HomeMy WebLinkAboutReso. 1989-232 - Adopting the city of redding electric utility 1988 - t
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RESOLUTION
A RESOLUTION OF THE CITY COUNCIL OF THE CITY OF REDDING
ADOPTING THE CITY OF REDDING ELECTRIC UTILITY 1988 RESOURCE
PLAN.
li WHEREAS , the City Council of the City of Redding has
considered the Electric Utility 1988 Resource Plan of the City of
Redding, 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 City of Redding Electric Utility 1988
Resource Plan;
NOW, THEREFORE, IT IS HEREBY RESOLVED that the City Council
of the City of Redding hereby adopts the attached Plan as the
City of Redding Electric Utility 1988 Resource Plan.
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 5th day of July, 1989 , and was duly
adopted at said meeting by the following vote:
AYES: COUNCIL MEMBERS: Buffum, Dahl , Fulton, Johannessen, & Carter
NOES: COUNCIL MEMBERS: None
ABSENT: COUNCIL MEMBERS : None
ABSTAIN: COUNCIL MEMBERS: None
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SCOTT CARTER, Mayor
City of Redding
ATTEST: ORM-f'PROVED:
ETHEL A. NICHOLS, City Clerk RAWDALL A. HAYS , City , ttorney
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CITY OF REDDING
Electric Utility
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1988 RESOURCE PLAN
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June , 1989
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TABLE OF CONTENTS
SECTION PAGE
I. EXECUTIVE SUMMARY 1
A. Introduction and Purpose 1
B. Resource Plan Development 3
C. Recommendations 3
II. PLANNING GOALS 5
III . CHANGES IN CONDITIONS AND EVENTS SINCE THE
1986 RESOURCE PLAN 7
A. Load Forecast Changes 7
B. Rate Changes 8
C. Regulatory and Legislative Changes 8
D. Price of Supplemental Resources 9
E. Natural Gas Industry Changes 9
F. Contractual Changes 9
G. Deferred or Abandoned Projects 9
H. Availability of Wood Waste Fuel 10
IV. FORECAST OF ELECTRIC POWER NEEDS 11
A. Forecasting Methodology 11
B. Energy Conservation and Load Management 15
C. Other Power Considerations 18
D. Adopted Forecast 18
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TABLE OF CONTENTS
SECTION (Continued) PAGE
V. RESOURCE CONSIDERATIONS 31
A. Economics 31 hi
B. Autonomy 34
C. Types of Resources 34
D. Transmission 38
E. Reserve Requirements 38
VI. RECOMMENDED POWER RESOURCE DEVELOPMENT PLAN 41
A. Avoid High-cost Supplemental Power Purchases 41
II B. Pursue Arrangements to Shape Loads and Resources42
C. Pursue Development of Spring Creek Pumped
Storage Project 42
li D Pursue Economic Hydroelectric Projects 43
II E. Pursue Development Negotiations with Independent
Power Producers (IPP) 43
F. Pursue Transmission Rights 43
G. Enhance Relationships with Western 43
H. Pursue Other Interutility Contracts 44
I . Pursue Conservation and Load Management
Programs 44
J. Selectively Participate in Baseload Projects 44
VII. APPENDICES 47
A. Resource and Transmission Projects Recommended
for Continued Investigation or Operations 48
B. Definitions 59
C. Acronyms 73
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TABLE OF CONTENTS
(Continued)
TABLES PAGE
1 - Parameter Projections 1987-2007 20
2 - Coincident Peak Demand for Electricity by
Customer Class 21
3 - Electrical Energy Use by Customer Class 22
4 - Historic and Projected Parameter Growth Rates 23
5 - Estimated Effects of Conservation & Load
Management Programs 24
6 - Monthly Peak Demand 25
7 - Monthly Energy Requirements 26
8 - Total City Peak Demand Needs 27
9 - Total City Electrical Energy Needs 28
10 - Recommended Plan 45/46
FIGURES
1 - Growth of Redding by Annexation 19
2 - Coincident Peak Demand 29
3 - Electric Energy Need 30
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i 1
CITY OF REDDING
Electric Utility
1988 RESOURCE PLAN
I . EXECUTIVE SUMMARY
A. Introduction and Purpose
Historically, the City of Redding (City) has relied upon
wholesale purchases from other utilities to meet its
power requirements . However, during the early 1970s , it
became evident that continued reliance upon other
utilities could not ensure the availability of reliable
,I! and low-cost power to meet the City' s future long-term
electrical demands . Therefore, in 1976 , the City began
to develop a broad-based program to provide the oppor-
tunity for the City to exercise some control of the cost
and availability of its long-term electrical needs. The
program includes suitable City-owned generating re-
sources , participation in joint powers agency resources ,
and power purchases . Essentially, in 1976 , the City
initiated a program to develop sufficient power
resources to meet the future power requirements 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 Redding City
Council and is updated and resubmitted to the Council
for approval biennially.
The need for developing a resource plan which contains a
well balanced mix of power resources has been clearly
substantiated in recent years. During the five-year
period beginning in 1982 , the cost of power purchased by
the City from its major supplier, the Western Area Power
Administration (Western) , escalated over 300% . In
addition, in 1984 , the City' s electric load exceeded
Western' s contractual limit and required the City to
purchase more expensive supplemental power from PG&E
during one month, at a total cost of $64 , 000 . By 1988 ,
the City' s electric load had grown to 154MW, requiring
the purchase of supplemental power from PG&E during four
months , at a total cost of $3 , 100 , 000 . The cost for
purchased supplemental power is expected to continue to
grow rapidly unless the City develops other lower cost
sources of power.
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If the rate of growth for the Citv' s electrical demand
continues at the same rate as experienced over the past
ten years , the City could expect its load to double
every nine years . The forecast included in this plan,
however, projects a reduction, not an increase , in the
rate of growth. The projected reduction in growth rate
is primarily due to the reduction in the volume of
developed property which will become available for
annexation over time . The forecast for the 1988
Resource Plan (1988 Plan) projects the City' s peak load
to grow by approximately 53% during the next nine years .
The 1988 Plan updates the Planning Goals , Forecast of
Electric Power Needs , Preliminary Assessment of
Resources , and Resource Planning included in the 1986
Resource 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 resource
plan to meet those needs are included in this update of
the 1986 Plan.
The 1988 Plan includes assumptions and data which are
current as of November 1988 . The 1988 Plan should not
be interpreted to represent a commitment by the City to
a specific course of action. Rather, the purpose of the
1988 Plan is to serve as an aid to the process of
decision making for individual projects. Decisions will
be influenced by future conditions which may not neces-
sarily match the assumptions used to prepare this 1988
Plan.
In evaluating the potential for developing new generat-
ing resources , the Electric Department staff compares
the economics of such resources to the City' s incremen-
tal cost for acquiring additional power. Currently, the
incremental cost of power is governed by the cost of
power supplied by the Pacific Gas and Electric Company
(PG&E) through a supplemental power purchase contract.
Before a commitment to a specific project is made,
detailed analyses which incorporate the most recent data
available are conducted for the project to consider the
benefits , costs , risks , need, timing, acceptability, and
environmental and financial impacts . These analyses are
repeated, as appropriate, 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 possible termination
of a project. The City' s Electric Utility Commission
reviews the analyses and forwards recommendations to the
City Council. The Redding City Council by specific
action and the City' s voters (who own the electric
system) ultimately, through referendum, decide upon the
projects selected for implementation.
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B. Resource Plan Development
The 1988 Plan (Section IV) provides a probable twenty-
year assessment of the City' s future need for power to
meet projected customer growth. The power need assess-
ment was conducted as suggested by the California Energy
Commission (CEC) in its forecasting guidelines known as
the Common Forecasting Methodology (CFM) . Through use
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of the CEC guidelines , the assessment considered several
parameters which influence the future need for power.
Section V discusses the merits of several resource
development options which could be used to meet the
power requirements forecasted by the power need assess-
ment. Section VI discusses the recommended plan as of
November 1988 , to meet the forecasted need.
The planning goals utilized as the primary criteria for
the 1986 Plan are listed in Section II.
C. Recommendations
If the City is successful in the development of several
resources alternatives , 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:
1 . The City should continue an aggressive and fore-
sighted power resource development program which
emphasizes the need to acquire long-term economical
sources of reliable power.
2 . The City should develop projects , inter-utility
agreements, or agreements with private developers
which provide support for City-owned generation
resources , and provide supplemental power require-
ments needed to meet City loads in excess of the
power received from Western and City resources .
3 . 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 Western power.
Such agreements would maximize 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.
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4 . 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 .
5 . The City should continue to work closely with
Western to ensure that it obtains an equitable share
of the United States Central Valley Project (CVP)
peaking capacity (if and when allocated) and to
protect its existing 116MW CVP allocation.
6 . 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.
7 . The City should continue to participate in power
pooling planning activities . Continued partici-
pation will ensure 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 1988 Plan, contains the projected energy and
capacity requirements and resources for the City, on an
annual basis , through fiscal year 2007 .
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II . PLANNING GOALS
II The City of Redding' s Electric Utility will support
Redding ' s continued economic growth and development by
providing the citizens of Redding with long-term, econom-
ical , efficient, reliable , and environmentally responsible
electric power.
A. Present and future power costs for the City' s customers
will be held as low as practicable
The long-term cost of electricity to the City' s custom-
ers is a primary consideration in the analysis of alter-
native power resources and programs . The ultimate test
of any resource plan is the ability to provide econom-
ical power resources to the City' s customers.
B. Reliability and service levels will be maintained and
improved whenever possible
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Dependable p e and safe electrical service must continue to
be provided to the City' s customers .
C. Local control and independence will be retained
Local control ensures that the City' s power system is
responsive to customer needs. Independence allows the
City more freedom in buying and selling power from
various power projects and various utilities . This
freedom will allow the City the flexibility to acquire
the least costly power.
D. Development of economic , local power resources is
Ij preferred
Whenever the costs are reasonably competitive , the
development of power projects which benefit the local
economy will be preferred over equivalent, but geo-
graphically distant projects . Sources of competitively
priced power will be sought from generation which is
ancillary to the primary business of a local firm --
typically, power produced from waste heat.
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 environ-
ment.
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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 locations , fuels , or technologies . Diversity
can reduce future risks to the City from interruption of
power production from one location, fuel, or technology.
G. Promote and develop load management and conservation
programs
Load management will provide a means of reducing crit-
ical peak load growth and will better utilize the City' s
power resources. Conservation programs will inform
customers of ways to efficiently utilize electricity and
will thus reduce the demand on the electrical system.
H. Promote a healthy local economy
Reasonably priced, reliable , electrical power is attrac-
tive to business. Jobs created by the availability of
reasonably priced, reliable, electrical power will
benefit the local economy.
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III . CHANGES IN CONDITIONS AND EVENTS SINCE THE 1986 RESOURCE PLAN
The City of Redding Electric Utility operates in a complex,
changing environment. This strategic resource plan consid-
ers numerous factors which may play a role in shaping City
policy regarding its electric utility. Most of these
factors are constantly changing. This section presents some
of the major changes which have occurred since adoption of
the 1986 Resource Plan. Examples are:
O Load forecast changes
O Rate changes
O Regulatory and legislative changes
0 Price of supplemental resources
O Natural gas industry changes
O Contractual changes
O Deferred or abandoned projects
O Availability of wood waste fuel
A. Load Forecast Changes
In 1987 , the City submitted its second biennial Common
Forecasting Methodology (CFM) filing with the California
Energy Commission (CEC) . Two forecasting methodologies
were used to prepare the City' s 1987 CFM filing. Data
was collected from a residential end-use survey and in-
corporated into an end-use model, wherein electric
energy consumption was forecasted based upon appliance
saturation rates and energy consumption values compiled
SII by the CEC. The end-use model results were found to be
consistent with the results of the second methodology,
the econometric forecast.
The econometric forecasting methodology, which was also
used to prepare the 1986 Resource Plan, involves the
preparation of a computer model based on historical
data. The econometric model develops a relationship
between several economic variables and the associated
load growth. The projected values of the economic
variables used to develop the load forecast in the 1986
Resource Plan were updated to prepare the load forecast
for the 1988 Resource Plan. Changes included a re-
duction
in the rate of growth for the prices of elec-
tricity and natural gas and a slight decrease in in-
flation rates.
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The Redding area continues to see high commercial and
residential development. This development, combined
with additional electrical load growth from annexations ,
has caused peak demand to grow by 13 . 8% , and energy con-
sumption to grow by 8 . 3% in 1987 . In 1988 , the CEC
adopted a forecast of Redding' s load growth with rates
averaging 4 . 9% for energy and 4 . 7% for demand for the
period 1987-1995 , with a slight decline in growth rates
thereafter. Redding' s estimated growth continues to
exceed expected state-wide averages .
The expected monthly load for the Redding Electric
Utility over the next 20 years can be found in Section
IV of this Plan. The load forecasts for the 1988
Resource Plan are slightly higher for the near term than
were the load forecasts adopted for those same years for
the 1986 Resource Plan. In later years , both forecasts
are virtually identical.
B. Rate Changes
In September, 1986 , City electric rates increased 10 . 3% .
In September, 1987 , rates were increased 7 . 2% . Those
increases represented the final steps in absorbing a
five-year, 300% wholesale rate increase imposed by West-
ern. The magnitude of those increases in Redding ' s
retail rates are expected to slightly decrease the rate
of growth in consumption of electricity in the City.
Also since 1986 , expenses for supplemental power pur-
chases from PG&E increased substantially, by 55% , due
primarily to higher summer peak purchases . In May 1988 ,
Western established new rates through 1993 . The new
rates initially reduced Western' s power rates to the
City by approximately 10% ; however, the rates will
gradually increase over the next five years .
C. Regulatory and Legislative Changes
The CEC has exclusive siting jurisdiction over all
thermal plants and related facilities located in the
State of California having a rated capacity of 50MW or
greater. The CEC is attempting to lower the 50MW output
qualification. Such a move could bring all thermal
resource options the City is considering under CEC
jurisdiction.
In 1987 , FERC approved a 21 . 8% demand-charge reduction
in PG&E ' s wholesale rates to the City. The key factor
in that reduction was the Tax Reform Act of 1986 .
However, in December 1988 , the CPUC approved PG&E' s
request for a retail rate increase designed to incorpo-
rate the capital cost of the Diablo Nuclear Power Plant.
It is likely that the CPUC decision will cause a FERC
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wholesale rate review in 1990 , which will result in a
70% - 90% increase in demand charges from PG&E.
D. Price of Supplemental Resources
Since the 1986 Resource Plan, the City' s forecasts for
capacity and energy charges for PG&E supplemental power
have been reduced by an averaae of 19% and 15% , respec-
tively. The primary reasons for the reductions are
j; downward revisions in anticipated prices for natural gas
dpi and oil, inflation rates , and rate increases associated
,II with the effects of adding the Diablo Nuclear Power
Project into the energy rate base. However, as stated
above , demand rates are expected to increase if the
Diablo Nuclear Power Project is added to the demand rate
base.
These changes are significant since the primary test of
cost effectiveness for any resource option is to compare
11' its cost with the alternative cost of PG&E supplemental
purchases .
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E. Natural Gas Industry Changes
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Several recent regulatory and market events have in-
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I� creased the availability and reduced the price of
natural gas. These events have thus increased the
viability of natural gas-fired turbine generators as an
alternative to purchases from PG&E.
F. Contractual Changes
1I; In August 1988 , a contract between Western and the City
fl of Redding was executed, providing for transmission ser-
vice from Western to the City. The contract specifies
11' the terms and conditions for the City to receive power
from locations which are remote from the City.
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II G. Deferred or Abandoned Projects
In 1987 , Sierra Pacific Industries terminated nego-
tiations on the CAMAGE Cogeneration Project. Therefore,
II the CAMAGE Project is not included in the 1988 Resource
Plan. However, several other Independent Power Produc-
ers (IPPs) are negotiating actively with the City. New
contracts with IPPs are expected to replace the power
which would have been available from CAMAGE.
The projected operational dates of several general proj-
ects
which were included in the 1986 Resource Plan have
been delayed one to three years in the 1988 Resource
Plan as a result of a number of regulatory and economic
I influences . The revised operational dates are provided
in Section VI of this plan. I
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H. Availability of Wood Waste Fuel
During preparation of the 1986 Resource Plan, fuel gen-
erated by waste from the lumber industry was relatively
abundant. However, several cogeneration projects have
since become operational which, have severely curtailed
the availability of wood fuel, and has caused the price
of wood fuel to rise.
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IV. FORECAST OF ELECTRIC POWER NEEDS
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The forecast of future electric power needs of the City is a
cornerstone of the 1988 Plan. The forecast defines the need
for additional City power resources , the potential for
conservation savings , and, to some degree , the level of
future City rates for electricity. This section describes
the development of the City' s forecast of peak demand in
megawatts (MW) and the total City energy requirements in
gigawatthours (GWH) for the planning period of City fiscal
years 1988-2007 .
A. Forecasting Methodology
1 . Energy
Historic energy consumption by customer class was
compiled on a monthly basis for the approximate
ten-year period of January 1977 through June 1987 .
ji Residential and commercial class customers have
historically been responsible for about 90% of
Redding' 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 comput-
er model, using several of the parameters , was then
developed to forecast energy usage for the residen-
t ! tial and commercial classes.
Energy projections for other customer classes
including industrial, agricultural, and govern-
mental, were based on the historic load growth of
each class as compared to the residential class .
Several parameters which may affect load growth were
tested to determine their effects on the City' s
historical load growth between the ten-year period
January 1977 and January 1987 . Regression analysis
was used to determine the relationship, if any, of
the tested parameters to the amount of energy sold.
The following parameters were found to have a
significant statistical effect, and were, therefore,
used in the computer model to project energy con-
sumption through 2007 .
(a) Number of Electric Customers :
As expected, this parameter significantly
determines the amount of energy needed by the
1 City.
Historically, the number of Electric Utility
customers does not match the ratio of the
Redding population divided by the average number
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of persons per household. This anomaly is due
to the fact that once an area has been annexed
into the City, several years may pass before all
of the customers are transferred over to the
City ' s Electric Utility. This time lag is
primarily due to the protracted negotiations and
legal actions required to acquire PG&E facil-
ities .
(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 in-
crease in electricity consumption. Shasta
County income per capita was used to establish
the historic relationships . Future growth is
estimated to be improved significantly from that
represented in the historic period due to the
projected evolution of the local economy toward
the manufacturing and services sectors .
(c) Heating and Cooling Degree Days :
These parameters were used to account for
electric usage associated with space heating and
cooling. Heating and cooling degree days are a
measure of space heating or cooling require-
ments . The greater the value of heating and
cooling degree days , the greater will be the
electric requirements for space heating and
cooling.
(d) The Price of Electricity:
Customer decisions to use electricity are
determined partly on the basis of the average
price of electricity. The historic, real
average price of electricity to City electric
customers was approximated using total custom-
er-class revenues divided by total custom-
er-class kilowatt-hour sales and was adjusted by
the Consumer Price Index to constant 1985 dol-
lars.
(e) Annexations:
Annexations by the City of Redding have played
an important role in load growth of the City' s
electric system over the historic period (see
Figure 1) . Some areas have been annexed but
have not yet received electric service from the
City. The areas within the Redding city limits
which have not yet received electric service
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represent future increases in load. These
increases have been explicitly considered in
developing the load forecast by adjusting the
forecast number of customers within the
commercial and residential classes , by the
li estimated number of customers associated with
each annexation. The effect of minor future
annexations was included in the number of
customers projection. Major future annexations
II were not included in the base forecast of future
need but were accounted for explicitly by their
addition to projected levels .
The other parameters tested did not have any
apparent statistical effect on energy usage. The
other parameters tested were: price of natural gas,
level of employment, and daylight hours .
Table 1 presents projections for the period
1987-2007 of the parameters used to forecast future
electricpower needs . Heating/cooling degree days
projections were essential for explaining the
historical test period. However, in the forecast,
due to the unpredicable nature of the weather, 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 for the period 1978-1986 . As the
City' s system expands and diversity increases , and
with the consideration of 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 con-
ditions , the Redding system annual load factor was
assumed to improve steadily from 45 . 4% in 1987 to
ti 51 . 3% by the year 2007 .
3 . Forecast of Customer Needs
II Table 2 lists historical and projected electrical
demand by customer class. Table 3 lists historical
and projected electrical energy use by customer
class . The effects of existing energy conservation
and load management programs are included in
Tables 2 and 3 .
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4 . Plausibility
The plausibility of the forecast is dependent
primarily on the validity of the projections of the
model parameters . Historic and projected growth
rates for each of these parameters are shown in
Table 4 .
While there are significant differences in the
growth rates of the historic and the projected
parameter values , such differences are explained as
follows .
a) Price of electricity:
The historic and ongoing increases in the price
of electricity are caused primarily by two
factors. First, the cost of power purchases
from Western has increased by 300% during the
1983-1986 time period. Second, in 1984 , the
City began to purchase high-priced supplemental
power from PG&E.
The rate of growth for the real price of elec-
tricity is expected to decrease since future
dramatic rate increases from Western are not
expected, and since the City is actively pursu-
ing more economical resources for supplemental
power than purchases from PG&E.
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 was based predominant-
ly on the lumber industry. The lower historic
growth in personal income is directly attribut-
able to the protracted depression of the lumber
industry during the late 1970s and early 1980s.
Recent trends in local economic growth have
shifted to the service and manufacturing sec-
tors, providing a more stable base for future
growth. Economic growth is expected to be
supported further by present and anticipated
stable energy prices .
c) Number of customers:
The number of City Electric Utility customers
grew at a compound annual rate of 10 . 9% during
the period 1977-1985 , while the population of
Redding grew at a compound annual rate of 3 . 2%
over the same perjod. These high growth rates
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were due largely to the effects of several
annexations during the period 1977-1983 . Over
1� the longer term of the forecast period ( from
1987 to 2007) , the effects of annexation,
natural increases and net in-migration are
projected to result in a compound annual popu-
lation growth rate of 3 . 2% , with a similar pro-
jected rate of growth in residential and commer-
cial customers.
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B. Energy Conservation and Load Management
, Forecasts of the City' s future need for electricity are
dependent upon the effectiveness of conservation and
load management programs . Many State and Federally
mandated programs currently affect the amount of elec-
trical energy consumed by City customers . These
programs include new building and appliance efficiency
standards , tax credits , etc . Conservation effects from
such programs are partially considered in the historical
regression analyses , since some energy savings have
already occurred due to these programs . Several conser-
vation and load management programs recently established
by the City are in various stages of development and are
°' expected to expand as described below. Table 5 lists
ll' each of the programs , with estimates of the impact of
II existing and future programs . In order to show the
effects of not developing the proposed conservation and
load management programs in the final forecast of power
needs , the capacity and energy expected to be saved by
Ii these programs were added to the forecasted customer-use
projections .
The conservation and load management programs considered
were:
' 1 . Air Conditioning Load Management (ACLM)
The ACLM program is designed to reduce peak elec-
trical capacity during summer months. The program
requires the installation of radio-activated control
switches on customer air conditioning units, thus '
allowing the City to selectively cycle the air
conditioners from a central location.
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In 1984 , load control switches were installed on all
till eligible City-owned air conditioning equipment. An ,I,
ACLM program for commercial customers was started in
��' April 1985 . It is estimated that each commercial
ACLM switch will control about 6 tons of air condi-
tioning, which is approximately equal to 6kW of
electrical capacity reduction.
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A total of 276 load control switches , controlling
1 , 870 tons of cooling, have been installed. The
total load reduction, using a cycling strategy of 10
minutes every half hour, is approximately 623kW.
Under emergency conditions, the load reduction is
estimated at 1 , 870kW.
2. Swimming Pool Load Management (SPLM)
The SPLM Program initiated in 1980 provides a
reduction of peak demand by shifting the operation
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 .
The Residential Energy Survey completed in the
second quarter of 1987 , revealed that approximately
11% of residential customers (i.e. , about 2 , 450
customers) have some type (above or below ground) of
swimming pool. The Residential Energy Survey also
revealed that about 13% of residential customers who
have swimming pools operate their pool filters be-
tween the hours of 2 : 30 p.m. and 6 : 30 p.m. on hot
summer weekdays. Thus , only about 313 customers
with pools were not participating in the program at
the time of the survey. It was assumed that each
pool uses a 1 . 5 horsepower pump system. From these
approximations , the SPLM load reduction was es-
timated to have been 2 . 5MW in 1987 , and is projected
to be 4 . 0MW by 2007.
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 standby generators.
This program is put into effect only at such times
as the electrical system is approaching peak load
conditions . Customers are notified of the need to
reduce their use of electricity by telephone and by
radio and television announcements. In 1987 , this
program reduced peak demand by an estimated 3 . 2MW,
and is projected to reduce peak demand by 3 . 7MW in
2007 .
As a supplement to the LCLM program, an extensive
advertising campaign is conducted from May to
September to encourage the reduction of electrical
usage between 2 : 30 p.m. and 6 : 30 p.m. Radio adver-
tisements are broadcast daily on the four leading
local radio stations and a newspaper advertisement
is published once a week in the local newspaper.
614 : 002 . 20 -16-
1
•
1
4 . Appliance Efficiency and Building Standards
It is expected that mandatory Residential Building
and Appliance Standards implemented in 1978 will
continue to reduce the energy consumption of space
heating, air conditioning, water heating, refrigera-
tion, and other major appliances . Estimates devel-
,i oped from the Residential Energy Survey project
energy and load reduction impacts of 9 , 100MWH and
2 . 0MW by 1992 , and 29 , 100MWH and 7 . 0MW by the year
2007 .
5 . Other Conservation Activities
Residential customers are provided residential
energy audits and general conservation information
and materials. To further encourage the conserva-
tion of energy, recording meters are loaned to
customers to monitor the electrical usage of various
appliances.
Commercial customers are provided technical assis-
tance in evaluating a wide range of conservation
measures designed to encourage energy efficient
lighting, water heating, heating and air condi-
tioning, pumps and motors , pools and spas , res-
taurant operations, and other equipment and pro-
cesses.
6 . Street Light Conversion Program
The City has an ongoing program of installing energy
efficient, high-pressure sodium street lamps when
existing, less efficient, mercury vapor lamps need
replacement. It is estimated that this program
saved 1 ,000MWH in 1987 and will save 3 , 000MWH by
2007 .
7 . Interruptible Load
In 1984 , the City established a rate for inter-
ruptible service which provides a reduction in the
cost of power for eligible customers who volunteer
for the rate. This class of service requires that
customers reduce or eliminate consumption of power
during peak usage times at the City' s request. Al-
though there were no customers receiving electrical
service under the Interruptible Rate as of December
1987 , the Electric Department estimates that up to
12 .5MW of interruptible load will be available by
2007.
614 : 002 . 21 -17-
it
+! •
C. Other Power Considerations
1 . Losses
Losses account for electricity which is used to
energize the transmission and distribution system,
and for electricity that is used but not metered
(power theft) . The City' s 10-year historical energy
losses have averaged 7 . 5% . During the forecast
years an improving load factor was used in the 1988
Plan to account for efficiency improvements in the
City' s distribution system.
2 . Monthly Power Requirements
The monthly power requirements projections 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 power requirements projections of
total customer load plus losses for 1986-1987 for
capacity and energy are shown by Tables 6 & 7 , re-
spectively. These projections were based on com-
puter modeling of the City' s historic monthly power
usage, normalized to temperature.
D. Adopted Forecast
Tables 8 & 9 list the City ' s historical and anticipated
need for capacity and energy, respectively, from 1978 to
2007 . Figures 2 and 3 , respectively, illustrate the
forecast of the City' s total need for capacity and
energy. The compound annual growth in capacity for the
historical period 1978-1987 was 8 . 2% and is expected to
be 3 . 3% for the period 1988-2007 . The compound annual
growth in energy for the historical period 1978-1987 was
6 . 4% and is expected to be 4 . 6% for the period
1988-2007 . These growth rates are higher than the
growth rates discussed in Section III . Section III
discussed customer needs only, while this section
includes customer needs plus losses. As discussed in
Section V, the City' s need for capacity will be higher
than the demand forecast since the capacity needed to
meet demand will need to include reserve requirements .
614 : 002 . 22 -18-
1
I
•
. I
CITY OF REDDING
1988 POWER RESOURCE PLAN ':.
. •-''''
k
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GROWTH OF REDDING BY ANNEXATION
4. -d••*i'l
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ANNEXATIONS . '
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PRIOR TO 1949
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1
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•••••
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1980 TO PRESENT -19-
1-
11,
40 •
TABLE 1 -
CITY OF REDDING
1988 Resource Plan
Parameter Projections 1987-2007
1/ Real Personal 2/ Real Price 3/
Number of Income of Electricity
Year Customers Per Capita Residential Commercial
1987 26 , 299 12 , 022 4 . 27 5 . 05
1988 27 , 261 12 , 262 4 . 13 4 . 89
1989 28 ,223 12 ,507 3 . 99 4 . 71
1990 29 , 192 12 , 757 4 . 22 4 . 99
1991 30 ,068 13 , 013 4 . 04 4 . 78
1992 30 , 970 13 , 273 4 . 14 4 .90
1993 31 , 899 13 , 358 4 . 30 5 . 09
1994 32 , 856 13 , 809 4 . 26 5 . 04
1995 33 , 842 14 ,085 4 . 35 5 . 15
1996 34 , 857 14 , 367 4 . 44 5 .26
1997 35 , 903 14 , 654 4 . 21 4 . 98
1998 36 , 980 14 , 947 4 . 16 4 .93
1999 38 , 090 15 , 246 4 . 11 4 . 87
2000 39 , 232 15 , 551 3 . 90 4 . 62
2001 40 , 409 15 , 862 3 . 93 4 . 65
2002 41 , 621 16 , 180 3 . 82 4 . 51
2003 42 , 870 16 ,503 3 . 62 4 . 28
2004 44 , 155 16 , 833 3 . 68 4 . 35
2005 45 , 481 17 , 170 3 . 71 4 . 39
2006 46 , 845 17 , 513 3 . 52 4 . 17
2007 48 , 250 17 , 863 3 . 53 4 . 18
1/ Residential customer growth rates are based on City of
Redding, Department of Urban Planning, Planning and Progress
Guide: Budget Preparation Information for 1987-1988 . These
projections include growth attributable to expected future
annexations . Commercial customer growth is estimated at 3% .
2/ 1985 dollars .
3/ 1985 cents/kWh, projections recognize an intent to gradually
equalize the average costs of electricity for commercial and
residential customers.
614 : 002 . 24 -20-
TABLE 2
CITY OF REDDING
1988 Resource Plan
1
Fiscal Year
i Coincident Peak Demand for Electricity by Customer Class
(Megawatts)
i
Total*
IYearCustomer
Ending Residential Commercial Industrial Agricultural Governmental Demand 1/
I
1978 25 31 1 0.1 3 60
1979 32 35 2 0. 1 3 72
1980 47 43 2 0.1 4 96
l 1981 53 42 3 0. 1 4 102
1 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 64 53 3 0.1 4 125
1988 68 57 3 0.1 4 133
1 1989 74 60 3 0. 1 4 142
1990 72 60 5 0.1 6 144
, 1991 73 61 5 0. 1 6 145
li, 1992 73 62 5 0.2 6 147
1993 75 63 5 0.2 6 150
1994 77 66 5 0.2 6 155
1995 79 69 5 0.2 6 159
I 1996 82 73 5 0.2 6 166
1997 84 75 5 0.2 6 170
1998 88 79 5 0.2 7 179
1999 90 82 5 0.2 7 184
11 2000 93 86 5 0.2 7 191
2001 97 90 5 0.2 7 199
2002 99 93 5 0.2 7 204
t
1 2003 103 96 6 0.2 7 211
2004 106 100 6 0.2 7 219
2005 109 103 6 0.2 7 224
i 2006 111 106 6 0.2 7 230
2007 115 110 7 0.2 7 239
i
*Compound Annual Growth Rate: 1978-1987 = 8.5%
1988-2007 = 3.1%
j 1/ Totals may not add due to rounding.
614 : 002. 25
-21-
i
III •
TABLE 3
CITY OF REDDING
1988 Resource Plan -
Fiscal Year
Electrical Energy Use by Customer Class
(Gigawatthours)
Total*
Year Customer
Ending Residential Commercial Industrial Agricultural Governmental Use 1/
1978 111 134 9 0.2 13 267
1979 145 145 12 0.3 13 315
1980 196 174 17 0.4 15 402
1981 211 185 19 0.4 16 431
1982 221 190 17 0.4 15 443
1983 218 187 19 0.4 13 437
1984 213 190 17 0.4 15 435
1985 236 210 19 0.5 17 483
1986 236 211 19 0.5 17 484
1987 224 213 18 0.4 18 473
1988 242 227 20 0.5 16 506
1989 290 274 31 0.5 25 621
1990 288 275 38 0.5 31 632
1991 294 284 39 0.6 31 648
1992 300 293 39 0.6 31 664
1993 309 306 40 0.6 31 687
1994 319 321 41 0.6 31 713
1995 331 335 42 0.6 31 740
1996 341 349 44 0.6 32 767
1997 356 366 46 0.6 32 801
1998 372 384 48 0.7 33 837
1999 385 401 50 0.7 33 870
2000 402 421 52 0.7 34 909
2001 417 439 54 0.8 35 946
2002 433 458 56 0.8 35 983
2003 449 479 58 0.8 36 1022
2004 466 499 60 0.8 36 1062
2005 480 518 62 0.8 36 1098
2006 497 538 67 0.9 37 1140
2007 514 561 72 0.9 37 1185
*Compound Annual Growth Rate: 1978-1987 = 6.67
1988-2007 = 4.6%
1/ Totals may not add due to rounding.
614 : 002 . 26 -22-
�? 1
• •
TABLE 4
CITY OF REDDING
1988 Resource Plan
Historic and Projected Parameter Growth Rates
Projected
Annual Average Annual Average
Compound Growth Compound Growth
PARAMETER Rate 1977-1985 Rate 1985-2007
Real Residential Price of 4 . 8% -0 . 5%
Electricity
Real Commercial Price of 6 . 3% -0 . 5%
Electricity
Real Personal Income -0 . 5% 2 . 2%
Per Capita
Number of Customers 10 . 9% 3 . 2%
(' I
II
II
111
It;
it
II
614 : 002 . 27 -23-
II
e •
TABLE 5
CITY OF REDDING
1988 Resource Plan
Estimated Effects of Conservation & Load Management Programs
1985 1992 1999 2007
GWH MW GWH MW GWH MW GWH MW
PROGRAM 1/
Air Conditioning N 0 . 3 N 3 . 3 N 8 . 0 N 15 . 8
Load Management
Program (ACLM)
Swimming Pool N 2 . 2 N 2 . 8 N 3 . 3 N 4 . 0
Load Management
Program (SPLM)
Load Curtailment 0 . 1 3 . 1 0 . 2 3 . 3 0 . 2 3 . 5 0 . 2 3 . 7
Load Management2/
(LCLM) Program -
Efficiency 2 . 1 0 . 5 9 . 1 2 . 0 17 . 1 4 . 0 29. 1 7 . 0
Standards
Other Conserva- N N 0 . 6 0 . 3 1 . 7 0 . 5 2 . 4 0 . 6
tion Activity
Street Lights 0 . 8 N 1 . 8 N 2 . 9 N 3 . 0 N
Interruptible
Customers NN N 4 . 0 N 7 . 5 N 12. 5
Total: 3 . 0 6. 1 11 . 7 15 . 7 21 . 7 26 . 8 34 . 7 43 . 6
N = negligible
1/ Effects of existing and proposed load management and conservation
programs are combined.
2/ Includes STEP advertising campaign.
614 : 002 . 28 -24-
s •
TABLE 6
CITY OF REDDING
1
1988 Resource Plan
1
4
Projected i.
Monthly Peak Demands (MW) 1/
(Fiscal Years 1988-2003)
1
MONTH 1988 1989 1990 1991 1992 1993 1994 1995
i
JUL 145* 154* 157 159 161 165 170 175
1 AUG 144* 146* 152 154 156 160 165 170
j SEP 136* 147* 144 146 148 152 156 161
i' OCT 116* 108* 99 100 101 104 107 111
NOV 93* 95* 121 122 124 127 131 135
H DEC 114* 114* 130 132 133 137 141 146
JAN 105* 125 127 128 132 136 140 145
FEB 103* 121 122 124 127 131 135 140
MAR 86* 111 113 114 117 121 125 129
1 APR 83* 97 98 100 102 105 109 113
r MAY 97* 135 136 138 142 146 151 156
JUN 141* 146 147 149 154 158 163 174
! MW-MO 1,363 1,499 1,546 1,566 1,597 1,642 1,693 1,755
Peak Demand 145* 154* 157 159 161 165 170 175
MONTH 1996 1997 1998 1999 2000 2001 2002 2003
ri JUL 182 187 196 202 209 218 224 232
111 AUG 176 182 190 196 203 211 217 225
1 SEP 167 172 180 186 192 200 206 213
1 OCT 114 118 123 127 132 137 141 146
NOV 140 144 151 156 161 168 172 179
DEC 151 155 163 168 174 181 186 193 I" I
JAN 150 157 162 167 174 179 186 192
FEB 144 151 156 161 168 172 179 185
I MAR 133 139 144 148 155 159 165 171
i APR 116 121 125 130 135 139 144 149
I MAY 161 168 174 180 187 193 200 207
JUN 174 182 188 194 202 208 216 224 '
MW-MO 1,808 1,876 1,952 2,015 2,092 2,165 2,236 2,316
I Peak Demand 182 187 196 202 209 218 224 232
I
*Actual data.
I 1/ Includes effects of present load management programs, however does not include
reserves.
1
1 !
614 : 002 .29 -25-
'1
III ' •
TABLE 7
CITY OF REDDING ,
1988 Resource Plan
Projected
Monthly Energy Requirements (GWH) i/
(Fiscal Years 1988-2003)
MONTH 1988 1989 1990 1991 1992 1993 1994 1995
JUL 53* 67* 65 67 69 71 73 76
AUG 58* 61* 62 64 65 68 70 73
SEP 47* 51* 54 56 57 59 61 64
OCT 44* 45* 49 50 51 53 55 57
NOV 43* 46* 55 56 57 60 61 64
DEC 63* 53* 62 64 65 67 69 72
JAN 52* 63 65 66 68 70 73 76
FEB 41* 51 52 53 55 57 60 62
MAR 42* 53 55 56 58 60 62 64
APR 40* 46 47 48 50 51 53 55
MAY 43* 49 50 51 53 55 57 59
JUN 50* 55 57 59 60 61 66 67
TOTAL 576 640 673 690 708 732 760 789
High 63 67 65 67 69 71 73 76
Low 40 45 47 48 50 51 53 55
MONTH 1996 1997 1998 1999 2000 2001 2002 2003
JUL 79 82 86 90 93 98 101 105
AUG 76 78 83 86 89 93 97 101
SEP 66 68 72 74 78 81 84 88
OCT 59 61 65 67 70 73 76 79
NOV 66 69 72 75 78 82 85 88
DEC 75 78 82 85 88 92 96 100
JAN 79 83 86 90 94 97 101 105
FEB 64 67 70 73 76 79 82 85
MAR 67 70 73 76 79 82 86 89
APR 57 60 63 65 68 71 74 77
MAY 61 65 66 70 73 75 78 82
JUN 69 74 75 77 83 86 88 91
TOTAL 818 855 893 928 969 1,009 1,048 1,090
High 79 83 86 90 94 98 101 105
Low 57 60 63 65 68 71 74 77
*Actual data.
1/ Includes effects of present energy conservation programs.
614 : 002 . 30 -26-
i 1
' i i . • HTABLE 8
` CITY OF REDDING
1988 Resource Plan L}
Fiscal Year I
1 Total City Peak Demand Needs
Megawatts
Total Total Total Net Future
i� *
Year Customer Demand Customer Load Total 1/ I
i,1' Ending Demand Losses Demand Management Demand —
'1' 1
11 (1) (2) (3) (4) (5) (6)
(2) + (3) (4) + (5)
1
1978 60 7 67 2/ 67
1979 72 5 77 2/ 77
1111 1980 96 7 103 2/ 103
11 1981 102 7 109 2/ 109 .
'11 1982 108 8 116 2/ 116
V
1983 100 7 107 2/ 107
1984 102 7 109 2/ 109
1985 110 8 118 2/ . 118 1
f 1986 118 8 126 2/ 126
li 1987 125 11 136 2/ 136
1988 133 12 145 2/ 145
1989 142 12 154 2/ 154
1990 144 13 157 2/ 157
1991 145 14 159 2/ 159 'I
k 1992 147 14 161 2/ 161 1
I' 1993 150 15 165 1 166 1
11 1994 155 15 170 1 171 i
1995 159 16 175 1 176
1996 166 16 182 1 183
1997 170 17 187 1 188
l
1998 179 17 196 1 197
1999 184 18 202 1 203
2000 191 18 209 4 213
2001 199 19 218 5 223
2002 204 20 224 5 229 1
1
2003 211 21 232 5 237
2004 219 21 240 5 245 1
ii 1, r 2005 224 22 246 6 252 ,
2006 230 23 253 6 259
li
2007 239 23 262 6 268 i
1
.
II *Compound Annual Growth Rates : 1978-1987 = 8 . 2%
ji 1988-2007 = 3 . 3%
1/ Total demand (Col. 6) excludes reserves.
2/ Effects of present load management are included in Total I,
Customer Demand (Col. 2) .
J
iIF 614 : 002. 31 -27-
; II
I:.
411
• TABLE 9 /
CITY OF REDDING
1988 Resource Plan
Fiscal Year
Total City Electrical Energy Needs
Gigawatthours
Total Total Total Future
Year Customer Energy Net Load Energy *
Ending Use Losses Energy Use Management Required
(1) (2) (3) (4) (5) (6)
(2) + (3) (4) + (5)
1978 267 23 290 1/ 290
1979 315 24 339 Ti 339
1980 402 28 430 Ti 430
1981 431 30 461 T/ 461
1982 443 39 482 1/ 482
1983 437 29 466 1/ 466
1984 435 29 464 1/ 464
1985 483 29 512 Ti 512
1986 484 31 515 Ti 515
1987 473 34 507 1/ 507
1988 506 36 542 1/ 542
1989 621 39 660 0 660
1990 632 41 673 0 673
1991 648 42 690 0 690
1992 664 44 708 1 709
1993 687 45 732 1 733
1994 713 47 760 1 761
1995 740 49 789 1 790
1996 767 51 818 1 819
1997 801 54 855 1 856
1998 837 56 893 1 894
1999 870 58 928 1 929
2000 909 60 969 1 970
2001 946 63 1009 1 1010
2002 983 65 1048 1 1049
2003 1022 68 1090 2 1092
2004 1062 70 1132 2 1134
2005 1098 73 1171 2 1173
2006 1140 76 1216 2 1218
2007 1185 78 1263 2 1265
*Compound Annual Growth Rates : 1978-1987 = 6 . 4%
1988-2007 = 4 . 6%
1/ Effects of present load management are included in Total
Customer Use (Col. 2) .
614 : 002 . 32 -28-
CITY OF REDDING
1988 POWER RESOURCE PLAN
COINCIDENT PEAK DEMAND
375 HISTORIC PROJECTED
f'....-::::::.1„?..V.::•RW:;-::::4.:: :]::0::m.•-,...4.*:.:.:::.
3 2 5 ,.;:*•<=w ? :>s>:
- 300 !
TOTAL DEMAND• illi
275 ::; :::::::> ::::: > ::
••••".::::.:..::::::.!::•$1::..1:11::.:M:,,,.„,,,::„.,,,,:,::.,,„,..,,„,7,, am ,
FUTl1iE LOAD MANr
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WArine A !
g
:...1.._. •. .' .1 T: .CUSTOMER DEMAND DIV
;
I Z 200 ;. • V
j 41 '
< • • • ••• LOSSES - /
W 1 7 6 k::::... _ *
O
. r Ill..
' OTHER CLASSES
s 1 50 ` >�::`:? < < _:s`:>: ::;; .'>:::`` :
W • I
a
IMII
d IMPAIU
100
L>: :.�'.::•r::?{:��:is
50
lEt�iTK
I 26
78 82 87 82 97 2002 07
YEARS ENDING JUNE 30th ;.v.
_
lla 11181111111
FIGURE- 2.: i�pi.-,,r
-2 9_,- ' — .umnr--1
1i
• •
CITY OF REDOING •
1988 POWER RESOURCE PLAN
ELECTRIC ENERGY NEED
HISTORIC PROJECTED
TOTAL ENERGY REQUIREMENT.. MiCf: >
\U I r A
iiip7:m
icii*.io::: ::..0„,:,. .0.:0m.4;,. ,::,..:ii::;i:?:,0.4
..„ ....::::::::.:.:..:.:.:..„.:.:::.:.::.,:,:. ...:::::::.:::::::::::.1:•::::::.:.::::!.,:z::::::1.::::::3...;::,:;:.:::::.:4
1100 ::?.....:::.:„..:::::::i...:::::::::.,:::i*::1...:::::::i:.::.:*:::: :::i:::: *3.:;:::L;;;;
.,.. ...::::::::::.....::..7:Y:::.:::!!..:::';'. :.::::.Vi .....:ii.3.M..:E;icr4f.:
FUTURE LOAD MANAGEMENT
/APPMI
1 000
rvr:
900 .::::..,...::...: :
Mr
TOTAL NET ENERGY SALES
oft ' PPP"'
LOSSES
::::...:::..:...„,::.„...,:,..- ...:.....:.,...........::: -...- ,- ....-or-A Ail
OTHER CLASSES
>,
CC
:::
W
Z
W ,::;::; : h: >: :;:;
VcCMIERC
M+IL
400 y:: :.:...'' ..
.... . ..:.....:.:....... :.,......:: :.:...:....:.,::-...:::.::.::::: Milliall
300
200 >-..: : ...:..:;:;::r7. :•:.:::::> : : -
RESIDENTIAL
.: ,-:=•.:: :::
7$ !t_ 87 92 97 2002 07
YEARS ENDING..AJ.U11E 301,h__
r�� tea
FIGURE,3 • may- / _
I _ ti I '
-30- \
• HS
f •
V. RESOURCE 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 price per unit of output.
Several other resource considerations as described below
need to be evaluated to determine which resource (s) should
it be developed by the City.
A. Economics
Several factors affect the economics of a resource , a
project, or a purchase contract.
1 . Fixed Costs
The fixed costs of a resource are those costs which
are incurred regardless of how much power is ob-
tained. The most notable fixed cost is debt service
for the capital investment to build the project
which must be paid even if the resource does not
provide power for a long time period. Fixed costs
are usually associated with the cost of capacity
produced by the resource and are expressed in $ per
kW-year or $ per kW-month.
2 . Variable Costs
The variable costs of a resource are those costs
which are the result of the amount of power
produced. The most significant variable cost is the
f' fuel cost. The fuel cost during a time period when
a resource does not provide power could be zero.
Variable costs are usually associated with the cost
11
of energy produced by the resource and are expressed
in mills per kWh.
3 . Summer Dependable Capacity
The amount of power a resource can reliably generate
during summer peak electric load time periods deter-
mines its summer dependable capacity. Some re-
sources such as small hydro projects , which generate
4I inexpensive energy during high river flow conditions
and cannot generate during the City' s summer peak
load, are lower in value than resources which pro-
duce reliable summer capacity for similar energy
costs.
4. Reliability
Resources which have a history of unexpected outages
or a nondependable fuel supply are not as valuable
614 : 002 . 35 -31-
I
• •
as projects which can be depended on for nearly
continuous operation.
5 . Useful Life
Resources which can continue operation without major
overhaul, long past the time when the debt service
is paid (such as hydroelectric projects) , are eco-
nomically more attractive than projects which re-
quire major overhaul before debt service is paid
and/or have little useful life after debt service is
paid.
6 . Fuel Supply
Future costs of most resources are primarily depen-
dent on the availability and future cost of the fuel
supply. Therefore , availability and cost of the
future fuel supply are important factors in
determining the economics of a particular resource.
7 . Ability to Schedule
Resources which have the ability to schedule and can
"follow load" are capable of reducing or increasing
their generation coincident with the City' s re-
duction or increase in demand for power. If the
City has too many resources which must generate
energy during off-peak hours , the City will have to
sell the excess energy at a rate that would usually
be below the City' s cost to produce the energy.
Resources which can increase their generation during
on-peak hours will help the City economically meet
the need for on-peak power. Resources which have
the ability to schedule are more valuable than fixed
operation resources.
8 . Contingencies
Some resources have high capital risks , such as
geothermal projects where high investment costs may
be required to drill exploratory holes to determine
whether enough steam is available. Others have a
high environmental risk, such as hydroelectric proj-
ects which may require post-project mitigation
costs. These contingency risk factors must be eval-
uated when determining project economic feasibility.
9 . Residual Capacity Charges
When a utility purchases wholesale power from anoth-
er utility, the price paid is primarily determined
by the energy component and the capacity component
of the applicable rate structure. Under most
614 : 002 . 36 -32-
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. Such charges are also common when
one utility must depend on another to provide power
when the utility' s resource (s) become unavailable.
Whereas each charge may have its own particular
justification, utilities justify these charges on
the basis that they have incurred significant capi-
tal expenditures to supply peak capacity and that
the charge allows them to obtain a just and reason-
! able return on the investment made to meet the peak
load requirements throughout the year. For example ,
1 some rate schedules require up to 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-$170
per kW of demand for the peak month.
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 avoiding these charges can be used to support
further City development of power projects and load
management programs which minimize residual capacity
charges . These charges must be considered when
determining the economic feasibility of purchasing
supplemental power.
When a power project is developed to meet a utili-
ty' s load requirements , provisions must be made to
1' replace the power from the project when the project
{ is off line for scheduled or unscheduled mainte-
nance. Such provisions are commonly referred to as
"firming" . A utility which can not firm its own
resources with other projects may be required to pay
firming charges (a type of residual capacity charge)
to another utility even if the utility has enough
resources to meet its need under normal conditions.
The cost to firm a project must be considered when
determining the economic feasibility of a power
project.
I 10 . Diversity
Diversity is a measure of the ability of a utility
to develop and maintain a mix of power resources.
614 : 002 . 37 -33-
411 S
Without diversity, a utility may be forced to sig-
nificantly raise its retail rates if the cost for
its main source of power increases . The City cur-
rently relies primarily on power purchased from
Western. Therefore , the City' s diversity is cur-
rently low. When Western imposed a 300% rate in-
crease , the City had no choice but to pass the rate
increase on to its retail customers . The magnitude
of the City' s recent rate increases was primarily
driven by Western ' s rate increase. A better diver-
sification of resources would reduce the rate impact
to our customers caused by a dramatic increase in
the cost of power from a single resource. The abil-
ity of a resource to add diversity to Redding' s mix
of power resources must be considered when determin-
ing the economic feasibility of a resource.
B. Autonomy
The City is one of the few public power entities in
California that is not directly interconnected to a
major IOU system. As a result, one other consideration
in developing power resources for the City is its abil-
ity to remain independent from constraining power ar-
rangements which would preclude the City from taking
advantage of the most economic sources of power avail-
able. The existing PG&E contract is an example of such
a constraint. The contract is automatically terminated
if Redding utilizes a power resource other than PG&E or
Western.
In the future , by pursuing the development of power
projects and contractual arrangements which would pro-
vide peaking capacity, coupled with arrangements which
defer City financial burdens or offer energy sales
options , the City will be able to retain its flexibility
and independence. Thus, the City will be able to retain
its autonomy as a separate electric utility controlled
by the City' s elected representatives .
C. Types of Resources
A host of environmental , technical, contractual, and
political issues must be addressed for every possible
resource. The following discussion addresses some of
the key considerations for most industry-accepted elec-
tric power resources:
1 . Large Hydroelectric Projects
Large hydroelectric projects are virtually nonexis-
tent due to increased difficulty to site, finance,
and develop.
614 : 002 . 38 -34-
II/ 411
2 . Small Hydroelectric Projects
Small hydroelectric projects have also inherited
their share of environmental siting problems.
Unmanageable siting time can seriously hamper the
usefulness of these smaller projects to smoothly fit
into a resource plan. The availability of local
sites for such projects and the dependable,
cost-effective nature of their output, however, help
keep these projects potentially attractive.
3 . Geothermal Projects
Geothermal projects suffer from a limited known
supply of accessible steam. Known production drill-
ing areas have become saturated with wells . Recent
indications of health hazards associated with work-
ing in and around the steam fields and plants are
becoming a major concern of the industry as well as
recent reduction in generation from several existing
projects .
4 . Wind Projects
Wind projects saw a great deal of development work
in the early 1980s, with the forced transfusion
PURPA injected into the industry. As the tax cred-
its have dwindled, so has the research and develop-
ment support for this technology. In the local
region, dependable winds seldom occur during peak
electrical load conditions , so at best, this tech-
nology could only supply nondependable energy.
5 . Cogeneration Projects
Cogeneration projects have , in the last six years,
moved to the forefront of the venture capital mar-
ket. During the early 1980s , the private developer
ii interest was due primarily to PURPA mandates that
require utilities to purchase all qualified
cogeneration output at the utilities "avoided cost" .
Recently, however, several IPPs have proposed devel-
opment which benefit both the utility and the devel-
oper without the need for the regulatory incentives
provided by PURPA.
In the Redding area, bio-fuel based cogeneration
plants have developed at a rapid rate with entre-
preneurs taking advantage of PG&E' s high "avoided
cost" purchase contract. Since PG&E has established
a waiting list for transmission capacity and subse-
quently reduced their Standard Offer purchase rates,
the cogeneration markets are looking toward Redding
to make electricity sales . Reduced prices for
614 : 002 . 39 -35-
I
lip
natural gas has also caused several IPPs to
investigate the possibilities of supplying power to
Redding. Opportunities for "quick" deals abound,
however, each IPP proposal must be individually
evaluated based on the availability,
dispatchability, and contractual transmission
constraints associated with each project.
6 . Nuclear Projects
Through membership in the Modesto-Santa Clara-Red-
ding Power Agency (M-S-R) , the City was offered
22 .5MW of firm capacity from the Arizona Nuclear
Power Plant. In June 1982 , City voters passed a
referendum prohibiting City involvement in the proj-
ect. The City is , therefore, constrained from con-
sidering future participation in nuclear power proj-
ects.
7 . Coal Projects
Coal projects remain as a viable resource option
where purchase into an existing plant is possible.
However, the California Energy Commission (CEC) has
exclusive siting jurisdiction over all proposed
coal-fired steam generating plants greater than 50MW
located in the State of California. The State has
identified certain preferred technologies which are
given preference in siting consideration. "Pre-
ferred technologies" from the CEC' s perspective
include wind, hydroelectric , geothermal , and
cogeneration. Coal is not a "preferred technology" ,
and, as a matter of State policy, there is no sup-
port for a coal-fired plant located in California.
In light of these issues, it would be extremely
difficult to license a coal plant in California,
especially in the Redding area. Therefore, a key
factor in considering most remote coal projects will
be the availability of firm transmission capacity
from the project to Redding.
8 . Fuel Cells
Fuel cells soon will provide a fast, environmentally
clean way to add small (10-15MW) increments of gen-
eration resource directly to the local electrical
system. However, the technology is still in the
research and development stage with production units
planned for the late 1990s . Installed capacity
costs are still projected to be high in comparison
to a gas turbine.
614 : 002 . 40 -36-
i f
II/ Ali
9 . Gas Turbines
Gas turbines are relatively inexpensive to con-
struct, but are expensive to operate. They are
designed to operate for relatively short periods of
time and to respond quickly during emergencies and
use natural gas or distillate oil as fuel. They are
ideally suited for use as peaking or reserve units .
In the Redding area, natural gas availability and
air quality constraints may limit the application of
this resource type. The addition of steam injection
reduces air quality concerns and increases the effi-
cient operating range of a combustion turbine.
10 . Combined Cycled Projects
Combined cycled projects have high efficiency, and
are ideally suited for converting natural gas to
electric energy on a continual basis . However,
combustion turbines or gas-fired boilers are pre-
ferred over combined cycled projects when signifi-
cant cycling of the project is needed.
11 . Gas-fired Boilers
it Gas-fired boilers have the advantage of increased
efficiency over a wider range of output than a
gas-fired combustion turbine . However, gas-fired
boilers have a higher installed cost than a com-
bustion turbine.
12 . Biomass Projects
Biomass projects typically use products such as wood
waste , agricultural waste , or municipal solid waste.
Although some of these projects tend to utilize new
technology, they are becoming increasingly popular
since they are becoming economically competitive
with other resources . However, they may have sig-
nificant fuel supply and air pollution difficulties
to resolve.
13 . Hydroelectric Pumped Storage Units
Hydroelectric pumped storage units, though basically
net energy users, are designed to supply power dur-
ing the peak-load periods and to utilize low-cost,
base-load generation to pump the water back to an
upstream reservoir during off-peak periods. Their
economic operation depends heavily on the availabil-
ity of low-cost, off-peak, base-load resources .
Without these low-cost resources , the installation
of pumped storage facilities is not economical.
614 : 002 . 41 -37-
i
411
14 . Purchase Contracts
With the construction of the California-Oregon
Transmission Project (COTP) , the City will be able
to enter into purchase contracts with several other
utilities. In addition, several IPPs have expressed
an interest in limiting their relationship with the
City to a purchased power contract. Although pur-
chased power contracts reduce the need for the City
to make capital expenditures , they usually have
lower long-term economic benefits than many of the
power projects discussed above .
15 . Support Contracts
Support contracts support a utility' s resources by
providing such things as : emergency power, spinning
and planning reserves , voltage and frequency control
and power exchanges . In some instances , support
contracts provide an economic alternative to con-
struction of the facilities which are needed to
provide support. If such facilities are not avail-
able, a support contract (s) may be necessary to
reliably meet the load.
D. Transmission
Currently, Redding' s Electric Utility operates as an
island within the transmission system of PG&E. The
Utility is interconnected with Western and is not inter-
connected with PG&E. Therefore , any power Redding re-
ceives from PG&E ' s system must be received by Western at
Tracy, near the Bay Area, and then delivered by Western
from Tracy to Keswick. With construction of the COTP,
Redding will be able to receive up to 44MW of power from
the COTP at the Olinda Substation, near Cottonwood, for
delivery by Western to Redding.
Potential resources which may seem to be close to
Redding' s Utility may be , electrically, very far, if the
resource ' s interconnection is with PG&E. The cost in
both dollars and losses to wheel power through PG&E' s
transmission system down to Tracy and from Tracy to
Keswick over Western' s system is usually too high to
provide for an economical source of power.
E. Reserve Requirements
Every electric utility strives to provide dependable
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 suffi-
cient reserves to meet customer load requirements.
614 : 002 .42 -38-
411 4110
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 (24 continu-
(„ ous hours) in ten years . Such a standard requires that
generation and power purchases must exceed customer
f
loads at all times except for one day in ten years . All
uncertainties such as weather, forced and planned out-
ages , and other factors such as routine maintenance must
be included. Utilities employ several strategies to
provide sufficient reserves to reduce their LOLP, howev-
er, the reserves of most utilities are divided into two
major types .
1. Planning Reserves
Planning reserves in the utility industry are typi-
cally
15% - 20% of system peak demand. Planning
reserves are designed to account for demand forecast
errors , long-term weather extremes , delays in the
construction of new power plants , and lengthy forced
outages .
I I
2 . Spinning Reserves
Spinning reserves in the utility industry are typi-
cally 5% - 10% of system peak demand. Spinning
reserves are designed to account for sudden loss of
existing generation. If, under emergency sit-
uations , existing generation is lost, spinning re-
serves are used to quickly (within a few minutes)
replace the sudden loss in generation.
3 . Redding' s Present Reserves
Planning and spinning reserves for Redding are cur-
rently provided under the present supplemental power
agreement with PG&E. Likewise, the City' s CVP power
has planning and spinning reserves included, pursu-
ant
( to the Western/PG&E agreements . Planning and
spinning reserves will, however, be needed for fu-
ture power resources exclusive of CVP and PG&E
purchases.
614 : 002 .43 -39-
i,
411
4 . Reserves Applied in This Plan
In planning for the City' s future power require-
ments , a reserve margin equal to the largest single
non-firm resource used to meet the City' s load was
utilized in the 1986 Plan to determine the City' s
total need for reserves . This strategy provided a
total of planning and spinning reserves between
13%-29% over the 20-year forecast period. Table 10
documents the amount of reserves provided in the
1988 Resource Plan.
614 : 002 . 44 -40-
411411VI . RECOMMENDED POWER RESOURCE DEVELOPMENT PLAN
Based upon the City' s planning goals , future power require-
ments ,
and the available alternatives , the following plan is
recommended to meet the City' s power requirements through
fiscal year 2007 . Table 10 provides a summary of the City' s
ability to meet its electrical power needs , if most of the
resources which are currently under active consideration are
included in Table 10 . Information regarding several re-
sources which are currently undergoing very preliminary
investigations is insufficient to include those resources in
Table 10 .
The City ' s contract with Western expires after the calendar
year 2004 . Therefore, any planning past the fiscal year
2005 , at this time, is very uncertain. For the purpose of
preparing Table 10 , it was assumed that the City' s Western
allocation will continue through 2007 . More should be known
about the validity of this assumption after Western has
completed its 1994 Remarketing Plan, a process which is
slated to begin during 1989 . The City should become
prepared for the consequences of not receiving a total
reallocation of Western' s resources in 2004 and the conse-
quences of not developing some or all of the undeveloped
resources identified in Table 10 .
The City should continue to develop a resources plan which
will reduce its dependence on PG&E supplemental power,
thereby reducing electric cost to its customers . By provid-
ing and alternative the City would be providing PG&E an in-
centive to maintaining its prices as low as possible.
A more detailed discussion of the recommended plan follows.
li
4I, A. Avoid High-cost Supplemental Power Purchases
Since future supplemental power purchases from PG&E are
likely to be expensive , the City should try to avoid
supplemental power purchases from PG&E by developing
power resources which are lower than the projected cost
of supplemental power purchases. As was noted in Sec-
tion V, it is possible that residual capacity charges
may make supplemental peaking capacity quite costly.
Table 10 includes every project which the City has iden-
tified and currently believes can be developed for a
production cost which is , in the long term (first 10
years of operation) , more economical than supplemental
purchase power options from PG&E. If the recommended
plan shown in this table is developed as scheduled. The
City' s purchase of supplemental power will be minimal.
However, the need to purchase supplemental power will
increase to the extent that the City does not success-
`i fully develop the projects as scheduled in Table 10
614 :002 . 45 -41-
it
��i I I
lip
a
unless other yet-undefined projects are developed. If
too large a percentage of the City ' s supplemental power
is purchased from a California IOU, then the City' s rate
to its customers may become equal or even exceed the
California IOU' s rate to its retail customers .
B. Pursue Arrangements to Shape Loads and Resources
The City needs to continue to develop arrangements that
can provide on-peak capacity and dispose of excess ener-
gy during those time periods when the City' s energy
requirements are reduced.
The following is a list of the most promising alterna-
tives which are not listed in any particular order:
o Scheduling of power from Western
0
Peaking capacity purchases
o Sale of excess energy to Western
o Pacific Northwest peaking capacity purchases
0
Capacity-for-energy exchange agreements
o Spring Creek Pumped Storage Project
0
Large interruptible customers
0
Supplemental power purchase contract with PG&E
o Other possible suppliers and purchases (DWR, MID,
SMUD, etc. )
C. 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 off-peak energy to be stored for
later use as on-peak capacity and energy. The pumped
storage project will also allow the City to use off-peak
energy which is often available at attractive rates from
other utilities. Finally, by maintaining a minimum pool
in the upper reservoir, the project may be able to pro-
vide some of the necessary reserve requirements for the
City' s other projects .
614 : 002 . 46 -42-
•
D. Pursue Economic Hydroelectric Projects
Two small-to-medium size hydroelectric power projects
remain available for development by the City. The proj-
ects can be developed using proven technology 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 Whis-
keytown Project is operational. The other two hydro-
electric projects are the Lake Redding Project and the
Lake Red Bluff Project.
E. Pursue Development Negotiations with Independent Power
Producers (IPP)
The IPP project known as the "CAMAGE Project" in the
1986 Plan offered the City an opportunity to reduce its
long-term cost of power and would have increased the
City' s diversity. However, the City has received sever-
al inquiries and preliminary proposals from several
other IPPs which could supply at least as much power as
the CAMAGE Project. Table 10 includes an unidentified
IPP project which is estimated to provide up to 25MW and
150GWH.
F. Pursue Transmission Rights
For the City to have free access to economical power
supplies , transmission rights must be obtained. The
Cityis presently a 6 .4% participant in TANC, which is
the project manager of the COTP. The COTP includes
upgrading and construction of new transmission facil-
ities
from the Pacific Northwest to Central California.
Studies are currently underway for the COTP. Table 10
includes 18 . 5MW of purchased firm peaking capacity from
the Pacific Northwest and delivered over the COTP begin-
ning in fiscal year 1992 . Pacific Northwest firm peak-
ing capacity is expected to gradually increase to 27 . 7MW
by the year 2000 . The City' s interest in the COTP south
of Redding will enable Redding to make power trans-
actions with other California utilities . Redding,
through its membership in M-S-R is developing access to
connect its San Juan entitlement to the COTP.
G. Enhance Relationships with Western
Since Western is the City' s primary source of 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. Since
adoption of the 1986 Resource Plan, the City has exe-
cuted a new transmission contract which increases the
City' s opportunities for utilizing transmission services
li from Western. Other contracts are currently under
614 : 002 . 47 -43-
li
negotiation for such interutility services as scheduling
and emergency support. Those contracts need to be
finalized to allow Redding maximum flexibility to
economically and reliably supply power to its customers .
H. Pursue Other Interutility Contracts
Prior to completion of the COTP Redding should develop
resources in the Pacific Northwest for delivery over the
COTP. Some of the most promising resources are inter-
utility purchase contracts with other utilities in the
Pacific Northwest. When Redding utilizes another re-
source, its current contract with PG&E will terminate.
Even so, Redding may need to purchase support services
or additional supplemental power. Redding should con-
tinue negotiations with PG&E such that all of Redding' s
options are available should PG&E offer services which
are in the long-term more economical than alternatives .
I . Pursue Conservation and Load Management Programs
As the City' s conservation and load management programs
are implemented, the City' s ability to avoid its excep-
tional summertime capacity peaks will increase. Elec-
tric loads in the City that can be safely and efficient-
ly reduced during the peak demand time periods will
directly benefit the City' s ratepayers through lower
costs from avoided supplemental power purchases .
J. Selectively Participate in Baseload Projects
Whenever the overall economics are favorable and the
diversity of power supply can be enhanced, the City may
wish to selectively participate in base load power proj-
ects . Although base load projects generate a lot of
off-peak and usually unneeded power, the cost per kWh
generated is usually very low. When base load projects
are pooled with other utilities, as the San Juan Project
is with M-S-R and if the project offers some flexibility
in energy deliveries , they may be beneficial to the
City. The City should selectively examine and partici-
pate in base load projects whenever such participation
meets the planning goals of the City.
614 : 002. 48 -44-
410 IF
• TABLE 10
CITY OF REDDING
1988 Resource Plan
Recommended Plan
Fiscal Year 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998
ENERGY (CWH)
REQUIREMENTS
1 Sales 621.0 632.0 648.0 664.0 687.0 713.0 740.0 767.0 801.0 837:0
Losses (1) 39.0 41.0 42.0 44.0 45.0 47.0 49.0 51.0 54.0 56:10
EnergyConserv. 0.0 0 0
0.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0
Contract Exp. 243.4 243.4 243.4 243.4 242.4 242.4 205.3 148.4 126.3 126.4
1 , TOTAL 903.4 916.4 933.4 952.4975.4 1,003.4 995.3 967.4 982.3 1,020.4
ENERGY (CWH) i
RESOURCES
' Western 587.4 591.3 588.2 585.6 597.0 608.7 611.3 604.3 602.1 612.3
i' Energy Conserv. 0.0 0.0 0.0 1.0 1.0 1.0 1.0 1.0 1.0 1.10
San Juan 127.2 127.2 127.2 127.2 127.2 127.2 127.2 127.2 127.2 127.2
Whiskeytown 8.2 8.2 8.2 8.2 8.2 8.2 8.2 8.2 8.2 8.�2
Spring Creek 0.0 0.0 0.0 0.0 0.0 -0.0 -0.0 -0.0 -0.0 -0.i0
Lake Redding 0.0 0.0 0.0 0.0 0.0 0.0 24.1 71.0 93.7 93.7
Lake Red Bluff 0.0 0.0 0.0 0.0 0.0 0.0 0.0 12.1 35.6 47.0
Northwest Imports 0.0 0.0 5.1 12.4 18.9 27.9 26.0 12.4 9.6 19:0
1„ Southwest Imports 108.0 108.0 108.0 108.0 108.0 108.0 72.0 18.0 0.0 0.0
IPPs 0.0 0.0 54.1 110.1 115.1 122.4 125.5 113.2 104.9 112.0
1I' Other Purchases 72.6 81.7 42.6 0.0 0.0 0.0 0.0 0.0 0.0 0:0
1
TOTAL 903.4 916.4 933.4 952.5 975.4 1,003.4 995.3 967.4 982.3 1,020.4
I
1
CAPACITY (MW)
REQUIREMENTS
Customer Demand(2)142.0 144.0 145.0 147.0 150.0 155.0 159.0 166.0 170.0 179:0
i Losses 12.0 13.0 14.0 14.0 15.0 15.0 16.0 16.0 17.0 17:10
it Interrupt. Load 0.0 0.0 0.0 0.0 1.0 1.0 1.0 1.0 1.0 1.0
Reserves 0.0 0.0 0.0 25.0 25.0 42.4 50.0 51.0 47.1 39.1
Contract Exp. 0.8 0.8 0.8 0.0 0.0 0.0 0.0 0.0 0.0 0.0
TOTAL 154.8 157.8 159.8 186.0 191.0 213.4 226.0 234.0 235.1 236.j1
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. 0.0 0.0 0.0 0.0 1.0 1.0 1.0 1.0 1.0 1.0
Whiskeytown 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0:8
II Spring Creek 0.0 0.0 0.0 0.0 0.0 50.0 50.0 50.0 50.0 50:0
jl Lake Redding 0.0 0.0 0.0 0.0 0.0 0.0 11.6 11.6 11.6 11.6
Lake Red Bluff 0.0 0.0 0.0 0.0 0.0 0.0 0.0 6.0 6.0 6.0
i
Northwest Imports 0.0 0.0 0.0 18.5 19.5 20.6 21.6 23.6 24.7 25.7
IPPs 0.0 0.0 0.0 25.0 25.0 25.0 25.0 25.0 25.0 25.0
Other Purchases 38.0 41.0 43.0 19.2 28.7 0.0 0.0 0.0 0.0 0.0
I TOTAL 154.8 157.8 159.8 186.0 191.0 213.4 226.0 234.0 235.1 236.1
(1) Includes effects of anticipated expansion of existing energy conservation programs.
(2) Includes effects of anticipated expansion of existing load management programs.
I
i
11 614 :002 . 49 -45-
i
I;
TABLE 10 (Cont.)
CITY OF REDDING
1988 Resource Plan ,
Recommended Plan
Fiscal Year 1999 2000 2001 2002 2003 2004 2005 2006 2007
ENERGY (GWH)
REQUIREMENTS
Sales 870.0 909.0 946.0 983.0 1,022.0 1,062.0 1,098.0 1,185.0 1,240.0
Losses 58.0 60.0 63.0 65.0 68.0 70.0 73.0 76.0 78.0
Energy Conserv.(1) 1.0 1.0 1.0 1.0 2.0 2.0 2.0 2.0 2.0
Contract Exp. 126.3 126.4 126.3 137.0 130.9 123.0 105.6 24.3 0.0
TOTAL 1,055.3 1,096.4 1,136.3 1,186.0 1,222.9 1,257.0 1,278.6 1,287.3 1,320.0
ENERGY (GWH)
RESOURCES
Western 628.2 643.7 654.7 663.5 670.6 680.6 682.4 672.5 669.1
Energy Conserv. 1.0 1.0 1.0 1.0 2.0 2.0 2.0 2.0 2.0
San Juan 127.2 127.2 127.2 127.2 127.2 127.2 127.2 127.2 127.2
Whiskeytown 8.2 8.2 8.2 8.2 8.2 8.2 8.2 8.2 8.2
Spring Creek -0.1 -0.1 -0.2 -0.5 -1.5 -2.1 -3.3 -4.9 -7.5
Lake Redding 93.7 93.7 93.7 93.7 93.7 93.7 93.7 93.7 93.7
Lake Red Bluff 47.0 47.0 47.0 47.0 47.0 47.0 47.0 47.0 47.0
Northwest Imports 29.9 46.8 68.9 95.9 125.7 150.5 169.0 185.3 203.9
Southwest Imports 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
IPPs 120.2 128.9 135.8 150.0 150.0 150.0 150.0 150.0 150.0
Other Purchases 0.0 0.0 0.0 0.0 0.0 0 .0 2.4 6.3 26.4
TOTAL 1,055.3 1,096.4 1,136.3 1,186.0 1,222.9 1,257.1 1,278.6 1,287.3 1,320.0
CAPACITY (MW)
REQUIREMENTS
Customer Demand(2)184.0 191.0 199.0 204.0 211.0 219.0 224.0 230.0 239.0
Losses 18.0 18.0 19.0 20.0 21.0 21.0 22.0 23.0 23.0
Interrupt. Load 1.0 4.0 5.0 5.0 5.0 5.0 6.0 6.0 6.0
Reserves 34.1 27.6 25.0 44.9 44.9 47.1 66.1 59.1 50.1
Contract Exp. 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
TOTAL 237.1 240.6 248.0 273.9 281.9 292.1 318.1 318.1 318.1
CAPACITY (MW)
RESOURCES
Western 116.0 116.0 116.0 116.0 116.0 116.0 116.0 116.0 116.0
Load Mgmt. 1.0 4.0 5.0 5.0 5.0 5.0 6.0 6.0 6.0
Whiskeytown 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8
Spring Creek 50.0 50.0 50.0 50.0 50.0 100.0 100.0 100.0 100.0
Lake Redding 11.6 11.6 11.6 11.6 11.6 11.6 11.6 11.6 11.6
Lake Red Bluff 6.0 6.0 6.0 6.0 6.0 6.0 6.0 6.0 6.0
Northwest Imports 26.7 27.2 27.7 27.7 27.7 27.7 27.7 27.7 27.7
IPPs 25.0 25.0 25.0 25.0 25.0 25.0 25.0 25.0 25.0
Other Purchases 0.0 0.0 5.9 31.8 39.8 0.0 25.0 25.0 25.0
TOTAL 237.1 240.6 248.0 273.9 281.9 292.1 318.1 318.1 318.1
(1) Includes effects of anticipated expansion of existing energy conservation programs.
(2) Includes effects of anticipated expansion of existing load management programs.
614 : 002 .50 -46-
•
II.
411
w
III
SECTION VII
�IIi
APPENDICES
1
(A) Resource and Transmission Projects Recommended
for Continued Investigation or Operations
(B) Definitions
; I
(C) Acronyms 1
t I
I �
614 : 002 .51 -4'7-
i
VII .
A. RESOURCE AND TRANSMISSION PROJECTS RECOMMENDED FOR CONTINUED
INVESTIGATION OR OPERATION
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. Generic IPP
IV. TRANSMISSION PROJECTS UNDER REVIEW
A. COTP
B. Multi-utility Trans-Sierra Line
C. Mead-Phoenix Direct Current Project
D. Mead-Adelanto-Lugo Direct Current Project
E. Palo Verde-Dever Line No. 2
614 : 002 . 52 -48-
Appendix A
I.1
• •
•
•
' E
SECTION VII .
APPENDIX A
A. I . PROJECTS WHICH CITY HAS COMMITTED TO FULL DEVELOPMENT
I f
!u
i f
I
WHISKEYTOWN HYDROELECTRIC PROJECT
Information Sheet
April, 1989
Location:
At the USBR Whiskevtown 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 , 600kVA
Head 239 '
Maximum Powerhouse Flow 195 cfs
Power Output:
Expected Operational Date June , 1986
Maximum Capacity 3 . 24MW
Summer Dependable Capacity 0 . 8MW
Average Annual Generation 8 , 200 ,000kWh
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, 1985 $
(Does Not Include Financing Costs) $4 , 010 , 000
Approximate 1st-Year Cost (Mills/kWh)
(Includes Financing Costs) 66
614 . 002.53 -49-
Appendix A
s
SAN JUAN PROJECT
Information Sheets
April, 1989
In November 1982 , the M-S-R Public Power Agency (M-S-R) purchased
fl, an option on 28 . 8% of San Juan Unit No. 4 which represents
approximately 143MW of the 498MW net Unit No. 4 generation. The
City has a 15% share of the 143MW which is equal to about 21 .5MW.
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) entered into an
Interconnection Agreement (Agreement) which provided 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 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 . 8GWH.
Since the end of 1985 , TEP has refused to make available the
SI' required annual energy. M-S-R and TEP are currently engaged in
litigation over the energy sales issue. M-S-R' s price for this
energy is three mills per kWh plus TEP' s weighted average cost
per kWh for its coal-fired generating plants , under the terms of
the Agreement.
Only interruptible transmission will be available to M-S-R prior
to the early 1990s . The interruptible nature of the transmission
arrangements in the early years should prove sufficient to allow
M-S-R to utilize the Project since M-S-R is only purchasing
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.
M-S-R and PNM executed an Early Purchase and Participation
Agreement (EPPA) on September 26 , 1983. The terms of the EPPA
provided for the transfer of the 28 . 8% Ownership Interest in San
614 : 002. 54 -50-
Appendix A
li �
411 •
Juan Unit No. 4 . The transfer was completed on December 31 ,
1983 . The EPPA also provides for the sale of 73 . 53% , approxi-
mately 105MW, of M-S-R' s capacity and associated 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 the approximately
38MW uncommitted share of San Juan Unit No. 4 , the Public Service
Company of New Mexico (PNM) will market the 38MW for M-S-R until
1995 .
614 : 002 .55 -51-
Appendix A
1
;
1
SECTION VII .
APPENDIX A
A. II . PLANNED HYDROELECTRIC PROJECTS
1
• 1
1
1
1
►
II
•
PROPOSED LAKE REDDING HYDROELECTRIC PROJECT
Information Sheet
November, 1988
Location:
On the Sacramento River in the City of Redding, Shasta County,
California.
Status:
FERC Application for License filed in February, 1982 . A Draft
EIR was released in December 1986 .
Physical:
Project Size 34 Acres
Powerhouse Size 145 ' x 131 '
Number of Units Three
Type of Turbines Bulb
Size of Generators 5 , 000kVA
Head 14 .5 '
Maximum Powerhouse Flow 15 ,000 cfs
Power Output:
Expected Operational Date Summer, 1991
Maximum Capacity 15MW
Summer Dependable Capacity 8MW
Average Annual Generation 92 , 000 , 000kWh
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 Hill are
expected to significantly decrease after design changes are con-
sidered during 1989 .
614 : 002.56 -52-
Appendix A
• •
I
1 ,
SECTION VII.
APPENDIX A
A. III . OTHER PLANNED PROJECTS 1
I
I
I I
1
i
410 •
•
PROPOSED LAKE RED BLUFF HYDROELECTRIC PROJECT
Information Sheet
November, 1988
Location:
At the existing Red Bluff Diversion Dam on the Sacramento River,
in Tehama County, California.
Status:
FERC License Application filed April 1983 . The Application for
License processing has been delayed to allow the Department of
Interior to complete ongoing studies near the dam.
Physical:
Project Size 40 Acres
Powerhouse Size 70 ' x 150 '
Number of Units Two
Type of Turbine Kaplan Bulb
Size of Generators 4 , 000kVA
Head 11 '
Maximum Powerhouse Flow 9 , 000 cfs
Power Output:
Expected Operational Date 1992
Maximum Capacity 8MW
Summer Dependable Capacity 4MW
Average Annual Generation 47 , 400 , 000kWh
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 lst-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.
614 . 002 . 57 -53-
Appendix A
• 410
i 4
it PROPOSED SPRING CREEK PUMPED STORAGE PROJECT
Information Sheet
November, 1988
Location:
On Spring Creek, west of Keswick Reservoir, Shasta County,
California.
Status:
( ll The FERC License Application will be filed on May 31 , 1989.
Physical:
Project Size 100MW
Powerhouse Size - Underground Cavern 50 'W x 90 'H x 210 'L
Number of Units Two
Type of Turbine Francis reversible
pump/turbine
i Size of Generators 58MVA
' Head 1 , 155 '
{ Maximum Powerhouse Flow 1 , 200 cfs
Power Output:
Expected Operational Date 1995
Maximum Capacity 100MW
j , P 1'
Summer Dependable Capacity 100MW
r, Average Annual Generation* N/A
Average Flow-through Generation 14GWH
Costs : (1989 Dollars)
Permit Process (to date) $ 400 ,000
Total cost for Permit Process (est. ) 1 , 000 , 000
Civil and Mechanical 195 ,500 ,000
Total Capital Cost $196 , 500 , 000
I j Approximate Cost ($/kW) $1 ,965
Miscellaneous:
(1) Cost provided in Draft FERC License Application as prepared
by Black & Veatch.
Pumped storage projects use more energy to pump than they
produce.
' 614 : 002.58 -54-
Appendix A
410
•
GENERIC INDEPENDENT POWER PROJECT
Information Sheet
November, 1988
Location:
In or near Redding, in Shasta County, California.
Status :
Special negotiations are ongoing.
Physical:
Project Size 25MW
Powerhouse Size N/A*
Number of Units N/A*
Size of Boilers N/A*
Size of Turbine Generator N/A*
Power Output:
Expected Operational Date 1992
Maximum Capacity 25MW
Summer Dependable Capacity 25MW
Average Annual Generation 150 , 000 , 000kWh
Average Annual Oil Savings
Costs : (1985 Dollars)
Permit Process (to date) $ N/A
Total Cost for Permit Process (est. ) N/A
Civil & Mechanical N/A
N/A
Approximate 1st-Year Cost (Mills/kWh) N/A
Miscellaneous :
* N/A - Not available at this time.
614 : 002. 59 -55-
Appendix A
W
• ff
I �
SECTION VII.
APPENDIX A
A. IV. TRANSMISSION PROJECTS UNDER REVIEW
it
I i
i t
I � I
II
I
I �
II
o I
I I
lip
4
IV. TRANSMISSION PROJECTS UNDER REVIEW
The projects listed below are transmission projects
major
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 .
A. California-Oregon Transmission Project (COTP)
Total Capacity/ (Available to City) :
1600MW/ ± (43 . 3MW)
Project Cost (1989 $) : $443 , 000 , 000*
Date of completion: 1992
Location: From a point near Malin, Oregon to
Tracy, California
Comments:
Line would open up purchase opportunities with the
Pacific Northwest. Joint feasibility studies are
underway with California utilities and Pacific
Northwest entities participating. More than one set
of studies are in progress.
*The Transmission Agency of Northern California and M-S-R may
incur additional costs associated with certain improvements
to PG&E' s system. The improvements are known as the Los
Banos-Gates (LB-G) Project. Neither TANC nor M-S-R will have
ownership interest in LB-G but will receive firm bidirectional
transmission service between Midway Substation and Tesla
Substation.
614 : 002 . 60 -56-
Appendix A
4 1
B. Multi-utility Trans-Sierra Line
Total Capacity/ (Available to City) :
1600MW/ (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 500kV 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 are complete , corridor studies are underway
by PG&E, Sierra Pacific Power Company, and Idaho
Power.
C. Mead-Phoenix Direct Current Project
Total Capacity/ (Available to City) : 1600MW/ (15MW)
I' I
Project Cost (1986 $) / (cost to City) :
$440 , 000 , 000/ ($4 , 125 ,000)
Date of Completion: 1993
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.
614 : 002 . 61 -57-
Appendix A
410
•
D. Mead-Adelanto-Lugo Direct Current Project
Total Capacity/ (Available to City) : 2 ,000MW/ (22 . 5MW)
Project Cost (1986 $) /Cost to City:
$387 , 000 , 000/ ($4 , 353 , 750)
Additional liability for system modification to
SCE' s system: $80 , 000 ,000 to $120 , 000 , 000 Project
Cost
Additional liability to City: x900 , 000 to
$1 , 350 , 000
Date of Completion: 1993
Location: Between Southern Nevada and the Los
Angeles area
Comments :
This project was developed as an alternative to the
McCullough-Victorville Project which is not under
consideration at this time (Spring 1989) . The City
is participating in the development of this project
through M-S-R and would be entitled to use 15% of
M-S-R' s capacity share in the project.
E. Palo Verde-Dever Line No. 2
Total Capacity/ (available to City) 1200MW/ (22 . 5MW)
Project Cost (1987$) / (Cost to City) :
$251 ,000 , 000/ (4 , 706 , 360)
Date of completion: Uncertain
Location: Between Phoenix, Arizona and the
Los Angeles area
Comments:
The date of completion is uncertain due to CPUC
conditioning SCE' s CPCN on SCE dropping plans to
merge with San Diego Gas and Electric or undergoing a
reevaluation of need. CPUC staff indicated 1993 or
more probably 1997 as an in-service date.
The City is participating in the development of this
project through M-S-R and would be entitled to use
15% of M-S-R' s capacity share in the project.
614 : 002 . 62 -58-
Appendix A
• •
• SECTION VII .
I
APPENDIX B
kj B. DEFINITIONS
11
i
i I
II�
I �
II
III . •
B. DEFINITIONS
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 utility 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.
614 : 002 . 63 -59-
Appendix B
• 411
Capacity The production level for which an
electric generating unit or other
electrical apparatus is rated, either by
the user or manufacturer. Also , the
total volume of natural gas 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
'j line is capable of carrying. (See DEMAND
definition)
a I
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 char-
acteristics (e.g. , residential,
commercial, industrial, etc. ) which are
identified for the purpose of setting a
rate for electric.
614 : 002 . 64 -60-
Appendix B
4 •
Code of Federal A compilation of the general and perma-
Regulations nent rules of the executive departments
and agencies of the federal government
as published in the Federal Register.
The Code is divided into 50 titles which
represent broad areas subject 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 than discharged
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 correlate 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, and
property taxes.
614 : 002 . 65 -61-
Appendix B
I i
•
Costs - Costs other than those associated with
Fixed Operating Costs capital investment which do not vary
with the operation such as maintenance,
payroll.
Current A movement of electricity 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.
II
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
I 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 points on the
li 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.
614 : 002 . 66 -62-
Appendix B
410
• r
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.
Energy The capacity for doing work. 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 convertible 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 the Federal
Water Power Act administered by the
Former Federal Power Commission. 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 sale 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
614 : 002 . 67 -63-
Appendix B
1
I 4
industries . It was abolished on
September 30 , 1977 , when the new
it Department of Energy was created and its
functions were embraced by the Federal
Energy Regulatory Commission, an
j independent regulatory agency.
Firm Energy Energy which is intended to have assured
availability to the customer to meet all
or any agreed-upon portion of his load
1 requirements over a defined period.
1
1 Firm Power The highest quality of electric power
which has a very low probability of
interruption.
I
Firm Service The highest quality generation and/or,
transmission service offered to
customers under a filed rate schedule
which anticipates no planned
1 interruption.
i
I Firm Transmission Transmission of energy by a utility over
its system for the account of another
{ party with the service intended to be
1 available at all times.
1
Fiscal Year Government ' s 12-month financial year.
I The federal govermnent' s is from Octo-
ber 1 , through September 30 . The City
of Redding' s is July 1 to June 30 .
1 Flat Rate Schedule A schedule that provides for a specified
charge regardless of the energy consumed
or demand.
I
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
II to a purchaser in which the seller
. 1 pledges to meet all of the purchaser' s
' 1 electric requirements .
1 Generation The process of producing electric
energy.
I
! I 614 : 002 . 68 -64- ! '
6 ' Appendix B
1
•
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 the generator
terminals .
Headwater Benefits The benefits resulting from 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 be 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/Pacific 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
500kV alternating current, extend from a
connection with the U.S. Columbia River
614 : 002 . 69 -65-
Appendix B
Power System at John Day Dam to various
points of connection with the system of
PG&E, 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 750kV direct current, with a
capacity of about 1 , 440 , 000 kilowatts.
The direct current line connects with
the federal system at Celilo, Oregon,
near the Dalles Dam. It extends to a
connection with the system of 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.
, i
I � Inverted Rate Design A rate design for a customer class for
16 which the unit charge for energy in-
'i creases as usage increases .
Kilo A prefix indicating a 1 , 000 ; thus , a
kilovolt (kV) equals 1 , 000 volts .
Kilovolt (kV) A unit of measurement of electrical
force equal to 1 , 000 volts .
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 about 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.
ii License Authorization by the Federal Energy
Regulatory Commission to construct,
operate, and maintain non-federal hydro
projects for a period of up to 50 years.
Load The amount of electric power or energy
i ; 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.
614 : 002 . 70 -66-
Appendix B
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 operating efficiency
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 .
Megawatt (MW) 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. It may 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 load periods.
The maximum output of a generating plant
or plants during a specified peak-load
period.
614 : 002 . 71 -67-
Appendix B
ii
• 1
1 ,
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. Electrically,
power is expressed in watts , which is
the product of applied voltage and
resulting in in-phase current.
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 hydroelectric license.
The preliminary permit enables the
permittee to prepare a license appli-
1 cation and conduct various studies such
as economic feasibility and environ-
1 mental impacts . The period for a
preliminary permit may extend to three
years .
Public Utility One part of the National 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
j elevation during off-peak periods when
excess generating capacity is available.
II 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 1
614 : 002 . 72 -68-
Appendix B
� i
• .
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.
Reserve Generating Extra generating capacity available to
Capacity meet peak or abnormally high demands for
power and to generate power during
scheduled or unscheduled outages.
Run-of-River Refers to hydroelectric projects 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 , and 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 a certain
specified season of the year.
614 : 002 . 73 -69-
Appendix B
•
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
II assured availability during the period
of reservation.
Short-Term Non-Firm Capacity and/or energy provided 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.
Standby Service Capacity and/or energy provided or made
II 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
II as a control and transfer point on an
electrical transmission or distribution
system. It serves the following pur-
poses:
614 : 002. 74 -70-
Appendix B
I
411
• .
(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 together two or
more electric circuits through switches .
The switches are selectively arranged 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 of electric
energy in bulk. Ordinarily, trans-
mission is considered to end when the
energy is transformed for distribution
to the consumer.
Volt The unit of measurement of electrical
force. It is analogous to water 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.
614 : 002 . 75 -71-
Appendix B
• AO .
Wheeling The use of the transmission facilities
of one system to transmit power of and
for another system.
1
11
1
I f
II
1
4I�
i
Y{41 1
1 �
614 : 002.76 -72-
Appendix B
• • . .
SECTION VII.
APPENDIX B
C. ACRONYMS
ir
r
C. ACRONYM LIST
ACID Anderson-Cottonwood Irrigation District
ACLM Air Conditioning Load Management (Program)
APPA American Public Power Association
I BPA Bonneyville Power Administration
CCPA Central California Power Agency
r CEC California Energy Commission
CFM Common Forecasting Methodology
I , CMUA California Municipal Utilites Association
COTP California-Oregon Transmission Project
CVP Central Valley Project
DWR Department of Water Resources
ECLM Energy Conservation/Load Management 1
FERC Federal Energy Regulatory Commission
GWH Gigawatthour
IOU Investor-Owned Utility
! IPP Independent Power Producer
KGRA Known Geothermal Resource Area
1 KWH Kilowatthour
LADWP Los Angeles Department of Water & Power
LOLP Loss of Load Probability
1 MID Modesto Irrigation District
MSR Modesto-Santa Clara-Redding Power Agency
MSW Municipal Solid Waste
MW Megawatt
NCPA Northern California Power Agency
PG&E Pacific Gas & Electric Company
PURPA Public Utility Regulatory Policy Act 1
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
1 l ' SPLM Swimming Pool Load Management (Program)
STEP Shave the Energy Peak (Program) ,
1 TANC Transmission Agency of Northern California
1 USBR U.S . Bureau of Reclamation
WAPA Western Area Power Administration
1
I
I
11 I
1
i
614 : 002. 77 -73-
I Appendix C 1
l
4
.l
i