HomeMy WebLinkAboutElectric Utility System, Sitka, Alaska, Analysis of Electric System Requirements 1974ELECTRIC UTILITY SYSTEM
SITKA, ALASKA
ANALYSIS OF
ELECTRIC SYSTEM REQUIREMENTS
CITY AND BOROUGH
of
SITKA, ALASKA
R. W. BECK AND ASSOCIATES
Analytical and Consulting Engineers
Seattle, Washington
Orlando, Florida Denver, Colorado Columbus, Nebraska
Welle.lev, M .... chu.etts Phoenix, Arizona Indianapoli., Indi.n.
APRIL 1974
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Honorable Members of Assembly
City and Borough of Sitka
Post Office Box 79
Sitka, Alaska 99835
Gentlemen:
Subject: Electric Utility System
Report on System Requirements
April 30, 1974
We herewith submit a report describing our evaluation of the
requirements and potential for development of the municipal electric uti-
li ty system.
Our investigations show that installation of a third unit at the
Blue Lake Hydroelectric Project has technical and economic feasibility, but
should not be undertaken until later.
We have determined that future development of the system should
be by installation of additional hydroelectric generation. Several hydro-
electric sites appear to have technical feasibility but studies to evaluate
the site are required to confirm this and to establish firm cost estimates.
To meet the projected load, the Green Lake Project is considered to be the
most favorable installation and should be brought into service as soon as
possible (December 1978). Installation of Unit 3 at the Blue Lake Project
should follow the Green Lake development by about five years. The next
development would be the Takatz Project with the first unit in late 1986.
In the period prior to the Green Lake Project coming on-line
it will be necessary to rely on increased diesel generation. System im-
provements including oil storage facilities are therefore required.
A significant amount of dependable capacity to~ether with high
load factor energy, as well as large amounts of secondary energy, will be
available for sale in the early years of the Green Lake Project operation.
A contractural commitment to supply maximum amounts of power to the Alaska
Lumber & Pulp Company, or other industrial customers, appears to be a pre-
requisite to financial arrangements for construction.
Honorable Members of Assembly -2-April 30, 1974
We consider the future generation sites recommended in the re-
port show sufficient indication of final technical and economic feasibility
to warrant the initiation of site evaluation studies. In order to place the
Green Lake Project on-line to meet the peak loads in the winter of 1978-1979,
the site evaluation should begin in June, 1974. Interim financing will be
required to permit the necessary investigation, design, and improvements
prior to financing for construction of the Project.
We appreciate the cooperation given us by the City during this
phase of our services.
Respectfully submitted,
CERTIFICATE OF ENGINEER
CITY AND BOROUGH OF SITKA, ALASKA
ANALYSIS OF
ELECTRIC SYSTEM
REQUIREMENTS
The technical material and data contained in this report were pre-
pared under the supervision and direction of the undersigned, whose seals, as
professional engineers licensed to practice as such are affixed below.
Richard H. McLemore
Executive Engineer
R. W. BECK AND ASSOCIATES
~~~~
) (.fames V. Williamson
Supervising Executive Engineer
R. W. BECK AND ASSOCIATES
Section
Number
I
II
III
IV
OUTLINE OF REPORT
Title
Letter of Transmittal
Certificate of Engineer
Outline of Report
List of Tables
List of Figures
Summary
INTRODUCTION
1.
2.
3.
Authorization
Scope of Services
Background to Present Study
EXISTING SYSTEM
1.
2.
3.
4.
5.
6.
General
Resources
a. Blue Lake Hydroelectric Project
b. Diesel Plant
c. Alaska Lumber and Pulp Company
(ALP) Thermal Units
Transmission Lines
Substations
a. Blue Lake Substation
b.
c.
Marine Street Substation
Diesel Plant Substation
Distribution
Historical Loads
BLUE LAKE PROJECT
1.
2.
3.
4.
5.
6.
Location
General Description of Project
Dam and Spillway
Intake
Tunnels and Penstocks
a. General
b. Tunnels
c. Steel Penstocks
Powerhouse
HYDROLOGY AND POWER OUTPUT OF BLUE LAKE
1. General
2. Availability of Water
3. Water to ALP
4. Fish Releases
Page
Number
1-1
1-1
1-1
II-l
II-l
II-l
II-2
II-2
II-3
II-3
II-3
II-3
II-3
II-4
II-4
III-l
III-l
III-1
III-1
1II-2
1II-2
III-2
1II-2
III-2
1II-3
IV-1
IV-l
IV-l
IV-l
IV-1
Section
Number
v
VI
VII
5.
6.
OUTLINE OF REPORT
(Continued)
Title
Hydroelectric Generation
Reservoir Operation
a. Rule Curve
b. Firm Energy
POTENTIAL NEW GENERATION
1. Blue Lake Expansion
a. Description
b. Power Output
2. Green Lake Project
a. Description
b. Geology
c. Hydrology and Power Output
3. Takatz Proj ect
a. Description
b. Geology
c. Hydrology and Power Output
4. Other Sites
a. Major
b. Minor
POWER STUDY
L
2.
3.
General
Loads
a. Peak Capacity
b. Dependable Capacity
c. System Load Factor
d. Energy
e. Load Growth Reserve
f. Forced Outage Reserve
g. Exports
Future Requirements
a. System in 1974-75
b. System in 1976-77
c. System in 1978-79
d. System Subsequent to
e. Secondary Energy
f. Reserves and Exnorts
1980
ESTIMATED CONSTRUCTION COST
L
2.
General
Bas is of Cos ts
a.
b.
Direct Construction Cost
Contingencies
Page
Number
IV-2
IV-3
IV-3
IV-3
V-l
V-l
V-l
V-l
V-l
V-l
V-2
V-2
V-3
V-3
V-lf
V-4
V-4
V-4
V-5
VI-l
VI-'l
VI-l
VI-l
VI-l
VI-l
VI-2
VI-2
VI-2
VI-2
VI-2
VI-2
VI-3
VI-3
VI-3
VI-4
VI-5
VII-l
VII-l
VII-l
VII-l
VII-l
Section
Number
VIII
IX
X
XI
3.
c.
d.
e.
f.
g.
OUTLINE OF REPORT
(Continued)
Title
Engineering and Client Administration
Escalation
Total Construction Cost
Capital Investment Cost
Bond Issue
Construction Cost Estimates
a. Green Lake Project
b. Blue Lake Expansion
c. Takatz Project
d. Diesels
COST OF POWER
1.
2.
3.
4.
General
Annual Costs
a. Diesels
b.
c.
Green Lake Project
Takatz Project
Comparison of Diesels and Green Lake Project
Comparison Between Green Lake
and Takatz Projects
PROPOSED PROGRAM OF DEVELOPMENT
1.
2.
Improvements Currently Required
a. General
b. Tie Line to ALP
c. System Power Factor
d. Blue Lake Substation
e.
f.
g.
h.
1.
j.
Marine Street Substation
Fish Release Valves and Uonitoring
Reservoir Level Gage
Pressure Gages in Powerhouse
Oil Storage Facilities
Central Control Station
Future Generation Program
a. General
b. Green Lake Project
c. Blue Lake Unit 3
d. Takatz Project
DESIGN AND CONSTRUCTION SCHEDULE
CONCLUSIONS AND RECOMMENDATIONS
1.
2.
Conclusions
Recorrrrnendations
Page
Number
VII-l
VII-l
VII-2
VII-2
VII-2
VII-2
VII-2
VII-2
VII-2
VII-3
VIII-l
VIII-l
VI II-I
VIII-l
VIII-l
VIII-2
VIII-2
VIII-3
IX-l
IX-l
IX-l
IX-l
IX-l
IX-l
IX-l
IX-l
IX-2
IX-2
IX-2
IX-2
IX-2
IX-2
IX-3
IX-3
IX-3
X-l
XI-l
XI-l
XI-l
Table
Number
II-1
II-2
IT-3
IV-1
IV-2
IV-3
IV-4, Sheet
IV-4, Sheet
IV-5
IV-6
IV-7, Sheet
IV-7, Sheet
IV-8
V-1
V-2
V-3
VI-l
VI-2
VI-3
VI-4
VI-5
VI-6
VI-7
VI-8
VII-1
VII-2
VIII-1
VIII-2
VIII-3
VIlI-4
VIII-5
VIII-6
VIII-7
1
2
1
2
LIST OF TABLES
Title
Summary of Loads, 1962-1974
System Energy Loads, 1962-1974
Summary of Monthly Energy Loads
Sawmill Creek Stream Flow Records
Total Precipitation -Gage at Sitka Observatory
Historical Water Use -A.L.&P Company
Reservoir Operation, Fish Release = 15 cfs
Reservoir O~eration, Fish Release = 50 cfs
Blue Lake Project, Historical Energy Generation
Blue Lake Project, Rule Curve Operation of Reservoir
Available Energy with Rule Curve Operation, Fish
Release = 15 cfs
Available Energy with Rule Curve Operation, Fish
Release = 50 cfs
Firm Energy Available with Different Fish Releases
Green Lake Outlet -Recorded Runoff in Acre-feet
Green Lake Project -Estimate of Firm Energy
Takatz Creek -Recorded Runoff in Acre-feet
Forecast of Loads
System Energy Loads, 1962-1974
Summary of Monthly Energy Loads
Forecast of Loads -Summary of Monthly Loads
Summanr of Loads and Resources, 1974-1979
Summary of Loads and Resources, 1979-1990
Anticipated Load Increases
Power Available to ALP with Reserve Sharing
Green Lake Project -Cost Estimate SummarY
Takatz Project -Cost Estimate Summary
Fixed Cost of New Diesel Installations
Estimated Cost of Diesel Fuel
Annual Cost of Power -Diesel Units
Annual Costs -New Hydroelectric Projects
Details of Annual Costs -New Hydroelectric Projects
Green Lake Project -Annual Cost of Power, 1979-90
Comparative Costs of Hydroelectric Generation
Figure
Number
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
LIST OF FIGURES
Title
Location Map
Blue Lake Project -Existing Arrangement
Blue Lake Reservoir -Area-Capacity Curve
Blue Lake Project -Reservoir Rule Curve
Green Lake Project -Proposed Arrangement
Green Lake Project -Proposed Dam Arrangement
Green Lake Reservoir -Area-Capacity Curves
Takatz Project -Proposed Arrangement
Takatz Reservoir -Area-Capacity Curves
Load Growth Curve -Peak Load
Load Growth Curve -Energy Load
Load Duration Curves
Comparative Cost of Power
Cost of Continued Diesel Generation vs Green Lake Project
Design and Construction Schedule
SUMMARY
In order to develop plans for meeting its long-term requirements for
generating resources in the most economical and dependable manner, the City of
Sitka has begun investigation of potential hydroelectric sites in the area.
This report presents a discussion of the forecast of loads and re-
sources, hydrology and reservoir operation of the Blue Lake Project, potential
new sites for hydroelectric development, economic comparisons of alternative
plans of development, a proposed program of development and a schedule for such
development.
It is determined that installation of a third unit with a capacity
of 4,000 kW at the Blue Lake Project is desirable, but should be preceded by
installation of a new hydroelectric project since the critical requirement of
the City is for additional energy.
Economic comparisons of alternative programs for system development
show that a system composed entirely of hydroelectric generating resources has
economic feasibility, and sites are available in the general vicinity which show
potential of having technical feasibility. The most favorable site for initial
development appears to be the Green Lake site.
A proposed schedule of development is included in the report which
requires that the Green Lake Project be on-line late in 1978 to meet the peak
loads during that winter, and that Unit 3 of the Blue Lake Project be on-line
late in 1983. The Takatz Project would be developed to be on-line late in 1986.
Large amounts of power will be available for sale subsequent to de-
velopment of the Green Lake Project and contractual arrangements for sale of
this power should be initiated. Location of new industrial facilities with
large load requirements in the area would require an accelerated development of
the proposed program. Firm contractual agreements for purchase of power ap-
pear to be essential to financing arrangements for construction of the project.
The proposed schedule of development recommends investigations into
the Green Lake Site, proceeding with arrangements for financing the investiga-
tions, application for FPC license, final feasibility studies, and construction
of the Green Lake Project upon determination of final feasibility and financial
arrangements. In order to maintain the proposed schedule, investigations of
the Green Lake site are to begin in June 1974. Since a large amount of diesel
generation will be required prior to completion of the Green Lake Project, in-
stallation of oil storage facilities at the diesel plant are recommended to be
done immediately.
SECTION I
INTRODUCTION
1. AUTHORIZATION
The work described in this report was authorized by an Agreement
for Engineering Services dated December 20, 1973, and which was approved by the
City and Borough of Sitka on December 27, 1973. The scope of work to be furnished
is described in the Agreement for Engineering Services and is outlined in this
report.
2. SCOPE OF SERVICES
The complete scope of work includes the following:
a. Field inspection of the electric system, including the features of
the Blue Lake Project which will relate to a future safety inspection for the
Federal Power Conunission (FPC).
b. A study of the hydrology of the Blue Lake Project including a review
of the United States Geological Survey (USGS) gage on Sawmill Creek. The study
would also include an analysis of generation and reservoir operation, the use of
water by the Alaska Lumber and Pulp Company (ALP), the fish releases and reservoir
spillway discharges, and an analysis of the hydraulic characteristics of the power
tunnel and penstocks.
c. An analysis of the historic load data, and a preliminary forecast
of loads, and establishment of load duration curves for the system.
d. A review of possible methods for increasing the hydroelectric genera-
tion during the study period, in the near future (1974-1977), and in the period
subsequent to 1980. The short-range methods would include a study of the advis-
ability of installing a third unit at the Blue Lake Project and the desirability
of increasing reservoir storage by raising the crest of the dam and spillway.
The long-range methods would include preliminary consideration of potential sites
for additional hydroelectric generation such as Takatz Lake and Green Lake.
e. Preparation of a schedule for development of resources to meet the
forecast load conditions.
f. Preparation of preliminary cost estimates for the potential devel-
opments. The estimates would be based on a cost-per kilowatt basis and would
be in accordance with previous broad-base estimates by the Alaska Power Admin-
istration (APA) and the FPC.
g. Preparation of a report discussing the results of the current in-
vestigations.
3. BACKGROUND TO PRESENT STUDY
Since the completion of the Blue Lake Hydroelectric Project in 1961
the water availability at the project had the potential to produce more energy
than required by the loads of the City, even during the driest years of the
1-2
period, but by 1973 the load requirements of the City developed to a magnitude
which approached the total firm energy which could be generated at the project.
Concurrently, the runoff from the Blue Lake watershed was very low in 1973. The
combination of these events has resulted in a severe drawdown of the reservoir,
and since it can be anticipated that such drawdowns will occur even under more
normal runoff conditions as the load requirements increase, a study of reservoir
operating methods to obtain maximum generation from the project is desirable.
During the same period a national shortage of fuel oil occurred and
is expected to continue during the foreseeable future. The decreased supply of
fuel oil was accompanied by a significant increase in costs. The City has die-
sel generating units which are more than sufficient to provide the required addi-
tional generation for the City, but the cost of such generation will be very high
and the uncertain availability of generating fuel will affect the dependability
of this generation. As a result it was decided to investigate the feasibility
of additional hydroelectric generation for the City.
In the recent decade many studies have been performed for Sitka and
other Alaskan cities to compare the economic advantages of single-purpose hydro-
electric projects with small diesel units. These studies have usually concluded
that the diesel units were more desirable with the prevailing costs at that time
and the larger capital investment required for the hydro. This situation has
altered significantly at the present time as discussed above, and the City au-
thorized this study to determine the potential for more effective operation of
the Blue Lake Project and the desirability of additional hydroelectric installa-
tions to meet the increased loads from future development of the electric utility
system.
SECTION II
EXISTING SYSTEM
1. GENERAL
Si tka is located on the wes t coas t of Baranof Island approximately
95 miles south-southwest of Juneau and 92 miles west-northwest of Petersburg.
Sitka Sound lies to the west of the City and forms a channel directly into the
Gulf of Alaska. Eastern Channel is located to the south of the City and forms
a channel connection between Sitka Sound and Silver Bay with the mouth of Silver
Bay being located about four miles southeast of town.
The powerhouse of the Blue Lake Hydroelectric Project is located
near the mouth of Sawmill Creek which flows southwest into Silver Bay at a
point about one and one-half miles from the mouth. The powerhouse is about
four airline miles east of town and access is by the Sitka Highway. Blue Lake
is located about one mile upstream on Sawmill Creek and is about 335 feet higher
in elevation. Access to the Blue Lake Dam is from the Sitka Highway by means of
a secondary road.
The diesel generating plant is located approximately one mile north-
west of city center on a major route of the City's street and road system.
A location map of the area is shown in Fig. 1.
2. RESOURCES
a. Blue Lake Hydroelectric Project
The powerhouse installation consists of two Francis turbines mounted
horizontally, and connected to individual generators each rated at 3,750 kVA
with an 80% power factor. The output at rated capacity is 3,000 kW and the
turbines are rated at 5,200 HP with 267 feet net head operating at a speed of
600 rpm. All powerhouse equipment was manufactured by Tokyo ShibAura Electric
Company (Toshiba).
Tests were made in January, 1974, by the powerhouse staff and per-
sonnel from R. W. Beck and Associates to determine the overload potential of
the units. The maximtml generator load attained was 4,480 kVA at a power factor
of 87% to give an output of 3,900 kW. This output was attained with a net head
of approximately 272 feet. This test did not result in excessive temperature
rises in either the generators or the transformers, but the tests were restricted
at this level due to a 600 Ampere rating of the current transformers.
It is concluded that the two units can be safely operated to pro-
duce a dependable capacity of 7,000 kW, with compatible transformers, under the
minimum head conditions which will result from rule curve operation of the re-
servoir during the winter peak period. The dependable capacity of the plant
at the minimum reservoir level shown by the rule curve (in May) is considered
to be about 5,600 kW. The firm energy content of the reservoir is estimated to
be 32,000,000 kWh as discussed later in this report.
11-2
b. Diesel Plant
The diesel plant contains four units as follows:
(1) Unit #1 is a Fairbanks Morse prime-mover driving a generator
rated at 375 kVA, with a power factor of 80%, 2,400 Volts, at 300 rpm; the
dependable capacity is 300 kW.
(2) Unit #2 is a Enterprise prime-mover driving an Electric Machinery
generator rated at 625 kVA, with a power factor of 80%, 2,400 Volts, at 900 rpm;
the dependable capacity is 500 kW.
(3) Unit #3 is a GMC prime-mover driving a Westinghouse generator
rated at 375 kVA, with a power factor of 80%, 2,400 Volts, at 1,200 rpm; the
dependable capacity is 300 kW.
(4) Unit #4 is a Fairbanks Morse prime-mover driving a generator
rated at 2,500 kVA, with a power factor of 80%, 12,470 Volts, at 720 rpm; the
dependable capacity is 2,000 kW.
The diesel plant has a combined capacity of 3,100 kW. Each diesel
unit, of course, has its own heat rate, which is inherent with the equipment
and which is also affected by the method of operation of that particular unit.
An average heat rate for all diesel units of 10,000 BTU per kilowatt-hour has
been assumed as being a practical value for the operation as anticipated by this
study. A mean value of 140,000 BTU per gallon for No. 2 fuel oil is assumed re-
sulting in the energy output of all diesel units being estimated at 14 kWh per
gallon of diesel fuel. With the current cost of diesel fuel of $0.33/gallon the
cost of diesel generation is 23.6 mills/kWh, not including the fixed costs of
operation and maintenance.
c. Alaska Lumber and Pulp Company (ALP) Thermal Units
ALP has an installation of steam generation with a total capacity
of approximately 25,000 kVA. These units are fired by waste materials assisted
by oil.
The ALP distribution system is interconnected to the low-voltage
cables of the Blue Lake generator step-up transformers. The tie is a double
2/0 copper circuit which has a nominal capacity of 5,000 kVA, however a short
section of the tie has a lower capacity which restricts the dependable capacity
of the tie to approximately 2,500 kVA. Breakers are provided at each end of
the tie which allows power to be transferred in either direction, and makes ex-
change agreements between ALP and the City possible. An agreement provides for
exchanges of energy being repayable in kind on a monthly basis. Any imbalances
in energy exchanges are paid at the rate of 10 mills/kWh at the end of each
month, with the same rate being applicable to either party to the agreement.
II-3
Although the ALP has small amounts of capacity available for export
on an emergency basis, it is anticipated that increased loads within its own
system will significantly reduce this possibility by the latter part of 1974.
The ALP system operates on a high load factor which prevents any large transfer
of off-peak energy to the City. The high plant factor indicates essentially con-
tinuous operation at close to peak load condition, which would cause any energy
transfer to be accompanied by a loss of peak capacity to ALP. Further the ex-
cess energy is probably being fired by Bunker C oil which has increased signi-
ficantly in cost. In addition the system has need of capacitive reactive capa-
b ility.
3. TRANSMISSION LINES
A 34.5 kV transmission line, approximately five miles long, connects
the Blue Lake Substation with the Marine Street Substation which is located near
the system load center. The conductor is 2/0 ACSR on wood poles. The ultimate
capaci ty of the line, assuming that the power factor of the sys tern can be improv-
ed to about 96%, would be approximately 11,500 kVA, and the line would conduct
power at this level with acceptable power losses and voltage drops. The line is
considered to have sufficient capacity for installation of a third unit at Blue
Lake as originally planned.
4. SUBSTATIONS
a. Blue Lake Substation
This station consists of the step-up transformers for the hydroelec-
tric plant and for power received from ALPC and transmitted to the load center.
Three single-phase units, each rated at 2,500 kVA, transform the output from
generator voltage at 4160 Volts to transmission line level. The high voltage
side has five taps which range from 32.6-kV to 36.2-kV. At present, the trans-
mission level is about 33.5-kV. One spare unit is provided to prevent any ex-
tended outage from failure or accident to a transformer unit.
b. Marine Street Substation
This station is located near the system load center and serves to
reduce the transmission voltage level to that of the primary feeder lines which
operate at 12,470 Volts. Three single-phase units, each rated at 2,500 kVA,
and one spare unit, are located in the yard.
c. Diesel Plant Substation
This station contains three single-phase units, each rated at
SOO-kVA, and provide transformation of voltage from Diesel Units Nos. 1, 2
and 3. The generator outputs are at 2,400 Volts which are stepped-up to pri-
mary feeder line level at 12,470 Volts. The generator voltage of Diesel
Unit No.4 is at 12,470 Volts and the generator bus connects directly to the
primary feeder line.
11-4
5. DISTRIBUTION
The Marine Street Substation supplies four primary feeder lines at
12,470 Volts, three-phase, which ar~ stepped-down to 7,200 Volts for the dis-
tribution system. The power factor of the system is low, but it is estimated
that approximately 1,000 kVAR of capacitors will increase the power factor to
approximately 96% with the present load conditions. The capacitors can be
installed in the Marine Street Substation, or individual capacitor banks to-
taling 1,000 kVAR can be installed in the distribution system. The most de-
sirable location appears to be in the substation since it is near the load
center, but this should be confirmed so that installation can proceed accord-
ing to schedule. The reactive requirement of the system is being supplied
by the hydroelectric units at the present time. Improvement of the power fac-
tor to about 93% will allow the Blue Lake units to produce power at 3,500 kW
each without exceeding the kVA rating of the generators or step-up transform-
ers.
6. HISTORICAL LOADS
Records of historical loads have been maintained by the City and
include monthly energy demands and monthly peaks, from which annual energy and
peak, as well as annual and monthly system load factors can be obtained.
The annual peak of the system occurs during the winter season, us-
ually in December or January, although the peak has occurred some years in Nov-
ember. Thus the peak load for an individual season could occur in either of
two calendar years, and if the annual energy is measured by calendar year, in-
consistencies will exist in determination of the system load factor for suc-
cessive years.
For the purposes of this report loads have been grouped into power
years which are assumed to be from July 1 of one year until June 30 of the suc-
ceeding year. In this way, the annual peak occurs in mid-year and is clearly
defined. A summary of historical loads for Sitka from July 1, 1962 until the
present time, which considers the effects of exchanges with ALP, is shown in
Table 11-1. As shown, during the past decade the system load factor has effec-
tively stabilized at about 55% and this value has been used in forecasting fu-
ture energy demands. A tabulation of historical monthly energy demands, grouped
by power years, is shown in Table 11-2. A summary of monthly energy demands ex-
pressed as percentages of the annual demand and including monthly load factors
is shown in Table 11-3.
Power Year
1962-63
1963-64
1964-65
1965-66
1966-67
1967-68
1968-69
1969-70
1970-71
1971-72
1972-73
1973-74
Peak
Capac ity
kW
5,500
4,950
5,300
5,150
5,300
6,200
6,050
6,400
5,985
CITY OF SITKA
SUMMARY OF LOADS
1962 -1974
Energy
1,000 kW h
18,419.2
22,220.9
24,544.5
22,368.4
22,872.7
24,658.2
25,728.1
26,640.6
28,889.0
29,979.5
30,653.7
Average
Capacity
kW
2,102.6
2,536.6
2,801. 9
2,553.5
2,611.0
2,814.9
2,937.0
3,041. 2
3,297.3
3,422.3
3,499.3
Note: All loads adjusted for transfers to and from ALP
TABLE II-I
Load
Factor
%
46.1
5l. 6
49.3
54.7
55.4
53.2
56.6
54.7
CITY OF SITKA
SYSTEM ENERGY LOADS
1962 -1974
1,000 kW h
POWER YEARf, ~ ~ ~ Oct. Nov. Dec. ---
1962-63 1,214.0 1,302.1 1,363.7 1,543.6 1,627.0 1,797.1
1963-64 1,505.6 1,632.0 1, 703.0 1,898.4 2,00".7 2,087.1
1964-65 1,625.4 1,711.3 1,838.3 1,986.1 2,153.5 2,477.2
1965-66 1,782.9 1,989.6 1,755.2 1,710.3 1,904.5 2, 162. 5
1966-67 1,446.3 1,642.6 1,735.7 1,911.5 1,987.7 2,197.3
1967-68 1,610.0 1,702.0 1,824.4 2,055.3 2,187.8 2,411.1
1968-69 1,769,9 1,867.9 2,011.8 2,207.1 2,194.8 2,495.2
1969-70 1,972.1 1,Y73.2 2,085.2 2,247.5 2,335.0 2,482.1
1970-71 2,063.7 2,112.4 2,236.3 2,444.3 2,497.5 2,843.2
1971-72 2,038.8 2,118.4 2,276.1 2,493.4 2,530.0 2,917.4
1972-73 2,108.9 2,168. 5 2,383.5 2,268.9 2,694.5 3,030.0
1973-74 2,207.2 2,273.1 2,342.8 2,682.0 2,878.0 2, 527. 7
f("Example: Power year 1962-63 is from July 1 ,1962 through June 30,1963.
~ Feb. Mar. ~ ---
1,b74.R 1,5l7.5 1,690.8 1,638.2
2,102.2 1,936.0 2,04:>.0 1,891.1
2,478.6 2,120.0 2,248.7 2,107.7
2,127.1, 1,8 '3.6 1,9%.9 1,774.1
2,201.9 1,952.7 2,256.6 1,976.3
2,509.8 2,263.4 2,276.7 2,120.2
2, i 26. 1 2,212.3 2,354.6 2,089.9
2,612.1 2,2 OS. 3 2,377.3 2,248.1
2,882.5 2,413.4 2,616.8 2,421.4
3,011.4 2,727.6 2,756.5 2,546.4
3,055.6 2,70".3 2,864.6 2,"69.9
2,798.9 2,418. J
~ June
1,616.8 1,433.6
1,834.0 1,578.8
2,004.7 1,19l.0
1,728.5 1,562.7
1,881.1 1,683.0
1,956.7 1,740.8
2,018.5 1, "80. °
2, 190. 9 1,911.8
2,331.2 2,021. 3
2,410.3 2,153.2
2,526.1 2,280,9
Annual
lR,419.2
22,220.9
24,544.5
22,368.4
22,872.7
24,6)8.2
25,728.1
n,6!,0.6
28,884.0
29,979.5
30,653.7
H
G;
r-<
tr:I
H
H
N
SUMMARY OF MONTHLY ENERGY LOADS
(Percent of Annual)
Oct. Nov. Dec. Jan. Feb.
1967-68 6.53 6.50 7.40 8.33 8.87 9.78 10.18 9.18
1968-69 6.88 7.26 7.82 8.58 8.53 9. 70 10.60 8.60
1969-70 7.40 7.41 7.83 8.44 8.76 9.32 9.80 8.28
1970-71 7.14 7.31 7.74 8.47 8.65 9.84 9.98 8.36
1971-72 6.80 7.07 7.59 8.32 8.44 9.73 10.05 9.10
1972-73 6.88 7.01 7. 78 7.40 8.79 9.88 9.97 8.82
Average 6.94 7.17 7.69 8.26 8.67 9.71 10.10 8. 72
Load Factor 64.2 67.7 72 .1 67.3 69.2 62.9 65.4 69.6
Mar.
9.23 8.60
9.15 8.12
8.92 8.44
9.06 8.38
9.19 8.49
9.35 8.38
9.15 8.90
70.5 65.4
June
7.94 7.06
7.84 6.92
8.22 7.18
8.07 7.00
8.04 7.18
8.24 7.44
8.06 7.13
67.4 70.2
H
H
i
UJ
SECTION III
BLlffi LAKE PROJECT
1. LOCATION
The Blue Lake Project is located adjacent to Silver Bay approxi-
mately five miles from the system load center by highway. The Sitka Highway
follows the shoreline of Silver Bay and extends a short distance beyond Saw-
mill Cove into which Sm.mull Creek discharges. The ALP mill and Blue Lake
Project powerhouse are located a short distance upstream of Sawmill Cove.
The portion of Sawmill Creek immediately upstream of the powerhouse tailrace
is locally referred to as the "Gorge" and is about 1400 feet in length. The
dam which impounds Blue Lake is about 6000 feet upstream of the powerhouse
tailrace. The general arrangement of the project is shown in Fig. 2.
2. GENERAL DESCRIPTION OF PROJECT
The project consists of a reservoir, concrete arch dam, intake
structure, two tunnels which are connected by a steel penstock, powerhouse,
substation and transmission line to the load center. It went into operation
in 1961.
The reservoir was created by ralslng Blue Lake to its present level
by construction of a concrete arch dam across Sawmill Creek a short distance
downstream of the previous natural outlet of Blue Lake. Construction of the
dam raised the water surface level from Elev. 205 to Elev. 342 feet (spillway
crest level) and provided a total storage volume of 145,000 acre-feet. The
surface area of Blue Lake at normal maximum reservoir level (Elev. 342) is
1,225 acres. Operation of the reservoir is described in a subsequent portion
of this report.
3. DAM AND SPILLWAY
The dam is a concrete arch structure located in a deep gorge of Saw-
mill Creek a short distance downstream of the main body of the reservoir. The
dam is approximately 225-feet high, has a crest length of 256 feet and a crest
width of 8-feet. The sound rock surface in the stream was located approximately
70-feet below the original ground surface so that the low point of the dam is
approximately at El. 125. The crest of the dam is at El 351 providing a free-
board of 9 feet from normal maximum reservoir level.
The spillway has an uncontrolled crest located in the center of the
concrete arch. The crest includes a downstream extension to provide a flip-
bucket effect to discharges. The spillway crest is essentially an ogee-type
and has a length of 138.57 feet. Maximum discharge without overtopping the dam
is estimated to be approximately 14,000 cfs. Derrick stone and riprap have been
placed downstream of the dam to prevent degradation of the stream bed and under-
cutting of the dam by flow from the spillway.
111-2
4. INTAKE
The power intake structure is located several hundred feet from
the dam adjacent to the access road on the right abutment. The structure is
equipped with a bulkhead gate, a by-pass line and gate, fixed wheel gate, trash
racks and air vent. Guides are provided on the abutment slope and the gates
are raised by cables connected to a power winch, and are lowered by gravity.
The center-line of the intake structure is at Elev. 210 and it is estimated
that a submergence of approximately 20 feet will provide an efficient operat-
ing level. The proposed drawdown of the reservoir is to El 252 which allows
more than adequate submergence.
5. TUNNELS AND PENSTOCKS
a. General
A tunnel (upper tunnel) connects the intake structure to a portal
located on the right bank of Sawmill Creek approximately 1800 feet downstream
of the dam. A similar portal for a second tunnel (lower tunnel) is located on
the left bank of the stream. The portals are connected by a steel penstock which
crosses Sawmill Creek and is supported by concrete piers. The lower tunnel
has an exit portal near the ALP settling basin and filter plant approximately
300 feet from the powerhouse. Downstream of this portal a steel penstock con-
tinues to a manifold with branches for each of the two existing units and a
stubbed-off section for the proposed third unit.
b. Tunnels
1. Upper Tunnel
This portion of the power conduit is essentially an II-foot
6-inch by II-foot 6-inch unlined horseshoe section approximately 1,535-feet
long. Local areas of the tunnel have been provided with concrete lining due
to adverse rock conditions, resulting in a 10-foot by 10-foot horseshoe sec-
tion. A short transition section is provided at the upstream end of this tun-
nel to connect the major portion of the tunnel to the intake structure.
2. Lower Tunnel
This portion of the power conduit is essentially a 10-foot
by 10-foot horseshoe section and is approximately 4995 feet long. Local
areas of this tunnel are also provided with concrete lining due to rock con-
ditions at these locations. The lined areas in this tunnel are 7-feet 10-
inches by 7-feet 10-inches horseshoe sections. The downstream portal of
this tunnel is approximately at El 77.
c. Steel Penstocks
1. Sawmill Creek Crossing
This portion of the power conduit is an 84-inch steel pipe
approximately 508-feet long. A 36-inch steel pipe is stubbed-off the penstock
1II-3
near the right-bank portal to allow diversion of water from the penstock into
Sawmill Creek, presently being controlled by a badly damaged l2-inch valve.
The valve is only partially open at the present time, and due to a significant
vibration and leakage problem at the valve, it is deemed prudent not to attempt
further operation of the valve until the penstock can be unwatered and a new
valve system installed.
2. Downstream Section and Manifold
The section of power conduit downstream of the tunnel portal
is again an 84-inch steel pipe which terminates in a manifold. Three 60-inch
steel pipe connections are provided to allow individual penstocks into the
turbine scroll cases. The connection for the proposed third unit is closed
with a blind flange.
A short distance downstream of the tunnel portal the penstock
is tapped to divert water for ALP requirements. One 36-inch steel pipe diverts
a portion of the water into a forebay area from which it flows by gravity through
a settling basin and filter bed and thence is piped by gravity into the mill area.
One l6-inch steel pipe diverts additional water, at penstock pressure, into the
mill area. A second l6-inch steel pipe is used to provide backwash water for the
filter bed. Overflows from the forebay and backwashing operation discharge dir-
ectly into Sawmill Creek in the "Gorge" portion of the stream.
6. POWERHOUSE
The powerhouse is a conventional indoor reinforced concrete struc-
ture housing two generating units. Each unit consists of a Francis turbine,
rated at 5,200 hp connected by a horizontal shaft to a generator rated at 3,750
kVA (3,000 kW). The machines operate at a synchronous speed of 600 rpm. The
generator output is at 4,160 Volts which is stepped-up to transmission line
voltage of 33,500 by three single-phase transformers, each rated at 2,500 kVA,
located near the powerhouse structure. The powerhouse tailrace empties into
Sawmill Creek approximately 400 feet upstream of the mouth and the tailwater
level is controlled by a weir in the tailrace channel.
SECTION IV
HYDROLOGY AND POWER OUTPUT OF BLUE LAKE
1. GENERAL
Average monthly discharge records are available for Sawmill Creek
for 28 complete water years. These records were obtained from stream gages
installed and operated by the United States Geological Survey (USGS). While
the stream gaging was in different locations during the entire period of record,
(1921 through 1957) the locations were within a few hundred feet of each other,
and the records can effectively be considered as for the same drainage area.
The drainage area upstream of the gage is approximately 39.0 square miles, while
the drainage area upstream of Blue Lake Dam is approximately 37.0 square miles.
The data for complete water years of record converted to monthly runoff in acre-
feet, are shown in tabulated form in Table IV-l. As shown in the table the long-
term average annual runoff is 351,040 acre-feet and the maximum and minimum
annual runoffs are 519,020 acre-feet and 230,140 acre-feet respectively. The
average annual runoff during the latest period of record (1946-1957), however,
is 320,200 acre-feet and from this the adjusted (for drainage area) average
annual discharge of Blue Lake is estimated to be approximately 420 cfs, but
reservoir operation and contractual and regulatory water requirements reduce
the water available for generation significantly. These items are discussed in
detail in subsequent portions of this report.
2. AVAILABILITY OF WATER
Long periods of record for total precipitation are available for
stations in Sitka and on Japonski Island. Table IV-2 shows the total precipita-
tion recorded at a station located at the Sitka Observatory from 1950 until the
present time. As shown in the table, the average annual precipitation for the
period of record is 92.4 inches. If a loss of 10% is assumed for evapo-trans-
piration and infiltration, the resulting runoff would be approximately 4435 acre-
feet per square mile, or about 6.1 cfs per square mile. Based on this precipitation
the average annual runoff of Blue Lake would be about 226 cfs, as compared to the
420 cfs estimated from gaged runoffs. This shows that the total precipitation over
the Blue Lake drainage basin is about 190% of that gaged in Sitka. This ratio is
not unusual in Southeast Alaska where great changes in precipitation occur over
relatively small distances and changes in elevation.
3. WATER TO ALP
Water is supplied to the ALP on a contractual basis for operation
of the mill. The contract amounts are 35 mgd supplied at El 175, and 15 mgd sup-
plied at penstock pressure. The water is supplied by one 30-inch and two 16-
inch lines tapped into the penstock near the downstream portal. The flow from
each line is metered and records are available of monthly use by the mill. The
last decade of water withdrawals by ALP, expressed in acre-feet per month, is
shown in Table IV-3. Calculations for power output of the reservoir are based
on ALP utilizing their full allocation of water of 50 mgd (77 cfs) at all times.
4. FISH RELEASES
The FPC license for the Blue Lake Project contains a requirement that
a constant release of water be made into Sawmill Creek in the amount of 50 cfs,
IV-2
the release being made at the point where the steel penstock crosses Sawmill
Creek. A 36-inch steel pipe branch is located on the right bank of Sawmill
Creek. At the present time a l2-inch gate valve is flange mounted on the end
of the 36-inch line.
A severe leakage problem exists due to inadequate connections of
the valve to the flange and perhaps the flange to the 36-inch pipe. The valve
has severe cavitation erosion and vibrates when discharging. At the present
time the valve is partially open and is discharging an estimated 20 cfs. The
vibration of the valve could lead to structural failure and loss of the valve
and it is considered that any attempt now to operate the valve could precipi-
tate this failure. Loss of the valve would result in drawdown of the reservoir
to El 206, the invert of the power intake, some 136 feet. Since no back-up
valve has been provided, it will be necessary to close the intake gate to de-
water the power conduit to replace the damaged valve, which cannot be done un-
til ice has cleared from the reservoir sufficiently to permit a diver to assist
in operating the intake gate.
Sitka has filed a request with the FPC for amendment of the license
to obtain relief from the mandatory 50 cfs fish release. It is anticipated
that if fish releases can be varied throughout the year the total water require-
ments can be reduced, and sufficient water still be provided for sustaining fish
life in the downstream portion (primarily the "Gorge" section) of the stream.
A monitoring program is proposed during the forthcoming year to vary the re-
leases and to provide a simultaneous review by the Alaska Department of Fish
and Game, and the US Bureau of Sports Fisheries and Wildlife as to the adequacy
of stream flows at that time to maintain fish life.
It is anticipated that the intake gate can be operated in late
spring this year, and the damaged fish release valve be replaced at that time.
Since lead times of one to two years are not unusual in procuring larger regu-
lating valves suitable for flow modulation, (Howell-Bunger) the City has pro-
cured a 10-inch globe valve which was readily available, so that replacement
can be made expeditiously and thereby remove the danger of loss of reservoir.
An l8-inch gate valve has been obtained and will be installed to act as a back-
up valve, with operation planned in the open-shut mode only. With the back-up
valve, any future replacement of the regulating valve would not require closure
of the intake gate. The l8-inch gate valve in combination with the 10-inch globe
valve will discharge about 23 cfs during average summer reservoir conditions.
To release 50 cfs under minimum reservoir conditions would require replacement
of the globe valve with a l4-inch Howell-Bunger valve.
Calculations for power outputs from the project have been based on
fish releases of 15 cfs and 50 cfs to provide a range of comparison, since the
magnitude of future releases has not yet been established.
5. HYDROELECTRIC GENERATION
As shown in Table IV-l, the minimum water year of record at the
gaging station on Sawmill Creek had a runoff of 230,140 acre-feet. This runoff,
when adjusted to the Blue Lake drainage basin, represents a corresponding in-
flow of approximately 220,000 acre-feet into Blue Lake. Under the low-runoff
conditions which Sitka is now experiencing, it is considered desirable to es-
tablish a rule curve for reservoir operation which will allow complete reservoir
recovery on an annual basis. To provide a more realistic basis for this type of
IV-3
operation some adjustments were made to the low-water year of record mentioned
above. The monthly and annual inflows assumed for the synthetic minimum-water
year are shown in Table IV-4. The table also shows allocations of water for
ALP, and fish releases of both 15 cfs and 50 cfs, and provides the basis for
annual distribution of power releases and for determination of the firm energy
available from rule curve operation. It further shows similar values for an
average water year. Table IV-4 shows that in a minimum water year with 50 cfs
fish releases the water available for generation is 118,660 acre-feet and with
15 cfs fish releases the value is 144,210 acre-feet, representing some 22% in-
crease in dependable hydroelectric energy. A tabulation of historical energv
generation from the project is shown in Table IV-5.
Although some spillway discharges will no doubt occur in wet years,
as the system load increases these occurrences will become more infrequent. In
years of higher runoff, large amounts of secondary energy can be generated by
the existing units, and with installation of a third unit and increase in de-
mand, it is anticipated that the runoff from wet years can be converted into
firm energy without provision of additional storage.
Firm energy is defined as the amount of energy which can be ob-
tained on a dependable annual basis, and is based on rule curve operation of
the reservoir in a minimum water year. Secondary energy is that available over
and above the firm energy in any individual year. The amounts of secondary
energy available will, of course, vary from year to year depending on the avail-
ability of water in excess of the minimum year runoff.
6. RESERVOIR OPERATION
a. Rule Curve
An area-volume curve of the Blue Lake reservoir is shown in Fig. 3.
As shown in the curve the total storage volume is 145,000 acre-feet at normal
maximum reservoir El 342 (spillway crest elevation). With the bottom of the
storage pool assumed at El 252, the total volume available for regulation of
inflow is 86,000 acre-feet.
Traditional reservoir operating practices dictate a residual draw-
down in reservoirs during very low water years, with refilling to take place in
succeeding wetter years. However, the erratic nature of the past few years of
runoff does not appear to be representative of long-term records and it is con-
sidered appropriate for Blue Lake to be operated on a rule curve, with annual
recovery, at the present time.
The proposed method of operation is shown in Table IV-4, for a mini-
mum water year with both 15 cfs and 50 cfs allocations for fish releases. For
comparison an average water year is also shown for each condition. Annual opera-
tion by the rule curve will produce a drawdown of approximately 90 feet, to
Elev. 252, and will utilize 86,000 acre-feet of storage. A tabulation of rule
curve operation is shown in Table IV-6, and is shown graphically in Fig. 4.
b. Firm Energy
The firm energy available from rule curve operation is summarized
in Table IV-7 for both 15 cfs and 50 cfs fish releases. A comparison of firm
energy available with different fish releases, is shown in Table IV-8. As can
be seen, in 1978 the loss of hydrogeneration for a 50 cfs versus a 15 cfs con-
I~6
tinuous fish release, amounts to a value of about $200,000 annually based on
replacement fuel cost for diesel generation. The energy available in an aver-
age water year is also shown to provide an estimate of the potential average
amount of secondary energy which will be available.
Since required fish releases have not been determined at this time,
a value for firm energy from the Blue Lake Project of 32,000,000 kWh has been
used in power studies of the system.
I Y21
1 YL 2
I Y)2
1 y 3 j
19 ),'.
I y39
1 '1~O
1941
1942
14:'6
1947
1 ~! ':> ()
1 y ~ 1
I Y ')11
AVERAGE
2 j , GOO 1 Y , 900
c)9,OOD 1">,200
.41l,70Il 40{}
-, I, L UO :.. i , 1 no
4U,I;(]rJ )l,0()O
')4, LOO 21,100
44, ::(I() 2 1,700
-'d,600 !+g. 21JI)
'iU, nUD 20,100
30,900 59,400
91,600 LOl,OI)()
74,O'iO Lt,lOO
42,O.'.U 27,61n
06,220 29,660
39,160 27,7UO
55,430 31.800
67,070 18.150
~h.810 46,190
)7,140 37,970
19,160 c)O.,~7(1
, L 1 () 1-'" H3D
L 3, r;/rl ':I, I:lHJ
~h, 120 II-l ':'YI)
(-'.i,9JU 'pi,870
h'i, I h(1 18,12(]
l'J,MJ(l 32,010
j2, ')h() 14,760
~~~ J6,4'1(\
48,140 32,2hO
). ')00
26,60n
2S,8ll0
I r), 3no
sn, lOU
g,I60
8,850
7,620
13, ')00
43,300
33, ROO
22,860
24.790
21,040
16,080
7,420
7, "70
5,700
Il,580
6.850
1 080
10, I flO
12,410
18. hr)(l
j 7,600
J,240
17 ,560
S,5;::0
H,36U
22,000
'i,D9Q
14, hOIl
14,000
7,870
15,000
8, bOO
L 7,100
17,200
13,280
15,910
10,650
11,710
30,620
6,910
10,080
22,260
14,890
l,0711
-4, rJ'H)
0, ..:.YO
7, lno
9,720
l, tl40
R,/O()
11,330
SAT..JMILI. CREEK STREAM FLOW RECORDS
RUNOFF IN ACRE-FEr.T
6,280
2,780
8,000
I I , 100
19,000
8,400
7,500
20, SOO
35,800
5,620
8,850
11 .. ,880
9,870
9,180
12,630
12,150
3,010
5,480
4,230
4,500
2, '>()O
1,840
J, Q20
,7 ,':"8D
":2,210
8, J70
:1,6')0
.:., S 70
9,430
Ha r.
],970
1, ')LO
15,800
8, '))0
0,520
8,180
3, J JO
11,100
9,530
21,800
8,610
13,120
8,420
7,990
13,24[)
7, I SO
4,500
22,4')0
J,240
8,030
2,700
2,870
). bOO
8,050
j, .-'180
8, h')O
'3,400
J,460
7,980
7,560
6,840
II, !~OO
17,40()
l7, 'lOO
J ,800
lfJ, no~)
21,600
13,000
39,400
1 ~, 900
10,860
12,150
1 b, 550
19,170
14,610
5,790
17. no
9,8bO
4,480
g. t;~U
10, 96()
12,800
3,84rJ
n, 81 0
9,200
8,09 0
12,530
25,600
30,000
l6,900
34,700
34,200
41,100
j 5,900
46,7 DO
52,900
JO,700
35,880
26,900
29,400
21,950
43,300
19,63U
40,970
41,280
34,600
21, 751)
} 1, '),)0
32,430
42,010
28, 110
I g, (61)
42, 77 0
30,4tH)
34.040
57,800
42,000
49,700
45,900
48,100
51,200
':'2,800
41, SOO
61,600
70,100
51,200
36,690
46,420
3 1,800
34,780
32,620
49, 130
34,940
46,330
53,920
! .. 8,660
46, J 60
42,290
47.090
4),no
39, blO
40,530
45,810
44,600 40,900
39,400 4l,400
46,300 4],300
44,200 40,300
45,300 44,600
44,500 42,000
48,800 54,600
42,50051,300
60,000 62,800
55,200 49,400
40,200 58,500
35,350 35,210
52,890 75,970
29,620 45,270
lJ,070 17,440
42,160 41,180
37,550 34,150
28,630 33,950
47,730 37,210
43,800 38,190
49,190 3],990
J6,5}O 27,600
-)},OiO }5,02L)
39,590 49,040
38,200 )0,050
54,740 43,B90
4'),080 53,750
3J,BO 20,120
43.270 42,430
TABLE IV-l
47,200
47,100
32,100
47,400
43,500
,b,OOO
26,800
32,500
61, BOO
67,900
39,400
4B,900
60,360
44,950
21,340
41,650
39,590
Ib,570
72,490
41,280
34,170
32,770
65,220
43,470
43, )40
32,840
39, 130
45,860
287,830
320,200
364,400
374,140
401,620
300,700
318,250
372,320
443,430
519,020
493,000
357, I BO
403,330
342,330
262,870
360,090
313,550
369,540
367,120
34'"),010
302,160
230,140
305, J90
371,860
323,)20
3J9,690
282,700
297,260
351,040
TOTAL PRECIPITATION
GAGE AT SITKA OBSERVATORY
Jan. ~ Mar. ~ ~ June ~
1950 2.7 4.7 3.6 4.2 4.7 1.1 7.1
1951 5.2 4.4 6.7 8.5 3.1 5.8 2.7
1952 10.0 8.1 6.4 6.8 10.1 2.5 5.2
1953 5.4 11.9 10.3 4.6 2.9 1.8 2.4
1954 4.9 10.7 6.7 4.0 3.1 1.8 3.5
1955 11.2 12.1 13.6 3.2 6.7 3.2 1.9
1956 2.7 8.0 6.3 4.6 8.9 2.3 3.9
1957 3.0 7.5 3.7 7.8 2.2 2.1 4.1
1958 7.2 2.9 4.4 6.3 7.6 3.4 7.4
1959 3.7 9.1 11. 7 7.5 4.8 1.5 10.8
1960 6.9 4.0 5.6 5.4 1.4 3.7 4.8
1961 10.0 7.3 6.7 10.7 3.0 6.0 8.2
1962 14.8 1.9 12.6 4.0 3.9 6.0 2.5
1963 15.4 8.4 7.8 5.3 2.6 7.9 3.5
1964 9.9 16.4 11.3 10.1 8.9 3.0 4.7
1965 12.8 7.1 2.8 5.4 6.6 8.6 2.4
1966 5.6 7.0 7.7 5.5 9.8 1.1 4.6
1967 7.9 9.0 3.4 2.9 4.5 2.6 4.7
1968 6.2 5.6 4.9 8.2 2.7 2.2 3.6
1969 2.6 2.2 6.8 2.4 3.2 2.4 10.2
1970 6.3 8.6 7.7 6.9 5.4 4.8 6.0
1971 11. 7 7.0 5.2 5.3 6.4 2.4 2.7
1972 7.8 4.6 7.6 6.0 5.6 3.5 2.0
1973 8.1 6.7 6.5 5.0 4.8 2.8 4.4
1974
Monthly Maximums 15.4 16.4 13.6 10.7 10.1 8.6 10.8
Monthly Minimums 2.6 1.9 2.8 2.4 1.4 1.1 1.9
Maximum Annual 10.0 7.3 6.7 10.7 3.0 6.0 8.2
~inimum Annual 2.7 4.7 3.6 4.2 4.7 1.1 7.1
Average Annual 7.6 7.3 7.1 5.9 5.1 3.4 4.7
~ ~ Oct.
7.3 8.6 7.0
4.3 7.8 7.9
6.3 17.6 20.1
8.7 9.6 18.1
3.3 8.5 10.0
8.0 8.3 12.9
13.0 7.6 11.9
2.8 8.5 9.7
8.1 10.2 16.6
9.5 8.5 10.3
9.3 14.8 19.7
18.2 10.2 18.6
8.1 15.4 10.7
2.7 10.2 14.9
5.4 4.6 11.3
6.9 6.0 18.7
8.6 11.1 20.5
7.4 16.0 14.1
3.2 19.3 8.4
7.5 6.8 6.2
6.5 16.2 10.7
4.6 8.8 12.2
8.5 18.2 18.2
9.9 6.8 14.7
18.2 19.3 20.5
2.7 4.6 6.2
18.2 10.2 18.6
7.3 8.6 7.0
7.4 10.8 13.5
Nov. Dec.
3.6 4.9
9.4 7.3
15.0 5.7
8.1 13.3
11.6 16.3
4.0 5.9
14.2 18.2
17.8 10.0
11.1 11.5
14.6 17.9
11.0 14.7
10.5 9.5
10.4 9.1
9.8 9.7
11. 7 7.4
5.1 11.5
8.7 5.0
12.2 6.3
11.1 5.8
17.2 8.8
7.0 8.7
8.9 6.9
6.2 8.7
2.7 5.3
17.8 18.2
2.7 4.9
10.5 9.5
3.6 4.9
10.1 9.5
Annual
59.5
73.1
113.8
97.1
84.4
91.0
101.6
79.2
96.7
109.9
101.3
118.9
99.4
98.2
104.7
93.9
95.2
91.0
81. 2
76.3
9 / •• 8
82.1
96.Q
77.7
118.9
59.5
92.4
H <:
I
N
BLUE LAKE PROJECT
HISTORICAL WATER USE
ALASKA LUMBER £. PULP COMPANY
Jan. ~ ~ ~ ~ June ~
1965 4,104 3,577 3,942 3,804 3,914 3,764 3,319
1966 4,405 3,484 3,902 3,478 3,663 3,902
1967 4,138 3,604 4,006 3,696 3,699 3,558 3,997
1968 4,000 3,383 3,638 3,804 3,785 3,555 3,831
1969 3,896 3,509 3,828 3,580 3,380 3,819 4,019
1970 4,390 3,957 4,059 3,970 3,705 3,629 4,510
1971 4,458 4,034 4,445 4,485 4,479 4,307 4,811
1972 4,559 4,350 4,685 4,709 4,541 4,344 4,835
1973 4,310 3,997 4,587 4,375 4,218 4,424 2,999
NOTE: All units are in acre-feet
~ ~ Oct.
4,028 3,595 4,012
3,736 3,472 3,896
3,944 3,352 3,982
4,114 3,196 3,930
3,970 3,567 3,960
4,525 4,089 4,752
4,728 4,212 4,596
4,688 3,773 4,409
2,097 2,327 4,786
Nov. Dec.
718 3,524
3,936 3,672
3,801 4,009
3,779 3,874
3,855 3,488
4,421 4,151
4,476 4,666
4,485 4,378
4,706 4,197
Total
42,301
41,546
45,789
44,890
44,871
50,158
53,697
53,755
47,023
H
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MINIMUM WATER YEAR
Inflow
Water to ALPC
Fish Release
Surplus or (Deficit)
Reservoir Storage
Water for Generation
Spillway Discharges
Power Discharge-cfs
End of Month
Reservoir Storage
AVERAGE WATER YEAR
Inflow
Wa ter to ALPC
Fish Release
S~rp1us or (Deficit)
Reservoir Storage
Water for Generation
Spillway Discharge
Power Discharge-cfs
End of Month
Reservoir Storage
Oct.
22,600
4,774
930
16,896
6,194
10,702
-0-
174
Nov.
9,440
4,620
900
3,920
(6,793)
10,713
-0-
180
Dec.
2,960
4,774
930
(2,744)
(14,750)
12,006
-0-
196
145,000 138,207 123,457
56,640
4,774
930
50,936
6,194
24,800
19,942
400
14,590
4,620
900
9,070
(6,793)
15,863
-0-
266
25,530
4,774
930
19,826
(4,974)
24,800
-0-
400
Jan.
4,380
4,774
930
(1,324)
(14,6 Z6)
13,352
-0-
218
108,781
8,020
4,774
930
2,316
(22,484)
24,800
-0-
400
145,000 138,207 133,233 110,749
NOTE: All units are in acre-feet, except as noted.
BLUE LAKE PROJECT
RESERVOIR OPERATION
FISH RELEASE = 15 cis
Feb.
1,770
4,312
840
(3,382)
(16,071)
12,689
-0-
228
92,710
2,670
4,312
840
(2,482)
(18,039)
15,557
-0-
278
92,710
Mar.
1,500
4,774
930
(4,204)
(19,058)
14,854
-0-
242
73,652
1,500
4,774
930
(4,204)
(19,058)
14,854
-0-
242
73,652
Apr.
6,570
4,620
900
1,050
(14,165)
15,215
-0-
256
59,487
6,570
4,620
900
1,050
(14,165)
15,215
-0-
256
59,487
May
28,800
4,774
930
23,096
8,614
14,482
-0-
236
68,101
28,800
4,774
930
23,096
8,614
14,482
-0-
236
68,101
June
40,320
4,620
900
34,800
24,142
10,658
-0-
179
July
35,070
4,774
930
29,366
19,345
10,021
-0-
163
92,243 111,588
40,320
4,620
900
34,800
24,142
10,658
-0-
179
92,243
37,820
4,774
930
32,116
19,345
12,771
-0-
208
111,588
Aug.
26,500
4,774
930
20,796
11,216
9,580
-0-
156
122,804
39,740
4,774
930
34,036
11,216
22,820
-0-
372
122,804
Sept.
31,460
4,620
900
25,940
16,002
9,938
-0-
167
Annual
211,370
56,120
10,950
144,210
-0-
144,210
-0-
138,806 Rule Curve
45,200
4,620
900
39,630
16,002
23,678
-0-
398
138,806
307,400
56,120
10,950
240,240
-0-
220,298
19,942
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MINIMUM WATER YEAR
Inflow
Water to ALPC
Fish Release
Surplus or (Defid t)
Reservoir Storage
Water for Generation
Spillway Discharges
Power Discharge-cfs
End of Mon th
Reservoir Storage
AVERAGE WATER YEAR
Inflow
Water to ALPC
Fish Release
Surplus or (Deficit)
Reservoir Storage
Water for Generation
Spillway Discharge
Power Discharge-cfs
End of Month
Reservoi~ Storage
Oc t.
22,600
4,774
3,100
14,726
6,194
8,532
-0-
138
145,000
56,640
4,774
3,100
48,766
6,194
24,800
17,772
400
145,000
Nov. Jan.
BLUE LAKE PROJECT
RESERVOIR OPERATION
FISH RELEASE = 50 cfs
Feb. Mar. Apr.
9,440 2,960 4,380 1,770 1,500 6,570
4,620 4,774 4,774 4,312 4,774 4,620
3,000 3,100 3,100 2,800 3,100 3,000
1,820 (4,914) (3,494) (5,342) (6,374) (1,050)
(6,793) (14,750) (14,676) (16,071) (19,058) (14,165)
8,613 9,836 11,182 10,729 12,684 13,115
-0--0--0--0--0--0-
144
138,207
14,590
4,620
3,000
6,970
(6,793)
13,763
-0-
229
138,207
159 180 192 205 219
123,457 108,781 92,710 73,652 59,487
25,530 8,020 2,670 1,500 6,570
4,774 4,774 4,312 4,77 1, 4,620
3,100 3,100 2,800 3,100 3,000
17,656 146 (4,442) (6,374) 0,050)
(7,144) (22,282) (16,071) (19,058) (14,165)
24,800 22,428 11,629 12,684 13,115
-0--0--0--0--0-
400 362 208 205 219
131,063 108,781 92,710 73,652 59,487
NOTE: All units are in acre-feet, except as noted.
28,800
4,774
3,100
20,926
8,614
12,312
-0-
199
68,101
28,flOO
4,774
3,100
20,926
8,614
12,312
-0-
199
68,101
June
40,320
4,620
3,000
32,700
24,142
8,558
-0-
143
92,243
40,320
4,620
3,000
32,700
24,142
8,558
-0-
143
92,243
Ju1v
35,070
4,774
3,100
27,196
19,345
7,851
-0-
127
1l1,588
37,820
4,774
3, J 00
29,946
19,345
10,601
-0-
171
111,588
Aug.
26,500
4,774
3,100
18,626
11 ,216
7,410
-0-
120
122,804
39,740
4,774
3,100
31,866
ll,216
20,650
-0-
333
122,804
Sept.
31,460
4,620
3,000
23,840
16,002
7,838
-0-
131
138,806
Annual
211,370
56,120
36,500
118,660
-0-
ll8,660
-0-
Rule Curve
45,200 307,400
4,620 56,120
3,000 36,500
37,580 214,690
16,002 -0-
21,578 196,918
-0-17,772
360
138,806
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BLUE LAKE PROJECT
HISTORICAL ENERGY GENERATION
POWER YEAR JULY AUG. SEPT. OCT. NOV. DEC. JAN. FEB. MAR. APR. MAY JUNE TOTAL ----
1961-62 1544 1596 1733 1722 1512 1691 1533 1459 1250
1962-63 1302 1407 1460 1596 1701 1796 1722 1554 2367 2489 2300 2237 21 ,931
1963-64 2268 2415 2331 2561 2562 2573 2699 2405 2615 2657 2699 2436 30,221
1964-65 2279 2468 2478 2646 2772 2076 3087 2657 2562 2468 2363 2516 30, j72
1965-66 2331 2289 2394 2594 2384 2523 2562 2279 2478 2268 2174 2100 28,376
1966-67 1922 2174 2205 2447 2489 2668 2825 2279 2539 2531 2384 2184 28,647
1967-68 2079 2205 2373 2636 2646 2594 2856 2489 2583 2468 2195 2006 29,130
1968-69 2027 2121 2237 2699 2541 2699 2888 2510 2468 2310 2247 2027 28,774
1969-70 2100 2195 2415 2457 2478 2657 2762 2500 2552 2384 2426 2184 29,110
1970-71 2310 2363 2447 2646 27rJ) 3077 3151 2625 2877 2678 2615 2247 31,745
1971-72 2394 2447 2573 3024 2951 3161 3266 2972 3035 2814 2709 2573 33,919
197 2 -73 2457 2457 27CE 2268 3018 3204 3284 2901 3107 2794 2762 2335 33,296
1973-74 2454 25 29 2633 2932 2983 2836 2312 1817 2620
>-3
;I>
OJ r-<
Note: All values are in 1,000 kWh. tTl
H <:
In
BLUE LAKE PROJECT
RULE CURVE OPERATION OF RESERVOIR
Oct. Nov. Dec. Jan. Feb. Mar. Apr. May June July Aug. _S!:p~
Reservoir Elevation
Beginning of Monte -Feet 337.0 342.0 336.0 324.0 310.5 294.5 273.5 255.0 266.5 294.0 313.0 323.0
Reservoir Elevation
End of Month -Feet 342.0 336.0 324.0 310.5 294.5 273.5 255.0 266.5 294.0 313.0 323.0 337.0
Elevation
Change -Feet +5.0 -6.0 -12.0 -13.5 -16.0 -21.0 -18.5 +11.5 +27.5 +19.0 +10.0 +14.0
Storage Change -Acre-ft. 6,194 -6, 793 -14,750 -14,676 -16,071 -19,058 -14,165 8,614 24,142 19,345 11,216 16,002
Cummulative
Reservoir Volume-Acre-ft. 145,000 138,207 123,457 108,781 92,710 73,652 59,487 68,101 92,243 111,588 122,804 138,806
Average Reservoir
Elevation -Feet 339.5 339.0 330.0 317.3 302.5 285.0 264.3 260.8 280.3 303.5 318.0 330.0
Average Tailwater
Elevation -Feet 14.0 14.0 14.0 14.0 14.0 14.0 14.0 14.0 14.0 14.0 14.0 14.0
Gross Head-feet 325.5 325.0 316.0 303.3 288.5 271.0 250.3 246.8 266.3 289.5 304.0 316.0
BLUE LAKE PROJECT
AVAILABLE ENERGY WITH RULE CURVE OPERATION
FISH RELEASE = 15 cfs
MINIMUM AND AVERAGE WATER YEARS
Oc t. Nov. Dec. Jan. Feb. Mar. Apr. Mav June July Aug. Sept. Annual -------
MINIMUM WATER YEAR
Power Discharge-cfs 174 180 196 218 228 242 256 236 179 163 156 167
Average Reservoir
Elevation 339.5 339.0 330.0 317 .3 302.5 285.0 264.3 260.8 280.3 303.5 318.0 330.0
Gross Head-Feet 326 325 316 303 289 271 250 247 266 290 304 316
Head Loss-Feet 17 18 21 26 28 32 36 30 17 14 13 15
Average Net Generating
Head-Feet 309 307 295 277 261 239 214 217 249 276 291 301
Average Output-kW 3,868 3,976 4,160 4,344 4,281 4,161 3,941 3,684 3,207 3,237 3,266 3,616 3,810
Energy-1,000 kWh 2,878 2,863 3,095 3,232 2,877 3,096 2,838 2,741 2,309 2,408 2,430 2,604 33,371
AVERAGE WATER YEAR
Power Discharge-cfs 400 266 400 400 278 242 256 236 179 208 372 398
Average Reservoir
Elevation 339.5 339.0 333.0 321. 0 303.0 285.0 264.3 260.8 280.3 303.5 318.0 330.0
Gross Head-feet 326 325 319 307 289 271 250 247 266 290 304 316
Head Loss-Feet 63 37 63 63 33 32 36 30 17 24 55 62
Average Net Generating
Head-Feet 263 288 256 244 256 239 214 217 249 266 249 254
Average Output-kW 7,568 5,511 7,367 7,022 5,120 4,161 3,941 3,684 3,207 3,980 6,664 7,273 5,450
Energy-1,000 kWh 5,631 3,968 5,481 5,224 3,441 3,096 2,838 2,741 2,309 2,962 4,958 5,237 47,886
Firm Energy-1,000 kWh 2,878 2,863 3,095 3,232 2,877 3,096 2,838 2,741 2,309 2,408 2,430 2,604 33,371
Secondary Energy-
1,000 kWh 2,753 1,105 2,386 1,992 564 -0--0--0--0-554 2,528 2,633 14,515
[JJ >-3 ~ ~ CD
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BLu~ LAKE PROJECT
AVAILABLE ENERGY WITH RULE CURVE OPERATION
FISH RELEASE = 50 cfs
MINIMUM AND AVERAGE WATER YEARS
Oct. Nov. Dec. Jan. Feb. Mar. AEr. -~ June July Aug. SeEt. Annual
MINIMUM WATER YEAR
Power Discharge-cfs 138 144 159 180 192 205 219 199 143 127 120 131
Average Reservoir
Elevation 339.5 339.0 330.0 317.3 302.5 285.0 264.3 260.8 280.3 303.5 318.0 330.0
Gross Head-Feet 326 325 316 303 289 271 250 247 266 290 304 316
Head Loss-Feet 13 14 16 18 20 23 26 21 14 12 11 12
Average Net Generating
Head-Feet 313 311 300 285 279 248 224 226 252 278 293 304
Average Output-kW 3,107 3,222 3,432 3,691 3,854 3,658 3,529 3,236 2,593 2,540 2,529 2,865 3,177
Energy-1,000 kWh 2,312 2,320 2,553 2,746 2,590 2,722 2,541 2,408 1,867 1,829 1,882 2,063 27,833
AVERAGE WATER YEAR
Power Discharge-cfs 400 229 400 362 208 205 219 199 143 171 333 360
Average Reservoir
Elevation 339.5 339.0 333.0 320.0 303.0 285.0 264.3 260.8 280.3 303.5 318.0 330.0
Gross Head-feet 326 325 319 306 289 271 250 247 266 290 304 316
Head Loss-Feet 63 28 63 53 22 23 26 21 14 17 49 53
Average Net Generating
Head-Feet 263 297 256 253 267 248 224 226 252 273 255 263
Average Output-kW 7,568 4,893 7,367 6,589 3,995 3,658 3,529 3,236 2,593 3,358 6,109 6,812
Energy-1,000 kWh 5,631 3,523 5,481 4,902 2,685 2,722 2,541 2,408 1,867 2,498 4,545 4,905 43,708
Firm Energy-1,000 kWh 2,312 2,320 2,553 2,746 2,590 2,722 2,541 2,408 1,867 1,829 1,892 2,063 27,833
Secondary Energy-
1,000 kWh 3,319 1,203 2,928 2,156 95 -0--0--0--0-669 2,663 2,842 15,875
(f) rl
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H1 --.J
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BLUE LAKE PROJECT
FIRM ENERGY AVAILABLE WITH DIFFERENT FISH RELEASES
(1000 kWh)
Period
January
February
March
April
May
June
July
August
September
October
November
December
Annual
Comparison
Fuel Oil Required
(gallons)
Estimated Differential
Cost of Diesel Generation
in 1978
o cfs
3,440
3,000
3,256
2,965
2,884
2,498
2,656
2,665
2,836
3,121
3,096
3,327
35,749
0
0
0
Fish Releases
15 cfs
3,232
2,877
3,096
2,838
2,741
2,309
2,408
2,430
2,604
2,878
2,863
3,095
33,371
-2,378
169,700
+$86,040
Table IV-8
50 cfs
2,746
2,590
2,722
2,541
2,408
1,867
1,829
1,882
2,063
2,312
2,320
2,553
27,833
-7,9l6
565,400
+ $286,660
SECTION V
POTENTIAL NEW GENERATION
1. BLUE LAKE EXPANSION
a. Description
The ultimate development of the Blue Lake Project was planned as
three 3,000 kW units, and the manifold has a branch installed for the third unit
which is closed by a blind flange. No provision for expansion has been made
at the powerhouse but addition of the third unit would not require significant
demolition at the existing structure. The transmission line is adequate for a
new unit, but additional transformer capacity would be required.
b. Power Output
As previously discussed, firm energy from the project is considered
to be limited to rule curve operation of minimum T,vater years with secondary
energy being generated by the installed capacity when excess water is avail-
able. As more information relating to reservoir operation becomes available
in future years it may be possible to develop firm yield of the reservoir and
increase the firm energy with a consequent reduction of secondary energy. At
the present time firm energy output cannot be increased by a third unit, but
the production of secondary energy can be increased.
Rule curve operation of the reservoir utilizes only about 86,000
acre-feet of the total potential storage of 102,000 acre-feet which is avail-
able to El 230, as previously mentioned. This operation provides the maximum
amount of firm energy which can be generated, when water available for power
usage is allocated in proportion to the historical distribution of monthly
energy loads.
Addition of a third unit of 4,000 kW, together with re-rating the
existing units at 3,500 kW each, would provide a total installed capacity of
11,000 kW. Based on total average energy production this capacity could be
operated at a plant factor of from approximately 45% to 50% depending on the
amount of fish releases required. This amount of capacity is needed in the
system, and installation will provide better reservoir operation. Since it does
not provide additional firm energy, installation of the third unit is included
in the proposed program of development following the next major installation.
2. GREEN LAKE PROJECT
a. Description
Green Lake is located approximately 12 miles from Sitka and about
7 miles from Blue Lake at the end of Silver Bay. The lake is a part of the
Vodopad River and has formed about 1,500 feet upstream of the mouth. The
existing outlet of the lake is a relatively narrow gorge which controls the
existing lake level at about El 230.
V-2
It is anticipated that ralslng the lake level to El 420, by means
of a concrete arch dam at the present outlet, will provide sufficient reser-
voir storage for control of the runoff and adequate head to develop economic
power from the site. The project was studied by the Alaska Power Administration
(APA) in its feasibility investigations of the Takatz Project. A preliminary
arrangement of project is shown in Fig. 5, and of the proposed dam in Fig. 6.
A concrete arch dam, approximately 580 feet long along the crest
and with a maximum height of 215 feet, will be required to control the reser-
voir and to provide full regulation of a low water year runoff. A dam of this
size would provide a normal maximum reservoir level at El 420, and contain
an active storage volume of 112,000 acre-feet. The power conduit is tentatively
proposed as a short tunnel 300 feet which would also serve for river diversion
during construction. A 78-inch diameter steel penstock approximately 1,300 feet
long would be connected to the downstream portal of the tunnel. A surface power-
house will be constructed at ground level near Silver Bay. It is anticipated
that two horizontally-mounted Francis reaction turbines would be installed, each
delivering about 11,500 hp at best gate, under average net head, and connected
by a horizontal shaft to a generator rated at 9300 kVA with about a 90% power
factor (8,300 kW). It is estimated that, including generator, transformer and
transmission losses, each unit will deliver 7,500 kW to the load center at peak
load conditions, at best-gate operation of the turbines, under winter reservoir
levels.
An access road approximately seven miles long will be constructed
from Sawmill Cove to the project site as an extension of the existing Sitka
Highway. The road will be used for construction and resurfaced with gravel or
crushed rock after completion of the project to provide access for maintenance
of the transmission line and to the powerhouse. The transmission line will be
located along the new road and then follow the route of the existing transmis-
sion line to the Marine Street Substation. Transmission line voltage will be
at 69 kV and the lines will be carried on wooden frame poles. The capacity of
the line will be sufficient to conduct the output of the Green Lake unit, the
proposed third unit at the Blue Lake Project and an allowance for emergency
capacity provided by ALP generation. Consideration should also be given dur-
ing design to future connection of additional developments to the lines.
Approximate reservoir area-capacity curves are shown in Fig. 7.
b. Geology
No. detailed site geology is available at the present time, but
investigations are proposed in this report. It is expected that the general
geology will be similar to that at Blue Lake and will prove adequate as an arch
dam site. The precipitous terrain in the area indicates that sound rock should
be near the ground surface which will reduce construction excavation problems.
c. Hydrology and Power Output
The USGS operated a stream gage on the Vodopad River between
1915-1925 and monthly average runoffs in acre-feet are shown in Table V-l.
Significant hydrologic and reservoir operating data have been compiled and
are shown in Table V-2.
As shown in the tables the average annual runoff is about 212,400
acre-feet, or approximately 291 cfs. The average annual discharge from the
lowest year during the period of record is 236 cfs. The drainage area of
V-3
Green Lake is approximately 28.9 square miles which produces an annual aver-
age runoff of about 7,350 acre-feet per square mile. This is significantly
less than the long-term runoff from the Blue Lake drainage basin of 9,844 acre-
feet per square mile, which indicates that there may be more firm energy avail-
able at the site than estimated from the one decade period of record.
It is anticipated the project can be developed to deliver 15,000 kW
of dependable capacity to the load center during periods of peak loads, and will
be capable of an output of 52,000,000 kWh of firm energy, or a plant factor of
approximately 40%, which is considered appropriate for the system at that time.
This project is considered to have potential feasibility and is in-
cluded in the proposed program of development.
3. TAKATZ PROJECT
a. Description
Takatz Lake is located approximately 4,000 feet upstream of the
mouth of Takatz Creek which flows into Chatham Strait (by way of Takatz Bay)
on the eastern shore of Baranof Island. The project would be located about
20 airline miles east of Sitka.
It is anticipated that ralslng the lake level to El 1040 by con-
struction of a dam at the existing outlet of the lake will provide sufficient
storage for regulation of inflow and adequate head to develop the economic
potential of the project. A preliminary arrangement of the proposed proj-
ect is shown in Fig. 8.
A concrete arch dam approximately 200 feet high will be required
to control the reservoir and to provide regulation of the annual runoff. A
dam of this size would provide a normal maximum reservoir level at E1 1040,
and contain an active storage volume of 82,400 acre-feet. The power conduit
is tentatively proposed as a 6.S-foot by 7.0-foot modified horseshoe tunnel
approximately 2,800 feet long with a downstream portal approximately 1,000 feet
from the powerhouse. A 72-inch steel penstock would connect the portal to the
powerhouse. A surface powerhouse would be constructed at ground level near
Takatz Bay. It is anticipated that two Francis turbines would be installed,
each delivering about 18,600 hp at best gate, under average net head, and con-
nected to a generator rated at 15,400 kVA, with about a 90% power factor
(13,850 kW). It is estimated that, including generator, transformer and
transmission losses, each unit will deliver 12,500 kW to the load center at peak
load conditions at best-gate operation of the turbines, under winter reservoir
levels.
The site was studied in some detail by the APA and was presented
in a report entitled "Takatz Creek Project -Alaska" dated 1968. The basic
data presented herein was obtained from that report. The reservoir area-capac-
ity curves are shown in Fig. 9.
b. Geology
The APA investigated the geology at the site and concluded that
conditions were adequate for construction of a concrete arch dam.
The topography appears to have been greatly influenced by glacia-
tion, probably during Pleistocene Time. Slopes are precipitous and covered
by a thin mantle of soil with heavy growths of underbrush.
V-4
The bedrock formation at the damsite is a massive quartz diorite
which is dense and indurated. The rock is medium-to-coarse grained and is
equigranular. This is typical of rocks associated with the Coastal Range Bath-
olith which generally is located along the coast of the mainland of Southeast
Alaska. The Coastal Range rocks are considered to be competent foundation
materials and if the geology at the site is indeed of that formation, the
foundation conditions should be entirely adequate. Further investigations
will be required of the site conditions.
c. Hydrology and Power Output
The drainage basin of Takatz Lake has an area of about 10.6 square
miles. Stream flow records for 15 complete water years are available at a
point on Takatz Creek downstream of the damsite ,,,ith a drainage area of 17.5
square miles and are listed in Table V-3. The average annual runoff at the gage
was 199,800 acre-feet or an average of 11,417 acre-feet per square mile which is
significantly higher than either Blue Lake or Green Lake. The annual average
precipitation at Baranof Warm Springs, however, is approximately 143 inches which
is about 154% of the long-term average at Sitka. The average annual inflow into
Takatz Lake is estimated to be about 121,000 acre-feet which would produce an
average annual discharge of about 166 cfs.
It is estimated that an average net head of approximately 950 feet
can be developed at the site which would produce an average generator output of
about 11,080 kW which would deliver approximately 91,200,000 kWh of firm energy
to the load center. At 40% plant factor, the peak generator output would be
27,700 kW, which would deliver 25,000 kW of dependable peak capacity to the load
center.
Ultimate development of the site could be planned as having two
units at 13,850 kW (total 25,000 kW delivered to load center). However, a
staged development could be considered, for comparison with the Green Lake
Project at the same time period, which would have two units at 7,500 kW each,
and with later installation of a third unit at 10,000 kT"T.
The project appears to be feasible and is included in the proposed
program of development.
4. OTHER SITES
a. Haj or
(1) Baranof Lake Project
A major potential site is located at Baranof Lake, about
four miles south of Takatz Lake. The drainage area is larger than Takatz
Lake but the total head which could be economically developed is much less.
The APA concluded that bus-bar power from a plant at Baranof Lake would be
nearly twice as costly as from Takatz. The site was rejected by comparison
with Takatz Lake.
(2) Lake Diana Project
Lake Diana is located about 16.5 miles southeast of Sitka,
and has the potential for a high-head development, but only has about 3.5
square miles of drainage area. Development of this site would be costly
for the power developed, and is not considered as attractive as Green Lake.
(3) Maksoutof Projects
Two sites are located in the area, but would require about
64 miles of transmission line which would be prohibitive in terms of both
cost and reliability.
b. Minor
(1) Cold Storage Lake
This site is located about 10 miles north of Sitka. The
drainage area is small and transmission costs would be very high in relation
to the capacity which could be developed. The site would not meet long-term
requirements of the system and was not considered further.
(2) Hogan Lake
This site, located about 13.5 miles northeast of Sitka,
V-5
has the same disadvantages as Cold Storage Lake and was rejected for the same rea-
sons.
(3) Indigo Lake
This site has a more favorable geographic location being near
(and between) both Blue Lake and Green Lake, but has a drainage area of only
900 acres which is much too small to result in a sufficiently-large development,
even with the relatively-high head available.
GREEN LAKE OUTLET
RECORDED RUNOFF IN ACRE-FEET
Oct. Nov. Dec. Jan. Feb. Mar. AEr. Mav June Ju1v Aug. Seot. Annual
1915 34,100
1916 29,900 11,200 7,200 1,400 4,200 2,500 6,900 17,400 33,800 27 ,400 30,700 33,600 206,200
1917 29,000 12,500 5,900 5,000 6,700 3,100 4,400 19,100 2S,300 30,200 32,300 26,900 213,400
1918 40,100 37, SOO 4,SOO 7,SOO 2,200 1,100 4,500 lS,200 34,600 36,900 30,100 29,300 247,400
1919 25,SOO 22,500 11,700 14,200 2,100 900 7,500 15,700 21,300 30,000 27,SOO 29,800 209,300
1920 24,100 10, SOO 7,900 13,300 4,800 1,700 2,400 10,600 2S,500 27,400 26,900 19,600 17S,000
1921 17,300 15,100 4,500 3,900 6,200 3,600 4,100 17,5C~ 32,300 23,SOO 19,000 24,700 172 ,000
1922 35,100 9,500 18,000 5,600 2,000 1,700 5,100 21,600 27,700 2S,400 30,700 33,900 219,300
1923 15,100 23,SOO 5,100 1,900 6,100 7,200 13,000 21,000 30,300 24,000 15,400 38,600 201,500
1924 18,000 2S, SOO 11,200 6,000 6,800 5,600 9,500 29,500 40,900 41,400 33,100 41,500 272,500
1925 26,900 17,000 10,000 2,100 1,400 3,100 5,100 29,100 30,900 34,400 24,300 20,200 204,500
Average 26,100 18,900 8,600 6,100 4,300 3,100 6,200 20,000 30,900 30,400 27,000 30,800 212,400
RESERVOIR DATA
GREEN LAKE PROJECT
ESTIMATE OF FIRM ENERGY
Drainage Area -square miles
Average Runoff -acre feet
Minimum Runoff -acre feet (estimated)
Average Annual inflow -cfs
Minimum Annual inflow -cfs
Normal Maximum Reservoir Elevation -feet
Mean High Tide -MSL -feet
Gross Head -feet
Dependable Capacity (Peak Load Conditions)
Reservoir Elevation -feet
Net Head -feet
Discharge -cfs (best gate)
Turbine Output -hp
Generator Output -kW
Capacity at Load Center (on feeder) -kW
Average Annual Conditions
Maximum Drawdown -feet
Average Net Head -feet
Average Regulated Discharge (minimum year)-cfs
Average Regulated Discharge (average year)-cfs
Firm Energy -1000 kWh (at load center)
Secondary Energy -1000 kWh (at load center)
Average Energy -1000 kWh (at load center)
28.9
212,400
172 ,000
291
236
420
12
408
380
345
653
23,000
16,600
15,000
120
352
244
285
52,000
10,000
62,000
TABLE V-2
TAKATZ CREEK
RECORDED RUNOFF IN ACRE-FEET
Oc t. Nov. Dec. Jan. Feb. Mar. AEr. ---.!i~ June July Aug. Seot. Annual
1951 29,900 19,000 20,000
1952 17,SOO 14,500 3,300 1,200 1,200 1,100 4,800 12,900 23,500 3S,500 25,SOO 37,500 lS2,100
1953 32,600 17,500 7,100 3,500 3,300 4,200 5,400 22,900 33,000 32,600 2S,100 29,000 219,200
1954 40,100 14,500 7,900 3,100 7,000 2,200 2,000 14,600 30,100 26,300 22 ,000 24,300 194,100
1955 21,100 24,700 13,500 3,900 2,600 2,400 3,200 S ,900 22,100 33,900 29,900 27,700 193,900
1956 17,400 6,000 2,300 1,400 1,400 1,500 3,800 16,900 29.900 33,300 37,000 17,8'1'1 1"iil,7'1f)
1957 16,200 13,300 12,800 4,100 2,200 2,100 3,900 18,500 30,500 27,900 22,400 24,100 173,000
1958 14,400 22,700 4,500 S ,000 2,500 3,100 7,000 19,600 31,100 23,300 23,700 16,000 175,900
1959 32, sao 13,100 6,SOO 2,900 2,500 3,900 4,600 17,100 37,100 37,200 2S,800 17,800 204,600
1960 16,600 E,100 6,700 3,000 3,700 2,900 5,700 22,900 30,700 38,000 23,500 28,500 193,300
1961 37,500 12,200 12,000 5,200 4,000 5,300 6,400 17,600 42,000 30,900 36,200 21,400 230,700
1962 31,700 7,200 2,800 4,600 2,500 2,300 7,200 9,600 24,300 28,000 29,600 27,600 177 ,400
1963 33,200 17,600 21,400 12,000 10,900 4,300 5,300 14,900 21,500 21,700 17,300 57,700 237,SOO
1964 57,700 11,000 13,200 6,300 5,000 3,000 5,400 11,800 37,800 39,699 31,600 19,100 241,500
1965 30,SOO 11 ,600 9,200 7,900 2,800 3,600 5,100 8,900 24,600 30,100 20,600 16,600 171,800
Average 2S,400 14,300 8,SOO 4,600 3,800 2,900 5,000 16,000 30,300 31,500 27,400 26, sao 199,800
SECTION VI
POWER STUDY
1. GENERAL
A forecast of loads is discussed in this section. Historical
loads were used to project annual peak and energy demands to the current
year from which the forecast loads were projected. The projection was com-
plicated by power conservation measures which caused reductions from normal
demands during the past winter, but it is assumed that load growths will continue
in an orderly and progressive manner even though there will be variations from
a smooth curve of growth in individual years. The Alaska Power Administration
(APA) has estimated that an annual growth rate of 8% per year is appropriate
for Southeast Alaska. Based on the analysis of the historical loads in Sitka,
the value of 8% is considered reasonable as an average and has been used in
this report. This growth rate of course incorporates any larger block loads
a nU-llbE:r of which are potential as listed in Table VI-7.
2. LOADS
a. Peak Capacity
From historic loads, it was estimated that the normal peak load for
the power year 1974-75 would be 6840 kW, and with inclusion of a load growth
reserve, the peak load would be 7,114 kW, with a total energy demand of 34,275,300
kWh. These loads were projected at an 8% increase per year to the 1989-90 power
year. In that year the peak load will have increased to 22,566 kW, with 108,723,000
kWh of energy being required. A tabulation of forecasted annual loads is shown
in Table VI-l, and a peak demand growth curve including reserves, is shown in
Fig. 10.
b. Dependable Capacity
Dependable capacity is defined as the capacity which can always be
delivered to the load center during a critical period. In this report the cri-
tical condition for hydroelectric units is considered to be during the winter
season when peak loads occur, with concurrent drawdown of the reservoir to mini-
mum levels for that season. The minimum amount of capacity which can be genera-
ted at any time during the critical period for all years is the dependable capa-
city for that project. Under this definition the delivered capacity during
periods of lower. loads (off-peak period) could be less than dependable capacity
with no detrimental effects. Conversely during most, if not all, of the cri-
tical periods during the life of the plant, the delivered capacity would be
actually greater than the dependable capacity.
c. System Load Factor
The system load factor expresses the relationship between total
energy and peak load in a given time period. For an annual condition the total
energy (in kWh) demand for that year is divided by 8,760 hours to determine an
average demand (average output when used with resources) in kW for the year.
The load factor for the year is the ratio of the average demand to the peak load
expressed as a percentage. The annual load factor of the City's system was
determined from historical loads to be 55%.
VI-2
d. Ener~
Forecasts of system energy demand were developed from projected peak
loads and the system load factor. Monthly energy requirements and peak loads
were forecast from the historical values shown in Tables VI-2 and VI-3. The
forecast of the monthly energy loads and peak loads is shown in Table VI-4. A
growth curve of energy loads is shown in Fig. 11.
e. Load Growth Reserve
Since projections for load growth are usually made in annual in-
creaseS of finite amounts, a small reserve allowance for load growth during
each period is considered to be necessary. For this study a load growth re-
serve of one-half of the projected annual increase has been included as a part
of the annual load forecast for the beginning of that year.
f. Forced Outage Reserve
In order to provide necessary reliability to the system, an adequate
amount of reserve capacity is required. For this study the required reserve
capacity has been taken as the difference between the required generation (peak
loads plus load growth reserve) and the resources, minus the largest individual
generating unit. If such a reserve is available, the system can continue to
provide reliable power even though a forced outage occurs with the largest unit.
g. Exports
The power requirements of ALP form a potential for Sitka to market
power, on a contractual basis. As seen in Figs. 10 and 11, excess capacity and
energy will be available in varying amounts in the years subsequent to completion
of new hydroelectric generating facilities. No attempt has been made in this
report to formulate a fixed amount which might be provided on a long-term con-
tractual basis. If an amount were determined by negotiations with ALP, it appears
that reasonable amounts of power could be made available on a firm basis. Ex-
ports are a part of system loads and are shown as such in the appropriate tables.
3. FUTURE REQUIREMENTS
a. System in 1974-75
During. this period the peak load is forecast to be 7,114-kW with an
energy requirement of approximately 34,275,000-kWh. Provision of a forced outage
reServe of 3500 kW, to correspond with the largest unit, will increase the required
capacity of resources to 10,614 kW. These loads and the resources available to
meet the loads are shown in Table VI-5. In this period 3100 kW of diesel capa-
city and 7000 kW of hydroelectric capacity will be available to meet loads, but
the system will have a capacity deficit of 514 kW, including the forced outage
reserve requirement.
The Blue Lake Hydroelectric Project will provide firm energy in the
amount of 32,000,000 which will require 2,275,000 kWh of generation by diesel
units during this period. It is estimated that this amount of diesel generation
will require about 162,500 gallons of fuel oil. A load duration curve for this
period is shown in Fig. 12.
VI-3
b. Sys tern in 1976-77
During this period the peak load is forecast to be 8,297 kW, with an
energy requirement of approximately 39,975,000 kWh. Provision of a forced outage
reserve of 3500 kW, again corresponding to the largest unit, will increase the
required capacity of resources to 11,797 kW. These loads and the resources
available to meet the loads are shown in Table VI-5. In this period 3100 kW of
diesel capacity and 7000 kW of hydroelectric capacity will again be available
to meet loads, but the capacity deficit of the system will have increased to
1,697 kW, including the forced outage reserve requirement.
The Blue Lake units will again provide firm energy of 32,000,000 kWh,
which will require 7,975,000 kWh of generation by diesel units during this period.
It is estimated that this amount of diesel generation will require approximately
570,000 gallons of fuel oil. A load duration curve for this period is also
shown in Fig. 12.
c. System in 1978-79
During this period the peak load is forecast to be 9 678 kW with an
energy requirement of approximately 46,628,000 kWh. Provision of a for~ed out-
age reserve of 3,500 klJ, corresponding to the largest unit, will increase the
required capacity of resources to 13,178 kW. These loads, and the resources
available to meet the loads, are again shown in Table VI-5. In this period 3100
kW of diesel capacity, and 7000 k1.J of hydroelectric capacity from the Blue Lake
Project, will again be available to meet loads, but the capacity deficit of the
system will have increased to 3,078 kW, including the forced outage reserve
req ui remen t .
If installation of the Green Lake Project proceeds in accordance
with the schedule proposed in this report, the t\.;ro units of the project would
be on-line about mid-way through this period to meet the peak load. Table VI-5
does not include the capacity from this project to show the affect of slippage
in the schedule so that installation of the units is not completed in time to
supply the peak load. The energy available from the project over the latter
portion of the period would, of course, eliminate all need of diesel generation
subsequent to the on-line date, but in order to show the fuel oil requirements
at a period prior to completion of the Green Lake Project, the energy available
from the project during the latter portion of the period is not shown in Table VI-5.
The Blue Lake Project will again provide firm energy of 32,000,000
kWh, which will require 14,628 kWh of generation by diesel units during this
period. It is estimated that this amount of diesel generation will require
approximately 1,045,000 gallons of fuel oil. With the Green Lake units on-
line during the last half of the period the fuel oil requirements would be
reduced to about one-half of that value. A load duration curve for this period
is also shown in Fig. 12.
d. System Subseguent to 1980
A summary
shown in Table VI-6.
shown in the table is
of loads and resources
A brief description of
given in the following
for the decade following 1980 is
the grm.;rth of loads and resources
paragraphs.
In the 1979-80 power year the peak load will have increased to
10,452 kW with an energy requirement of 50,358,000 kWh. With the installation
VI-4
of the larger units at the Green Lake Project, the forced outage reserve require-
ment will be 7500 kW. It is estimated that there would be 33,642,000 kWh of sur-
plus firm energy available for export during this period. Sale of this amount
of energy at unity load factor would require 3840 kW of peak capacity which is
also available. The total loads from the above have a peak of 21,792 kW and an
energy requirement of 84,000,000 kWh, assuming that the exports can indeed be
marketed.
The available resources during this period will still include 3100 kW
of diesel capacity and 7000 kW of hydroelectric capacity from the Blue Lake Pro-
ject. In addition there will be available 15,000 kW of hydroelectric capacity
from the Green Lake Project, or a total capacity of 25,100 kW, with firm energy
of 84,000,000 kWh. Including the requirements for forced outage reserves, the
system will have a surplus capacity of 3208 kW. If it were decided to deactivate
the diesel plant at this time the capacity surplus would, of course, be reduced to
108 kW, and a capacity deficit would again exist in the ensuing years until the
next hydroelectric unit could be installed. In order to maintain a surplus capa-
city the diesel units should be maintained until the Blue Lake -Unit #3 goes on-
line which is proposed to occur late in 1983. The diesels are not considered
however to provide energy.
In the 1984-85 power year the peak load will have increased to
15,358 kW with an energy requirement of 73,994,000 kWh. The forced outage re-
serve requirement will again be 7500 kW. During this period it is estimated
that there would be 10,006,000 kWh of surplus firm energy available for export.
Sale of this energy at unity load factor would require 1142 kW of peak capacity.
The total load has a peak of 24,000 kW and an energy requirement of 84,000,000
kWh, again assuming that the exports can be marketed.
The available resources during this period will be entirely hydro-
electric, and will consist of 11,000 kW at the Blue Lake Project and 15,000 kW
at the Green Lake Project as delivered at the load center. The total available
firm energy will again be 84,000,000 kWh again delivered at the load center.
Installation of the third unit at the Blue Lake Project will significantly in-
crease the capability of that project to utilize water from high-runoff years
for production of secondary energy.
In the 1989-90 power year the peak load will have increased to
22,566 kW with an energy requirement of 108,723,000 hlfh. With the installation
of the first unit at the Takatz Project which is scheduled to be on-line
late in 1988, the forced outage reserve requirement will be 12,500 kW. During
this period it is estimated that there would be 30,082,000 kWh of surplus firm
energy available for export. Sale of this energy at unity load factor would
require 3434 kW of peak capacity. The total loads have a peak of 38,500 kW and
an energy requirement of 138,805,000 kWh, again assuming that the exports can
be marketed.
The available resources during this period will be 11,000 kW at the
Blue Lake Project, 15,000 kW at the Green Lake Project, and 12,500 kW from Unit
f!l at the Takatz Project. The firm energy from these projects is estimated
to be 175,200,000 kWh. All values are for delivery at the load center.
e. Secondary Energy
All resource values stated above are either dependable capacity or
firm energy, which are available at all times. A significant amount of secon-
VI-5
dary is expected to be available from the hydroelectric projects which would be
available for export on "as available" basis, and would permit appreciable sav-
ings in fuel oil by ALP. It is anticipated that future hydrological studies
will show that the Blue Lake and Green Lake Reservoirs can be operated so as
to provide about 10 to 15% additional firm energy, \vith a consequent reduction
of secondary energy.
f. Reserves and Exports
Reserve capacity sufficient to allow the system to meet loads even
though the largest unit in the system is forced off-line is an essential require-
ment for system dependability. If such reserve capacity is not available an
outage will cause a blackout of the system and force a serious curtailment of
loads when power is restored. This is most significant during an extended out-
age such as might be caused by a bearing failure or damage to the turbine or
generator.
Forced outage reserves in small isolated systems must be equivalent
to the capacity of the largest unit in the system, but the incremental cost of
installing additional capacity in a unit is usually relatively low. A large
reserve capacity requirement however, reduces the amount of power which is
available for marketing and a resultant loss of revenue. Interconnected systems
often share reserves and thereby reduce the amount of required reserves in each
system. Sharing of reserves by Sitka and ALP is possible but is limited by the
capacity of the tie line between the mill and Blue Lake powerhouse. With the
size of units proposed for the Green Lake Project, the tie is sufficient to
allow the Sitka reserves to be reduced by 3750 kW. The amount of reserves fur-
nished Sitka by ALP, must, of course, be considered in marketing negotiations.
The ALP reserves can be provided by an allowable curtailment of power to the
mill which would range from zero to almost 2900 kW in, the period until 1190. A
summary of the effect of reserve-sharing on power available for exports is shown
in Table VI-8, and can be compared with the exports shown in Table VI-6 in
which no sharing is considered. Sharing of reserves ,viII allow a dependable capacity
of 4000 kW to be available for export until 1986, when 8,000 kl.J will be avail-
able on a dependable basis. The interconnection will, of course, require im-
provements at that time. The export capacity would be associated with large
amounts of energy which are also shown in Table VI'-S,
(1)
197{-75
1975-76
1976-77
1977-78
1978-79
1979-80
1980-81
1981-82
1982-83
1983-84
1984-85
1985-86
1986-87
1987-88
1988-89
1989-90
Normal
Peak
kW
6,840
7,387
7,978
8,616
9,306
10,050
10,854
11,723
12,660
13,673
14,767
15,948
17 ,224
18,602
20,090
21,698
FORECAST OF LOADS
(2) Load Growth
Reserve
kW
?74
296
319
345
372
402
435
469
507
547
591
638
689
744
804
868
(1) Escalated at 8% per year.
(2) Estimated at one half of annual growth.
(3) Based on annual system load factor of 55%.
Peak
Load
kW
7,11L:
7,683
8,297
8,961
9,678
10,452
11,289
12,192
13,167
14,220
15,358
16,586
17,913
19,346
20,894
22,566
(3)
TABLE VI - 1
Energy
kWh
34,275,300
37,016,700
39,974,900
43,174,100
46,628,600
50,357,700
54,390,400
58,741,100
63,438,600
68,512,000
73,994,800
79,911,300
86,304,800
93,209,000
100,667,300
108,723,000
CITY OF SITKA
SYSTEM E;NERGY LOADS
1962 -1974
1,000 kW h
POWER YEAR* July Aug. Sept. Oct. Nov. Dec. Jan. Feb. Mar. Apr. May June Annual
1962-63 1,214.0 1,302.1 1,363.7 1,543.6 1,627.0 1,797.1 1,674.8 1,517.5 1,690.8 1,638.2 1,616.8 1,433.6 18,419.2
1963-64 1,505.6 1,632.0 1,703.0 1,898.4 2,007.7 2,087.1 2,102.2 1,936.0 2,045.0 1,891.1 1,834.0 1,578.8 22,220.9
19c4-65 1,625.4 1,713.3 1,838.3 1.986.i 2,153.5 2,477.2 2,478.6 2,120.0 2,248.7 2,107.7 2,004.7 1,791. 0 24,544.5
1965-66 1,782.9 1,989.6 1,755.2 1,710.3 1,904.5 2,162.5 2,127.6 1,873.6 1,996.9 1,774.1 1,728.5 1,562.7 22,368.4
1996-67 1,446.3 1,642.6 1,735.7 1,911.5 1,987.7 2,197.3 2,201.9 1,952.7 2,256.6 1,976.3 1,881.1 1,683.0 22,872.7
1967-68 1,610.0 1,702.0 1,824.4 2,055.3 2,187.8 2,411.1 2,509.8 2,263.4 2,276.7 2,120.2 1,956.7 1,740.8 24,658.2
19&8-69 1,769.9 1,867.9 2,011.8 2,207.1 2,194.8 2,495.2 2,726.1 2,212.3 2,354.6 2,089.9 2,018.5 1,780.0 25,7'18.1
1969-70 1,972.1 1,973.2 2,085.2 2,247.5 2,335.0 2,482.1 2,612.1 2,205.3 2,377.3 2,248.1 2,190.9 1,911.8 26,640.6
1970-71 2.063.7 2,112.4 2,236.3 2,444.3 2,497.5 2,843.2 2,882.5 2,413.4 2,616.8 2,421.4 2,331.2 2,021. 3 28,884.0
1971-72 2,038.8 2,118.4 2,276.1 2,493.4 2,530.0 2.917.4 3,011.4 2,727.6 2,756.5 2,546.4 2,410.3 2,153.2 29,979.5
1972-73 2,108.9 2,168.5 2,383.5 2.268.9 2,694.5 3,030.0 3,055.6 2,702.3 2,864.6 2,569.9 2,526.1 2,280.9 30,653.7
1973-74 2,207.2 2,273.1 2,342.8 2,682.0 2,878.0 2,527.7 2,798.9 2,418.3
*Exam~le: Power year 1962-63 is from July 1.1962 through June 30,1963.
1967-68 6.53 6.50 7.40
1968-69 6.88 7.26 7.82
1969-70 7.40 7.41 7.83
1970-71 7.14 7.31 7.74
1971-72 6.30 7.07 7.59
1972-73 6.88 7.07 7.78
Average 6.94 7.17 7.69
Load Factor 64.2 67.7 72 .1
SUMMARY OF MONTHLY ENERGY LOADS
Oct.
8.33
8.58
8.44
8.47
8.32
7.40
8.26
67.3
(Percent of Annual)
Nov. Dec. Jan.
8.87 9.78 10.18
8.53 9.70 10.60
8.76 9.32 9.80
8.65 9.84 9.98
8.44 9.73 10.05
8.79 9.88 9.97
8.67 9.71 10.10
69.2 62.9 65.4
Feb.
9.18
8.60
8.28
8.36
9.10
8.82
8.72
69.6
Mar. June
9.23 8.60 7.94 7.06
9.15 8.12 7.84 6.92
8.92 8.44 8.22 7.18
9.06 8.38 8.07 7.00
9.19 8.49 8.04 7.18
9.35 8.38 8.24 7.44
9.15 8.90 8.06 7.13
70.5 65.4 67.4 70.2
CITY OF SITKA
FORECAST OF LOADS
SUMMARY OF }10NTHLY LOADS
~ ~ ~ Oc t. Nov. Dec. Jan. Feb. Mar. ~ ~ June Annua 1
ENERGY ~1. 000 kW il)
1974-75 2, 37H. 7 2,957.6 2,635.8 2,83l.1 2,971.7 3,328.L 3,46l. 8 2,988.8 3,136.2 2,879. L 2,762.6 2,443.8 34,275.3
1975-76 2,569.0 2,654.1 2,846. 6 3,057.6 3,209.4 3,594.3 3,738.7 3,227.9 3,387.0 3,109.4 2,983.5 2,639.3 37,016.7
1976-77 2,774.3 2,866.2 3,074.1 3,301.9 3,465.9 3,881. 6 4,037.4 3,485.8 3,657.7 3,357.9 3,222.0 2850.2 39,974.9
1977-78 2,996.3 3,095.6 3,320.L 3,566.2 3,743.2 4,192.2 4,3hO.6 3,764.8 3,950.4 3,626.6 3,479.0 3,078.3 43.l74.1
1978-79 3,236.0 >,343.3 l, 585.8 3,851.5 4,042.7 '.,527.6 4,709.5 4,066.0 4,266.5 3,916.8 3,758.3 3,324.6 46,628.6
1979-80 3,494.9 3,610.8 3,872.7
AVERAGE ENERGY (kW)
197:'-75 3, 197 3,303 3,661 3,805 4,127 4,413 1',653 4,448 4,215 3,999 3,713 3,394 3,913
197)-76 3,453 3,567 3,954 4.110 4,45R 4,811 5,025 4,S03 4, 5) 2 4,319 4,010 3,666 4,226
1976-77 3,72') 3,H52 4,270 4,4:38 4~814 5,217 5,427 5,187 ~, 91 6 ~, bb,~ "+,331 3,959 4,563
1977-/8 4,027 4,161 !t,611 4,793 '),199 ),635 5,861 5,602 5,310 ",037 4,677 4,275 4,929
1978-79 4,34', 4,494 '.,980 '),177 5,615 6,085 6,330 6,051 5,735 5,440 5,05L 4,618 5,284
L979-80 4,697 1+,853 5,379
PEAK LOAD (kW)
1974-75 '.,980 4,879 5,078 5,654 5,964 7,114 7,114 6,391 6,048 6,048 5,509 4,835 7,114
1975-76 5,379 5,269 '), ~84 6,107 6,442 7,683 7,683 6,901 6,530 6,530 5,950 5,222 7,683
1976-77 5,808 5,690 5,922 6,594 6,957 8,297 8,297 7,45 j 7,052 7,052 6,426 5,640 8,297 H
~
1977-78 6,273 6,146 6,395 7,122 7,513 8,961 8,961 8,049 7,617 7,617 6,939 6,090 8,961 r-<
tr1
1978-79 6,774 6,638 6,907 7,692 8,114 9,678 9,678 8,694 8,227 8,227 7,494 6,578 9,678 <:
H
1979-80 7,226 7,168 7,471
.j>-
Sm1MARY OF LOADS AND RESOURCES
1974-1979
1974-75 1976-77
Peak Energy Peak
kH 1,000 kHh kH
LOADS
Residential, Commercial
and Industrial Loads 6,840 32,955 7,978
Load Growth Reserve 274 1,320 319
Peak Loads 7,114 34,275 8,297
Exports
Forced Outage Reserve 3 2 500 3,500
Total Loads 10,614 34,275 11,797
RESOURCES
Diesel Unit No. 1 300 1,275 300
Diesel Unit No. 2 500 500
Diesel Unit No. 3 300 1,000 300
Diesel Unit No. 4 2,000 2,000
Blue Lake Unit No. 1 3,500 16,000 3,500
Blue Lake Unit No. 2 3 2 500 16 2 000 3,500
Total Resources 10,100 34,275 10,100
Surplus or (Deficit) (514) (1,697)
Note: 1. Diesel generation can be reduced by secondary energy from the
Blue Lake Project or imports from ALP, when available.
Energy
1 ,000 k~fu
38,438
1,537
39,975
39,975
1,275
1,000
5,700
16,000
16 2 000
39,975
1978-79
Peak Energy
kW 1,000 kWh
9,306 44,836
372 1,792
9,678 46,628
3,500
13,178 46,628
300 1,275
500 1,353
300 1,000
2,000 11 ,000
3,500 16,000
3 2 500 16 2 000
10,100 46,628
(3,078)
2. Resource values are considered as dependable capacity and firm energy at load center.
3. 1978-79 period does not include Green Lake Project in
operation as scheduled to reflect the effect of slippage
on the system.
S ill'iMARY OF LOADS AND RESOURCES
1979-1990
1979-80 1984-85 1989-90
Peak Energy Peak Energy Peak Energy
kW 1,000 k\m k~" 1,000 kWh kW 1,000 kIm
LOADS
Residential, Commercial
and Industrial Loads 10,050 48,421 14,767 71,147 21,698 104,541
Load Growth Reserve 402 1,937 591 2,847 868 4,182
Exports 33,642 1,142 10,006 3~9:3~
Peak Loads 84,000 16,500 84,000 25,451 138,805
Forced Outage Reserve 7,500 12.50Q
Total Loads 84,000 24,000 38,500 138,805
RESOURCES
Diesel Unit No. 1 300
Diesel Unit No. 2 500
Diesel Unit No. 3 300
Diesel Unit No. 4 2,000
Blue Lake Unit No. 1 3,500 16,000 3,500 10,000 3,500 10,000
Blue Lake Unit No. 2 3,500 16,000 3,500 10,000 3,500 10,000
Blue Lake Unit No. 3 4,000 12,000 4,000 12,000
Green Lake Unit No. 1 7,500 26,000 7,500 26,000 7,500 26,000
Green Lake Unit No. 2 7,500 26,000 7,500 26,000 7,500 26,000
Takatz Bay Unit No. 1 12,500 91.200
Takatz Bay Unit No. 2
Total Resources 25,100 84,000 26,000 ,000 38,500 175,200 H
~
t-<
(Deficit) 3,208 2,000 a 36,395 trl Surplus or <:
H
Note: 1. Exports can be increased on "as available" basis by secondary energy
from all hydroelectric projects. 0\
2.Resource values are considered as dependable capacity and firm energy at load center.
LOAD
Meyers Court
Sollars Court
Arrowhead Court
Sitka Seafoods
Public Safety Acadewy
Sirstad Addition
Berglund Subdivision
Wolf Subdivision
High School Addition
State Office Building
State Health Building
U. S. Coast Guard
U. S. Forest Service
Sheldon JacKson College
TOTALS
ANTICIPATED LOAD INCREASES
Demand in kW
1973-74
100
100
600
270
75
75
1,220
POWER YEAR
1974-75
100
150
225
475
TABLE VI -7
1975-76
t;95
U!5
150
50
1,500
2,340
POWER AVAILABLE TO ALP
WITH RESERVE SHARING
Sitka ALP Firm
Reserves Reserves (1) Peak Energy
kW kW kW 1000 kWh
1979-80 3750 0 4000 33,640
1980-81 3750 789 4000 30,610
1981-82 3750 1692 4000 25,260
1982-83 (4) 3750 2667 4000 32,560
1983-84 (5) 3750 0 4000 27,490
1984-85 3750 858 4000 22,010
1985-86 3750 2086 4000 16,090
1986-87 (6) 6250 0 8000 70,080
1987-88 6250 1346 8000 70,080
1988-89 6250 2894 8000 70,080
1989-90 (7) 6250 0 8000 70,080
(1) Curtailment of exports in lieu of reserve sharing.
(2) Based on average water year.
(3) Based on average energy.
(4) Anticipates increase of firm energy by improved reservoir operation.
(5) Blue Lake Unit 3 on-line.
(6) Takatz Unit lon-line.
(7) Takatz Unit 2 on-line.
EXPORTS TO ALP
Secondary Average Load
Energy (2) Energy Factor (3)
1000 kWh 1000 kWh %
1,400 35,040 100
4,430 35,040 100
9,780 35,040 100
2,480 35,040 100
7,550 35,040 100
12,000 34,010 97
12,000 28,090 80
0 70,080 100
0 70,080 100
0 70,080 100
0 70,080 100
SECTION VII
ESTIMATED CONSTRUCTION COST
1. GENERAL
The cost estimate for Green Lake Project was based on the preliminary
arrangement and dimensions. Quantities were established for or civil features
to which unit costs were applied, while for equipment and other features costs
per kilowatt were used from experience with similar installations and from pub-
lished information by the FPC and APA. These costs were based on contractor's
bid prices, adjusted to a January 1974 level. These costs therefore in general,
have built-in escalation which would permit completion of the work in a two-year
period, which would correspond to the project b on-line by January,
1976.
Costs for the Blue Lake exnansion were estimated based on an overall
cost per kH. The costs of the Takatz project is based generally on escalation of
that developed by APA, with certain adjustments, to arrive at an overall cost
per kH.
Diesel costs are based on a oer-kH basis for similar installations
in Southeast Alaska.
2. BASIS OF COSTS
a. Direct Construction Cost
This includes the total of all costs dire chargeable to
struction of the project and in essence represents a contractor's bid.
sales taxes are included in this item where appropriate.
the con-
State
Indirect costs are defined as those which are added to the Direct
Construction Cost to result in the Total Construction Cost. Indirect costs in-
clude an allowance for contingencies, engineering, and escalation where neces-
sary .
b. Contingencies
To allow for unforeseen difficulties during construction and to
reflect possible omissions of estimate items, an allowance of 15% for contin-
gencies has been applied to the Direct Construction Cost estimates for hydro-
electric installations. For diesel generation an allowance of 10% for contin-
gencies was provided.
c. Engineering and Client Administration
Engineering costs for the project were based on a comparison with
actual costs for similar work. This item includes investigations, feasibility
and design engineering, field inspection of construction and client administra-
tion.
d. Escalation
All preliminary cost estimates for hydro have been considered as
a January 1974 bid level which corresponds to completion of the construction
VII-2
by the end of 1975 (2 years construction period). Bid prices for construction
anticipated to end at a later time have been escalated from the January 1974
level to the appropriate time of bid for such work. Costs for diesel have
been established by escalating from an estimated cost based on in-service in
January 1974. A blanket escalation rate of 6% per year for both labor and
materials has been assumed for investment costs.
e. Total Construction Cost
This includes the total of all direct construction costs, contin-
gencies, engineering and escalation.
f. Capital Investment Cost
This includes the Total Construction Cost plus interest during
construction, and represents the total investment in the project.
g. Bond Issue
This includes the Capital Investment Cost plus costs relating to
selling the bond issue. The bond issue amount is considered equal to the capital
investment herein for hydroelectric projects, and is the basis for establishing
annual costs as discussed in Section VIII. Since the method of financing con-
struction is not yet determined, in this study bond costs are assumed as an
addition of 8% to the annual costs. For diesels the capitalized value of the
bond costs is estimated as 14% of the total construction cost.
3. CONSTRUCTION COST ESTIMATES
a. Green Lake Project
A cost estimate summary for the proposed development of the Green
Lake Project is shown in Table VII-l. The estimated Total Construction Cost
for the two unit installation, in-service in January 1976, is equivalent to
$1,208/kW delivered to the load center, including roads, substations, and trans-
mission. The estimated Total Construction Cost when escalated to an in-service
date in December 1978, is $21,576,900, which is equivalent to $1,438/kW deliv-
ered to the load center.
b. Blue Lake Expansion
The Direct Construction Cost for the Blue Lake Expansion is estimated
to be $500/kW for entering into service in January 1977, based on judgement
developed from experience with projects of similar size in the area. The cor-
responding Total Construction Cost is equivalent to $66l/kW for the third unit
being on-line in January 1977, and to $938/kW on-line in December 1983.
c. Takatz Project
Costs for the Takatz Project were estimated at $925/kW based on
Direct Construction Cost excluding transmission (not including sales tax), and
being in-service in January 1976. This is reasonably compatible with costs
derived by the APA, in their 1968 report "Takatz Creek Project, Alaska, January,
1968". The APA costs were adjusted for different project arrangement and sche-
VII-3
dule, and reescalated from the viewpoint of 1974 experience of cost increases.
The estimated Total Construction Cost for the two-unit project, in-service in
December 1978, is $37,153,000 which is equivalent to $1486/kW, excluding trans-
mission. A cost estimate summary for the proposed development is shown in Table
VII-2.
d. Diesels
The direct construction cost of installing new diesel units is esti-
mated to be $220 per kilowatt for the unit to be in-service in early 1974. This
cost, escalated at 6% per year, is used to determine the estimated construction
cost for installation of units in future years.
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
GREEN LAKE PROJECT
COST ESTIMATE SUMMARY
Mobilization
Access Road
Dam and Spillway
Channel Improvements
Diversion Tunnel
Penstock
Powerhouse
Mechanical Equipment
Electrical Equipment
Substations
Transmission Line
Sub-total
Sales Tax
DIRECT CONSTRUCTION COST
Contingencies
Sub-total
Engineering and Client
Administration
Escalation (1)
TOTAL CONSTRUCTION COST
Installation Cost per kW (2)
Bid-date
January, 1974
$ 600,000
1,400,000
5,280,000
150,000
450,000
980,000
800,000
1,310,000
1,000,000
500,000
960,000
$13,430,000
268,600
$13,698,600
2,054,800
$15,753,400
2,363,000
$18,116,400
$ 1.208
(1) Escalation at 6% per year
TABLE VII-l
Bid-date
(On-line Dec. 1978)
$ 3,460.500
$21,576,900
$ 1,438
(2) Based on Total Construction Cost, including transmission. and
capacity at load center.
TAKATZ PROJECT
COST ESTIMATE SUMMARY
On-line date
January 1976
Estimated Construction Cost-$/kW $ 925
ESTIMATED CONSTRUCTION COST $23,125,000
Sales Tax 462,500
DIRECT CONSTRUCTION COST $23,587,500
Contingencies 3,538,100
Sub-total $27,125,600
Engineering costs 4,068,800
Es ca1at ion (1)
TOTAL CONSTRUCTION COST $31,194,400
Installation Cost per kW (2) $ 1,248
(1) Escalation at 6% per year
(2) Based on Total Construction Cost, excluding transmission, and
capacity at load center.
TABLE VII-2
On-line da te
December 1978
$ 5.258.~QQ
$37,153,000
$ 1,486
SECTION VIII
COST OF POI.JER
1. GENERAL
The on practical alternatives available for future development
of the Sitka electric system are installation of additional diesel units or
development of new hydroelectric sites. Installation of gas turbines or steam
generating units is not appropriate for the loads which the system has at
present or in the foreseeable future. The alternative of diesel generation
was compared with the development of the Green Lake site and the hydroelectric
alternati ve is more favorab Ie. An additiona 1 comparison ~.;ras made between the
Green Lake Project and the Takatz Project, ,,,;rith the Green Lake Project again
b the more favorable alternative.
2 . Al'lNUAL COS TS
a. Diesels
New diesel units which would be required were considered as having
annual fixed costs established on a capitalized basis and are determined as a
percentage of the total bond issue. Fixed costs established in this manner
include debt service, 0 & M, administration, replacements, insurance and taxes
and represent a levelized annual cost throughout the life of the units.
An appropriate increase of the Total Construction Cost was deter-
mined to include interest during construction, the necessary reserves and other
costs to arrive at the estimated bond issue. This increase was determined to
be 14% of the Total Construction Cost. The annual fixed cost for new diesel
units was estimated to be 13% of the total bond issue, based on a 25-year unit
life, 6% interest rate, and one-year construction period. A summary of fixed
costs for installation of new diesel units is shown in Table VIII-I.
Variable annual costs are considered as those associated with the
generation of energy and which vary as energy production varies. The only
variable cost considered in this study is the cost of fuel oil. An estimate
of the anticipated costs of fuel oil during the period of time considered in
this study is shown in Table VIII-2. The fuel cost has been escalated at 10%
annually from the cost of $0.33 per gallon in January 1974.
The annual costs of installing diesel capacity, with the related
energy production equivalent to the Green Lake Project, are tabulated in Table
VIII-3. This table was based on the diesel capacity going on-line in January
1979, the same proposed schedule as for the Green Lake Project.
b. Green Lake Project
The estimated cost of development of the Green Lake Project re-
sulted in a $1,208/k~.J value for in-service in January 1976, which escalated is
a $1, 438/kW value for the proposed on-line date in December 1978. These are
total construction costs inclusive of roads, substation and transmission line
and are based on capacity delivered to the load center. A summary of con-
struction cost, capital investment cost and annual cost is shown in Table
VIII-4.
VIII-2
The Capital Investment Cost was developed by adding the interest
prior to and during construction to the Total Construction Cost. The Capital
Investment Cost for an on-line date of December 1978 is $23,262,000. The
total of all annual costs, fixed and variable, was found to be 7.8% of the
Capital Investment Cost, exclusive of bond costs, based on 6% interest bonds.
The annual costs include debt service, 0 & M, administration, replacements,
insurance and taxes. Annual costs for the proposed neH hydroelectric projects
are shown in Table VIII-5 for an on-line date of December 1978 and annual
costs in succeeding years for the Green Lake Project. are shown in Table VIII-6.
The total annual cost. of the proif'.c:" n service in December 1978,
is estimated to be $1,966,000 including bond C'.;sts which is equivalent to an
annual cost of $131. 06 per kH based on capad ;; '\/ered at load center.
c. Takatz Project
The case of development of the TakdL? eet is estimated at
$1,408/kl-l value for in-service in January 1971" vl!il:!l escalated is $1,677/kW
value for a proposed on-line date in December 19 , i'or comparison with the
Green Lake Project at the same time period. f'!H::SC Rre Total Construction Costs
inclusive of roads, substations and transmis:::-i 1, ines, and are based on capacity
delivered at the load center. A summary of cOlF;Lruction cost, capital investment
cost and annual cost is shown in Table VIII-·!;_
The Capital Investment Cost for an ')~!~line date of December 1978
is $45,480,000. Annual costs were based on the same relationships to the
Capital Investment Cost as discussed for the Green Lake Project.
The total annual cost of the project in-service in December 1978,
is estimated to be $3,831,200, which is equivalent to an annual cost of
$153.25 per kW.
3 • COMPARISON OF DIESELS fu~D GREEN LAKE PROJECT
A comparison was made b etHeen the t,vo generating a1 terna ti ves
on the basis of the same installed capacity for each and each generating
the same annual amount of firm energy. As shov,r;:l in Table VIII-3 the esti-
mated annual cost of the diesel alternative is $2" 37,800 in 1979 which,
due to escalating fuel oil costs, increases to )682,600 in 1990.
Although normal annual costs of a hydroelec.tric project have been
assumed as a levelized amount (equivalent to 8.42/' of Total Capital Invest-
ment) a small percentage of this is subject to escalation. For the purposes
of comparison an es calation of 6% per year was applied to 1.38% of the bond
issue to reflect increases in salaries during the of comparison. On
this basis, the annual cost of the Green Lake Project \,1as determined to be
$1,966,000 in 1979, which escalates to $2,259,700 bv 1990.
The comparison between the two alternatives is shown graphically in
Fig. 13. The Green Lake Project shows a significant saving over the diesel
alternative.
VIII-3
A comparison was also made of the annual costs associated with
Sitka continuing with diesel generation solely to meet its load requirements
(and not to develop diesel generation of size equal to Green Lake as shown
in Fig. 13) as compared to Green Lake, and the result is shown in Fig. 14.
As can be seen with continued diesel operation by late 1978 when Green Lake
is scheduled to go on-line, annual diesel operating costs would be $270,000
more than annual operating costs for Green Lake. By late 1982, only some
four years later the costs of diesel generation would be equal to the total
annual costs including debt service, of Green Lake. Whereas the annual cost
of the hydro will continue to increase only slightly following this, the die-
sel costs increase at an astronomical rate.
4. COMPARISON BETWEEN GREEN LAKE AND TAKATZ PROJECTS
The annual cost of the Green Lake Project as shown in Table VIII-6,
is based on an installation of 16,600 kW delivering 15,000 kW to the load center
and generating firm energy of 52,000,000 kWh annually (about 40% plant factor at
load center). Approximately 10,000,000 kWh of secondary energy are expected to
be available on an average basis.
As shown in Table VIII-4, the annual cost of the Takatz Project is
estimated to be $3,831,200 in December 1978. This cost, however, is based on an
installation of 27,700 kW delivering 25,000 kW (in two units) to the load center
which would generate firm energy of 91,200,000 kWh annually (about 42% plant fac-
tor at load center). For comparison with the Green Lake Project, it is assumed that
the Takatz Project will be developed with three units, and that two units of 7,500
kW each will be installed to be in-service in December 1978 with a third unit of
10,000 kW to be installed later. It is estimated that a 3-unit installation will
increase the Total Construction Cost of the project by 10% over the 2-unit instal-
lation, but will not affect the cost of transmission. It is also estimated the
first stage construction would cost about 80% of estimated Total Construction Cost
for the ultimate development of the 3-unit plant. The Total Construction Cost for
first stage develoment of two 7,500-kW units, on-line in December 1978, is esti-
mated to be $32,694,600, plus cost of transmission of $4,764,100, for a Total Con-
struction Cost of $37,458,700 for the complete first stage installation. This re-
sults in an estimated capital investment of $40,642,700 and an estimated annual
cost of $3,423,700. This installation would generate about 91,200,000 kWh of
firm energy annually. With this level of operation, no secondary energy is
expected to be available until installation of the third unit and consequent
reduction of the plant factor.
A ~omparison of the costs of generation for the Takatz and Green
Lake Projects is shown in Table VIII-7, and again in Fig. 13 with each project
having a capacity of 15,000 kW delivered to load center. This represents
staged development of the ultimate capacity of 25,000 kW at Takatz. The Green
Lake Project shows a definite economic advantage in cost of power and has
significantly less annual cost. Also it is not considered possible to place the
Takatz units on-line until December 1979, which would require large additional
amounts of diesel generation for the extra year and is a penalty to the Takatz
Project. The Green Lake Project is therefore considered to be the more favorable
alternative. A comparison of costs is shown in Table VIII-7
VIII-4
A comparison of costs between the Green Lake Project, and the Takatz
Project developed to its ultimate installation of 25,000 kW (delivered to load
center) is also shown in Table VIII-7. As shown the cost of average energy from
the Takatz Project is slightly higher than Green Lake when an allowance is made
for the value of the additional 10,000 kW of dependable capacity from the Takatz
units. Further, the Takatz Project would require a capital investment (and annual
cost) of about twice that required for the development of the Green Lake Project,
and it is doubtful that the additional 10,000 kW of dependable capacity could be
marketed at that time since only secondary energy would be associated with the
additional capacity. In addition, the longer construction time of the Takatz
Project requiring additional diesel generation, as mentioned above, makes the
Takatz development less attractive. The Green Lake Project is therefore con-
sidered to be the most attractive alternative to meet the needs of Sitka at
this time. The comparison also shows that ultimate development of the Takatz
Project with two 12,500 kW is more desirable than the staged development with
two 7,500 kW units initially and 10,000 kW later, considering an on-line date
when the additional capacity is needed by the system.
When Placed
In -Service (3)
Jan. 1974
Jan. 1975
Jan. 1976
Jan. 1977
Jan. 1978
Jan. 1979
Jan. 1980
Direct
Construction
Cost -$lkW (1)
$220.00
233.20
247.19
262.02
277.74
294.41
312.07
(1) Escalated at 6% per year.
Contingency
and
Engineering (2)
$36.52
38.71
41. 03
43.50
46.10
48.87
51. 80
(2) Contingency estimated at 10% .
and engineering estimated at 6% •
FIXED COST OF NEW
DIESEL INSTALLATIONS
Total
Cons truc tion
Cost -$!kW
$256.52
271. 91
288.22
305.52
323.84
343.28
363.87
IDC, Reserve
and Cost
of Bond(4)
$35.91
38.07
40.35
42.77
45.34
48.06
50.94
Bond
Issue
$/kW
$292.43
309.9B
328.57
348.29
369.18
391. 34
414.81
(3) Years shown are calendar years with the units shown coming on-line at the beginning
of that year. If a unit is completed, for example, late in 1978 to meet the
calendar year 1979 loads, (on-line in January 1979) debt service and other annual costs
will be payable for the entire year (1979).
(4) Estimated at 14% of Total Construction Cost.
(5) Estimated at 13% of Bond Issue.
Annual Fixed
Cost
$!kW (5)
$38.02
40.30
42.71
45.28
47.99
50.87
53.93
Jan.
Mid
Mid
Mid
.Mid
Mid
Mid
Mid
1974
1974
1975
1976
1977
1978
1979
1980
ESTIMATED COST OF FUEL
FOR DIESEL GENERATION
Cost per
Barrel Cost per
(42 gallon) Gallon
$13.86 $0.330
14.57 0.347
16.00 0.381
17.60 0.419
19.36 0.461
21.29 0.507
23.44 0.558
25.79 0.614
TABLE VIII -2
Cost of
Power
Mills/kWh
23.6
24.8
27.2
29.9
32.9
36.2
39.9
43.9
Assumptions: (1) Cost of fuel escalated at 10% per
year from base ptice in January 1974.
(2) Average heat rate of diesel units
assumed at 10,000 BTU/kWh.
(3) Heat content of diesel fuel assumed
at 140,000 BTU/Gallon.
(4) Cost of power in mid-year is assumed
for generation during that calendar year.
Fixed Costs
1979 $763,000
1980 763,000
1981 763,000
1982 763,000
1983 763,000
1984 763,000
1985 763,000
1986 763,000
1987 763,000
1988 763,000
1989 763,000
1990 763,000
(1)
ANNUAL COST OF POl-lER
DIESEL UNITS
Variable Costs (2)
$2,074,800
2,282,300
2,510,500
2,761,600
3,037,700
3,341,500
3,675,600
4,043,200
4,447,500
4,892,300
5,381,500
5,919,600
Total Annual Cost of Power
Cost of Mills/kHh
$2,837,800 54.6
3,045,300 58.6
3,273,500 63.0
3,524,600 67.8
3,800,700 73.1
4,104,500 78.9
4,438,600 85.4
4,&06,200 92.4
5,210,500 100.2
5,655,300 108.8
6,144,500 118.2
6,682,600 128.5
(1) -Based on installation of 15,000 kH in diesel capacity, on-line in Januarv 1979, at
unit costs shown in Table VIII-I.
(2) -Based on generation of 52,000,000 kHh of firm energy annually at fuel oil costs as
shown in Table VIIl-2~ and escalated at 10% per year subsequent to this period.
Total Construction Cost-Project
Total Construction Cost-Transmission
TOTAL CONSTRUCTION COST
Interest prior to and during
construction on all bond issues
CAPITAL INVEST~lliNT COST
Installation Cost per kW (2)
ANNUAL COST
ANNUAL COST OF CAPACITY-$ikW (5)
-Included in project costs.
ANNUAL COSTS
NEH HYDROELECTRI C PROJECTS
GREEN LAKE PROJECT
15,000 k1;.] (4)
On-Line Dates
January 1976 December 1978
S18,116,400 $21,576,900
(1)
h8,1l6,400
_11 685) 10Q.
$23,262, 000
$1,208 $1,438
$1,966,000 (3)
$131. 06
TAKATZ PROJECT
25,000 kW (4)
On-Line Dates
Januarv 197n December 1978
531,194,400 S37,153,OOO
4,00U,uUO 4,764,100
$35,194,400 $41,917,100
3 a 562,90g
$45,480,000
$1,408 $1,677
$3,831,200
$153.25
(2) -Based on Total Construction Cost, including transmission, and capacity at load center.
(3) -As detailed in Table VIII-5.
(4) -Delivered at load centers.
(5) -Including transmission and based on capacity delivered at load center.
DETAILS OF ANNUAL COSTS
NEW HYDROELECTRIC PROJECTS
ON-LINE DECE?-1BER 1978
GREEN LAKE
Percentage of Fixed
____ ~ __ ~ It em __ _ Costs
Capital Investment ( $2J, 261,600)
Debt Service (6% at 47 years) (1) 6.42 1,493,400
Operation and Maintenance 0.50
Additional Operat Expenses 0.28
Administrative and General O.LO
Insurance 0.10
Interim Replacements 0.30
Taxes Nil
Totals 7.80 1,493,400
Subtotal Annu&l Cost
Bond costs 145 600 (3)
TOTAL A~~Ul~ COST $ 1,966,000
(1) Based on 50 year bonds with interest prior to and during construction
(2) Based on first stage development with two 7,500 k'\.J units.
(3) Bond costs estimated at 8% of Subtotal Annual Cost.
Variable
Costs
$ 116, JOO
65,100
46,500
26,300
72,800
327,000
deferred;
TAKATZ ( 2)
Fixed Variable
Costs Costs
($40,642,700)
2,609,300
$ 203,200
113,800
81,300
40,600
121,900
---_ ..
$ 2,609,300 560,800
3,170,100
$ 253,600 (3)
$ 3,423,700
as s Ufae 47 year financing.
<:
H
H
H
I
l.I1
GREEN LAKE PROJECT
ANNUAL COST OF pm~ER
1979 -90
Variable Total Annual Cost Cost of
Year Costs 2 of Generation Mills
1979 $ 1,639,000 $ 327,000 $ 1,966,000 31. 7
1980 1,639,000 346,600 1,985,600 32.0
1981 1,639,000 367,400 2,006,400 32.4
1982 1,639,000 389,500 2,028,500 32.7
1983 1,639,000 412,t500 2,051,800 33.1
1984 1,639,000 437,600 2,076,600 33.5
1985 1,639,000 463,900 2,102,900 33.9
1986 1,639,000 491,700 2,130,700 34.4
1987 1,639,00 521,200 2,160,200 34.8
1988 1,639,000 552,500 2,191,jOO 35 . .)
1989 1,639,000 585,600 2,224,600 35.9
1990 1,639,000 620,700 2,259,700 36.4
(1) Debt service based on 6%, 47 year retirement.
(2) Based on cos t shmvn in Table VIII-5, including bond costs, escalated at 6% per year.
(3) Based on total Everage energy (firm plus secondary).
Power
<
H
H
H
I
V'
COMPARATIVE COSTS OF HYDROELECTRIC GENERATION
Capaci ty-kl-v
Firm Energy-kWh
Secondary Energy-k\{h
Total Energy
Annual Cost
(On-line Dec. 1978) (3)
Value of Incremental Capacity
Adjusted Annual Cost
of Firm
Cost of Average Energy-
Mills/ktm
Green Lake Project
15~OOO
52,OOO~OOO
10,000,000
62,000,000
$1,966,000
( 4) 0
$1,966,000
31. 7
Takatz Project
15~OOO
91,200,000
0
91,200,000
$3~423,700
0
$3~423,700
37.5
(1)
(1) -First s development with two units delivering 15,000 kW at load center.
25~000
91~200~000
9~400~000
100,600,00(1
3,831,200
-508,700
3~322,500
33.0
(2) -Ba~ed on ultimate development of site with twounits delivering 25~000 kW at load center.
(3) -It is not considered possible to place either Takatz Project on-line until December, 1979.
Costs are shown for economic comparison only.
(4) -Based on equivalent cost of diesel capacity ($50.87 for on-line January 1979).
SECTION IX
PROPOSED PROGRAM OF DEVELOPMENT
1. IMPROVEMENTS CURRENTLY REQUIRED
a. General
An investigation was made of system improvements which should be
performed at an early date, but was restricted to generating resources, and
was not intended as a review of the distribution system. The improvements
discussed herein are therefore related to power delivered to the load center,
system dependability and reservoir water storage. Most items are scheduled
for this year (1974) and the more important ones are shown in Fig. 15, the
Design and Construction Schedule.
b. Tie Line to ALP
The existing tie has the capacity to conduct 5,000 kVA between the
ALP distribution and the Blue Lake Project, except for a short section of the
line which reduces the capability of the tie significantly. Breakers are in
place at each end of the tie sufficient for the 5,000 kVA load. Since it is
anticipated that excess capacity of this magnitude will be available from the
City's system in the future for export to ALP, it is proposed that the tie line
be improved to its full capability.
c. System Power Factor
I t is proposed that the system power fac tor be improved by install-
ing a 1,000 kVAR capacitor bank in the Marine Street Substation. It is antic-
ipated that with the existing magnitude and types of loads in the system the
capacitor bank will increase the system power factor to approximately 96%. This
improvement will allow the transmission line to conduct approximately 11,000
kW, rather than the 9,000 kW present limitation, without overloading and the
existing transfonners at Blue Lake Substation and Marine Street Substation
would operate at 7,200 kW rather than at the current 6,000 kW rated capacity.
d. Blue Lake Substation
The transformers are sufficient for the existing two units at the
project, but have a smaller capability than the transmission line and ultimate
installation of the project. It is proposed that when system loads develop to
approximately 10,000 kW, three 4,000 kVA, single-phase, transfonners be installed
and connected to Units 1 and 2, and to the 5,000 kVA tie-line from ALP.
e. Marine Street Substation
This installation is sufficient at the present time, but should
be upgraded to conform with the improvements at the Blue Lake Substation at
the s arne time.
f. Fish Release Valves and Monitoring
The valves recently acquired should be installed on the fish
release outlet as soon as possible. A stream flow monitoring program, in
cooperation with the state and Federal game and fish agencies' personnel, should
be developed.
IX-2
g. Reservoir Level Gage
To provide accurate information as to reservoir levels, a recording,
nitrogen-bubbler type level gage should be installed at Blue Lake. The infor-
mation from the gage should be provided at a read-out point at the control cen-
ter. This information is essential to successful reservoir management follow-
ing the rule curve.
h. Pressure Gages in Powerhouse
To provide information for hydrological and power studies, pressure
gages which provide more accurate readings should be installed upstream of the
scroll-cases of each unit. The existing gages are divided in intervals of 20-
feet which allows significant errors between successive readings of different
conditions. The existing gages should be replaced by gages divided in inter-
vals of 5-feet, and having an accuracy of plus or minus 0.5%.
i. Oil Storage Facilities
During the next five years, an increasing amount of diesel genera-
tion will be required to meet system loads. Normal oil storage facilities should
be provided to allow for the delivery date schedule and the possibility of de-
lays in delivery or missed shipments. In addition, it is proposed that a reserve
storage tank containing 125,000 gallons of fuel oil should be provided for emergency
conditions. It is estimated that this amount of oil would provide approximately
1,750,000 kWh of energy (about one month generation with existing installations).
j. Central Control Station
As diesel generation increases, it will probably be economical to
establish a central control station and operate the Blue Lake Project by remote
control from that point. Operation of the Green Lake Project is also proposed
to be from a central control station. It is anticipated that this method of
operation will reduce the annual costs of all installations.
2. FUTURE GENERATION PROGRAM
a. General
The program of development described in this section is proposed
to be accomplished during the period 1974 to 1990 inclusive. It is anticipated
that during this period the peak load of the system will increase from 7,114 kW
to 22,566 kW and the energy requirements will increase from 34,275,300 kWh to
108,723,000 kWh. Including adequate forced outage reserves the required capac-
ity will increase from 10,614 kW in 1974-75, to 38,500 kW in 1989-90.
The proposed program of development will provide Sitka with 32,500
kW of capacity and approximately 144,100,000 kWh of firm energy from new or
improved hydro-electric resources through 1990, will allow retirement of all
diesel generating units by 1984, provide more economical and reliable genera-
tion, and relieve the system from the uncertainty of fuel oil supply. The
program will conserve a national resource and eliminate the undesirable en-
vironment effects of diesel generation. It is anticipated that, with the
IX-3
Takatz Project going on-line, the first link in a mini-grid could be established
by the connection of Sitka and Baranof Warm Springs with transmission lines.
The proposed program of development of future generation through
1990 follows the schedule in Fig. 15. It consists of the Green Lake Project,
followed by expansion of Blue Lake, and the first unit of Takatz.
b. Green Lake Project
Investigations should be undertaken commencing this summer of the
Green Lake site. It is proposed that it will be developed to its ultimate
installation of two 8,300-kW units as the first phase of new development. The
units are scheduled to be placed in service to meet the peak loads in power
year 1978-79 (~ovember-December 1978). It is estimated that, including
generator, transformer and transmission losses, each unit will deliver 7,500
kW to the load center at peak load conditions, at best-gate operation of the
turbines, under winter reservoir levels.
c. Blue Lake Unit 3
\fuile completion of the Green Lake Project will provide sufficient
firm energy to meet the requirements of the system for approximately ten years
at the forecasted growth rate, additional capacity to meet peaks with ade-
quate reserve allowances, will be required for the 1983-84 winter loads. It
is proposed to add a new unit, with an output of 4,000 kW, at the existing
Blue Lake Project in late 1983.
d. Takatz Project
The capital investment required for development of the site is
high per capita for a city the size of Sitka, primarily due to costs of road
and transmission, and it should therefore be deferred in the generating pro-
gram until the load grows sufficiently to support the investment requirements.
This project is therefore scheduled to have the first unit of 12,500 kW in
service late in 1986. If large new industrial loads develop in the area as a
result of the availability of power and a market is available for the power,
the project could be required at an earlier date. Periodic reevaluations of
the system load growth should be made to determine when the project will actually
be required.
S~CTION X
DESIGN AND CONSTRUCTION SCHEDULE
A schedule for investigations, design and construction for system
generation through 1990 is shown in Fig. 15. This schedule is for the pro-
posed program of development, which includes initial development of the Green
Lake Project with the units coming on-line late in 1978. This is considered
to be the earliest possible schedule for the program considering the time re-
quired for investigations, FPC licensing, design and construction. The sched-
ule shows the need to begin investigations of the Green Lake Project in the
summer of 1974. Subsequent to completion of the Green Lake Project, the Blue
Lake Expansion would follow entering into service in 1983, and the Takatz Bay
Project in 1986.
Critical dates on the schedule are summarized as follows:
a. Investigate Green Lake site during June -December 1974. Evaluation
Report completed by January 1975.
b. Obtain funds for existing system improvements and preparation of
Evaluation Report of Green Lake Project in June 1974 ($250,000).
c. Obtain funds for final feasibility investigations and prepare FPC
License Application for Green Lake Project in January 1975 ($300,000).
d. Apply for FPC license for Green Lake Project in August 1975.
e. Obtain funds for first stage design, construction of access road,
and initial payment on major equipment items of Green Lake Project
in January 1976 ($2,000,000).
f. Establish final feasibility of Green Lake Project by March 1976.
g. Begin final design of Green Lake Project in March 1976.
h. Begin construction of access road for Green Lake Project in June 1976.
i. Order major equipment items for Green Lake Project in August 1976.
j. Receive license from FPC for Green Lake Project in November 1976.
k. Sell bonds for financing Green Lake Project in January 1977 ($20,862,000).
1. Begin construction of major works of Green Lake Project in April 1977.
m. Green Lake Project in-service by end of 1978.
n. Complete feasibility report of Blue Lake Expansion by July 1980.
o. Sell bonds for financing Blue Lake Expansion by July 1981.
p. Complete feasibility of Takatz Bay Project by August 1982.
X-2
q. Blue Lake Unit 3 in-service in late 1983.
r. Takatz Bay Unit 1 in-service in late 1986.
SECTION XI
CONCLUSIONS AND RECor~NDATIONS
1. CONCLUSIONS
The following conclusions are made as a result of this study.
a. The generation program for the Sitka Electric Utility System should
be directed to development of additional hydroelectric installations, with essen-
tially no diesel generation after 1979 and full retirement of the diesel plant
within the next decade.
b. Expansion of the Blue Lake Project by installation of a third gene-
rating unit is technically feasible but will not increase the availability of
firm energy from the project. It will increase capacity and allow generation of
additional amounts of secondary energy and should be brought into service in
late 1983.
c. Although the system has a potentially dangerous deficiency in capa-
city, the more critical condition is lack of sufficient energy to supply the
future needs of the City without reliance on the availability of large amounts
of diesel fuel oil at high costs.
d. Preliminary studies show that the Green Lake Project will meet the
City's power requirements at less cost than any alternative. It should be
brought into service as soon as possible; however, the earliest possible on-line
date is late 1978.
e. Initial investigations of the Green Lake site must be undertaken
this year if the schedule for the proposed program of development is to be
maintained.
f. Prior to the Green Lake Project going into operation, over the next
4 to 5 years, it will be necessary to substantially increase operation of the
existing diesel plant to meet the City's load. Additional oil storage facili-
ties and other improvements to the system are an immediate requirement.
g. To finance construction of the proposed program will necessitate the
City incurring a large financial obligation and will require careful planning.
The plans should include alternative bond arrangements and the possibility of
shaping the debt service. The possibilities of obtaining financial assistance
from state and Federal sources should also be investigated.
2. RECOMMENDATIONS
The following recommendations are submitted:
a. Field investigations and office studies of the Green Lake Project
should be performed, commencing in June 1974, so that a project evaluation re-
port can be prepared by January 1975 to firmly establish the project viability
prior to proceeding with more detailed and costly investigations. Investigations
XI-2
should continue in 1975 to establish final feasibility including preparation of
an application for an FPC License in August, 1975.
b. Construction of an access road to the Green Lake site should begin
in the spring of 1976, to allow the construction of the major project works to
proceed on schedule.
c. Arrangements for financing the proposed program should be initiated
immediately so that funds will be available when required. Funds are estimated
to be required on the following schedule:
$250,000 in June 1974 -System improvements and evaluation report
of Green Lake Project.
$300,000 in January 1975 -Final Feasibility investigation and
preparation of FPC License application for Green Lake Project.
$2,000,000 in January 1976 -First stage design, construction of
access roads and initial payment on major equipment itemS.
$20, 862,000 in January 1977 -Bonds for financing construction of
Green Lake Project.
d. The possibilities for financing future generation should be pursued
with state and Federal agencies, and with the State legislature in combination
with other cities in Southeast Alaska to attempt to develop a region-wide basis
for hydroelectric project financing.
e. In the interest of avoiding delays in the schedule of the proposed
program, information meetings should be scheduled with appropriate local, state
and Federal agencies and on the public level, and continued as required.
f. A periodic review and re-evaluation of the system loads should be
made, and the program of generation development adjusted accordingly.
g. Improvements to the existing facilities of the City to be initiated
immediately should include the following:
(1) Oil storage tanks and a reserve storage of fuel oil of 125,000
gallons should be provided at the diesel plant. This amount should be in addition
to storage for normal operation during the next five years.
(2) The tie line between ALP and the Blue Lake Project should be
improved to conduct 5,000 kVA in either direction.
(3) The transformers at Blue Lake Project and Marine Street Sub-
station are inadequate for the combined capacity of the present Blue Lake units
and tie-line from ALP, and should be replaced with larger units. The replacement
will not be required, however, until about 1979 or until system loads have devel-
oped to the level of the combined capacity.
(4) A capacitor bank of 1,000 kVAR should be installed in the Marine
Street substation.
XI-3
(5) Installation of new valves on the fish release pipe should pro-
ceed as soon as possible and a program for monitoring release discharges in co-
operation with personnel from the Alaska Department of Fish and Game and the U.S.
Fisheries and Wildlife Service, should be initiated.
._-----------------
..---COLD
STORAGE
LAKE TAKATZ
BAY
PROPOSED
TAKATZ r----,""
PROJECT
TRANSMISSION
LINE
PROPOSED GREEN
LAKE PROJECT
~VODAPAD
RIVER
... "r-LAKE 1
~
DIANA
-... .... -""'\
5 o 5miles .. ~~--~~--.. ~======~ Scale
RW.BECK and ASSOCIATES
Analytical and Consultino EnQlneers
Seattle ,Washinoton Denver,Colorado
CITY AND BOROUGH OF SITKA
ALASKA
ELECTRIC UTILITY SYSTEM
LOCATION MAP
area
Releases to
mill
I
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)
Drainage area = 37 square miles
Topooraphy from U.S.G.S quadrangle
Sitka, (A-4) Alaska
Scale I: 63360
fOOO
1°L.P..u?u.;'"LJ.,' k'c" ~~-;-:-_I-,OpO'
Scale
ntour Interval 200 Feet
R.W.BECK and ASSOCIATES
ANALYTICAL ANO CONSULTING ENGINEERS
Seattle, Waoh ington Ou.er,Colorado
DATE:
CITY AND BOROUGH OF SITKA
ALASKA
ELECTRIC UTILITY SYSTE M
BLUE LAKE PROJECT
EXISTING ARRANGEMENT
FIG:
APR. 1974 2
....
LLJ
LLJ
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0
I-
<t >
LLJ
...J
w
AREA -ACRES
1500 1400 1300 1200 1100' /000 900 800 700 600 500 400 300
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~ ,NORMAL MAXIMUM RESERVOIR EI.342 ~
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~ MINIMUM RlsERVOIR EI
1
230 ~
260
/V ~ 220
180
/ ~
/ \
140-r------~--------r_------~------_+------~--------+_------~------_+--------~------~------~------~
o 20 40 60 80 100 120 140
CAPACITY -1000 ACRE -FEET
NOTES: I. Power storage determined by rule curve operation
of reservoir in minimum water year.
2. Rule curve operation is proposed only during
interim period until unit '3 is in -service.
160 180 200 220 240
RW. BECK and A sse elATES
Analytical and Consulting Engineers
Sea tt Ie, Washi n9 ton Denver,Colorado
CITY AND BOROUGH OF SITKA
ALASKA
ELECTRIC UTILITY SYSTEM
BLUE LAKE RESERVOIR
AREA -CAPACITY CURVE
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_t_------+ ------+------~-_t_____~----------_+___---_t_---_+------___I------,--------t-------------t-----------------1-------'1-2 4 0
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November December January February March Apri I May June J ul y August lSeptember October
.....
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a::
R..W.BECKandASSOCIATES
Analylical and Consuiling Engineers
Sea tile ,Was hing Ion Den'er,Colorado
CITY AND BOROUGH OF SITKA
ALASKA
ELECTRIC UTI LITY SYSTEM
BLUE LAKE PROJECT
RESERVOIR RULE CURVE
Transmission Line
69 KV
MON LAKE:
!
~
\
f
!
f
~
I
!
f
(
f
(
Drainage area = 28.9 square miles
~
"\ Topography from U.S.G.S. quadrangle
\ Port Alexander CD 4). Alaska
"'-Scale I' 63,360 ,'"
" ~
/
o 1000
I
interval 100 feet
R.W.BECK and ASSOCIATES
ANALYlICAL ANO CONSULTING ENGINEERS
S eo t fie 1 Wo s h i n 9 tOn De nveT f Colora do
AND BOROUGH OF
ALASKA
ELECTRIC UTILITY SYSTEM
GREEN LAKE PROJECT
PROPOSED ARRANGEMENT
5
TUNNEL
INTAKE GATE fIt t" ....... '. " .... =Xv ','i' ••••• , •..•.•......•...• ~~ ............................. '.'
SCALE
R.W.BECKandASSOCIATES
Analytical and Consulting Engineer,
Seattle,Wa,hington Oenver,Colorado
CITY 4NO BOROUGH OF SITKA
ALASKA
ELECTRIC UTILITY SYSTEM
GREEN LAKE PROJECT
PROPOSED DAM ARRANGEMENT
6
,.-------------------------------------------------------------.--..•. ----------------~.-
I-
W
UJ
LL.
Z
0 -I-« >
UJ
...J
LLl
1600
500
400
AREA -ACRES
1400 1200 1000 800 600 400
\"'~! i //
~'2 g V
'( ~V NORMAL MAXIMUM RESERVOIR EI. 420
~V
v ..... ,
I-, UJ t:i
LLl ......... (!) LLl
LLl « LL.
LL. ~ I /iAREA I 0 LLl
W I-~
200 o
300
~ Wu .,
~i V~CAPACITY ~ ~ ---=~t-.-'-,-,-......... -....... -+-,-------1------+------1
w ~ MINIMUM RESERVOIR EI. 300
" ~ '----
20') L-_____ ~ ____ ~ _____ ~ ____ ~ ____ ~ _____ ~ ____ ~ ____ _J
o 50 100 150 200 250 300 350 400
CAPACITY -1000 ACRE -FEET
L..-_______________ .... _ ... ___ .. ______ _ ---.--.. -...
R.W.BECKandASSOCI ATES
Analytical and Consulting Engineers
Se a It I e, Was hi ng ton Denver,Colorado
CITY AND BOROUGH OF SITKA
ALASKA
E LECTR IC UTILITY SYSTEM
GREEN LAKE RESERVOIR
AREA -CAPACITY CURVES
AApRJ974 I ° EtSB IA;;Jp:lf". 7
I
/
/
f
!
I
i
\
\
~
\
\
~
i
" '\. ,
i
f
I
J
I
/'
Drainage area = 10.6 square miles
rj
1 f
/ f / I
/
Line /'
/
/'
1
f
I
Tunnel
f-Limit of drainage
\
\
/
/'
\ 0
~
\
.--.--'-:~ ~
,/7 -\ /
"--.-/
o
Topography from U.S.G.S. quadrangle
Sitka (A-3), Alaska
Scale I: 63,360
area
1000 0 1000
I'llrlll!!' I
Scale
Contour interval 100 feet
R.W.BECK and ASSOCIATES
ANALYTICAL AND CONSULTING ENGINEERS
Seot t Ie jWash inoton Denver, Co lora do
CITY AND BOROUGH OF SITKA
ALASKA
ELECTRIC UTILITY SYSTEM
TAKATZ PROJECT
PROPOSED ARRANGEMENT
-----------------------------------------------------------------------------------------------------------------------
AREA -ACRES
1000 900 800 700 600 500 400 300 200
1100 ~ V V
'\ /NORMAL MAXIMUM RESERVOIR EI. 1040 ./
\ , /
1000
I-w
W
LL.
I
z 900 0
I-« > w
.....I
W
-
j
"'" v ~ w en w w
'" LL.
I-a: w w (J
w « a: -w V (J
(!) LL. I-0 « « I w ¢ I 0 a: w ,....
0 W LL. 0
I-a: I 0
(/) (J
'"
~ « w to
w a:; ¢
> 0_ (J -
----~--« V ~ -
I-0
(J ¢ 0
r.( -0 (\J ~ ~NIMUM ro RESE~VOIR EI. 90~~ ro
to
1
~ ~CAPACITY / -
800
/ j L AREA --\
/ \
/ ~
700
o 20 40 60 80 100 120 140 160 180
CAPACITY -1000 ACRE -FEET
---------------------------~---
o
200
RW.BECKandASSOC I ATES
Anolytical aod Coosuiling lngineers
Sea tt Ie, Wo s hi ogton Denver,Colo rado
CITY AND BOROUGH OF SITKA
ALASKA
EL ECTRIC UTILITY SYSTEM
TAKATZ RESERVOIR
AREA -CAPACITY CURVES
DATE lORAWN !APPROV
4
E_D",' F;;,
APR 19741 BBB ~2 I 9
~
~
1
>-....
o «
Q. « o
~ «
laJ
Q.
36,000
32,000
40,000
'+t+f-H+. 3 2 ,000
TAKATZ
UNIT I 28,000 r-------~-.----~~"-------r_------r_------r_------r_----~r_----~----................. -1------~------~~
-1 12,500 KW
24,000
20,000
16,000
12,000
8,000
4,000
o
LOAD Q R ESERVES ~ ~~?:
------t----/------if---"---t--'\ BLUE LAKE UNIT 3 -4000 :W
-:-------, i --~ ..
----
----
24,000
20,000
16,000
12,000
8,000
4,000
~
~
I
>-....
o «
Q. « o
~ «
LLJ
Q.
--f-~~=-=--.~~:-~ ~1_9_7_4_-_7_5~1_9_7_5_-_7_6~' __ Q7 __ C_7_7~19_7_7_-_7_8~1_9_7_8_-_79_L1_9_7_9_-_8_0~1_9_8_0_-_8_1~1_9_8_1-_8_2~····~19_8_2_-_8_3_L1_9_8_3_-_8_4~1_9_8_4_-_8 __ 5~-86 1986-87 1987-88 1988-89 1989-90 o
POWER YEARS
NOTE: I. Resource capacity Is dependable ,delivered at load center.
2. Power years extend from July I,through June 30.
R.W. BECK and AS SO elATES
Analytical and ConsultlnQ Engineers
Sea ttlt, WoshinQton De nver,Colo rodo
CITY AND BOROUGH OF SITKA
ALASKA
ELECTRIC UTILITY SYSTEM
LOAD GROWTH CURVE
PEAK LOAD
FIG: 10
140
120
100 ---+-------
TAKATZ
UNIT I
140
120
100
1974-75 1975-76 1976-77 1977-78 1978-79 1979-801980-81 1981-82 1982-83 1983-841984-85 1985-861986-87 1987-881988-89 1989-90
POWER YEARS
NOTE: I. Resource capacity is dependable, delivered at load center.
2. Power years exten d from July I, through June 30.
RW.BECKandASSOCIATES
ARalytlcal and ConsultlnQ EnQlneers
Sea ttle,WashinQ ton Denver,Colorado
CITY AND BOROUGH OF SITK A
ALASKA
ELECTRIC UTILITY SYSTEM
LOAD GROWTH CURVE
ENERGY LOAD
II
14000
12000
10000
en t-t-8000 OIl
~
0
...J
:ac: 6000
4000
2000
SYSTEM IN 1974-75 SYSTEM IN 1976-77
------~----~----~----~----~----~-----r----~--~14000 14oo~----~----~----~----~-----'-----'-----'-----'----~14000
~----~-----+-----+----~----~~----~----+-----4---~~20oo 12000+-----4-----~----~-----+----~----~~-----~----~---+12000
+-----~----~-----+-----4----~------~----+_----+_--_r10000 10000+-----4-----4
en
t-
t-
~----~----~----~----~----~----+IOOOO
4-----~----_+----_+----~----~~----~----+_----4_--_+8000; 8000~----4-----~----~-----+----~································~~----~----i----8000
o
~~~~~~~~=-~--~4~-~----+-----+-----+-----~----r---~~--~----+6000 ~ 6000~~~~~~F;;;~h::::Jt:==~----~----_r----_r--__r6000
1~~~·~~·~~i~~~~~.~~-~-~-~~~-~-~-~~~~~~~~;;:::1~----1_----_1----~ 4000 ·-i-----.-1-. .-,:...--:-: .. :-:.... ~
_____ c~ ~_-_ ____ .-:1-:-.... ._~-, .... -:. __ . __ ,~-___ -,-...,,~
::.:=::.:::':::.:=::.:== __ = ==_=_-_====---. Hydro.leetrle(Blu. Lak,) == I_-----·?-':'""'-..c-_'--?-c:...l~
---------:.---1-------. -- - --_-1.-.---' 1---::.--:--~::.:-::.:-~ ~
1-_____ . .:1._ ......... --·Di .... Unit '5 r ::::-t-=-::-I-··-.:=---....:-.c--------------_-_-_-~ 2000
::':::.:=::.:=::.:=::.:=::.:===::.:-:=---:::=---:..: I=Z~··:'" ------L=-...:'Oi, •• fUnit T::.:---==-:::F:=====::':=::':::.:=::.:= ~==::.:=::.:::.:
-- - --- - - - --- -:1., -- ----... .::": :..:...:~~t:=--;~_~_-_::::-: 1_-_-_-_-:== f-= ---:.~ ----
o I I 0 O~~~~~~~~~~~~~~~~~O
1400 0
120 00-
t! 10000 t-oe
II
g 80 00
:ac:
60 00
40 00
20 00
0
o 1000 2000 3000 4000 5000 6000 7000 8000 8760
HOURS
SYSTEM IN 1978-79
14000
12000
10000
l
==~ 8000
----------'" ~
-..:.. ............ :c-.:-c-c -f-~ -----
:::--I-=---::.:-= ----------
H yd ro .Ie etrie (Shl' Lak'L __ == ~ -_. -
~ =-=-=----1----.:-_------
-----1-Di I U 't 2 "".:i=------------r _____ -_-~ ----.... ····c .. t.r-::J ft, nl Dill.i-un't 3 -----;:::------------.-::.: ---~ =~.....---~ :::-;~:::~;::;~ = :::~-& . . -~----;:;;.-0.11.1 Unit I -:-_ :....--~
............ I-. ... .-c'::::' ':..: -
... D i •• ,I Unit 4 I-:-_ ,.... ,..=-:..-.-
..-' -,::::-!--. .-' I-::.. [---=--I-:..::..
I
1000
4000
2000
o o 1000 2000 3000 4000 5000 6000 7000 8000 8760
HOURS
o 1000 2000 3000 4000 5000 6000 7000 8000 8760
HOURS
R.W.BECKandASSOC I ATES
Aft.lytlc.1 aM Coullltl", EnQln .. n
s •• ttl •• W.ahift,tOll Denver,Colorado
CITY AND IOROUIH Of SITKA
ALASKA
ELECTRIC UTILITY SYSTEM
LOAD DURATION CURVES
7
POWER PRODUCTION
DELIVERED TO LOAD CENTER
AL TERNATIVE CAPACITY FIRM SECONDARY
6 ENERGY ENERGY
(KW) (IOOOKWh) (lOOOKWh)
DIESEL 15,000 52,000 0
GREEN LAKE 15,000 52,000 10,000
5
TAKATZ 15,000 91,200 0
(J)
a::
<l
-l
~ On -line dote
-l
0 4 a
z
0
~~
.....
-l
..J
:E
I 3
~ ~
""...
I-
(J)
0
0
..J
<l
::::> 2 z
Z
<l
o
1979 1980 1981 1982
~ ~ DIESEL ALTERNATIVEl>
~ ~ TAKATZ PROJECT
~ /
~ ( First Stoge Development)
I
/GREEN LAKE PROJECT
/
1983 1984 1985 1986 1987 1988
CALENDER YEAR
~
1989
~
1990
RW.BECKandASSOC 1 ATES
Analytical and Consulting Engineers
Seattle,Wa&hlngton De nver,Col 0 rado
CITY AND BOROUGH OF SITKA
ALASKA
ELECTRIC UTILITY SYSTEM
COMPARATIVE COST OF POWER
13
4,000,000
3,500,000 II V II
/ I
3,000,000 / Vt/ DIESEL"
2,500,000 " / /
en VS 1
[/ a:: « In 1982, diesel fuel cost alone ..,J ...
....J is equal to debt service
0 for Green Lake Projecf / / ~ Cl q~ 2.,000,000
V//
~' z
0 \ -....J
....J / ~i{ -~
1,500,000 I,
Debt service plus .6. /'
I-Debt Service '" fixed operatingv--::
//, ~ IA-GREEN LAKE PROJECT
/ 1:000,000 ./ //
~, v/ / ~ I--Diesel Fuel v/
~------.."./ ~---500,000 ~ ----~-----f-
..,......"""'" --~----~ ----~---
.-"".-""
...-~ Operating Costs
-f-----• 0 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990
CALENDER YEAR
R.W.BECKandASSOCIATES
Analytical and Consulting Engineers
Sea It Ie, Washino ton Denver,Colorodo
CITY AND BOROUGH OF SITKA
ALASKA
ELECTRIC UTILITY SYSTEM
COST OF CONTINUED
DIESEL GENERATION VS.
GREEN LAKE PROJECT
~-
A~~.19?4IDEA~t7JJP;IF1G 14
SYSTEM IMPROVEMENTS
ANAL. OF ELEC. SYSTEM
FISH RELEASE VALVES AND MONITORING
OIL STORAGE TANKS AND SUPPLIES
NEW TRANSfORMER -BLUE LAKE
CAPACITORS
GREEN LAKE PROJECT
EVALUATION REPORT
FEASIBILITY REPORT
FPC LICENSING
FINAL DESIGN
ACCESS ROAD
MAJOR EQUIPMENT
CONSTRUCTION
TRANSMISSION
BLUE LAKE EXPANSION
FEASIBILITY REPORT
AMEND FPC LICENSE
CONTRACT DOCUMENTS
MAJOR EQUIPMENT
CONSTRUCTION
TAKATZ PROJECT
EVALUATION REPORT
FEASIBILITY REPORT EVALUATION REPORT GREEN
l-AKE, SYSTEM IMPROVEMENTS
FPC LICENSING . I I I I I : I I I I I I
FINAL DESIGN FINAL FEASIBILITY,FPC
LICENSING GREEN LAKE
ACCESS ROAD I I I I I I I I
J----M-A-JO-R-E-Q-U-I-P-M-E-N-T-------+-+-+1 -+-+-+-+ t-+-+++-+ FIRST STAGE DESIGN , LUlJlJLLll_U--l-U-ll-ll--LU-UjjJjlLUU~~t!tt~~~u~U,rN.I~T~I~ll_U___U__L_U_U_WlLUUJ_l~ ACCESS ROAD, ORDER MAJOR
CONSTRUCTION EQUIPMENT,GREEN LAKE
TRANSMISSION ++++++++ SELL BONDS SELL BONDS
--------,----t--1r--t-r-t--t-1"--r-lH -+-+--1f-+-+-+++ BLUE LA K E E XPANSI ON T A KATZ UN IT I t-++-+-+--1f-+-t-+-+++-+-+-t-+-+++-+--+-II-t-t-++-t-t-lf-+-+-++++-t-+-l
FINANCIAL ARRANGEMENTS
1978 1979 1980
LEGEND
FEASIBILITY STUDIES
FINAL DESIGN
CONSTRUCTION
1981 1982 1983 1984 1985 1986 1987 1988 1989 1990
R.W. BECKandASSO elATES
Analytical and Consulting Engineers
Sea tt le,Washington De nver,Colo rado
CITY AND BOROUGH OF SITKA
ALASKA
ELECTRIC UTILITY SYSTEM
DESIGN AND CONSTRUCTION
SCHEDULE