~ 1974 T 1 7 399 995 -I 0-1,395 90 0'"'" m T;73T 9.3
1975 E 5i 295 567 1 0 863 55 161 0 216 1,079 20.3
1975 N 16 ~ 428 0 0 & ~ ~ 0 ill 664 4.0
1975 T m 995 -1 0 I, 0 93 0 339 T;7I+3 8.'0
1976 E 53 301 567 1 0 869 56 161 0 217 1,086 20.5
1976 N ill Wo -r:m 0 0 818 ..J!L 166 0 m .L.lli ...hl.... 1976 T 230 90 1,19 -I 0 T;bS7 103 327 0 2,117 9.2
1977 E 53 307 567 1 0 875 58 161 0 219 1,094 20.7
1977 N 210 ill ~ 0 0 822 48 166 0 214 ~ +.f-1977 T m 500 1,19 -, 0 T;69"7 T5'6" m 0 m 2,130 .1
1978 E 53 313 567 1 0 881 59 161 0 220 1,101 20.8
1978 N 1M ~ 1.008 0 0 ~ ~ 166 0 ~ 1.420 6.0
1978 T 1,575 -I 0 2,0 m 0 35 2,521 T.7
1979 E 53 319 567 1 0 887 61 161 0 222 1,109 20.9
1979 N 263 202 '.008 0 0 l.d.!.Q ,t¥-.ill 0 224 tm * 1979 T m m 1.575 -I 0 2.097 335 0 ~ 2,5 3 .0
1980 E 53 325 567 1 0 893 62 161 0 223 1,116 21.1
1980 N m 206 1.008 0 0 .L.lli ...iL .ill 0 ~ ~ 4+ 1980 T TIT 1,575 -I 0 2,107 113 335 0 2,555 7.
2,651 24,476
14-YEAR AVERAGE COST ................................................................................................................................... 1:l
E --ex i 5 t i ng. N --new, T --tota I
*Debt, insurance and repl?cements, based on the figures listed on page VI-II