HomeMy WebLinkAboutReso. 1986 - 278 - Adopting the 1986 power resource plan of the city of redding electric utility .
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RESOLUTION NO. 46.-027,
A RESOLUTION OF THE CITY COUNCIL OF THE CITY OF REDDING
ADOPTING THE 1986 POWER RESOURCE PLAN OF THE CITY OF REDDING
ELECTRIC UTILITY.
WHEREAS, the City Council of the City of Redding has
considered the 1986 Power Resource Plan of the City of Redding
Utility, a true copy of which is attached hereto and incorporated
herein by reference; and
WHEREAS it is in the best interests of the City of Redding
to adopt said Plan as the 1986 Power Resource Plan of the City of
Redding;
NOW, THEREFORE, BE IT RESOLVED that the City Council of the
City of Redding hereby adopts the attached Plan as the 1986 Power
Resource Plan of the City of Redding Electric Utility.
I HEREBY CERTIFY that the foregoing Resolution was
introduced and read at a regular meeting of the City Council of
the City of Redding on the 6th day of October , 1986 , and
was duly adopted at said meeting by the following vote:
AYES: COUNCIL MEMBERS: Carter, Dahl , Gard, Johannessen, & Fulton
NOES: COUNCIL MEMBERS: None
ABSENT: COUNCIL MEMBERS: None
ABSTAIN: COUNCIL MEMBERS: None
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LEE D. FULTON, M.D. , Mayor
City of Redding
AT ,EST• -� Zidi � / FORM PPROVED:
ET EL A. NICHOLS, Cit/ Clerk RA` DALL A. HAYS,�Cit�y Attorney
by Connie Strohmayer, `Deputy
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CITY OF REDDING
Electric Utility
1986 POWER RESOURCE PLAN
July, 1986
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TABLE OF CONTENTS
SECTION PAGE
I. EXECUTIVE SUMMARY 1
A. Introduction and Purpose -----1—
B.
B. Resource Plan Development 2
C. Recommendations 3
II . PLANNING GOALS 5
III. CHANGES IN CONDITIONS AND EVENTS SINCE THE
1984 RESOURCE PLAN 7
A. Availability and Cost of Future Power
Projects 7
B. Revised Forecasting Information and Data" 8
C. New Arrangements for Power Purchases and
Sales 9
D. Deferred or Abandoned Projects II 9
IV. FORECAST OF ELECTRIC POWER NEEDS 11
A. Forecasting Methodology II 11
B. Energy Conservation and Load Management II 20
C. Other Power Needs II 25
D. Adopted Forecast II 26
V. RESOURCE OPTIONS CONSIDERED 34
A. Purchase Options 34
B. Development Options I 37
C. Transmission Options 41
VI . OTHER CONSIDERATIONS 42
A. Economics 42
B. Residual Capacity Charges 43
C. Diversity 44
D. Autonomy 44
VII. RECOMMENDED POWER .RESOURCE DEVELOPMENT PLAN 46
A. Avoid High-cost Supplemental Power
Purchases 46
B. Pursue Conservation and Load Management
Programs 46
C. Pursue Near-term Wholesale Purchases 47
D. Pursue Economic Hydroelectric Projects U 47
E. Pursue Development of Spring Creek Pumped
Storage Project 47
F. Pursue Development of the Carnage
Cogeneration Project 48
G. Pursue Transmission Rights Q 48
H. Enhance Relationships with Western II 48
I. Selectively Participate in Baseload. Projects. 49
VIII. DEFINITIONS b 52
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TABLE OF CONTENTS
(Cont. )
TABLES PAGE
1 - Parameter Projections 1986-2005 16
2 - Coincident Peak Demand for Electricity by
Customer Class 17
3 - Electrical Energy Use by Customer Class 18
4 - Historic and Projected Parameter Growth Rates19
5 - Estimated Effects of Conservation & Load
Management Programs 24
6 - Total City Peak Demand Needs 28
7 - Total City Electrical Energy Needs 29
8 - Projected City of Redding Monthly Energy
Requirements 30
9 - Projected City of Redding Monthly Peak
Demands 31
10 - Recommended Plan 50
FIGURES
1 - Growth of Redding by Annexation i14
2 - Coincident Peak Demand 32
3 - Electrical Energy Need 33
APPENDICES
A Recommended Resource and Transmission Projects
for the City of Redding
B Acronym List
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CITY OF REDDING
Electric Utility
1986 POWER RESOURCE PLAN
I. EXECUTIVE SUMMARY
A. Introduction and Purpose
The City of Redding (City) historically has relied upon
wholesale purchases from other utilities Ito meet its
power requirements. During the late 196Ns and early
1970 ' s, however, it became evident that continued
reliance upon other utilities could not enure a long-
term, reliable source of power at a rearonable� cost
under conditions which would afford the City an oppor-
tunity for any control. Therefore, in 1976, the City
began to develop a broad-based program which would
include suitable City-owned generating resources as well
as power purchases to meet the future powerlrequirements
of its customers in a reliable and cost-effective
manner.
During 1981 , the program was consolidated into the first
City of Redding Electric Utility Resource Plan. The
Plan was adopted early in 1982 by the City Council and
is updated and resubmitted to the Council for approval
biannually.
The 1986 Power Resource Plan (1986 Plan) updates the
Load Forecast, Preliminary Assessment of Resources and
Resource Plan prepared in 1984 (1984 Plan) .
The changes in conditions and events, which properly
reflect the City' s most recent projection of power
needs, and the City' s current power r_esourrce plan to
meet those needs are included in this update of the 1984
Plan.
The 1986 Plan includes assumptions and data which are
current as of April, 1986 . The 1986 Plan should not be
interpreted to represent a commitment by the City to a
specific course of action. Rather, the purpose of the
1986 Plan is to serve as an aid to thel process of
decisionmaking for individual projects. Decisions will
be influenced by future conditions which may not neces-
sarily match the assumptions used to prepare this 1986
Plan.
In_ evaluating the potential for developing new generat-
ing resources, the Electric Department staff compares
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the economics of such resources to the City' s incremen-
tal cost of acquiring additional power. Currently, the
incremental cost of power is governed by power supplied
by the Pacific Gas and Electric Company (PGandE) through
a supplemental power purchase contract.
Before committing to a specific projeFt, detailed
analyses will be conducted to consider the benefits,
costs, risks, need, timing, acceptability,pand environ-
mental and financial impacts using the most recent data
available. These analyses are repeated, as�;lappropriate,
with the most up-to-date information available at each
critical decision point in the project development
process so that mid-course corrections can be made,
including termination of a project. The City Council of
Redding and the City' s voters (who own Ilthe electric
system) through referendum ultimately decide upon the
projects selected for implementation.
B. Resource Plan Development
The 1986 Plan (Section IV) provides a probable twenty-
year assessment of the City' s future need for power to
meet projected customer growth. The power lneed assess-
ment was conducted as suggested by the California Energy
Commission (CEC) in its forecasting Guidelines known as
the Common Forecasting Methodology (CFM) . II Through use
of the CEC guidelines , the assessment considered several
parameters which influence the future need for power.
Section V and VI discuss the merits of several resource
development options which could be used to meet the
power requirements forecasted by the power peed assess-
ment. Section VII discusses the Electric Department ' s
current recommended plan to meet the forecasted need.
The planning goals utilized as the primary Ilriteria for
the 1986 Plan are:
1 . Present and future City power costs are to be held
as low as practicable.
2 . The reliability and service levels for the City' s
electric system are to be maintained or improved
where possible.
3 . Local control and independence are to beiretained.
4 . The development of economical, local power resources
is preferred.
5 . Power resources will be developed in an environ-
mentally responsible manner.
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6 . An active load management program, as well as an
aggressive conservation effort, will be an integral
part of the City' s power resource development
program.
7. A diversified power supply is preferred to help
prevent rate shock and unexpected power shortages.
8 . A resource plan which continues to promote a healthy
local economy is preferred.
C. Recommendations
The City has an aggressive and foresighted power re-
source development program which emphasizesIthe develop-
ment of local projects. If the City is s11uccessful in
the development of these projects , and also obtains
power from the Pacific Northwest, in addition to an
aggressive load management program, it will be able to
avoid higher-cost supplemental power purchases. The
long-term savings to the City' s ratepayers under this
approach could be substantial. Specific recommendations
are as follows: I
1 . In order to maximize the benefits of future genera-
tion resources , the City should develop agreements
with the Western Area Power Administration (Western)
which will allow the City to schedule We! tern power.
Such agreements would maximize City project benefits
by:
(a) Reducing the amount of excess energy available
during off-peak time periods.
(b) Reducing the amount of supplemental purchases
required to meet the City' s peak load require-
ments .
2 . The City should develop firm transmission rights to
the Pacific Northwest and implement appropriate
agreements to acquire peaking capacity (preferably
under a capacity/energy exchange type of arrange-
ment) from Pacific Northwest entities.
3 . The City should develop an inter-utility agreement
which provides support for City-owned 11 generation
resources and provides supplemental power require-
ments needed to meet City loads in excess of the
power received from Western and City resources .
4 . The City should proceed with the rapid development
of the proposed Spring Creek Pumped Storage Project
which could be instrumental in providing inter-
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utility agreements which would provide reliable
electric service at minimum cost.
5. The City should continue with the implementation of
the active load management program. A commercial
program has been in operation since 1985 and the
peak load reduction obtained is significant. More
publicity concerning the conservation program, which
reduces our peak demand, should be undertaken to
obtain more widespread participation in the program.
6 . The City should continue to work closely with
Western to ensure that it obtains an equitable share
of the United States Central Valley Prioject (CVP)
peaking capacity (if, and when, allocated) and to
protect its existing 116 MW CVP allocation.
7. The City should continue to participal�e in power
pooling planning activities. Continued partici-
pation will insure that the City will have the
opportunity to participate on an equitable basis
within the power pool if and when it becomes opera-
tional.
Table 10 in the 1986. Plan, contains the projected energy and
capacity requirements and resources for the City, on an.
annual basis, through fiscal year 2005.
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II . PLANNING GOALS
The established planning goals were utilized extensively in
the development of this 1986 Plan for the City.
A. Present and future power costs for the City' s customers
are to be held as low as practicable. The long-term
cost of electricity to the City' s customers is a primary
consideration in the analysis of alternative power
resources and. programs. The ultimate test of any
resource plan is the ability to provide economic power
resources to the City' s customers.
B. Reliability and service levels are to be maintained and
improved upon whenever possible . Dependable and safe
electrical service must continue to be provided to the
City' s customers.
C. Local control and independence are to be retained.
Local control ensures that the City' s power (system will
be responsive to the needs of its customers. Inde-
pendence will allow the City more freedom in buying and
selling power from various power projects and various
utilities. This freedom will allow the City the flexi-
bility of acquiring the least costly power.
D. Development of economic, local power resources is
preferred. Whenever the costs are reasonably competi-
tive, the development of power projects which benefit
the local economy will be preferred over equivalent, but
geographically distant projects . Power from distant
projects, when wheeled by other utilitiesu, normally
cannot be used as efficiently as local resources which
can be individually and locally controlled.
E. Power resources will be developed in an environmentally
responsible manner. New City power projects will
provide for protection of the environment in compliance
with applicable laws and regulations . When economically
feasible, new City power projects will be developed to
benefit the local environment.
F. A diversified power supply is preferred. Projects will
be preferred when they allow the City to economically
diversify its power supplies by using different loca-
tions, fuels, or technologies . Diversity can reduce
future risks to the City from interruption of power
production from one location, fuel, or technology.
Diversity can lessen rate shock which can result from
dependence on a single source of power, as evidenced. by
the 1973 oil shortage, or the recent Western° rate
increase of totaling 300% .
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G. Promote and develop load management and conservation
programs . Load management will provide pa means of
reducing critical peak load growth and beitter utilize
the City' s power resources. The Electric Department
staff has projected that by 2005 , the Citylcould manage
46 . 6 MW of peak load. Conservation programs inform
customers of ways to efficiently utilize electricity and
thus reduce the demand on the electrical system.
H. Promote healthy local economy. Reasonably priced,
reliable electrical power is attractive to business.
Jobs created by the availability of reasonably priced,
reliable electrical power will benefit the local econ-
omy.
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III. CHANGES IN CONDITIONS AND EVENTS SINCE THE 1984 PLAN
Conditions and events have changed since the 1984 Plan was
developed. Some of these changes have had e negligible
effect while others have had a significant effect on
formulation of the 1986 Plan. Areas where significant
changes have occurred are discussed in this section of the
1986 Plan.
Since 1984 , there have been changes in the cost of future
power projects . Revised forecasting information based upon
more current data is now available, and new contractual
arrangements for power purchases and sales have been devel-
oped. The most significant changes from the 1984 Plan are:
A. Availability and Cost of Future Power Projects
1 . Large hydroelectric projects have continued to
increase in cost and have become increasingly
difficult to site, finance, and develop.
2. Small hydroelectric projects remain potentially
attractive, risks are generally manageable, and
costs depend upon the merits of each individual
project. However, environmental clearance is
difficult to obtain.
3 . Geothermal projects have developmental risks which
continue to increase because the known productive
drilling areas are becoming fully developed.
4. Small wind projects have become more viable due to
advances in technology. However, dependable winds
of useable velocities do not occur in the Redding
area, and development costs remain very high.
5. Cogeneration projects have become more attractive to
the City since the ability of cogenerators to sell
power above the wholesale market rate oto investor-
owned utilities (IOU' s) has been reduced. The
reduction occurred when PGandE estahlis1'ed a waiting
list for transmission capacity and when PGandE' s
"avoided cost" dramatically declined primarily due
to the low fuel cost of the Diablo Nuclear Power
Project. Because of the change in market conditions
for cogeneration projects , the 1986 Plari places much
more emphasis on cogeneration than did the 1984
Plan.
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6. Nuclear projects continue to receive more critical
review and costs continue to escalate. As a result
of the June, 1982 referendum prohibiting City
involvement in the Palo Verde Nuclear Project, the
City has not considered involvement in other nuclear
projects.
7 . Coal projects remain potentially attractive when
purchase of an existing plant is possible. However,
access to transmission lines to wheel power from
distant plants can be costly. New coalkprojects are
substantially more expensive and subject to siting
difficulties, financing difficulties, and increasing
regulatory constraints.
B. Revised Forecasting Information and Data
1 . Changes in the City' s rate structure have been made
since the 1984 Plan to encourage the reduction of
peak power demands, the use of off-peak energy, and
to encourage interruptible loads .
2 . More recent data (1983 - 1985) have been included in
the 1986 Plan to update the historic load growth
trends for the City.
3 . In 1985 , the City participated for the first time in
the California Energy Commission Biennial Electri-
city Report (ER Proceedings) . Part of the City' s
participation in the ER Proceedings included the
preparation of a 20-year forecast of the City ' s
future need for power. This forecast was prepared
in accordance with the forecasting guidelines
established by the CEC. As discussed in Section IV,
the forecast of the need for power, which was
submitted to the CEC on September 30, 1985 as part
of the ER Proceedings, uses a mathematical model of
several parameters to project future power needs .
4 . The forecast in the 1984 Plan projected average
annual growth rates for customer needs of 4 . 3% for
energy and 4 . 0% for demand. In the 1986 Plan, the
growth rates for customer needs have been increased
to 4 . 6% for energy and 4 . 3% for demand. The City ' s
load forecast has increased, primarily due to
changes in:
(a) Electrical load growth from additional annex-
ations;
(b) Projected electrical loads from future indus-
trial development; and
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(c) Increase in customer ability to pal rchase power
caused by recent improvements in economy.
C. New Arrangements for Power Purchases and Sales
1 . The City is a member of the Transmission Agency of
Northern California (TANC) which is actively partic-
ipating in efforts to develop the California-Oregon
Transmission Project (COTP) which will provide
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access to power produced in the Pacific Northwest
and Southwest.
D. Deferred or Abandoned Projects
The following projects were identified in the 1984 Plan
as desirable to develop to meet the City' s needs .
However, for reasons described below these projects are
no longer considered viable projects.
1 . North Fork Project - On January 29 , 1986 , the
Federal Energy Regulatory Commission (FERC) denied
the City' s application for license on the basis that
the United States Bureau of Reclamation ' s (USBR)
proposed Auburn Dam would better utilize the water
resources. The City' s legal counsel has indicated
that a successful appeal of FERC ' s denial is unlike-
ly since it currently appears more likely that the
USBR will construct Auburn Dam than it did in 1984
when the City applied for a license.
2. ACID Projects - Feasibility studies performed in
late 1984 concluded that these project located on
the Anderson-Cottonwood Irrigation District (ACID)
Canal are not economically feasible if the Lake
Redding Project is constructed. Since the Lake
Redding Project is a much larger and more feasible
project, a decision by Council to ( discontinue
development of the ACID Projects was made. However,
should development of the Lake Redding�l Project be
discontinued, the ACID Projects would be reconsid-
ered.
3 . Cottonwood Project - In late 1985, the Army Corps of
Engineers announced that it would ( discontinue
development of the proposed Cottonwood. Dams . Since
the Cottonwood Project would have utilized these
dams and since it is not economically feasible for
the City to construct the dams, the Cityldevelopment
of the Cottonwood Project has been discontinued.
The California Department of Water Resources has
proposed an alternative project which ilncludes the
construction of four dams , even though the City was
successful in obtaining a preliminary permit from
the FERC for one of the dams . The project is not
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considered in the 1986 Plan since construction of
the four dams is highly speculative at this time.
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IV. FORECAST OF ELECTRIC POWER NEEDS
The forecast of future electrical power needs of the City is
a cornerstone of the 1986 Plan. The forecast defines the
needfor additional City power resources, the potential for
conservation savings, and, to some degree, the level of
future City prices for electricity. This section describes
the City' s forecast of peak demand in megawatts (MW) and the
total City energy requirements in gigawatthourp (GWH) for
the planning period of City fiscal years 1986 - 2005 .
A. Forecasting Methodology
1 . Energy - Historic energy consumption by customer
class was compiled on a monthly basis for the period
of January, 1976 , through June, 1985 . ilResidential
and commercial class customers have historically
been responsible for about 90% of Redd�ing' s total
energy sales. Recognizing the significance of these
customers to total system load the parameters which
affect load growth for each of these two classes
were evaluated. A computer model, using) several of
the parameters, was then developed to forecast
energy usage for the residential and commercial
classes.
Energy projections for other customer classes
including industrial, agricultural, and govern-
mental, were forecasted basedon the historic load
growth of each class as compared to the presidential
class.
The parameters were tested to determine their effect
on the City' s historical load growth between the
period of January, 1976 and January, 1985. Test
computer models were used to determine the relation-
ship, if any, of the tested parameters to the amount
of energy sold. The following parameters were found
to have a significant statistical effect on the
amount of energy sold. All of these parameters were
therefore used for purposes of producinglla computer
model to project energy consumption through 2005 .
(a) Number of Electric Customers
As expected, this parameter significantly
determines the amount of energy needed by the
City.
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(b) Disposable Personal Income
Historic personal income was determined to have
an effect on electricity consumption. An in-
crease in income contributes to a slight
increase in electricity consumption. Shasta
County income per capita was used to establish
the historic relationships. Futu+ growth is
estimated to be significantly improved from
that represented in the historic period due to
projected continued evolution offl the local
economy toward the manufacturing and services
sectors. Income appears to be a�n important
factor in discretionary electricity consump-
tion.
(c) Heating and Cooling Degree Days
These parameters were used to account for
electric usage associated with space heating
and cooling. Heating and cooling �cdegree days
are a measure of space heating or cooling
requirements. The greater the value of heating
and cooling degree days, the greater will be
the electric requirements for space Cheating and
cooling.
(d) The Price of. Electricity
The historic real average price of electricity
to Redding electric customers was approximated
using total class revenues divided by total
class kilowatt-hour sales and adjusted by the
Consumer Price Index to constant 1983 dollars.
Customer decisions to use electricity is partly
determined on the basis of the average price of
the electricity. The average future electric-
ity price was determined by then price of
electricity developed in the recommended
resource plan discussed in Section VII.
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(e) Annexations
Annexations by the City of Redding have played
an important role in load growth olf the Redding
system over the historic period (see Figure 1) .
Some areas have been annexed, butllhave not yet
received electric service from Redding. The
areas within the Redding city limps which have
not yet received electric service represent
future increases in load which have been
explicitly considered in developing the load
forecast by adjusting the forecast number of
customers within the commercial and residential
classes by the estimated number Vof customers
associated with each annexation. The effect of
minor future annexations was included in the
projection of number of customers . Major
future annexations were not included in the
forecast of future need.
The other parameters tested did not have anv apparent
effect on energy usage. The other parameters tested
were; price of natural gas, level of employment, and
daylight hours. The effect of new applianelles replacing
less efficient appliances was also considered, however,
insufficient data exists to adequately test this con-
cept.
Table 1 presents projections during the period 1986 -
2005 of the parameters used to forecast future elec-
trical power needs. Although heating/cooling degree
days were essential for explaining the historical test
period, the projection of degree days was held constant
at a value equal to the historical average daily temper-
ature in Redding.
2 . Demand - System peak demand was determined by using the
forecasts made for energy usage and the average system
load factor (see Section VIII - Definitions) for the
period 1976 - 1984 . As the City' s system Il expands and
diversity increases , and with future effects of load
management and energy conservation programs, it was
estimated that slight improvements in average load
factors will result. Although annual load factors will
certainly fluctuate with yearly weather conditions, the
Redding system annual load factor was projected to
steadily improve from 48% in 1985 to 50% by the year
2005 .
3. Other Forecast Considerations - Since preparation of the
City' s electrical load forecast for the ER PI�roceedings,
the City has actively negotiated with Sierra-Pacific9
regarding the Carnage Project. The expected power need
of the lumber mill associated with the Camage Project is
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CITY OF REDDING
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• 198 POWER RESOURCE PLAN
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ANNEXATIONS
-,... !`
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.;.%.7.. ..
•.L. ,
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PRIOR TO 1949 F7771 v*
1 1 ,
1950 —
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'‘.
1960 — 1969 -,--7:.•,,,
1970 — t979
1 .
--14-
ww. .
1980 TO PRESENT FIGURE 1
i
•
18 GWH per year and a non-interruptibile capacity
requirement of 2 MW. Therefore, beginning in 1988,
18 GWH of energy and 2 MW of capacity were added each
year of the forecast used in the ER Proceedings to
obtain the forecast in the 1986 Plan.
4 . Forecast of Customer Needs - Table 2 lists the histor-
ical and projected electrical demand by customer class.
Table 3 lists the historical and projected electrical
energy use by customer class. The effects of energy
conservation and load management are included in Tables
2 and 3 .
5 . Plausibility - The plausibility of the forecast is
primarily dependent on the validity of projections of
the model parameters used. Historic growths rates over
the period 1976 - 1985 and projected gro4 rates for
each of these parameters are shown in Table 4 .
While there are significant differences in the growth
rates between the historic and the projections, such
differences can be explained as follows .
a) Price of electricity - The historic and ongoing
increases in the price of electricity are primarily
caused by the cost of power purchases from Western,
which increased by 300% during the 1983-86 time
period, and purchases of high-priced supplemental
power from PGandE, which began in 1984 . The rate of
growth for the real price of electricity is expected
to decrease since future dramatic rate increases
from Western are not expected and since lthe City is
actively pursuing more economical resources for
supplemental power than purchases from PGandE.
b) Personal income - The per capita personal income
projections differ significantly from the historic
series due to current trends in the Redding economy.
Historically, the economy has been predominantly
based on the lumber industry and the lower historic
growth is directly attributable to the repent severe
depression of the lumber industry. Recent trends in
local economic growth have shifted to thel service
607-220
-15-
• •
TABLE 1
CITY OF REDDING
1986 Power Resource Plan.
Parameter Projections 1986-2005
(1) Real Personal (2) Real Price (3)
Year Number of Customers Income Per Capita of Electricity
Residential Commercial
1
1986 25,412 10,416 4.22 4.91
1987 26,387 10,788 4.41 5.07
1988 27,402 11,172 4.60 5.22
1989 28,455 11,568 4.80 5.39
1990 29,549 11,976 5.01 5.56
1991 30,685 12,396 5.21 5.72
1992 31,867 12,828 5.43 1 5.89
1993 33,093 13,284 5.65 6.06
1994 34,367 13,752 5.88 6. 24
1995 35,691 14,232 6.12 6.42
1996 37,066 14,736 6.38 6.61
1997 38,494 15,264 6.59 6.76
1998 39,979 15,804 6.74 6.85
1999 41,520 16,356 6.83 6.88
2000 43, 121 16,932 6.84 6.84
2001 44,785 17,532 6.45 6.45
2002 46,514 18, 156 6.08 6.08
2003 48,310 18,792 5.74 5.74
2004 50,1.76 19,452 5.41 5.41
2005 52, 115 20,136 5. 11 5. 11
(1) The projected number of residential customers is based on
the Planning Department population growth forecast of 4%
per year. Commercial customer growth is estimated at 3%
per year.
(2) 1983 dollars.
(3) 1983 cents/kWh, projections recognize an intent to
gradually equalize the average costs of electricity forI
commercial and residential customers.
li
607-220
-16-
• TABLE 2 0
CITY OF REDDING
1986 Power Resource Plan
Fiscal Year
Coincident Peak Demand for Electricity by Customer Class
(in Megawatts)
YearTotal
Customer
Ending Residential Commercial Industrial Agricultural Governmental Demand
1976 20 26 1 0. 1 2 49
1977 22 29 1 0. 1 3 55
1978 25 31 1 0.1 3 60
1979 32 35 2 0. 1 3 72
1980 47 43 2 0.1 4 96
1981 53 42 3 0. 1 4 102
1982 56 45 3 0.1 4 108
1983 53 41 3 0. 1 3 100
1984 54 42 3 0.1 3 102
1985 57 46 3 0. 1 4 110
1986 61 50 3 0.1 4 118
1987 62 51 3 0. 1 I 4 120
1988 66 53 3 0.1 4 126
1989 67 55 5 0.1 4 132
1990 70 58 6 0.1 4 138
1991 72 60 6 0. 1 4 142
1992 74 63 6 0.2 4 148
1993 77 66 6 0.2 5 155
1994 80 69 6 0.2 5 160
1995 82 72 7 0.2 5 167
1996 85 76 7 0.2 5 173
1997 88 79 7 0.2 5 180
1998 91 82 7 0.2 5 186
1999 95 86 8 0.2 5 194
2000 99 90 8 0.2 5 202
2001 103 94 8 0.2 5 210
2002 108 98 9 0.2 5 221
2003 113 103 9 0.2 5 231
2004 118 108 9 0.2 6 241
2005 123 112 10 0.2 6 252
Average Projected Growth - 4.3%.
607-220
-17-
•
.
TABLE 3 •
. CITY OF REDDING
1986 Power Resource Plan
Fiscal Year
Electrical Energy Use by Customer Class
(in Gigawatthours)
Total
Year
Customer
Ending Residential Commercial Industrial Agricultural Governmental Use
1976 93 132 6 0.2 12 243
1977 102 140 7 0.2 13 262
1978 111 134 9 0.2 13 268
1979 145 145 12 0.3 13 315
1980 196 174 17 0.4 15 403
1981 211 185 19 0.4 16 432
1982 221 190 17 0.4 15 443
1983 218 187 19 0.4 13 438
1984 213 190 17 0.4 15 435
1985 236 210 19 0.5 17 482
1986 236 211 19 0.5 17 483
1987 255 227 21 0.5 17 521
1988 269 241 22 0.5 18 551
1989 283 258 23 0.5 18 583
1990 293 270 24 0.5 18 607
1991 304 283 25 0.5 19 632
1992 316 295 27 0.6 19 657
1993 329 308 28 0.6 19 685
1994 341 321 30 0.6 20 712
1995 354 335 32 0.6 20 742
1996 365 349 33 0.6 21 769
1997 380 364 35 0.7 21 801
1998 395 379 37 0.7 22 834
1999 412 398 39 0.7 22 870
2000 429 414 41 0.7 23 908
2001 448 434 43 0.8 24 950
2002 471 454 46 0.8 24 996
2003 493 474 49 0.8 25 1043
2004 516 497 52 0.9 26 1092
2005 541 518 55 0.9 27 1142
Average Projected Growth - 4.6%.
607-220 -18-
•
TABLE 4
CITY OF REDDING
1986 Power Resource Plan
Historic and Projected Parameter Growth Rates
Projected
Annual Average Annual Average
Compound Growth Compound Growth
PARAMETER Rate 1976 - 1985 Rate 11986 - 2005
Real Residential Price of 4 . 7% 1 . 1%
Electricity
Real Commercial Price of 6 . 6% 0 . 3%
Electricity
Real Personal Income -1. 3% 3. 6%
per Capita
Number of Customers 12. 9% 3 . 9%
607-220 -19-
•
and manufacturing sectors, providing a stable
base for future growth. Higher growth is expec-
ted to be supported by present and anticipated
stable energy prices and a more optimistic
outlook for the national economy over the fore-
cast period.
c) Number of customers - The number of City
Electric Utility customers grew at an annual
compound rate of 12 . 9% during the period of
1976 - 1985, while the population df Redding
grew at an annual compound ratelof 13. 6%
over the same period. These high growth
rates were largely due to the effect of the
several annexations during the peri1od 1976 -
1983 . Over the longer term of theNforecast
period (from 1986 - 2005) the effects of
annexation, natural increases and net
in-migration are projected to average out to
a 4% rate of population growth, with similar
moderation in the projected rates n(3 . 9%) of
growth in residential and commerdial cus-
tomers.
B. Energy Conservation and Load Management
Forecasts of the City' s future need for electricity
are dependent on effects of conservation and load
management programs . Several conservation and load
management programs are in various stages oflldevelop-
ment as described below. Table 6 lists each of the .
programs and staff estimates of the effects of
existing and future programs. In order tol include
the effects of conservation and load management
programs in the final forecast of power needs, the
energy and capacity expected to be saved by these
programs were added to the forecasted custmer-use
projections developed as described in A. above.
The conservation and load management programs con-
sidered were:
1 . Air Conditioning Load Management (ACLM)
The ACLM is designed to reduce demand for capa-
city during the summer peak periods. Thedprogram
consists of the installation of radio activated
control switches on customer air conditioning
units to allow the City to selectively cycle the
air conditioners from a central location.
In 1984 , load control switches were installed on
all eligible City air conditioning equipment. A
607-220 -20-
I
•
•
pilot ACLM program for commercial customers was
started in April, 1985 . It is estimated that
each commercial ACLM switch will control about
10 tons of air conditioning.
A total of 104 load control switches, controlling
808 tons of cooling were installed in 1984-85 .
The total load reduction, using a cycling
strategy of 10 minutes every half hour is
approximately 0 . 269 kW. Under emergency
conditions, the load reduction is estimated at
808 kWh.
A brochure soliciting participation in the
program was mailed to all commercial customers in
the February, 1986 utility billing. . It is
expected that a minimum of 150 additional.
switches will he installed in response to this
solicitation.
2 . Swimming Pool Load Management (SPLM)
The SPLM Program initiated in 1980, provides a
reduction of peak demand by shifting the opera-
tion of swimming pool filters, pumps, and sweeps
to off-peak hours. A request to operate pool
equipment before 2 :30 p.m. and after 6 : 30 p.m. is
periodically mailed to pool owners .
A telephone survey of pool owners indicates a
very high compliance with the request. The SPLM
load reduction is estimated to be 0 . 5 MW.
3 . Load Curtailment Program (LCLM).
The LCLM program consists of the voluntary
reduction of electrical usage by certain
large-use customers and by the general public.
Most City pumping loads are also shut down or
placed on stand-by generators . This pgpgram is
put into effect only at such times as the system
is approaching peak load conditions. Customers
are notified of the need to reduce their use of
electricity by telephone and by radio and tele-
vision announcements. In 1985 , this program
reduced peak demand by an estimated 3. 7 MW.
As a supplement to the LCLM program, an extensive
advertising campaign is conducted from May to
September to encourage the reduction of elec-
trical usage between 2 : 30 p.m. and 600 p.m.
Radio advertisements are broadcast daily on the
four leading radio stations and a newspaper
1
607-220 -21-
• • •
advertisement is published once a week in the
local newspaper.
4 . Appliance Efficiency and Building Standards
It is expected that several regulatory (standards
will continue to reduce the energy consumption of
water heating, air conditioning, refrigerators
and freezers , and other major appliances.
Regulatory standards will continue toll mandate
minimum performance criteria for new buildings
and appliances. Estimates developed by PGandE of
non-price-induced load reductions associated with
mandated efficiency standards were assumed to be
similar in proportion to the eff_ectFs these
standards would have on the City' s customers .
5 . Other Conservation Activities
Residential customers are provided Residential
Conservation Service (RCS) audits and general
conservation information and materials. To
further encourage the conservation of energy,
recording meters are loaned to customers to
monitor the electrical usage of various appli-
ances.
Small commercial customers are provided technical
assistance in evaluating a wide range of
conservation measures.
An estimated 220 MWH of energy reduction will
occur in 1986 due to customer response t10 these
audits and other activities.
6. Street Light Conversion Program
The City has an ongoing program of installing
energy efficient high-pressure sodium l street
lamps when existing, less efficient, mercury
vapor lamps need replacement. Itis estimated
that this program will save 1, 500 MWH in 1986.
7. Interruptible Load
In 1984 , the City established an interruptible
rate which provides eligible customeIs who
volunteer for the rate, a reduction in the cost
for power provided that the customers reduce or
eliminate consumption of power during peak usage
times when the City requests the_customerM to do
so. Although there were no customers receiving
electrical service under the Interruptiblie Rate
607-220 -22-
• •
as of February, 1986 , the Electric Department
estimates that up to 20 MW of interruptible load
will be available by 2005 .
Ili
607-220 -23-
. .
. III •
..
TABLE 5
City of Redding
1986 Power Resource Plan
Estimated Effects of Conservation & Load Management Programs
1986 1990 1997 2005
GWH MW GWH MW GWH MW GWH MW
PROGRAM
Air Conditioning N 0 . 5 N 4 . 0 N 4 . 9 N 6 .2
Load Management
Program (ACLM)
Swimming Pool N 0 .5 N 0 . 6 N . 8 N 1 . 1
Load Management
Program (SPLM)
Load Curtailment N 3 . 7 N 3. 9 N 4 . 4 N 05 . 1
Load Management
(LCLM) Program (1)
Efficiency 1 . 5 1 . 6 4 . 1 5 .4 10 . 6 9 . 6 16. 3 14 .2
Standards
Other Conserva- 0 . 2 N 0 . 3 N 0 .5 N 0 . 6 N
tion Activity
Street Lights 1 . 5 N 2. 1 N 2 . 8 N 3 . 8 N
Interruptible
Customers N2 .0 N 10 . 0 N 15 . 0 N 20 . 0
Total 3 . 2 8 .3 6 . 5 24 . 4 13 .9 34 . 7 210 . 7 46 . 6
u
N = negligible
(1) Includes STEP advertising campaign
607-220 -24-
•
• o
C. Other Power Needs
1
Other power needs include reserves and losses . These
needs were added to the forecast of customer use
developed in A. , above.
1. Reserve Requirements
Every electric utility strives to provide depend-
able electric service to its customers . A
utility' s failure to meet customer loads due to
insufficient capacity will result in a variety of
economic and technical problems . Therefore,
utilities must plan for and develop sufficient
reserves to meet customer load requirements .
Within the utility industry, there are several
important standards that generally (determine
reserve requirements. One such standard is to
maintain a Loss of Load Probability (LOLP) of not
more than one day in ten years. Such al standard
requires that generation and power purchases must
exceed customer loads at all times except for one
day in ten years . All uncertainties such as
weather, forced and planned outages, and other
factors such as routine maintenance must be
included. As a result of this LOLP process, a
fixed planning reserve percentage can be iden-
tified.
(a) Planning Reserves
Planning reserves, (in the utility industry,
are typically 15-20% of system peak demand)
are designed to account for demand forecast
errors, long-term weather extremes, delays
in the construction of new power plants, and
lengthy forced outages .
Planning reserves for the City are included
in power that would be provided under the
present supplemental power agreement with
PGandE. Likewise, the City' s CVP power has
planning reserves included, pursuant to the
Western/PGandE agreements. Planning re-
serves will, however, be needed (for the
City' s own power resources, exclusive of CVP
and PGandE purchases.
I
607-220 -25
• •
(b) Spinning Reserves
Spinning reserves, (in the utility industry,
are typically 9% of system peak demand) are
designed to account for sudden loss of
existing generation. If, under emergency
situations, existing generation is lost
spinning reserves are used to quickly
(within a few minutes) replace the sudden
loss in generation.
(c) Reserves Applied in this Plan
In planning for the City' s future power
requirements, a planning reserve margin
equal to 25% of the City' s peak summer load
(excluding the 116 MW CVP allilocation,
interruptible loads, and other utility
purchases) was utilized in the 1986 Plan to
determine the City' s total need for
reserves.
2 . Losses
Losses account for electricity which is used to
energize the transmission anddistribution
system, and for electricity that is used but not
metered (power theft) . The average 10-year
historical energy losses have averaged 7. 5% .
Losses of 6 . 5% were used in the 1986 Plan to
account for the City' s recent efficiency improve-
ments in the City' s distribution system.
D. Adopted Forecast
Tables 6 & 7 list the annual forecast of the City' s
need for demand and energy respectively, from 1986 -
2005 . Figures 2 and 3 illustrate the annualllforecast
of the City' s total need for demand and energy
respectively. The average annual growth in demand is
expected to be 6 . 1% . The average annual growth in
energy is expected to be 4 . 6% . These growth rates
are higher than the growth rates discussed in, Section
III . Section III discussed customer needs only.
This section includes losses and reserves in the
forecasted growth rates.
607-220
-26-
• •
1 . Load Profiles
Load profiles provide an indication of when power
will be used by the City' s customers. Power usage is
usually higher in the summer months and lower in the
spring and fall months. Monthly load projections of
total customer load plus losses for 1986 JI 87 for
energy and demand are shown on Tables 8 & 9 respec-
tively. These projections were based on computer
modeling of the City' s historic monthly power usage,
normalized to temperature.
607-220 -27-
, „
• TABLE 6111
. .
, ,
CITY OF REDDING
1986 Power Resource Plan
Fiscal Year
Total City Peak Demand Needs
Megawatts
Total
Year Customer Interruptible Total
Ending Demand Losses Load Reserves Demand
1976 49 4 (1) NA 53
1977 55 7 (1) NA 62
1978 60 7 (1) NA 67
1979 72 5 (1) NA 77
1980 96 7 (1) NA 103
1981 102 7 (1) NA 109
1982 108 8 (1) NA 116
1983 100 7 (1) NA 107
1984 102 7 (1) NA 109
1985 110 8 (1) NA 122
1986 118 8 (1) NA 126
1987 120 9 8 NA 137
1988 126 9 12 NA 147
1989 132 10 16 5 163
1990 138 10 20 5 174
1991 142 11 24 5 183
1992 148 11 26 14 199
1993 155 12 27 29 222
1994 160 12 28 30 230
1995 167 13 30 30 239
1996 173 13 31 36 253
1997 180 14 33 45 272
1998 186 14 34 46 280
1999 194 15 36 46 291
2000 202 15 38 46 301
2001 210 16 39 46 311
2002 221 17 42 46 325
2003 231 17 43 46 337
2004 241 18 44 46 349
2005 252 19 46 46 363
Average Projected Annual Growth - 6 . 1%
(1) Effects of load management included in actual sales.
607-220 -28-
- , 'H
III TABLE 7 •
•
CITY OF REDDING
1986 Power Resource Plan
Fiscal Year
Total City Electrical Energy Needs
Gigawatthours
Total Total
Year Customer Energy Energy
Ending Use Losses Conservation Required
1976 243 20 (1) 263
1977 262 10 (1) 272
1978 268 23 (1) 291
1979 315 24 (1) 339
1980 403 28 (1) 431
1981 432 30 (1) 462
1982 443 39 (1) 482
1983 438 29 (1) 467
1984 435 29 (1) 464
1985 482 29 (1) 511
1986 483 31 (1) 514
1987 521 34 4 559
1988 551 36 5 592
1989 583 38 6 627
1990 607 39 7 653
1991 632 41 8 681
1992 657 43 9 709
1993 685 45 10 739
1994 712 46 11 769
1995 742 48 12 802
1996 769 50 13 831
1997 801 52 14 868
1998 834 54 15 903
1999 870 57 16 942
2000 908 59 17 984
2001 950 62 18 1029
2002 996 65 18 1079
2003 1043 68 19 1131
2004 1092 71 19 1182
2005 1142 74 21 1237
Average Projected Growth - 4 . 7% per year l
I
(1) Effects of energy conservation included in actual
sales.
I
607-220
-2 -
I
• •
TABLE 8
CITY OF REDDING
1986 Power Resource Plan
PROJECTED CITY OF REDDING
MONTHLY ENERGY REQUIREMENTS (GWH) (1)
(Fiscal Years 1986 - 2001)
Fiscal Year:
MONTH 1986 1987 1988 1989 1990 1991 1992 1993
JUL 53.7* 51.9 53.8 57.7 60.0 62.7 65.5 68.2
AUG 46.2* 49.0 50.8 55.2 57.5 59.6 61.9 64.3
SEP 36. 1* 46.5 48.5 51.9 53.9 56.2 58.4 61.0
OCT 37.5* 39.7 41.4 44.0 46. 1 48.2 50.4 52.0
NOV 43.5* 46.3 48.6 52.1 54.3 56.7 58.6 61.3
DEC 48.2* 52.0 54.2 58.1 60.2 62.5 65.3 68.3
JAN 45. 1* 54.4 58.5 61 .1 63.8 66.5 68.8 71.2
FEB 39.3* 43.7 46.8 48.7 50.7 52.9 54.7 57.2
MAR 39. 1* 46.5 50.0 52.3 53.9 56.3 58.6 61.0
APR 36.5* 38.4 40.9 42.5 44.3 46.3 48.4 50.4
MAY 41. 1* 41.0 44.2 46.0 48.3 50.1 51.7 53.8
JUN 47.9* 45.7 49.6 51.4 53. 1 54.8 57.7 60.4
TOTAL(2) 514.2* 555. 1 587.3 621.0 646.1 672.8 700.0 729. 1
MONTH 1994 1995 1996 1997 1998 1999 2000 2001
JUL 70.7 73.3 76.2 79.9 83.1 86.6 90.7 94.6
AUG 66.9 70.1 73.0 75.4 78.2 81.6 85.9 89.8
SEP 63.7 _ 66.1 68.6 71.1 74.4 77.7 1 80.5 83.8
OCT 54.0 56.0 58.2 61.3 63.6 66.0 1 68.8 71.5
NOV 63.6 66.5 68.9 71.8 74.3 77.6 80.9 84.5
DEC 71.1 74.0 76.2 79.7 83.1 87.0 90.4 94.5
JAN 74.3 77.7 80.8 84.2 87.2 89.9 93.7 98.4
FEB 59.3 61.8 64.1 66.8 69.5 72.6 76.1 79.7
MAR 63.4 66.3 68.4 71. 1 74.4 77.7 80.8 84.8
APR 52.0 54.2 56.4 58.9 61.3 63.9 66.8 70. 1
MAY 56.2 58.7 61.0 63.2 65.6 69.8 72.6 76.5
JUN 62.8 65.2 67. 1 70. 1 73.5 75.9 79.3 83.0
TOTAL(2) 758.0 789.9 818.9 853.5 888.2 926.3 966.5 1,011.2
* Actual amounts
(1) Includes effects of energy conservation.
(2) Totals may not add due to rounding.
607-220 -30-
' • TABLE 9 •
_- CITY OF REDDING
1986 Power Resource Plan
PROJECTED CITY OF REDDING
MONTHLY PEAK DEMANDS (MW) (1)
(Fiscal Years 1986 - 2001)
MONTH 1986 1987 1988 1989 1990 1991 1992 1993
JUL 121* 129 135 142 148 153 159 167
AUG 108* 123 128 135 141 145 151 156
SEP 91* 121 127 133 139 144 149 154
OCT 90* 80 84 88 92 95 99 102
NOV 100* 99 104 109 114 118 122 126
DEC 105* 107 112 118 123 127 1 132 136
JAN 94* 109 115 120 124 129 134 133
FEB 91* 107 112 117 121 126 131 130
MAR 86* 100 105 110 113 118 123 121
AP 77* 88 92 96 99 103 108 107
MAY 113* 116 122 127 132 137 143 141 '
JUN 127* 117 124 129 = 133 138 144 143
TOTAL(2) 1,203 1,296 1,360 1,424 1,479 1,533 1,595 1,616
MONTH 1994 1995 1996 1997 1998 1999 2000 2001
JUL 172 179 186 193 200 208 217 226
AUG 163 170 177 183 190 . 198 206 213
SEP 162 168 175 181 188 196 204 211
OCT - 107 111 115 120 124 129 135 139
NOV 132 138 -= 143 149 154 160 167 172
DEC 143 149 154 160 166 173 180 186
JAN 145 151 156 162 168 176 1 = 183_ 181
FEB 141 147 152 158 164 171 179 177
MAR 132 138 143 148 154 161 167 166
APR 116 121 125 130 135 141 147 146
MAY 154 160 166 172 179 187 194 193
JUN 156 162 168 174 181 189 _ 197 195
TOTAL* 1,723 1,794 1,860 1,930 2,003 2,089 1 2,176 2,205
* Actual amounts.
(1) Includes effects of load management, however does not include reserve need.
(2) Totals may not add due to rounding.
607-220 -31-
II
CITY OF REDDING .
_ • .'....:
1986 POWER RESOURCE PLAN
COINCIDENT PEAIC . DEMAND
HISTORIC PROJECTED
35
0
TOT D D
AL EMAN
325 >`
?, II
TOT
A
L CUS
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OMER EMAND
300
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125 -
100 ii
COMMERCIAL II
75 lul
50 -
RESIDENTIAL
25
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76 80 85 90 95 2000 05
YEARS •ENDING JUNE 30th
CITY OP \
FIGURE 2 REDDING
ita ELECTRIC
_32- UTILITY
i
II
• CITY OF REDDING •
1986 POWER RESOURCE PLAN
ELECTRIC . ENERGY NEED
HISTORIC PROJECTED
1300 -..?..:::::::::..::::-...::::::?...::::.:E:„:.:::::::'"'"..--
s: .•....,..,,,,...-..,::.:-..,::::::::-..,...
1200
.... TOTAL AL EN
ER
GY REQUIREMENT
U
IREMEN
T
1100
ENERGY GY C N
1000 CONSERVATION
O
li
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9
00 n
TOTAL AL EN
ERGY
SALES
11
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LOSSES 0
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Q
Q
COMMERCIAL
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400 t.: ..:..;;:.; ,.
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II
200
RESIDENTIAL'
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AL
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0 -I6 80 85 90 95 2000 05
YEARS ENDING JUNE 30th•
CI?l OP
REDDING
FIGURE _ 3 /,'', Ai/7'r ELECTRIC—33— -
r/ur1
s.' , ,• 410
V. RESOURCE OPTIONS CONSIDERED
In developing the 1986 Plan, a number of options were
considered to meet the City' s future power requiirements.
Overall, all of these options can be considered within
three major categories : purchase options, generation
project development options, and transmission options .
The following discussion analyzes the most promising
within each of these categories, as they pertain to the
City.
A. Purchase Options
When the City' s power demands exceed its 116 MW CVP
allocation, the City may meet all or parr of its
additional power requirements through supplemental
purchases of power. Supplemental purchases from
other utilities will be required if the City' s power
resources do not meet the City' s supplemental power
requirements.
1 . Supplemental Purchases from PGandE
Currently the City may, pursuant to an existing
agreement between the City and PGandE, purchase
from PGandE all of the City' s supplemental
power requirements above the City' s C9 alloca-
tion, up to 44 MW. However, the City/PGandE
agreement may be cancelled upon one year' s
advance notice by either party. The City peak
supplemental power requirements is expected to
exceed the 44 MW provided by the PGandE
contract by 1992.
Disadvantages of continued long-term supple-
mental power purchases from PGandE include the
following:
(a) Expenditures made by the City ford supple-
mental power do not develop "equity" in
any particular project or resource.
(b) Costs of supplemental power from PGandE
are increasing substantially with the
inclusion of the Helms Creek and the
Diablo Canyon Projects into PGandE ' s rate
base. In November, 1985 , PGandE requested
a rate increase which included tripling
the demand charge beginning January 2,
1986 . Lower than normal rainfall condi-
tions reduce the amount of PGandE ' s
low-cost surplus hydroelectric energy
purchases, which results in increases in
607-220 -34-
• •
the fuel cost adjustment component of
PGandE' s wholesale power rates to the
City.
(c) The City' s present agreement with PGandE
is for total supplemental requirements,
i.e. , PGandE supplies all of the addi-
tional capacity and energy needed to meet
the City load when the City exceeds its
116 MW allocation from the CVP. This
agreement terminates automatically if the
City receives power from sourcles other
than the CVP or PGandE.
(d) If the City decides to receive power from
other sources and if the City decides to
purchase from PGandE additionalicapacity
and energy, which is needed in excess of
that provided by City projects Vor other
purchases, a new agreement with PGandE
will be required. The new agreement may
contain a capacity ratchet which would
require the City to purchase capacity
during the entire year, even if the City
only needed the capacity during part of
the year. Considering the City' s peak
summer loads, this type of contract could
be very expensive.
(e) The City is currently negotiating with
PGandE for a new supplemental purchase
contract.contract. This 1986 Plan assumes that a
reasonable agreement can be reached with
PGandE; if not, other utilities will be
approached with regard to supplying the
City' s supplemental power needs.
2. Supplemental Purchases from Others
There are several other possible power purchase
options which may become available to the City
in the near future:
(a) CVP peaking capacity is presently sold by
Western to PGandE at the CVP capacity
(without energy) rated $3 . 75 per kW-month.
In the recent settlement between . Western
and the Sacramento Municipal ' Utility
District (SMUD) , 100 MW of CVP peaking
capacity (without energy) was included as
a settlement provision. Western has
stated that it may allocate additional CVP
peaking capacity. Since a portionjof this
607-220 -35
•
capacity could be directly available to
the City, it may provide an ideal source
of supplemental capacity.
(b) Pacific Northwest power (firm and
non-firm) is presently available in the
Pacific Northwest for those entities with
transmission rights. (The City has no
current rights to Northwest transmission. )
As a member of TANC, the City will obtain
approximately 41 MW of transmission
capacity to the Northwest when the COTP is
constructed between Northern California
and the Northwest. The' seasonal diversity
between California and the Northwest
should allow Pacific Northwest entities to
indefinitely sell summer peakingjcapacity
and energy to Redding at attractive rates .
(c) Exchange arrangements presently exist
whereby several California utilities
exchange their excess winter power for
summer power from the Pacific Northwest.
Exchange arrangements of this type may
also prove attractive for the City if
necessary transmission rights for access
to the Pacific Northwest are obta ]ned.
(d) Purchase from private developers may
become economically feasible las the
effects of the Public Utility Regulatory
Policy Act (PURPA) are diminished`. PURPA
originally established very high--cost
power purchase contracts between) private
developers and IOU' s. These contracts
generally provided private developers a
market for their power at rates whkch were
much higher than the City' s cost for
supplemental power from PGandE. Because
of recent downward trends in IOU avoided
costs, however, privatedevelopers are
currently experiencing considerable
difficulty in obtaining attractive trans-
mission and power purchase contracts from
IOU' s. To the extent that private devel-
opers are able to develop power projects
more economically, the City may belable to
participate equitably with the private
developers in the purchase of privately-
developed resources .
607-220 -36-
•
• s
B. Development Options
Power project development will help defray supple-
mental power purchases when the City exceeds its 116
MW allocation from Western. There are several
different types of power projects which could be
developed by the City.
1 . Small-to-medium Size Hydroelectric Projects
The City has a number of alternativeismall-to-
medium size hydroelectric projects under
consideration and development. Appendix A con-
tains specific information on each of these
projects, including timing and estimated costs.
One of these projects, the Whiskeytown Power
Project, will become commercially operational
in 1986 .
The most promising hydroelectric prpjects at
this time appear to be the Lake Redding Project
and the Lake Red Bluff Project. The primary
obstacles to development of these projects are
the extensive regulatory requirementsp particu-
larly relating to protection of fisheries, and
the relatively high capital costs typical of
hydroelectric projects which result in corre-
spondingly high, long-term debt service obliga-
tions.
The advantages of these projects inglude high
summer dependable capacity, geographic prox-
imity to the City, relatively low annual costs
for operation and maintenance (no fuel costs) ,
and the likelihood that over the long term,
these projects will be very economical.
Other small-to-medium size hydroelectric
projects have, as a result of PURPA, been
identified by various developers . Aoll of the
projects in this category which the City has
had the opportunity to review, however, do not
appear to be viable for the City to develop for
one or more of the following reasons :
(a) The inability of the projects to produce
summer dependable capacity and/dor reduce
winter energy production.
(b) The remoteness of the projects from trans-
mission lines to which the City has
access.
607-220 -37-
111 •
(c) The cost of power produced by the
projects.
(d) The environmental impacts which would be
created by the projects .
2 . Large Hydroelectric Projects
Unfortunately, large hydroelectric projects in
Northern California have become difficult to
develop due to excessive construction costs and
environmental concerns. Other than the New
Melones Project (federal) , and PGandE ' s Helms
Creek and Kerchoff Projects (pumped storage) ,
there have been no new large projectslsuccess-
fully completed. Several large hydroelectric
projects near the City have been identified
(locations : on the Sacramento River at Iron
Canyon, and above Shasta Lake on Squaw Valley
Creek and the Pit River) which are very
economically attractive; however, the
environmental impacts, which would be created
by the projects are too large to adequately
mitigate.
3 . Pumped Storage Projects
Pumped storage projects use water from two
reservoirs. Water is pumped with excess energy
available at night from a lower reservoir to an
upper reservoir. During the day, water is
released back to the lower reservoir generating
power when it is needed most. Pumped storage
projects are an excellent means to store excess
low-cost energy which is available during
offpeak periods for use during onpeak periods .
In addition, by maintaining a minimum pool in
the upper reservoir, certain reserve require-
ments can be achieved.
The City is actively pursuing the Spring Creek
Pumped Storage Project which is described in
Attachment A.
607-220 -38-
• •
4 . Renewable Resource Projects
Municipal Solid Waste (MSW) , biomass, wood
waste, and other renewable resourcelprojects
are feasible and under development or pperation
(on a relatively small scale) throughout
Northern California. These projects tend to be
relatively high capital cost projects with
uncertain capacity capability. Sitell specific
concerns, such as air pollution requirements
and the fuel supply are very important.
Because of the apparent supply of fuel near the
Redding area, City participation in such
projects are anticipated before 1990 .
5 . Thermal Projects
In California, there are essentially no new
large thermal. , (coal, nuclear, II oil or
gas-fired) power plants being developed.
Development of thermal power projects has
become increasingly difficult. This is due
primarily to project costs, reduced load
growth, and environmental considerations . One
exception, however, involves the increased
development of combustion turbines designed
strictly to meet system peak loads.
Several public power entities, such as SMUD and
the Modesto Irrigation District (MID) , are
planning, or are now operating combustion
turbines fueled by natural gas or distillate
oil. These facilities have relatiively low
capital costs , high operating costs, fairly
stringent environmental cons illllderations.
Combustion turbines respond well to short dura-
tion peak load requirements and are commonly
included in the resource mix for utilities with
high peaking requirements .
The operating characteristics of combustion
turbines would be compatible with the City's
peak power demands. An appropriate site and
fuel supply, which has not yet been identified,
would be required for a combustion turbine
project.
6. Geothermal Projects
Several areas of California, most notably the
Geysers Known Geothermal Resource Area (Geysers
KGRA) , have substantial potential for
geothermal power. These projects are baseload,
high-energy producing facilities with limited
607-220 -39-
• • ••
•
peaking capability. Risks for new projects are
substantial since the prime geothermal areas
were the first areas to be developedlin the
Geysers KGRA. Accordingly, the City is
reviewing continued geothermal project
participation at this time.
7 . Landfill (Methane) Projects
Landfills are specifically designated areas
established as repositories for variousNmunici-
pal wastes. Regulations require the operators
of such landfills to monitor a number of
parameters through test wells. Methanegas has
been found in a number of landfills in suffic-
ient quantities and suitable quality to econom-
ically justify the installation of! power
producing facilities . A number of these
projects are presently operating in California.
The City is currently reviewing the possible
development of this type of project.
8. Nuclear Projects
Through membership in the Modesto-Santa
Clara-Redding Power Agency (M-S-R) , the City
was offered 22 . 5 MW of firm capacity from the
Arizona Nuclear Power Plant. In JuneJ, 1982,
City voters passed a referendum prohibiting
City involvement in the project. The lity is,
therefore, constrained from considering future
participation in nuclear power projects'L
9. Solar Projects
The City' s high summer power needs are concur-
rent with the City' s hot summer days.
Therefore solar power appears to be a possible
source of power to help meet its peakkdemand.
Currently, the costs for solar poyer are
prohibitive when compared to other power
options. However, the technology foIIr solar
power is rapidly expanding and costs are
decreasing. The City plans to continually
review the possible development of solar
projects.
10 . Small Wind Projects
i
The 1986 Plan does not consider wind power
electric generating facilities. Dependable
winds of usable velocities do not normally
occur in the Redding area. Sites where small
wind projects appear to be feasible have the
607-220 -40-
• •
same transmission constraints as the small
hydro projects discussed above.
11 . Energy Conservation and Load Management
Energy conservation/load management (ECLM)
offers an opportunity to help meet the power
needs of the City' s customers . ECLM is
expected to increase as more programs become
cost effective. To place extra emphasis on the
value of the City' s ECLM, these programs are
included in the 1986 Plan as power redources.
The City' s ECLM programs will, h&wever,
actually reduce the projected City peak period
energy demand and usage and will not "generate"
power.
C. Transmission Options
New transmission lines can provide the opportunity
to obtain power either under contractual arrange-
ments for power purchases or from power projects.
1 . Northwest Transmission
The most promising of transmission options for
the City are those transmission facilities
proposed by the COTP which would provide direct
access to the Pacific Northwest. PeakJing and
exchange arrangements are now available at the
California-Oregon border for those entities
with firm transmission rights. They rates
applicable to Northwest peaking and exchange
arrangements are currently substantially lower
than alternative supplemental power purchase
options.
The City is actively participating in COTP
through its membership in TANC which is the
manager of COTP. The City expects to receive
ownership rights for up to 41 MW of trans-
mission capacity from COTP between Southern
Oregon and Redding, and Redding south to
Tracy-Tesla.
2 . Southwest Transmission
The City is also pursuing transmission paths to
the Southwest via participation of M-S--R in the
Mead-Phoenix Dirrect Current IntertiejProject
and the Mead-Adelanto Project. These projects
are currently in the engineering study phase.
607-220 -41-
• •
VI . OTHER CONSIDERATIONS
Development of a reliable and economical power resource
plan to meet forecasted load requirements is a complex
process which requires more consideration than merely
choosing the cheapest resource in terms of dolkars per
kWh or dollars per kW. Several other considerations as
described below will be evaluated in determining which
resources should be developed by the City.
A. Economics
The cost of a project should not be considered
strictly in terms of dollars per kWh or dollars per
installed kW. Several other factors affect project
economics :
1 . Summer dependable capacity: Some projects such
as small hydro projects which generate inex-
pensive energy cannot generate dining the
City' s peak load. These kinds of projects are
lower in value than projects which produce
reliable summer capacity for similar energy
costs.
2 . Reliability: Projects which have a history of
unexpected outages are not as valuable as
projects which can be depended on fdr nearly
continuous operation.
3 . Useful life: Projects which can continue
operation without major overhaul long past the
debt service is paid (such as hydroelectric
projects) are economically more attractive than
projects which require major overhauL before
debt service is paid and/or have little useful
life after debt service is paid.
4. Fuel supply: Future costs of most projects are
primarily dependent on the future cost and
availability of the fuel supply. Therefore,
availability and cost of the future fuel supply
are important factors to determine project
economics.
5 . - Ability to follow load: Projects which can
"follow load" are projects which are capable of
reducing or increasing their generation coinci-
dent with the City' s reduction or increase in
demand for power. If the City has itoo many
projects which must generate energy during
offpeak hours, the City will have toHsell the
excess energy. Such sales will usually be at
a rate below the City ' s cost to produce the
607-220 -42-
-. . ' ,
• •
energy (dump power rate) . Projects which can
increase their generation during onpeak hours
will help the City to reduce expensive pur-
chases of onpeak power.
6 . Contingencies: Some projects have high capital
risks, such as geothermal projects where high
investment costs may be required too drill
exploratory holes to determine whether enough
steam is available. Others have a high
environmental risk, such as hydroelectric
projects which may require postLproject
mitigation costs . These risk factors must be
evaluated when determinincr project economic
feasibility.
B. Residual Capacity Charges
When a utility purchases wholesale power from
another utility, the price paid is primarily deter-
mined by the energy component and the 'capacity
component of the applicable rate structure! Under
most wholesale purchase contracts, residual capacity
charges are imposed. These charges are commonly
referred to as ratchet charges , reserve charges,
standby charges, firming charges and/or customer
service charges.
Whereas each charge may have its own particular
justification, utilities justify these charges on
the basis that they have incurred significant
capital expenditures to supply peak capacity and
that the charge allows them to obtain a just and
reasonable return on the investment made to 'meet the
peak load requirements throughout the year. For
example, some rate schedules require up td 94% of
the peak value of power capacity supplied in the
summer must also be paid for in the next 11 billing
months. If one assumes a rate for wholesale
capacity in the $10-$15 per kW month range, it is
possible that peak summer capacity may effectively
cost from $115 to $170 per kW of demand for the peak
month.
Wholesale purchased power rates with residual
capacity charges are becoming increasingly popular
as the costs for new capacity continues to rise.
This factor will become more important in the future
since the peak summer loads for the City may require
payment of the charge during off-peak months.
Alternatively, the savings made available by avoid-
ing these charges can be used to support ' further
City development of power projects and load manage-
ment programs which minimize residual capacity
607-220 -43-
••
VII . RECOMMENDED POWER RESOURCE DEVELOPMENT PLAN
Based upon the City' s planning goals, future power
requirements and the available alternatives, the',, follow-
ing plan is recommended to meet the City' s power require-
ments through fiscal year 2005 . Table 10 summarlizes the
City' s current plans to meet its electrical power needs.
It should be noted that the City' s contract withI Western
expires after the calendar year 2004 . Therefore, plan-
ning past the fiscal year 2005 at this time is too
uncertain to warrant much consideration, except that the
City should be prepared for a total reallocation of
Western ' s resources and the consequences which may be a
result of that reallocation.
A. Avoid High-cost Supplemental Power Purchases
Since future supplemental power purchases are likely
to be high, the City should try to avoid
supplemental power purchases by developing power
resources which are lower than the projected cost of
supplemental power purchases . As was rioted in
Section VI, it is possible that residual capacity
charges may make supplemental peaking capacity quite
costly.
Table 10 includes every project which the City
currently believes can be developed and which is in
the long term (first 10 years of operation) more
economical than supplemental purchase power, options
from California IOU' s.
If the recommended plan shown in this table is
developed as scheduled. The City' s purchase of
supplemental power from California IOU Twill be
minimal. However, the need to purchase supplemental
power will increase the extent that the City does
not successfully develop the projects listed in
Table 10 as currently scheduled unless other
yet-undefined projects are developed. If tioo large
a percentage of the City' s supplemental power is
purchased from California IOU' s, the City rate to
its customers will equal or exceed the California
IOU ' s rate.
B. Pursue Conservation and Load Management Progrrams
As the City' s conservation and load management
programs are implemented, the City' s ability to
avoid its exceptional summertime capacity peaks will
increase. Electric loads in the City that can be
safely and efficiently reduced during the peak
demand time periods will directly benefit the City' s
607-220 -46-
• •
ratepayers through lower costs from avoided supple-
mental power purchases.
Table 6 includes the forecasted impact of the City' s
load management programs. A total of 46 . 6 MW' s is
assumed to be shed from the City' s peak power
demands through the use of load management during
fiscal year 2005.
C. Pursue Near-term Wholesale Purchases
As shown in Table 10, the City needs arrangements
that can provide near-term capacity and dilispose of
excess energy during those time periods when the
City' s energy requirements are reduced.
The most promising alternatives are:
1 . Scheduling of power from Western
2 . Peaking capacity purchases in California
3. Sale of excess energy to Western
4 . Pacific Northwest peaking capacity purchases
5 . Exchange arrangements
6 . New supplemental power purchase contract with
PGandE
7 . Other possible suppliers and purchases (DWR,
MID, SMUD, etc. )
8 . Large interruptible customers.
D. Pursue Economic Hydroelectric Projects
Two small-to-medium size hydroelectric power
projects remain available for development by the
City. Small-to-medium size hydroelectric projects
can be developed using proven technology Il and can
provide additional direct construction benefits for
the local economy. Three hydroelectric projects in
various states of development are listed in Table
10 . The Whiskeytown Project is expected to become
operational in 1986 . The other two hydroelectric
projects are the Lake Red Bluff Project and the Lake
Redding Project.
E. Pursue Development of Spring Creek Pumped Storage
Project
Development of the Spring Creek Pumped Storage
Project will allow the City to maximize the benefits
of other projects by allowing offpeak energy to be
stored for later use as onpeak capacity andlenergy.
The pumped storage project will also allow the City
to use offpeak energy which is often available at
attractive rates from other utilities. Finally, by
maintaining a minimum pool in the upper reservoir,
- I
607-220 -47-
the City can provide the necessary reserve require-
ments for its other projects.
F. Pursue Development of the Carnage Cogeneration
Project
The Carnage project offers the City an opportunity to
meet its near term power needs. The cost of power
produced by Carnage for the first tent years of
operation is expected to be less than the cost of
equivalent power purchased from PGandE. The Carnage
Project will help to increase the City diversity
since the project will be powered by wood fuel and
has the ability within certain constraintslto follow
load. Table 10 assumes that this project will be
available in fiscal year 1988 .
G. Pursue Transmission Rights
For the City to have free access to economical power
supplies, transmission rights must be obtained. As
previously discussed, peaking capacity 1 from the
Pacific Northwest, the CVP, or elsewhere appears
particularly attractive.
The City is presently a 6 . 4% participant in TANC,
which is the project manager of the COTP. The COTP
includes upgrading and construction of new trans-
mission facilities from the Pacific Northwest to
North Central California. Studies are currently
underway for the COTP, and the project is currently
scheduled for completion in 1991 . Table 10 includes
27 . 7 MW of purchased peaking capacity from the
Pacific Northwest and delivered over the COTP
beginning in fiscal year 1991 . Pacific Northwest
will gradually increase to 41 . 5 MW by the year 2000 .
The City' s interest in the COTP from Redding to the
Tracy-Tesla Substations will enable Redding to
directly interconnect with other California utili-
ties for transmission of its San Juan entitlement
and other power purchases .
H. Enhance Relationships with Western
Since Western is the City' s primary sourceiof power,
and since Western is the City ' s transmission link to
other utilities, it is important for the City to
maintain and enhance its working relationships with
Western. Agreements which are mutually beneficial.
to Western and the City should continue to be
emphasized.
607-220 -48
• 0
•
I, Selectively Participate in Baseload Projects,
Whenever the overall economics are favorable and the
diversity of power supply can be enhanced, *he City
may wish to selectively participate in baseload
power projects . The San Juan Project, described in
detail in Appendix A, is one such example. The San
Juan agreements provide for flexibility in energy
deliveries and allow the City to acquire a ruelative-
ly low-cost interest in an operating, coal-fired
power plant. It is recommended that t1he City
selectively examine and participate in other such
projects whenever such participation meets the plan-
ning goals of the City.
607-220 -49-
TABLE 10
O •
CITY OF REDDING
1986 Power Resource Plan
Recommended Plan
Fiscal Year 1987 1988 1989 1990 1991 1992 1993 Q 1994 1995 1996
ENERGY (GWH)
REQUIREMENTS
Sales 521.2 551.5 583.1 606.7 631.7 657.3 684.6 711.7 741.7 768.9
Losses 33.9 35.8 37.9 39.4 41.1 42.7 44.5 46.3 48.2 50.0
Energy Conserv. 4.0 5.0 6.0 7.0 8.0 9.0 10.0 11.0 12.0 13.0
Contract Exp. 229.3 257.4 291.7 324.9 402.6 554.6 507.2 484.7 449.8 344.1
TOTAL 788.4 849.7 918.7 978.0 1,083.4 1,263.6 1,246.3 1,253.7 1,251.7 1,176.0
ENERGY (GWH)
RESOURCES
Western 544.8 565.4 583.4 591.7 600.1 604.4 608.4 613.4 615.9 618.1
Energy Conserv. 4.0 5.0 6.0 7.0 8.0 9.0 10.0 11.0 12.0 13.0
San Juan 116.7 116.7 116.7 116.7 116.7 116.7 116.7 116.7 116.7 116.7
Whiskeytown 8.2 8.2 8.2 8.2 8.2 8.2 8.2 8.2 8.2 8.2
Carnage 0.0 50.0 100.0 150.0 200.0 205.0 205.0 205.0 205.0 205.0
Spring Creek 0.0 0.0 0.0 0.0 0.0 0.0 -51.6 -51.6 -51.6 -51.6
Lake Redding 0.0 0.0 0.0 0.0 46.0 92.1 92.1 92.1 92.1 92.1
Lake Red Bluff 0.0 0.0 0.0 0.0 0.0 24.0 47.9 47.9 47.9 47.9
Northwest Imports 0.0 0.0 0.0 0.0 0.0 99.8 105.2 106.6 118.5 126.6
Southwest Imports 104.4 104.4 104.4 104.4 104.4 104.4 104.4 104.4 87.0 0.0
Other Purchases 10.3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
TOTAL 788.4 849.7 918.7 978.0 1,083.4 1,263.6 1,246.3 1,253.7 1,251.7 1,176.0
CAPACITY (MW)
REQUIREMENTS
Customer Demand 120.0 125.6 132.1 137.7 142.3 147.9 154.4 160.0 166.5 173.0
Losses 9.0 9.4 9.9 10.3 10.7 11.1 11.6 12.0 12.5 13.0
Interrupt. Load 8.0 12.0 16.0 20.0 24.0 26.0 27.0 28.0 30.0 31.0
Reserves 0.0 0.3 5.3 5.3 5.3 14.4 29.6 30.0 30.5 35.5
Contract Exp. 18.8 17.8 17.8 17.8 17.8 17.9 56.5 51.6 46.3 36.6
TOTAL 155.8 165.1 181.1 191.1 200.1 217.3 279.1 281.6 285.8 289.1
CAPACITY (MW)
RESOURCES
Western 116.0 116.0 116.0 116.0 116.0 116.0 116.0 116.0 116.0 116.0
Load Mgmt. 8.0 12.0 16.0 20.0 24.0 26.0 27.0 28.0 30.0 31.0
San Juan 17.8 17.8 17.8 17.8 17.8 17.8 17.8 17.8 17.8 17.8
Whiskeytown 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0
Carnage 0.0 0.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0
Spring Creek 0.0 0.0 0.0 0.0 0.0 0.0 55.0 55.0 55.0 55.0
Lake Redding 0.0 0.0 0.0 0.0 0.0 8.0 8.0 8.0 8.0 8.0
Lake Red Bluff 0.0 0.0 0.0 0.0 0.0 0.0 4.3 4.3 4.3 4.3
Northwest Imports 0.0 0.0 0.0 0.0 0.0 28.5 30.0 31.5 33.7 36.0
Other Purchases 13.0 18.3 10.3 16.3 21.3 0.0 0.0 0.0 0.0 0.0
TOTAL 155.8 165.1 181.1 191.1 200.1 217.3 279.1 281.6 285.8 289.1
I
607-220
-50-
OTABLE 10 (Cont.) •
CITY OF REDDING
1986 Power Resource Plan
Recommended Plan
Fiscal Year 1997 1998 1999 2000 2001 2002 20037 2004 2005
ENERGY (GWH)
REQUIREMENTS
Sales 801.4 834.0 869.8 907.5 949.5 996.0 1,043.71 1,092.1 1,142.2
Losses 52.1 54.2 56.5 59.0 61.7 64.7 67.8 71.0 74.2
Energy Conserv. 14.0 15.0 16.0 17.0 18.0 18.0 19.01 19.0 21.0
Contract Exp. 266.4 238.7 202.1 166.6 143.9 131.4 118.1 85.6 32.8
TOTAL 1,133.9 1,141.9 1,144.4 1,150.1 1,173.1 1,210.1 1,248.6 1,267.7 1,270.2
ENERGY (GWH)
RESOURCES
Western 621.3 623.1 623.0 623.9 624.9 625.5 626.71 627.6 628.1
Energy Conserv. 14.0 15.0 16.0 17.0 18.0 18.019.0` 19.0 21.0
San Juan 116.7 116.7 116.7 116.7 116.7 116.7 116.71 116.7 116.7
Whiskeytown 8.2 8.2 8.2 8.2 8.2 8.2 8.2 8.2 8.2
Carnage 205.0 205.0 205.0 205.0 205.0 205.0 205.0! 205.0 205.0
Spring Creek -103.3 -103.3 -103.3 -103.3 -103.3 -103.3 -103.311 -103.3 -103.3
Lake Redding 92.1 92.1 92.1 92.1 92.1 92.1 92.11 92.1 92.1
Lake Red Bluff 47.9 47.9 47.9 47.9 47.9 47.9 47.9 47.9 47.9
Northwest Imports 132.0 137.2 138.8 142.6 163.6 200.0 236.3 254.5 254.5
Southwest Imports 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Other Purchases 0.0 0.0 0.0 0.0 0.0 0.0 0.01 0.0 0.0
TOTAL 1,133.9 1,141.9 1,144.4 1,150.1 1,173.1 1,210.1 1,248.6 1,267.7 1,270.2
CAPACITY (MW)
REQUIREMENTS
Customer Demand 179.5 186.0 193.5 201.9 210.2 220.5 230.7 240.9 252.1
Losses 13.5 14.0 14.5 15.1 15.8 16.5 17.3 18.1 18.9
Interrupt. Load 33.0 34.0 36.0 38.0 39.0 42.0 43.0 44.0 46.0
Reserves 45.2 45.6 45.7 46.0 46.2 46.2 46.2 46.2 46.2
Contract Exp. 58.7 52.7 45.2 36.9 28.6 17.6 6.6 0.0 0.0
TOTAL 329.9 332.3 334.9 337.9 339.8 342.8 343.8 349.2 363.2
CAPACITY (MW)
RESOURCES
Western 116.0 116.0 116.0 116.0 116.0 116.0 116.0 116.0 116.0
Load Mgmt. 33.0 34.0 36.0 38.0 39.0 42.0 43.0 44.0 46.0
Whiskeytown 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0
Carnage 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0
Spring Creek 110.0 110.0 110.0 110.0 110.0 110.0 110.0 110.0 110.0
Lake Redding 8.0 8.0 8.0 8.0 8.0 8.0 8.0 8.0 8.0
Lake Red Bluff 4.3 4.3 4.3 4.3 4.3 4.3 4.3 4.3 4.3
Northwest Imports 37.6 39.0 39.6 40.6 41.5 41.5 41.51 41.5 41.5
Other Purchases 0.0 0.0 0.0 - 0.0 0.0 0.0 O.OI, 4.4 16.4
TOTAL 329.9 332.3 334.9 337.9 339.8 342.8 343.81 349.2 363.2
I
i
607-220 -51-
, VIII . DEFINITIONS 411
Term Definition
Ampere (Amp) The unit of measurement of electrical
current. It is analogous to the flow of
a cubic foot of water past a given point
during a specified time period. An
ampere is the unit of current produced
in a circuit by one volt acting through
a resistance of one ohm.
Avoided Costs The costs an electric utility would
otherwise incur to generate power if it
did not purchase electricity from
another source.
Backup Power Electrical energy supplied by a utility
to replace power and energy lost during
an unscheduled equipment outage.
Base Load The minimum demand for service of an
electric or gas utility over a stated
period of time.
Base Rate A fixed amount charged each month for
any of the classes of utillity service
provided to a customer.
Biomass Organic Materials (such ] as trees,
plants, and crop residues) used as a
source of energy.
Boiler Fuel Fossil fuel used as the primary energy
source to generate steam.
Btu Abbreviation for British thermal unit.
The quantity of heat necessary to raise
the temperature of one pound of water
one degree Fahrenheit at a specified
temperature and pressure (from 59° F to
60° F at atmospheric pressure of 29 .92
inches of mercury) .
Capability The maximum production level which a
generating unit or electrical apparatus
can maintain under specified conditions
for a given period of time without
exceeding approved limits of temperature
and stress.
607-220 -52-
capacity • The production levee for which an
electric generating unit or other '
electrical apparatus is rated, either by
the user or manufacturer. I Also, the
total volume of natural gals that can
flow through a pipeline over a given
period of time, considering such factors
as compression and pipeline size.
The maximum load that a machine,
station, or system can carry under
existing service conditions. In trans-
mission, the maximum load a transmission
line is capable of carrying. (See DEMAND
definition)
Capacity Factor The ratio of the average load on a
generating resource to its capacity
rating during a specified period of
time, expressed in percent.
Charge - Connection An amount levied on a customer in a lump
Charge sum, or in installments, for' connecting
his facilities to those of his supplier.
Charge - Customer An amount charged periodically to a
Charge customer for such utility costs as bill-
ing and meter reading without regard to
demand or energy consumption.
Charge - Energy Charge That portion of the charge for electric
service which reflects a customer' s
energy (kWh) use over a specified
billing period.
Charge - Termination A charge levied on a customer when ser-
Charge vice is terminated at his request.
Charge - Wheeling An amount charged to one electrical
Charge system, by another electrical system, to
transmit the energy of, and for, the
other system.
Circuit A system of conductors through which an
electric current is intended to flow.
Sometimes normally open paths which do
not ordinarily conduct in a network can
also be considered part of a circuit.
Classes of Service Groups of customers with similar
characteristics (e.g. , residential,
commercial, industrial, etc. ) which are
identified for the purpose of setting a
rate for electric.
607-220 -53-
' Cpde of Federal • A compilation of the ral and pe.rma-
• Regulations nent rules of the execu ive departments
and agencies of the federal government
as published in the Federal Register.
The Code is divided into 50 tLt1es which
represent broad areas subjectil to federal
regulation. Title 18 contains the
Federal Energy Regulatory Commission' s
regulations .
Cogeneration The sequential production of electricity
and useful thermal energy from the same
energy source.
Combined Cycle When otherwise wasted heat is converted
into electricity rather thanOdischarged
into the atmosphere . One of the tech-
nologies of cogeneration in which elec-
tricity is sequentially produced from
two or more generating technologies.
Combustion Turbine A machine in which high pressure gases
from the combustion of fuel, usually
natural gas or oil, expand through
fan-type blades to drive �a rotating
shaft.
Commercial Service Service to customers engaged primarily
in the sale of goods or services,
including institutions and government
agencies.
Conservation Making the wisest use of energy over the
long term,' usually without any compro-
mise of lifestyle. It can be voluntary
or mandatory.
Cost of Service A ratemaking concept used for the design
and development of rate schedules to
ensure that the filed rate schedules
recover only the cost of providing the
gas or electric service at issue. This
concept attempts to correlates the utili-
ty' s costs and revenues with the service
provided to each of the various customer
classes.
Costs - Fixed Costs Costs associated with capital investment
such as equipment overhead, property
taxes.
Costs - Fixed Operating Costs other than those associated with
Costs capital investment which dog not vary
with the operation such as maintenance,
payroll.
607-220 -54-
Current • A movement of electrify and the rate
of such movement. Refers to current '
intensity or strength = as a current of
five amperes. Technically, a flow of
electrons in an electrical conductor.
Curtailment Reduction of deliveries of electricity
because of a shortage or other reasons .
Curtailment Plan A plan to accommodate shortages of
electric energy which restrict the
utility' s service to its customers.
Electric curtailment plans are developed
to assure public health and safety and
the equitable treatment of customers.
Declining Block Rates A rate structure in which the charge for
energy decreases as the amount of energy
consumed increases .
Demand Demand is expressed in kilowatts . The
rate at which electric energy is deliv-
ered to or by an electric utility system
over any designated period.
Dependable Capacity The load-carrying ability of a gener-
ating station or system under adverse
conditions for a specified time period.
Distribution System Also, network, grid. That portion of an
electric system used to deliver electric
energy to an end-user from pints on the
transmission or the bulk power system.
Dump Energy Energy generated which is in excess of
the needs of the electric system produc-
ing the energy.
Economy Energy Energy produced from a source in one
system and substituted for energy that
could have been produced by a less
economical (more costly) source in
another system.
Economy of Scale A proposition that relatively larger
production facilities have lower unit
costs than relatively smaller
facilities. Economy of scale may exist
for any of the phases of operation:
generation, transmission, or distri-
bution.
607-220 -55-
. , ° ;Energy • The capacity for doinrk. There are
several forms of energy, and one form
may be changed to another - such as
burning coal to produce steam to drive a
turbine which produces electricity.
Most of the world' s convertLible energy
comes from fossil fuels which are burned
to produce heat. Energy is measured in
terms of the work it is capable of
doing. Electric energy is usally
measured in kilowatt hours .
Energy Load In a power system, the demand averaged
over a substantial period of time.
Federal Energy The federal agency which has Regulatory
Regulatory Commission jurisdiction over natural gas pricing,
(FERC) wholesale electric rates, hydroelectric
licensing, oil pipeline rates and gas
pipeline certification.
Federal Power Act Enacted in 1920, the Act, as amended in
1935, consists of three parts. The
first part incorporated tihe Federal
Water Power Act administered by the
Former Federal Power Commlssion. It
confined FPC activities almost entirely
to licensing non-federal hydroelectric
projects . With the passage of the
Public Utility Act, which added parts II
and III, the Commission' s jurisdiction
was extended to include regulating the
interstate transmission of electric
energy and rates for its salve at whole-
sale for its sale at wholesale in
interstate commerce.
Federal Power Predecessor of the Federal Energy Regu-
Commission latory Commission. The Federal Power
Commission was created by an Act of
Congress under the Federal Water Power
Act on June 10 , 1920. It was originally
charged with regulating the nation' s
water power resources, but later was
given responsibility for regulating the
electric power and natural gas indus-
tries . It was abolished 9 September
30, 1977 , when the new Department of
Energy was created and its functions
were embraced by the Fede��ral Energy
Regulatory Commission, an ,independent
regulatory agency.
Firm Energy Energy which is intended to heave assured
availability to the customer Ito meet all
or any agreed-upon portion of his load
requirements over a defined period.
607-220 -56-
411
i •Eirm Power e The highest quality electric power
which has a very low probability of
interruption.
Firm Service The highest quality generation and/or
transmission service offered to
customers under a filed rate schedule
which anticipates no planned
interruption.
Firm Transmission Transmission of energy by a utility over
its system for the accountpof another
party with the service intended to be
available at all times .
Fiscal Year Government ' s 12-month financial year.
The federal govermnent ' s is from Octo-
ber 1 , through September 30. The City
of Redding' s is July 1 to June 30 .
Flat Rate Schedule A schedule that provides for a specified
charge regardless of the energy consumed
or demand.
Fuel Cost Adjustment A clause in a rate schedule that adjusts
Clause the amount of the customer's electric
bill as the cost of fuel varies from a
specified base amount.
Full Requirements A sale of power and energy by a utility
to a purchaser in which the seller
pledges to meet all of the purchaser' s
electric requirements .
Generation The process of producing electric
energy.
Geothermal Energy Natural heat contained in the rocks, hot
water, and steam of the earth' s subsur-
face. Geothermal energy can be used to
generate electric power, to heat resi-
dences and for industrial needs . In the
United States , such energy is nearest
the earth' s surface and most accessible
in the western United States.
Giga A prefix indicating a billion; thus a
gigawatthour (GWH) equals 1 , 000 , 000, 000
watthours, or 1 , 000, 000 kilowatthours .
Gigawatt (GW) 1 million kilowatts (kW) .
Gigawatt-hour (GWh) 1 million kilowatt hours (kWh) .
Gross Generation The total amount of electric energy
produced by a generating station or
stations, measured at they generator
terminals.
607-220 -57-
H Headwater Benefits • The benefits resultinerom the storage
or release of water by a reservoir proj-
ect upstream.
Hydroelectric Energy The production of electricity from
kinetic energy in flowing water.
Installed Capacity The total manufacturer rated capacity of
such kinds of equipment as turbines,
generators, condensers, transformers,
and other system components.
Interruptible Power Power that may he interrupted through
curtailment or cessation of delivery by
the supplier by agreement with the cus-
tomer.
Intertie A transmission line or system of trans-
mission lines permitting a flow of
energy between major power systems.
Intertie, Pacific The Pacific Northwest/Pacifilc Southwest
Northwest/Pacific Intertie was approved by Congress in
Southwest 1964 . Five investor-owned utilities ,
the City of Los Angeles and the Federal
Government agreed to join in Intertie
construction. The Intertie consists of
three extra-high-voltage transmission
lines and appurtenant substation facil-
ities . Two of the lines, operating at
500 kV alternating current, extend from
a connection with the U.S . Columbia
River Power System at John Day Dam to
various points of connection with the
system of PGandE, and to a connection
with the Southern California Edison
Company system near Los Angeles. The
nominal capacity of each of these lines
is 1 ,000,000 kilowatts . The other line
operates at 750 kV direct current, with
a capacity of about 1 , 440 ,000 kilowatts.
The direct current line connects with
the federal system at Celillo, Oregon,
near the Dalles Dam. It extends to a
connection with the system the City
of Los Angeles at Sylmar, California and
thence, through the City ' s system, to a
connection with the system of Southern
California Edison.
Inverted Rate Design A rate design for a customer class for
which the unit charge for energy in-
creases as usage increases.
Kilo A prefix indicating a 1 , 000 ; thus, a
kilovolt (kV) equals 1 ,000 volts.
607-220 -58-
•
;Kilovolt (kV) 411 A unit of measureme of electrical
force equal to 1 , 000 vo ts.
Kilowatt (kW) A unit of power equal to 1 , 000 watts or
1 ,341 horsepower. It is a measure of
electrical power or heat flow rate and
equals 3 , 413 Btu per hour. An electric
motor rated at one horsepower' uses elec-
tric energy at a rate of abot 3/4 kilo-
watt/hour.
Kilowatthour (kWh) The common unit of electric energy equal
to one kilowatt of power supplied to or
taken from an electric circuit for one
hour.
License Authorization by the Federal Energy
Regulatory Commission to construct,
operate, and maintain non-federal hydro
projects for a period of up too 50 years.
Load The amount of electric power or energy
required at any specified point or
points on a system to supply the
energy-consuming equipment of the user
customers.
Load Factor The ratio of average load to the peak
load during a specified period of time.
A 100% load factor would mean average
load equals peak load or complete
utilization of the transmission system.
Load Management Influencing the level and shape of the
demand for electrical energy so that
demand conforms to present supply
situations and long-run objectives and
constraints.
Maintenance Expenses That portion of operating expenses con-
sisting of labor, materials,' and other
direct and indirect expenses incurred
for preserving the operatinglefficiency
or physical condition of utility plants
which are used for power production ,
transmission and distribution of energy.
Master Metering Use of one central meter for several
customers so that individual customers
have no means of judging their individ-
ual energy consumption.
Mega A prefix indicating a million; thus a
megavolt (MV) equals 1 , 000 , 000 volts and
a megawatt (MW) equals 1 , 000, 000 watts.
607-220 -59-
Megawatt (MW) 0 1 , 000 kilowatts or 1 million watts .
• Net Generation Gross generation less plant use,
measured at the high voltage terminals
of the station ' s step-up transformer.
Non Firm (Energy or Energy or power, or power-producing cap-
Power or Capacity) acity supplied or available under an
arrangement which does not have the
guaranteed continuous availability
feature of firm power.
Peak Load The maximum electrical demand in a
stated period of time. Itlmay be the
maximum instantaneous load or the
maximum average load within a designated
interval of the stated period of time.
Peaking Capacity Generating capacity available to assist
in meeting that portion of the load
which occurs during peak lord periods.
The maximum output of a generating plant
or plants during a specified peak-load
period.
Pool Capacity Total capacity provided by a power pool
in order to meet installed or reserve
capacity obligations .
Power The time rate of transferring or
transforming energy. ElPectrically,
power is expressed in wattsJ, which is
the product of applied voltage and
resulting in in-phase currents.
Power Pool A power pool consists of two or more
interconnected electric systems which
operate as a single system to supply
power to meet combined load requirements
and maintenance programs.
Preliminary Permit A permit granted by the FERC which gives
the permittee priority over anyone else
to apply for a hydroelectriic license.
The preliminary permit enables the
permittee to prepare a licgnse appli-
cation and conduct various studies such
as economic feasibility and environ-
mental impacts. The period for a
preliminary permit may extedd to three
years.
it
607-220 -60-
Public UtilityII/ ,
One part of the Natal Energy ' Act,
Regulatory Policies PURPA contains measures designed to of
Act 1978 (PURPA) encourage the conservation of energy,
more efficient use of resources, and
equitable rates. Principal among these
were suggested retail rate reforms and
new incentives for production of elec-
tricity by cogenerators and users of
renewable resources . The FERC has
primary authority for implementing
several key PURPA programs .
Pumped Storage An arrangement in which water is pumped
into a storage reservoir at a higher
elevation during off-peak periods when
excess generating capacity is available.
During on-peak periods, when additional
generating capacity is needed, the water
can be released from the reservoir
through a conduit to turbine generators
located in a power plant at a lower
level.
Rate Base The value, specified by a regulatory
authority, upon which a utility is
permitted to earn a specified rate of
return. Generally, this represents the
amount of property used and useful in
public service and may be based on the
following values or combinations
thereof: fair market value, prudent
investment, reproduction cost, or
original cost; and may provide for cash
working capital, materials and supplies,
and deductions for accumulated provis-
ions for depreciation, contributions in
aid of construction, and accumulated
deferred income taxes.
Renewable Energy An energy source which is regenerative
Source or virtually inexhaustible.� Typical
examples are wind, geothermal energy,
and water power.
Requirements, Power The power required by designated load
plus losses from the points of supply,
I
Reserve Generating Pxtra generating capacity available to
Capacity meet peak or abnormally high demands for
power and to generate power during
scheduled or unscheduled outages.
607-220 -61-
HR.un-of-River 41, Refers to hydroelectr• prodects whose
operation cannot be regulated for more
than a few hours from storage at or
above the site, but are controlled
mainly by the volume of water flowing in
the stream. These flows must be used as
they occur or their energy volume will
be lost forever.
Sales for Resale Sales (wholesale) covering energy sup-
plied to other electric utilities, co-
operatives, municipalities, hand federal
and state electric agencies for resale
to ultimate consumers.
Scheduled Maintenance Capacity and/or energy provided by a
utility during the period that genera-
ting facilities of the receiving party
are inoperative due to scheduled mainte-
nance on the facilities .
Seasonal Rate A schedule containing an electric rate
Schedule available only during certain specified
season of the year.
Seasonal Rates The rates charged by an electric or gas
utility for providing service! to consum-
ers at different seasons of the year,
taking into account demand based on
weather and other factors.
Service Area Territory in which a utility system or
distributor provides service to consum-
ers.
Short-Term Firm Capacity and/or energy provided on a
daily or weekly basis, generally for
periods not to exceed one month, with
assured availability during the period
of reservation.
Short-Term Non-Firm Capacity and/or energy prol�ided on a
daily or weekly basis, generally for
periods not to exceed one month with
limited or no assured availability
during the period of reservation.
Spinning Reserve Generating capacity which is connected,
operating, and ready to take load. Units
which are operating at less than full
capacity.
Standby Charge Fixed monthly charge for the potential
use of a utility service.
607-220 -62-
• ' Standby Service i Capacity and/or enerclprov�ided or made
available when the purchaser ' s gener-
ation is unable to meet its entire load
or has dropped below a stated level of
reserve capacity.
Standby Facility A facility that is not regularly used
but is available to replace or supple-
ment a facility normally in service.
Station Service Energy that is used in the operation of
an electric generating plant. It in-
cludes energy consumed for plant light-
ing, power, and auxiliaries regardless
of whether the energy is produced at the
plant or comes from another source.
Substation An electrical power station which serves
as a control and transfer (point on an
electrical transmission or distribution
system. It serves the following pur-
poses:
(1) To route and control electrical
power flow.
(2) To transform a voltage to higher or
lower voltage.
(3) To serve as a delivery point to a
private or publicly-owned utility, or
to a large industrial customer, such as
an aluminum plant.
A substation can be designed to include
equipment for one, or any combination,
of the above purposes.
Surplus Energy Energy generated that is beyond the
immediate needs of the producing system.
Switching Station Equipment used to tie togehher two or
more electric circuits through switches.
The switches are selectivelylarranged to
permit a circuit to be disconnected, or
to change the electrical connections be-
tween the circuits.
Transformer _An electrical device for changing the
voltage of alternating current.
Transmission The movement or transfer If electric
energy in bulk. Ordinarily, trans-
mission is considered to end when the
energy is transformed for distribution
to the consumer.
607-220 -63-
411
Volt The unit of measuremill of electrical
force. It is analogous to Vwater pres-
sure in pounds per square inch. It is
the electrical force which, if steadily
applied to a circuit with a resistance
of one ohm, will produce a current of
one ampere.
Waste Heat Heat contained in exhaust gases or liq-
uids that is usually discharged to the
environment.
Watt See POWER.
Watthour The amount of electric energy used by a
one watt load in one hour. A 100-watt
light bulb will use 100 watt-hours of
electricity every hour it is in use.
Wheeling The use of the transmission facilities
of one system to transmit power of and
for another system.
607-220 -64-
I
4111 •
APPENDIX A
RECOMMENDED RESOURCE AND TRANSMISSION PROJECTS
FOR THE CITY OF REDDING
1986 POWER RESOURCE PLAN
•
I. PROJECTS WHICH CITY HAS COMMITTED TO FULL DEVELOPMENT
A. Whiskevtown
B. San Juan
II . PLANNED HYDROELECTRIC PROJECTS
A. Lake Redding
B. Lake Red Bluff
III . OTHER PLANNED PROJECTS
A. Spring Creek Pumped Storage Project
B. Carnage Cogeneration Project
IV. POTENTIAL PROJECTS
A. Municipal Solid Waste
B. Methane Gas (Landfills)
C. Methane Gas (Airport)
D. Cogeneration with Interruptible Service
E. Renewable Resource Allocation
V. TRANSMISSION PROJECTS UNDER REVIEW
A.- COTP
B. Multi-utility Trans-Sierra Line
C. Western System Upgrade
D. Mead-Phoenix Direct Current Project
E. McCullough-Victorville Project
607-220
1111
WHISKEYTOWN HYDROELECTRIC PROJECT
Information Sheet
April, 1986
Location:
At the USBR Whiskeytown Dam on Clear Creek, in Shasta County,
California.
Status :
Construction 99% complete. Expected to be operational in 1986.
Physical:
Project Size . 65 Acres
Powerhouse Size 36 ' x 43 '
Number of Units One
Type of Turbine Horizontal Francis
Size of Generator 4 , 600 kVA
Head 239 '
Maximum Powerhouse Flow 195 cfs
Power Output :
Expected Operational Date June, 1986
Maximum Capacity 3.24 MW
Summer Dependable Capacity 0 . 8 MW
Average Annual Generation 8,200, 000 kWh
Average Annual Oil Savings 15, 000 Barrels
Costs : (1985 Dollars)
Development Costs (to date) $ 250 , 000
Civil and Mechanical 3 , 760,000
Environmental Mitigation -0-
Total Capital Cost, 1983 $
(Does Not Include Financing Costs) $4,010 , 000
Approximate 1st-Year Cost (Mills/kWh)
(Includes Financing Costs) 66
Miscellaneous:
(1) Cost estimates based on staff estimates after review of
expenditures through April, 1986 .
607-220 Appendix A
I - A
1111
SAN JUAN PROJECT
Information Sheets
April, 1986
The M-S-R Public Power Agency (M-S-R) purchased an option on
28 . 8% of San Juan Unit No. 4 which represents approximately 136
MW of the 472 MW net Unit No. 4 generation. The City has a 15%
share of the 136 MW which is equal to about 20. 4 MW. The San
Juan arrangements are fairly complex and provide for a number of
services and benefits.
M-S-R and the Tucson Electric Power Company (TEP) have entered
into an Interconnection Agreement which provides the terms of the
sale of energy by TEP to M-S-R as follows:
M-S-R.
Annual Redding' s
Calendar Energy Share
Year (GWH) (GWH)
1983 400 60
1984 500 75
1985 600 80
1986-1994 800 120
1995 267 40 '
The Interconnection Agreement permits M-S-R to defer and carry
over to later years the delivery of energy due to transmission
constraints . At the end of 1985 , M-S-R had a carry forward
balance of 442 . 8 GWH. M-S-R' s cost of this energy will be at a
rate equal to three mills per kWh plus the sum of TEPls actual
weighted average cost per kWh for its coal-fired generating
plants.
Only interruptible transmission will be available to M-S-R prior
to the early 1990 ' s . The interruptible nature of the trans-
mission arrangements in the early years should prove sufficient
to allow M-S-R to utilize the Project since M-S-R is only pur-
chasing energy from TEP in the first few years of the Project.
The Agreement also provides for the exchange of M-S-R capacity
and energy at the San Juan Generating Station for TEP capacity
and energy at the Arizona Nuclear Power Plant Switchyard or the
Westwing Switchyard.
607-220 Appendix A
I -- B. 1
1111
M-S-R and PNM executed an Early Purchase and Participation
Agreement (EPPA) on September 26, 1983. The terms of the
agreement provided for the transfer of the 28 . 8% Ownership
Interest in San Juan Unit No. 4. The transfer was completed on
December 31, 1983. The Agreement also provides for! the sale of
approximately 74% (100 MW) of M-S-R' s capacity and lgassociated
energy from San Juan Unit No. 4 during the period beginning with
the transfer of the Ownership Interest through April 30 , 1995
unless partially terminated by M-S-R.
If M-S-R elects not to use or sell to others, approximately 36 MW
share of San Juan Unit No. 4 until 1995, the Public Service
Company of New Mexico (PNM) will market the 36 MW for M-S-R.
607-220 Appendix A
I - B. 2
41! 1111
PROPOSED LAKE REDDING HYDROELECTRIC PROJECT
Information Sheet
April, 1986
Location:
On the Sacramento River in the City of Redding, Shasta County,
California.
Status:
FERC Application for License filed in February, 1982. An EIR
and EIS are currently being prepared. The EIR is scheduled for
completion by December, 1986 . The EIS is scheduled for
completion in mid-1987 .
Physical:
Project Size 34 Acres
Powerhouse Size 145 ' x 131 '
Number of Units Three
Type of Turbines Bulb
Size of Generators 5 ,000 kVA
Head 14 . 5 '
Maximum Powerhouse Flow 15 , 000 cfs
Power Output:
Expected Operational Date Summer, 1991
Maximum Capacity 15 MW
Summer Dependable Capacity 8 MW
Average Annual Generation 92, 000 , 000 kWh
Average Annual Oil Savings 167 , 000 Barrels
Costs : (1986 Dollars)
Permit Process (to date) $ 615 , 000
Civil and Mechanical 61 , 800, 000
Environmental Mitigation 20 , 000, 000
Total Capital Cost (does not
include financing costs) $82 , 415, 000
Approximate 1st-Year Cost (Mills/kWh) 130
Miscellaneous :
(1) Project ' s power production curve closely follows City' s load
curve.
(2) Cost estimates provided in a 1986 report from CH2M! H.ill.
607-220 Appendix A
II - A
PROPOSED LAKE RED BLUFF HYDROELECTRIC PROJECT
Information Sheet
April, 1986
Location:
At the existing Red Bluff Diversion Dam on the Sacramento River,
in Tehama County, California.
Status :
FERC is considering a request by the Department of Interior to
delay Application for License processing until 1988 in order that
DOI may complete its ongoing studies.
Physical :
Project Size 40 Acres
Powerhouse Size 70 ' x 1501
Number of Units Two
Type of Turbine Kaplan Bulb
Size of Generators 4, 000 kVA
Head 11 '
Maximum Powerhouse Flow 9 , 000 cfs
Power Output:
Expected Operational Date 1992
Maximum Capacity 8 MW
Summer Dependable Capacity 4 MW
Average Annual Generation 47, 400, 000 kWh
Average Annual Oil Savings 86, 000 Barrels
Costs : (1987 Dollars)
Permit Process (to date) $ 450, 000
Civil and Mechanical 28 , 850, 000
Environmental Mitigation 7 , 000, 000
Total Capital Cost $36, 300 , 000
Approximate 1st-Year Cost (Mills/kWh) 98
Miscellaneous :
(1) Project ' s power production curve closely follows City' s
load curve.
(2) Cost estimates provided in a 1983 report from Sverdrup
& Parcel .
607-220 Appendix A
II - B
1111
PROPOSED SPRING CREEK PUMPED STORAGE PROJECT
Information Sheet
April, 1986
Location:
On Spring Creek, west of Keswick Reservoir, Shasta County,
California. •
Status :
The Preliminary Permit filed on September 9 , 1985 is in competi-
tion with Iron Mountain Mines proposed project.
Physical:
Project Size N/A*
Powerhouse Size N/A*
Number of Units Two or more
Type of Turbine N/A
Size of Generators N/A
Head 1 , 100 '
Maximum Powerhouse Flow 300 to 2 , 700 cfs
Power Output:
Expected Operational Date 1993
Maximum Capacity 100 - 500 MW
Summer Dependable Capacity 100 - 500 MW
Average Annual Generation N/A
Average Annual Oil Savings N/A
Costs : (1986 Dollars)
Permit Process (to date) $ 118 , 000
Total cost for Permit Process (est. ) 1 ,000 , 000
Civil and Mechanical 100, 000 , 000
to
530 ,000, 000
Total Capital Cost $ N/A
Approximate Cost ($/kW) 1 ,000 to:
2,300
Miscellaneous:
(1) Cost provided in 1985 report prepared by Black & Veatch.
* N/A - Not available at this time.
607-220 Appendix A
III - A
•
Oir •
PROPOSED CAMAGE CO-GENERATION PROJECT
Information Sheet
April, 1986
Location:
South of Redding, Shasta County, California, at old Champion
Lumbermill site.
Status:
Negotiation and feasibility analysis ongoing.
Physical :
Project Size N/A* ,
Powerhouse Size N/A*
Number of Units Two
Size of Boilers 20 MW each
Size of Turbine Generator 25 MW each
Power Output:
Expected Operational Date 1988
Maximum Capacity 37 . 5 MW
Summer Dependable Capacity 20 MW
Average Annual Generation 205, 000,000 kWh
Average Annual Oil Savings 380 , 000 Barrels
Costs : (1985 Dollars)
Permit Process (to date) $ 7 , 300
Total Cost for Permit Process (est. ) 600 000
Civil & Mechanical 62, 000 000
62, 607;300
Approximate 1st-Year Cost (Mills/kWh) 70
Miscellaneous :
* N/A - Not available at this time.
607-220 Appendix A
III - B
1111
•
IV. POTENTIAL PROJECTS
1 . Cottonwood Creek Hydroelectric Project
The original two-dam proposal for the Cottonwood Dam Project
was replaced in early 1984 with a four-dam proposal. Although
the City was successful in obtaining a preliminary permit for
electrical generation on one of the dams, actual construction
of one dam is too speculative at this time to ilnclude the
project in this 1986 Plan.
2. Municipal Solid Waste
The City is investigating the combustion of municipal solid
waste for production of energy rather than usin!g local
landfills.
3. Methane Gas (Landfills)
Existing landfill locations around the City may have the
potential for methane gas which could be used to generate
power.
4 . Methane Gas (Airport)
Methane gas deposits have been identified at the City' s
Airport. Development of this resource will be subject to the
same general considerations that will be used to evaluate
combustion turbine projects .
5 . Cogeneration with Interruptible Service
Some major commercial/industrial -customers within the City' s
sphere of influence may have the potential of ultilizing
cogeneration to yield steam and also generate elaectricity.
Other City customers may be able to interrupt City power
deliveries during peak load periods . Further iinvestigation
and negotiations with these customers will be undertaken by
the City.
6 . Renewable Resource Allocation
The City holds a 4 . 0 MW "alternate" allocation from Western
for renewable resource and cogeneration projects. In 1984 ,
the City may be able to receive a firm CVP allocation for one
of its renewable resource hydroelectric project's. The amount
of allocation, if any, is unknown at this time.
607-220 Appendix A
IV - 1
1111
IV. TRANSMISSION PROJECTS UNDER REVIEW
The projects listed below are major transmission projects which
could provide the City with opportunities for power purchases .
Those listed are now undergoing various degrees of technical
investigation. It is not expected that all of the projects listed
will be constructed. The projects which will finally be
constructed will depend upon many complex and interrelated
economic, technical, political, and environmental factors.
1 . California-Oregon Transmission Project (COTP)
Total Capacity/ (Available to City) : 1500 MW/ ± (41 . 5 MW)
Project Cost (1983 $) : $447, 000,000 to $678 , 000, 000
Date of completion: 1991
Location: From a point near Malin, Oregon to Tracy,
California.
Comments : Line would open up additional purchases with
the Pacific Northwest. Joint feasibility studies
underway between California utilities and Pacific
Northwest. More than one set of studies are in
progress.
2. Multi-utility Trans-Sierra Line
Total Capacity/ (Available to City) :
1600 MW/ (Undetermined)
Project Cost (1983 $) : Undetermined
Date of Completion: Undetermined
Location: Trans-Sierra Line north of Lake Tahoe and
south of the Oregon border. Eastern terminal points
- Possibly, Garrison, Montana, or, the Thousand
Springs Project in Nevada, and the western terminal
point is the 500 kV system in the Sacramento Valley.
Comments : Project would be joint utility owned and
would open up resource areas in the Northwest, Utah,
Wyoming, Idaho, Montana, and Nevada. Preliminary
electrical studies complete, corridor studies
underway by PGandE, Sierra Pacific Power Company,
and Idaho Power.
3 . Western System Upgrade - (345 kV/500 kV)
Total Capacity/ (Available to City) : Undetermined
Project Cost (1983 $) : Undefined
Date of Completion: Undetermined
Location: Various Western 230 kV transmission lines in
Northern and Central California.
Comments: Project could lead to the third Pacific
Intertie. Project could lead to additional Pacific
Northwest purchases . Joint preliminary feasibility
studies are underway with Western and the Northwest
Transmission Joint Venture.
607-220 Appendix A
V - 1
1111
4. Mead-Phoenix Direct Current Project
Total Capacity/ (Available to City) : 1600 MW/ (15 MW)
Project Cost (1983 $) / (cost to City) : $500 ,0001000/ ($470, 000)
Date of Completion: 1988
Location: Between Phoenix, Arizona, and Southern Nevada
Comments : The City is a participant via its
participation in M-S-R. The City would be entitled
to use 15% of M-S-R' s capacity share in the project.
5. McCullough-Victorville Project
Total Capacity/ (Available) : Undefined*/ (15 MW)
Project Cost: Undetermined
Date of Completion: Late 1980 ' s
Location: Between Southern Nevada and the Los Angeles
Metropolitan Area.
Comments: Capacity associated with the Mead-Phoenix
Direct Current Project cannot be fully utilized
unless transmission additions are mad between
Nevada and Southern California. The California
participants in the Mead-Phoenix Project will,
therefore, be required to pursue the development of
the McCullough-Victorville Project or an alternate
project.
*Engineering Studies required to determine the rating of this
proposed transmission line transmission line are not complete.
Preliminary costs estimates will be available by the end of June,
1986 . Final cost estimates will be available by end of July, 1986 .
Rating may not be finally determined until after July, 1986 .
607-220 Appendix A
V - 2
1110
APPENDIX B
ACRONYM LIST
1986 POWER RESOURCE PLAN
ACID Anderson-Cottonwood Irrigation District
ACLM Air Conditioning Load Management (Program)
APPA American Public Power Association
BPA Bonneyville Power Administration
CCPA Central California Power Agency
CEC California Energy Commission
CFM Common Forecasting Methodology
CMUA California Municipal Utilites Association
COTP California-Oregon Transmission Project
CVP Central Valley Project
DWR Department of Water Resources
ECLM Energy Conservation/Load Management
FERC Federal Energy Regulatory Commission
IOU Investor-Owned Utility
KGRA Known Geothermal Resource Area
LADWP Los Angeles Department of Water & Power
LOLP Loss of Load Probability
MID Modesto Irrigation District
MSR Modesto-Santa Clara-Redding Power Agency
MSW Municipal Solid Waste
NCPA Northern California Power Agency
PG&E Pacific Gas and Electric Company
PURPA Public Utility Regulatory Policy Act
PUC Public Utilities Commission
RCS Residential Conservation Service
SCE Southern California Edison Company
SDGE San Diego Gas and Electric Company
SMUD Sacramento Municipal Utility District
SPLM Swimming Pool Load Management (Program)
STEP Shave the Energy Peak (Program)
TANC Transmission Agency of Northern California
USBR U.S. Bureau of Reclamation
WAPA Western Area Power Administration
607-220 Appendix B
Page 1 of 1