HomeMy WebLinkAboutReso 91-199 - Adopting the COR Electric Utility 1990 Resource Plan i
RESOLUTION NO.
a A RESOLUTION OF THE CITY COUNCIL OF THE CITY OF REDDING
ADOPTING THE CITY OF REDDING ELECTRIC UTILITY 1990 RESOURCE
PLAN.
WHEREAS, the City Council of the City of Redding has
considered the Electric Utility 1990 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
i to adopt said Plan as the City of Redding Electric Utility 1990
i 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 1990 Resource Plan.
I HEREBY CERTIFY that the foregoing Resolution was
introduced and read at a regular meeting of the City Council of
i the City of Redding on the 7th day of May , 1991, and was duly
adopted at said meeting by the following vote:
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AYES: COUNCIL MEMBERS: Arness, Dahl, Fulton, Moss & Buffum
{ NOES: COUNCIL MEMBERS: None
ABSENT: COUNCIL MEMBERS: None
ABSTAIN: COUNCIL MEMBERS: None
NANCY,/ BUFFUM; Mayor
City lof Redding
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ATTEST: FORM ROVE
ETHEL A. NICHOLS, City Clerk RANDAL A. HAYS, City Attorney
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C=TY OF REDD=NG
Electric Utility
1.990 RESOLyRCE pT.ZAN
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Draft Approved by Electric Utility Co®ission
February 7, 1991
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TABLE OF CONTENTS
SECTION PAGE
I. EXECUTIVE SUMMARY . . . . . . . . . . . . . . . . . . 1
A. Introduction and Purpose . . . . . . . . . . . . 1
B. Resource Plan Development . . . . . . . . . . . 4
C. Recommendations . . . . . . . . . . . . . . . . 5
II. PLANNING GOALS . . . . . . . . . . . . . . . . . . . . 8
III. CHANGES IN CONDITIONS AND EVENTS SINCE THE
1988 RESOURCE PLAN . . . . . . . . . . . . . . . . 11
A. Load Forecast . . . . . . . . . . . . . . . . 11
B. Rates . . . . . . . . . . . . . . . . . . . . 13
C. Regulatory and Legislative . . . . . . . . . 13
D. Price of Supplemental Resources . . . . . . . 14
E. Natural Gas Industry . . . . . . . . . . . 15
F. Contracts . . . . . . . . . . . . . . . . 15
i G. Generation/Transmission Projects . . . . . . . 16
H. Independent Power Producers . . . . . . . . . 17
I . Sacramento River . . . . . . . . . . . . . . . 17
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IV. FORECAST OF ELECTRIC POWER NEEDS . . . . . . . . . . 18
A. Forecasting Methodology . . . . . . . 18
B. Energy Conservation and Load Management . . . 25
C. Other Power Considerations . . . . . . . . . . 29
D. Adopted Forecast . . . . . . . . . . . . . . . 30
V. RESOURCE CONSIDERATIONS . . . . . . . . . . . . . . 44
A. Economics . . . . . . . . . . . . . . . . . . 44
B. Diversity . . . . . . . . . . . . . . . . . . 48
C. Autonomy . . . . . . . . . . . . . . . . . . . 49
D. Types of Resources . . . . . . . . . . . . . . 49
E. Transmission . . . . . . . . . . . . . . . . . 57
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F. Reserve Requirements . . . . . . . . . . . . . 58
G. Interutility Support . . . . . . . . . . . . . 60
H. Pooling . . . . . . . . . . . . . . . . . . . 60
I . Analysis . . . . . . . . . . . . . 61
VI. RECOMMENDED POWER RESOURCE DEVELOPMENT PLAN . . . . 64
A. Avoid High Cost Supplemental Power Purchases 64
B. Pursue Arrangements to Shape Loads & Resources 64
C. Pursue Development of Spring Creek Pumped
Storage Project . . . . . . . . . . . . . . . 65
D. Pursue Development Negotiations with
Independent Power Producers . . . . . . . . . 66
E. Pursue Transmission Access . . . . . . . . . . 66
F. Enhance Relationships With Western . . . . . . 67
G. Pursue Other Interutility Contracts . . . . . 67
H. Pursue Natural Gas-fired Resources . . . . . . 68
I . Pursue Economic Hydroelectric Projects . . . . 68
J. Pursue Conservation and Load Management Programs 68
K. Selectively Participate in Resource Projects 69
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TABLE OF CONTENTS
(Continued)
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TABLES . . . . . . . . . . . . . . . . . .
PAGE
1 Parameter Projections 1989-2009 . . . . . . . . . . 32
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2 Coincident Peak Demand for Electricity by Customer
Class . . . . . . . . . . . . . 33
3 Electrical Energy Use by Customer Class . . . . . . 34
4 Historic and Projected Parameter Growth Rates . . . 35
5 Estimated Effects of Conservation &
Load Management Programs . . . . . . . . . . . . . . 36
6 Projected Monthly Peak Demands . . . . . . . . . . . 37
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7 Projected Monthly Energy Requirements . . . . . . . 38
8 Total City Peak Demand Needs . . . . . . . . . . . . 39
9 Total City Electrical Energy Needs . . . . . . . . . 40
10 Recommended Plan . . . . . . . . . . . . . . . . . 73-74
FIGURES
1 Growth of Redding by Annexation . . . . . . . . . . 41
' 2 Coincident Peak Demand 42
3 Electric Energy Need . . . . . . . . . . . . . . . . 43
4 Capacity Outlook . . . . . . . . . . . . . . . . . . 75
5 Energy Outlook . . . . . . . . . . . . . . . . . 76
i 6 Energy Mix: Low Load Growth . . . . . . . . . . . . 77
7 Energy Mix: High Load Growth . . . . . . . . . . . . 78
8 Committed Capacity Outlook . . . . . . . . . . . . . 79
9 Committed Energy Outlook . . . . . . . . . . . . . . 80
APPENDICES
A. Future Resources
B. Acronyms
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CITY OF REDDING
Electric Utility
1990 RESOURCE PLAN
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I . EXECUTIVE SUMMARY
A. Introduction and Purpose
The City of Redding (Redding or City) is in a unique
position to meet its energy needs with a fiscally and
environmentally sound package. We are also presented
with an opportunity to clearly define our vision of
Redding' s energy future and to specify how we plan to
achieve those goals. Over the next 20 years, Redding
will need to make several decisions to acquire a
significant amount of resources to meet increased energy
needs. The magnitude of this resource commitment,
several 100 million dollars, makes the decisions very
important. Because Redding residents will pay for these
new resources through their electric bills, we believe
they should take an active part in this decision-making
process. This report has been prepared to encourage
community involvement.
Historically, Redding 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 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 opportunity for the City to
exercise some control over the cost and availability of
the resources needed to meet these demands. The program
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includes suitable City-owned generating resources,
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
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biennially.
The need for developing a resource plan that contains a
well balanced mix of power resources has been clearly
substantiated. 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°x. In addition, in 1984,
the City' s electric load exceeded Western' s contractual
limit and required the City y to purchase more expensive
supplemental power from PG&E during one month, at a total
cost of $64,000. By calendar year 1990, the City' s
electric load had grown to 173 Megawatts (MW) and
required the purchase of supplemental power from PG&E
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during six months, at a total cost of $5, 663 , 070. The
cost for purchased supplemental power is expected to
continue to grow rapidly unless the City develops other
lower cost sources of power.
If the rate of growth for the City' s electrical demand
continues at the same rate as experienced since 1980, the
City could expect its load to double in 12 years. The
forecast included in this plan, however, projects a
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reduction, not an increase, in the rate of growth. The
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projected reduction in growth rate is primarily due to
the assumption that the rate of annexing developed
property will diminish. The base forecast for the 1990
Resource Plan ( 1990 Plan) projects the City' s peak load
to grow by approximately 30% during the next ten years,
while the high forecast anticipates a 58% growth by the
year 2000.
The 1990 Plan updates the Planning Goals, Forecast of
! Electric Power Needs and Resource Considerations included
in the 1988 Resource Plan ( 1988 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 1988 Plan.
The 1990 Plan includes assumptions and data that are
current as of November 19901. The 1990 Plan should not
be interpreted to represent a commitment by the City to
a specific course of action. Rather, the purpose of the
1990 Plan is to serve as an aid in the process of
decision making for individual projects. Decisions will
be influenced by future conditions that may not
necessarily match the assumptions used to prepare this
1990 Plan.
1 During the late stages of the review process for this Plan, the Lake
Redding Hydroelectric Project was still an active project for the City. However,
on April 3, 1991, the Office of Hydropower Licensing at the Federal Energy
Regulatory Commission denied the City's license application for the Project. On
April 16, 1991, the City opted not to appeal the decision, thereby eliminating
the project as a potential resource. Consistent with the concept that this Plan
is not intended to represent a commitment, a last-minute revision of the entire
resource plan, exclusively, because of the late breaking development concerning
the Lake Redding Project would have been imprudent. However, all references to
the Lake Redding Project contained in this Plan are appropriately footnoted and
should be considered for illustrative purposes only.
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In evaluating the potential for developing new generating
resources, the Electric Department staff compares the
economics of such resources to the City' s incremental
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 that incorporate the most recent data
available are conducted to assess the benefits, costs,
risks, need, timing, acceptability, and environmental and
financial impacts of that project. 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
(EUC) , which is a seven-member commission of public
volunteers appointed by the City Council to serve in an
advisory role, reviews the analyses and forwards
recommendations to the Redding City Council. The 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.
B. Resource Plan Development
The 1990 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
assessment was conducted as suggested by the California
Energy Commission (CEC) in its forecasting guidelines
known as the Common Forecasting Methodology (CFM) .
Through use of the CEC guidelines, the assessment
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considered several parameters that 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 assessment.
Section VI discusses the recommended plan as of November
1990 to meet the forecasted need.
The planning goals utilized as the primary criteria for
the 1990 Plan are listed in Section II .
C. Recommendations
If the City is successful in the development of several
resources alternatives, and an aggressive load management
program, it will be able to avoid higher-cost supple-
mental 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
foresighted power resource development program that
emphasizes the need to acquire long-term economical
sources of reliable power.
2 . The City should develop projects, interutility
agreements, or agreements with private developers
that provide support for City-owned generation
resources and provide supplemental power
requirements needed to meet City loads in excess of
the power received from Western and City-owned
resources.
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3 . To ' maximize the benefits of future generation
resources , the City should develop agreements with
Western that 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.
4 . The City should continue with the implementation of
the demand side management program. Many demand
side management programs are becoming cost
competitive with new power projects and demand side
management often is more environmentally
responsible. Opportunities may soon exist to
expand the City' s existing demand side management
programs.
5 . The City should continue to work closely with
Western to ensure Redding obtains an equitable
share of the United States Central Valley Project
( CVP) peaking capacity ( if and when allocated) and
to protect the City' s existing 116MW CVP
allocation.
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6 . The City should continue to participate in power
pooling planning activities. Continued partici-
pation will ensure that the City has the
opportunity to participate on an equitable basis
within the power pool if and when it becomes opera-
tional.
Table 10 in the 1990 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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I� II. PLANNING GOALS
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Redding' s Electric Utility will support the City' s continued
economic growth and development by providing its citizens with
long-term, economical, efficient, reliable, and
environmentally responsible electric power.
j 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 customers
is a primary consideration in the analysis of alternative
power resources and programs. The ultimate test of any
resource plan is the ability to provide economical power
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B. Reliability and service levels will be maintained and
improved whenever possible.
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Dependable 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 utilities. This freedom will
allow the City the flexibility to acquire the least
costly power.
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D. Development of economic, local power resources is
preferred.
Whenever the costs are reasonably competitive, the
development of power projects that benefit the local
economy will be preferred over equivalent, but geo-
graphically distant projects. Sources of competitively
priced power will be sought from generation ancillary to
the primary business of a local firm--typically, power
produced from waste heat.
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iE. Power resources will be developed in an environmentally
responsible manner.
i 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.
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G. Load management and conservation programs will be
promoted and developed.
Load management will provide a means of reducing critical
peak load growth and will better utilize the City' s power
resources. Conservation programs will inform customers
of ways to efficiently utilize electricity and thus
reduce the demand on the electrical system.
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H. A healthy local economy will be encouraged.
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 1988 'RESOURCE PLAN
The Electric Utility operates in a complex, changing
environment. This strategic resource plan considers numerous
factors that may play a role in shaping City policy regarding
its electric utility. Most of these factors are changing
constantly. This section presents some of the major changes
that have occurred since adoption of the 1988 Plan. Examples
are:
• Load forecast
• Rates
• Regulatory and legislative
• Price of supplemental resources
' Natural gas industry
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• Contracts
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• Generation/transmission projects
• Independent Power Producers ( IPP)
• Sacramento River
A. Load Forecast
In 1989 , the City submitted its third biennial CFM filing
to the CEC. Two forecasting methodologies were used to
prepare this filing. Data were collected from a
residential end-use survey and incorporated into an end-
use model, wherein electric energy consumption was
forecasted based upon appliance saturation rates and
energy consumption values compiled by the CEC. The end-
use model results were found to be consistent with the
results of the second methodology, the econometric
forecast.
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The econometric forecasting methodology, which was also
used to prepare the 1988 Plan, involves the preparation
of a computer model based on historical data. The
econometric model develops a relationship between several
economic variables and load growth. The projected values
of the independent economic variables used to develop the
load forecast in the 1988 Plan were updated to prepare
the load forecast for the 1990 Plan. The forecast for
the 1990 Plan uses a lower rate of growth for all of the
independent variables except for commercial gas prices.
The Redding area continues to see a high level of
commercial and residential development. This
development, combined with additional electrical load
growth from annexations, has caused peak demand to grow
I by an average of 7 . 9% per year from 1978 to 1989 . The
forecast used in the 1990 Plan is consistent with the CEC
adopted forecast of load growth, for the period
1989-2009, with rates averaging 3 . 3% for demand and 3 . 4%
for energy. These growth rates are slightly lower than
the growth rates represented in the 1988 Plan. The
reduction is due mainly to upward estimates of the
effectiveness of conservation and load management
i programs. These programs are projected to play a
significant role in offsetting future load growth.
Redding' s estimated growth continues to exceed expected
state-wide averages.
The expected monthly peak load for Redding over the next
16 years can be found in Section IV of this Plan.
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B. Rates
Although Redding did not have a rate increase in 1988,
electric rates increased by an average of 6 . 5% in October
1989 . That rate increase was caused primarily by the
increased cost to purchase electricity from Western and
PG&E. Increases in Redding' s retail rates are expected
to slightly decrease the rate of growth in consumption of
electricity in the City.
In January 1990, PG&E established new rates for the
period through December 1993 . The new rates will
increase PG&E' s power rates to Redding by approximately
29% to 500 over the three-year period, depending on the
operation of the Diablo Canyon Nuclear Power Plant. On
October 1, 1989, Western raised its rates for purchased
power by 9.7% and plans to increase its rates by 3 . 4% in
1991. The combined effect of rate increases and load
growth is expected to cause the City' s purchased power
cost to grow from $20. 4 million in 1989 to $29. 0 million
in 1992 .
C. Regulatory and Legislative
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The CEC has exclusive siting jurisdiction over all
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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
limitation. Such a move could bring all thermal resource
options the City is considering under CEC jurisdiction.
Since 1988, there has been growing interest in opening
access to transmission markets. Regulatory or
legislative reform in transmission access is expected to
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occur in the next few years. This will assist Redding in
developing power resources distant from Redding.
The California Public Utilities Commission (CPUC) has
begun a Collaborative Process for Investor Owned
Utilities ( IOU) . This process will increase the IOU
stockholders ' profit if certain conservation and load
! management programs are expanded. The CPUC is currently
working with Western and CMUA to determine if similar
incentives can be arranged in order to expand energy
conservation and load management programs for publicly
owned utilities such as Redding' s.
D. Price of Supplemental Resources
Currently, the City' s only source of supplemental power
is PG&E. Subsequent to the 1988 Plan, the CPUC and PG&E
settled the rate issues that surrounded PG&E' s Diablo
Canyon Plant since its inception. The settlement was
instrumental in establishing electric rates between PG&E
and Redding for a three-year period beginning January
1990. The long-term forecast of PG&E capacity costs is
lower, while that of energy prices is slightly higher,
relative to the forecast presented in the 1988 Plan. The
forecast changes are due mainly to the resolution of the
rate treatment for Diablo Canyon and to upward revisions
in the prices for natural gas and oil.
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E. Natural 'Gas Industry
Several recent regulatory and market events have in-
creased the availability and reduced the price of natural
gas. These events have thus increased the viability of
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to purchases from PG&E. However, degradation of Shasta
County air quality has reduced the potential for
constructing natural gas fired electric generation
projects without exceeding air quality standards. The
cost of the resulting mitigation has reduced the
viability of gas-fired turbines.
F. Contracts
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I On March 22 , 1989, the Modesto-Santa Clara-Redding Public
j Power Agency (M-S-R) executed the Sale and Exchange
' Agreement with the Bonneville Power Administration (BPA) .
That agreement provides a 20-year power resource which,
depending on BPA' s long-term resource availability, may
convert and revert from either a firm power purchase, or
an exchange of M-S-R off-peak energy for firm peaking
capacity from BPA. Redding' s share of the M-S-R firm
power purchase shall initially be 15MW of capacity and
65,700 Megawatthours (MWH) of energy per year, and will
be effective as of the commercial operation date of the
California-Oregon Transmission Project ( COTP) . On July
31, 1996 , the purchase will increase for the remainder of
the contract term to 22. 5MW of capacity and 98,500MWH of
energy. If the agreement converts to an exchange, BPA
will continue to provide Redding summer capacity in
exchange for Redding delivering BPA 180, 000MWH ( 270,000
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after July 31, 1996 ) during the winter.
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In ;June '1990 , Redding and the other M-S-R members signed
the Pacific Northwest Sales Agreement between M-S-R and
its members. This agreement establishes the necessary
obligatory relationships between M-S-R and its three
members for the purchase, use, and exchange requirements
' of the BPA/M-S-R Sales and Exchange Agreement.
G. Generation/Transmission Projects
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None of the projects identified in the 1988 Plan have
been deferred or abandoned'. However, the projected
operational dates of several projects have been postponed
one to three years in the 1990 Plan as a result of a
number of regulatory and economic influences. The
revised operational dates are provided in Section VI of
this plan.
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Groundbreaking for the COTP took place on October 15,
1990 . The COTP, which is a 500kV transmission line
extending from the California-Oregon border into the San
Francisco Bay Area, is scheduled for completion in 1993
and will eventually provide the City with access to low-
cost power resources within California and throughout the
Pacific Northwest.
In November 1989, Airport Substation was placed into
service, further enhancing the reliability of Redding' s
electric system. This substation provides the City with
a second point of delivery from Western' s system and
increases the total transfer capability between the two
systems from 160MW to 275MW.
' See footnote regarding Lake Redding on Page 3 for exception.
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H. Independent Power Producers
The City has received numerous inquiries from IPPs
interested in selling either electrical power or power
projects to the City. The significant increase in IPP
inquiries results from the City' s greater forecasted need
for power, and from fewer opportunities for IPP sales to
the IOUs because of less favorable government mandated
incentive programs supporting IPPs.
In response to the IPP inquiries, the City has developed
a Resource Project Questionnaire Packet (Resource
Packet) . The Resource Packet includes a description of
the Electric Utility' s operating parameters, projected
needs, and the project review process. Also included are
a short initial questionnaire and a comprehensive final
questionnaire for the IPP to complete. The Resource
Packet provides a consistent means for evaluating
projects, and also streamlines the review process. Thus
far, several IPPs have completed the Resource Packet and
their projects are being evaluated.
I . Sacramento River
The declaration of the winter run salmon as a federal
threatened species and a state endangered species, along
with the increased general public' s concern about the
Sacramento River, has increased the difficulties
associated with developing hydroelectric projects within
the Sacramento River drainage.
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IV. FORECAST OF ELECTRIC POWER NEEDS
The forecast of future electric power needs of the City is a
cornerstone of the 1990 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 MW and
the total City energy requirements in gigawatthours (GWH) for
the planning period of City fiscal years 1990-2009.
A. Forecasting Methodology
1 . Energy
Historic energy consumption by customer class was
compiled on a monthly basis for the thirteen-year
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idential and commercial class customers
historically have been responsible for about 90% of
Redding' s total energy sales. Recognizing the
significance of these customers to total system
load, the parameters that affect load growth for
each of these two classes were evaluated. A
computer model, using several of the parameters,
was then developed to forecast energy usage for the
residential and commercial classes.
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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 sum of the residen-
tial and commercial classes.
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Several parameters that may affect load growth were
tested to determine their effects on the City' s
historical load growth between January 1976 and
December 1988. Regression analysis was used to
I determine the relationship, if any, of the tested
i parameters to the amount of energy sold. The
following parameters were found to have a signif-
icant statistical effect and were therefore used in
the computer model to project energy consumption
through 2009.
(a) Number of Electric Customers:
As expected, this parameter is a significant
determinant in the amount of energy needed by
the City.
Historically, the number of Electric Utility
customers does not match the ratio of the
Redding population divided by the average
+ number 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
i
before all of the customers are transferred
over to the City' s Electric Utility. This
time lag is due primarily to the protracted
negotiations and legal actions required to
acquire PG&E facilities.
(b) Disposable Personal Income:
Personal income was determined to have an
effect on electricity consumption. An in-
crease in income contributes to a slight
increase in electricity consumption. Shasta
Draft: EDC Recommended: 2/7/91
j rc/r/9 19
1
11
1
County income per capita was used to establish
i
the historic relationships. Future personal
I
income growth is projected to improve
significantly from that represented in the
historic period due to the projected evolution
of the local economy toward the manufacturing
and services sectors.
i
(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
i are a measure of space heating or cooling
requirements. The greater the value of
heating and cooling degree days, the greater
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
customer-class revenues divided by total
customer-class kilowatthour (KWh) sales and
was adjusted by the Consumer Price Index to
constant 1987 dollars.
iDraft: EDC Recommended: 2/7/91
rc/r/9 2 Q
I
I
i
i
i
(e1 Annexations:
Annexations by the City have played an
important role in load growth of Redding' s
electric system over the historic period ( see
Figure 1 ) . Some areas have been annexed but
i have not yet received electric service from
the City. The areas within the Redding city
limits that have not yet received electric
I
service represent future increases in load.
These increases have been explicitly
considered in developing the load forecast by
adjusting the forecasted number of customers
within the commercial and residential classes
by the estimated number of customers
associated with each annexation. The effect
of minor future annexations was included in
the number
of customers projected
econometrically. Major future annexations
were not included in the base forecast of
future need; instead, those believed likely to
occur in the near term were accounted for
explicitly by their addition to base forecast
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
1989-2009 of some of the parameters used to
forecast future electric power needs.
Heating/cooling degree days projections were
essential for explaining the historical test
Draft: EUC Reca®ended: 2/7/91
rc/r/9 21
i
period. However, in the forecast, due to the
unpredictable nature of the weather, the projection
of degree days was held constant at a value equal
to the historical average daily temperature 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 1980-1988. 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 conditions, the Redding system annual load
factor was assumed to improve steadily from 44. 6%
in 1988 to 51. 4% by the year 2009.
3 . Forecast of Customer Needs
Table 2 lists historical and projected electrical
demand by customer class. Table 3 lists historical
and projected electrical energy use by customer
i
class. The effects of existing energy conservation
and load management programs are included in
Tables 2 and 3 .
Draft: EUC Rec:o®ended: 2/7/91
rc/r/9 22
ii
I
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 increased by 3000
during the 1983-1986 time period. Second, in
1984, the City began to purchase higher-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
pursuing 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.
Draft: EOC Recommended: 2/7/91
rc/r/9 23
Historically, the economy was based
predominantly on the lumber industry. The
lower historic growth in personal income is
directly attributable 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 sectors, 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 customers grew at
a compound annual rate of 10. 3% during the
period 1977-1986, while the population of
Redding grew at a compound annual rate of 4. 2%
over the same period. These high growth rates
were due largely to the effects of several
annexations during the period 1977-1985. Over
the longer term of the forecast period ( from
1989 to 2009) , 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 similar pro-
jected rates of growth in residential and
commercial customers.
Draft: EDC Recommended: 2/7/91
rc/r/9 24
1
• i
B. Energy Conservation and Load Management
I
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 electrical 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 conservation 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 each of the
programs, with estimates of the impact of existing and
future programs. In order to show the effects of not
developing the proposed conservation and load management
in the final forecast of
programs power needs, the
capacity and energy expected to be saved by these
programs were added to the forecasted customer-use pro-
jections.
The conservation and load management programs considered
were:
s
i
i
Draft: EOC Recommended: 2/7/91
rc/r/9 25
i
1 . Air Conditioning Load Management (ACLM)
The ACLM program is designed to reduce peak elec-
trical demand during summer months. The program
requires the installation of radio-activated con-
trol switches on customer air conditioning units,
thus allowing the City to selectively cycle the air
i
conditioners from a central location.
i
d
In 1984, load control switches were installed on
all eligible City-owned air conditioning equipment.
An 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 conditioning, which is approximately equal to
6kW of electrical capacity reduction.
A total of 326 load control switches, controlling
2,188 tons of cooling, have been installed. The
total load reduction, using a cycling strategy of
10 minutes every half hour, is approximately . 8MW.
Under emergency conditions, the load reduction is
estimated at 2 . 2MW.
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 equip-
ment before 2 : 30 p.m. and after 6: 30 p.m. is peri-
odically mailed to pool owners.
The Residential Energy Survey completed in the
second quarter of 1987, revealed that approximately
Draft: EOC Recc®ended: 2/7/91
rc/r/9 26
i
110 of residential customers ( i.e. , about 2 , 570
customers) have some type (above or below ground)
of swimming pool. The Residential Energy Survey
also revealed that about 31% of residential
customers who have swimming pools operate their
pool filters between the hours of 2 : 30 p.m. and
6: 30 p.m. on hot summer weekdays. Thus, only about
855 customers with pools were participating in the
program at the time of the survey. The SPLM load
reduction was estimated to have been . 5MW in 1987 ,
and is projected to be 1. 3MW by 2009.
! 3 . Load Curtailment Load Management (LCLM)
The LCLM program consists of the voluntary re-
duction of electrical usage by certain large-use
customers and by the general public. Most City
pumping loads are also shut down or placed on
stand-by generators. This program is put into
effect only at such times as the electrical system
is approaching peak load conditions. Customers are
notified by telephone and by radio and television
announcements of the need to reduce their use of
electricity. In 1987, this program reduced peak
demand by an estimated 3 . 2MW, and is projected to
reduce peak demand by 3 . 8MW in 2009.
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.
Draft: EDC Reco®ended: 2/7/91
rc/r/9 27
4 . Efficiency 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,
refrigeration, and other major appliances.
Estimates developed from the Residential Energy
Survey project energy and load reduction impacts of
25. 1GWH and 12. 5MW by 1994, and 84. 6GWH and 47MW by
the year 2009.
5 . Other Conservation Activity
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.
Draft: EOC Recommended: 2/7/91
rc/r/9 28
i
6 . Street Lights
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 pro-
gram saved 1. 1GWH in 1987 and will save 3GWH by
2009 .
I
7 . Interruptible Customers
i
t In 1984, the City established a rate for inter-
ruptible service that 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
1990, the Electric Department staff estimates that
up to 7. 6MW of interruptible load will be available
by 2009.
C. Other Power Considerations
1. Losses
Losses account for electricity 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
1990 Plan to account for efficiency improvements in
Draft: EUC Recommended: 2/7/91
' rc/r/9 29
the City' s distribution system, 'therefore, losses
were expected to improve to 6 . 1%.
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 and lower in the spring and fall.
Monthly power requirements projections of total
customer load plus losses for 1989-2004 for
i
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
2009. 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 1978-1989 was 7 . 9% and is expected to
be 3 . 3% for the period 1989-2009. The compound annual
growth in energy for the historical period 1978-1989 was
7 . 1% and is expected to be 3 . 4% for the period 1989-2009.
These growth rates are higher than the growth rates dis-
cussed 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.
Draft: EDC Recommended: 2/7/91
rc/r/9 3 0
It 'shouid also be noted that, while the forecast results
discussed above are consistent with the City' s CFM 8
filing, the near-term historical trend shows a much
higher rate of growth. The CFM process is by nature
conservative. The City has historically exceeded the
growth rate predicted by earlier CFM forecasts.
Therefore, it would not be unreasonable to consider an
alternative forecast which assumes a higher annual growth
which is consistent with the historical trend.
I
For planning purposes, we consider the growth predicted
by the CFM process as the low load growth scenario.
While the growth predicted by the historical trend is the
high load growth scenario. The high load growth
scenario' s compound annual growth in capacity for the
1989-2009 period is on the order of 4 . 8%, and for energy,
a rate of some 5. 5%. The capacity and energy
requirements suggested by these alternative growth rates
are represented in Figures 2 and 3 as the top-most dashed
line which depicts the aggregation of the projected
components of capacity and energy needs, respectively.
Draft: EQC Recommended: 2/7/91
rc/r/9 3 1
1
TABLE 1
9
I CITY OF REDDING
1990 RESOURCE PLAN
PARAMETER PROJECTIONS 1989 - 2009
REAL PRICE 3/
1/ REAL PERSONAL 2/ OF ELECTRICITY
NUMBER OF INCOME ------------------------
YEAR CUSTOMERS PER CAPITA RESIDENTIAL COMMERCIAL
1989 29, 649 13 ,464 5. 17 5. 84
1990 30, 853 13 , 649 5.07 5. 68
1991 32 ,079 13 , 836 5. 13 5 .70
1992 33 , 321 14, 026 5. 16 5. 67
1993 34, 572 14,219 5. 18 5. 63
1994 35, 825 14, 398 5. 25 5 . 68
1995 37, 078 14, 580 5. 18 5. 58
1996 38, 334 14,765 5. 25 5. 65
1997 39, 590 14, 952 5. 31 5. 69
1998 40,848 15, 141 5. 40 5 .78
j 1999 42,069 15, 332 5. 37 5.73
2000 43 , 254 15,526 5. 42 5.76
2001 44,434 15,722 5. 27 5. 63
2002 45, 610 15, 921 5. 07 5. 45
2003 46,780 16, 122 4. 97 5. 37
2004 48,007 16,326 4. 79 5. 19
2005 49,293 16,533 4. 59 5.02
2006 50, 570 16,742 4. 38 4. 81
2007 51,837 16 , 953 4. 21 4 . 65
2008 53 ,093 17,168 4. 01 4. 45
2009 54, 343 17 , 385 3. 86 4 . 29
1/ Residential customer growth rates are based on econometric
and City of Redding, Department of Urban Planning
projections, including estimates of future annexations.
Commercial customers are forecast through an estimated
relationship between the City's population and the number of
commercial customers.
2/ 1987 Dollars.
i
3/ 1987 cents/kWh, projections recognize an intent to gradually
equalize the average costs of electricity for commercial and
residential customers.
Draft: EUC Recommended: 2/7/91
rc/r/9 3 2
TABLE 2
CITY OF REDDING
1990 RESOURCE PLAN
i
FISCAL YEAR
COINCIDENT PEAK DEMAND FOR ELECTRICITY BY CUSTOMER CLASS
i (MEGAWAT`"S)
i
1
TOTAL
YEAR CUSTOMER
i ENDED RESIDENTIAL COMMERCIAL INDUSTRIAL AGRICULTURAL GOVERNMENTAL DEMANDI/
1978 25 31 1 0.1 3 60
1979 32 35 2 0. 1 3 72
1980 47 43 2 0. 1 4 96
1981 53 42 3 0.1 4 102
1982 56 45 3 0. 1 4 108
1983 53 41 3 0.1 3 100
1984 54 42 3 0.1 3 102
1985 57 46 3 0.1 4 110
1986 61 50 3 0.1 4 118
1987 64 53 3 0.1 4 125
1988 66 58 3 0.2 5 133
1989 71 61 4 0.2 6 142
1990 66 63 4 0.2 5 138
1991 76 71 5 0.2 6 159
1992 77 72 5 0.2 6 160
1993 78 73 5 0.2 6 162
1994 79 74 6 0.2 9 168
1995 80 75 6 0.2 9 170
1996 81 77 6 0.3 9 174
1997 84 79 7 0.3 9 179
1998 87 82 7 0.3 9 185
1999 90 84 8 0.3 9 190
2000 93 86 8 0.3 9 196
2001 96 88 9 0.3 9 202
2002 100 90 10 0.4 9 209
I
2003 104 93 10 0.4 9 216
2004 108 96 11 0.4 8 223
2005 112 98 12 0.4 8 230
2006 117 100 13 0.4 8 238
2007 122 103 13 0.5 8 246
2008 126 105 14 0.5 8 254
2009 131 108 15 0.5 8 262
* Compound Annual Growth Rate: 1978-88 = 8.3%
1989-09 = 3.1%
1/ Totals may not add due to rounding.
Draft: EDC Recommended: 2/7/91
rc/r/9 3 3
1
TABLE 3
CITY OF REDDING
i 1990 RESOURCE PLAN
FISCAL YEAR
ELECTRICAL ENERGY USE BY CUSTOMER CLASS
(GIGAWATTHOURS)
TOTAL
YEAR CUSTOMER
ENDED 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
I 1981 211 185 19 0.4 16 431
i 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 255 243 21 0.6 23 542
1989 268 255 24 0.6 21 569
1990 275 258 25 0.6 21 580
i 1991 304 281 29 0.7 22 638
1992 318 289 31 0.7 23 660
1993 333 299 33 0.8 23 688
1994 348 309 35 0.8 23 716
1995 363 316 37 0.8 23 741
1996 377 325 39 0.9 23 766
1997 390 333 41 0.9 23 789
1998 403 340 44 1.0 23 811
1999 417 348 46 1.0 23 835
2000 431 356 48 1.0 23 859
' 2001 447 364 51 1. 1 23 885
i 2002 465 372 54 1.1 23 915
2003 482 381 56 1.2 23 944
2004 500 390 59 1.2 23 973
2005 519 400 63 1.3 22 1004
2006 538 410 66 1.4 22 1037
2007 557 420 69 1.4 22 1069
2008 575 430 73 1.5 22 1101
2009 593 441 76 1.5 21 1132
Compound Annual Growth Rate: 1978-88 = 7.30
1989-09 = 3.5%
1/ Totals may not add due to rounding.
i
i
Draft: EUC Recommended: 2/7/91
rc/r/9 34
i
i
i
TABLE 4
CITY OF REDDING
1990 RESOURCE PLAN
Historic and Projected Parameter Growth Rates
PROJECTED
ANNUAL AVERAGE ANNUAL AVERAGE
COMPOUND GROWTH COMPOUND GROWTH
PARAMETER RATE 1977-1986 RATE 1987-2009
------------------------- --------------- ---------------
REAL RESIDENTIAL PRICE OF 5 .70 -0. 50
ELECTRICITY
REAL COMMERCIAL PRICE OF 6.7% -1. 4%
ELECTRICITY
REAL PERSONAL INCOME 0. 30 1. 3%
PER CAPITA
NUMBER OF CUSTOMERS 10. 30 3 . 3%
1
I
Draft: EUC Recommended: 2/7/91
rc/r/9 35
i
TABLE 5
CITY OF REDDING
1990 RESOURCE PLAN
ESTIMATED EFFECTS OF CONSERVATION & LOAD MANAGEMENT PROGRAMS
i
1987 1994 2001 2009
GWH MW GWH MW GWH MW GWH MW
PROGRAM 1/
I
AIR CONDITIONING N 0.7 N 1.0 N 4.4 N 10.5
LOAD MANAGEMENT
PROGRAM (ACLM)
SWIMMING POOL N 0.5 N 0.8 N 1.1 N 1.3
LOAD MANAGEMENT
PROGRAM (SPLM)
LOAD CURTAILMENT 0.1 3.2 0.2 3.4 0.2 3.5 0.2 3.8
LOAD MANAGEMENT
(LCLM) PROGRAM 2/
EFFICIENCY N 0.0 25.1 12.5 50.1 27.9 84.6 47.0
STANDARDS
OTHER CONSERVA- N N 0.6 N 1.2 N 2.1 N
TION ACTIVITY
STREET LIGHTS 1.1 N 2.1 N 2.9 N 3.0 N
INTERRUPTIBLE N N N 2.2 N 4.1 N 7.6
CUSTOMERS
--- --- ---- ---- ---- ---- ---- ---
TOTAL: 1.2 4.4 28.0 19.8 54.5 41.0 89.9 70.1
N = Negligible
1/ Effects of existing and proposed load management and conservation
programs are combined.
2/ Includes STEP advertising campaign.
Draft: EDC Recommended: 2/7/91
rc/r/9 36
TABLE 6
CITY OF REDDING
1990 RESOURCE PLAN
PROJECTED
PROJECTED MONTHLY PEAK DEMANDS (MW) 1/
i (FISCAL YEARS 1989-2004)
MONTH 1989 1990 1991 1992 1993 1994 1995 1996
--------------------------------------------------------
JUL 154 * 151 * 168 * 175 177 182 186 189
AUG 146 * 144 * 173 * 174 177 182 185 189
SEP 147 * 121 * 133 * 160 162 167 170 173
OCT 108 * 90 * 118 119 120 124 126 129
NOV 95 * 102 * 120 121 122 126 128 131
DEC 114 * 110 * 144 145 147 152 155 158
JAN 117 * 113 * 135 136 138 143 145 148
FEB 122 * 116 * 121 122 124 128 130 133
MAR 102 * 102 * 115 116 118 122 124 126
APR 92 * 92 * 110 111 113 116 118 121
MAY 106 * 115 * 146 147 149 154 157 160
JUN 132 * 151 * 166 168 170 175 178 182
--------------------------------------------------------
MW-MO 1437 1406 1650 1694 1718 1772 1801 1839
PEAK 154 151 173 175 177 182 186 189
MONTH 1997 1998 1999 2000 2001 2002 2003 2004
--------------------------------------------------------
JUL 195 201 207 214 220 228 236 243
AUG 195 201 207 214 220 227 235 242
SEP 179 184 190 196 202 208 216 222
OCT 133 137 141 146 150 155 160 165
NOV 135 139 143 148 152 157 163 168
DEC 163 168 173 178 183 190 196 202
JAN 153 157 162 167 172 178 184 190
FEB 137 141 145 150 154 159 165 170
MAR 130 134 138 143 147 152 157 162
APR 125 128 132 136 140 145 150 155
MAY 165 170 175 181 186 192 199 205
JUN 188 194 199 206 212 219 227 233
--------------------------------------------------------
MW-MO 1897 1956 2012 2078 2137 2210 2288 2358
PEAK 195 201 207 214 220 228 236 243
* Actual Data
1/ Includes effects of present load management
however does not include reserves.
i
Draft: EOC Recommended: 2/7/91
' rc/r/9 3 7
TABLE 7
CITY OF REDDING
1990 RESOURCE PLAN
PROJECTED
PROJECTED MONTHLY ENERGY REQUIREMENTS (GWH) 1/
(FISCAL YEARS 1989-2004)
MONTH 1989 1990 1991 1992 1993 1994 1995 1996
-----------------------------------------------------------
JUL 67 * 62 * 72 * 72 75 78 80 83
AUG 61 * 59 * 66 * 71 74 77 80 82
SEP 51 * 49 * 56 * 58 60 62 65 67
OCT 45 * 46 * 49 50 53 55 57 59
NOV 46 * 46 * 49 51 53 56 57 59
+ DEC 53 * 54 * 65 67 70 73 76 78
JAN 55 * 55 * 63 65 68 71 74 76
FEB 48 * 50 * 49 51 53 55 57 59
MAR 48 * 48 * 52 54 56 59 61 63
! APR 44 * 44 * 46 48 50 52 54 56
MAY 45 * 48 * 52 54 57 59 61 63
JUN 53 * 55 * 59 61 64 66 68 71
--- --- --- --- --- --- --- ---
TOTAL 615 615 678 703 733 762 789 816
High 67 62 72 72 75 78 80 83
Low 44 44 46 48 50 52 54 56
MONTH 1997 1998 1999 2000 2001 2002 2003 2004
--------------------------------------------------------
JUL 86 88 91 93 96 99 102 105
AUG 85 87 90 93 95 99 102 105
SEP 69 71 73 75 77 80 82 85
OCT 60 62 64 66 68 70 72 74
NOV 61 63 65 67 69 71 73 75
DEC 81 83 85 88 90 93 96 99
JAN 78 80 83 85 88 91 94 97
FEB 61 62 64 66 68 70 72 75
MAR 65 66 68 70 72 75 77 80
APR 57 59 61 63 64 67 69 71
MAY 65 67 69 71 73 75 78 80
JUN 73 75 77 79 82 85 87 90
--- --- --- --- --- --- --- ---
TOTAL 840 864 889 915 942 974 1005 1036
High 86 88 91 93 96 99 102 105
Low 57 59 61 63 64 67 69 71
* Actual Data
1/ Includes effects of present energy conservation
programs.
i
Draft: EDC Recommended: 2/7/91
rc/r/9 38
TABLE 8
CITY OF REDDING
1990 RESOURCE PLAN
I FISCAL YEAR
TOTAL CITY PEAK DEMAND NEEDS
t MEGAWATTS
I TOTAL TOTAL TOTAL FUTURE
YEAR CUSTOMER DEMAND SYSTEM LOAD TOTAL*
ENDING DEMAND LOSSES DEMAND MANAGEMENT DEMAND 1/
1
( 1) ( 2) ( 3 ) ( 4 ) ( 5 ) ( 6 )
( 2) + ( 3 ) ( 4) + ( 5 )
1978 60 7 67 2/ 67
1979 72 5 77 Z/ 77
1980 96 7 103 Z/ 103
1981 102 7 109 Z/ 109
1982 108 8 116 Z/ 116
1983 100 7 107 2/ 107
1984 102 7 109 Z/ 109
1985 110 8 118 Z/ 118
1986 118 8 126 Z/ 126
1987 125 11 136 Z/ 136
1988 133 12 145 2/ 145
1989 142 13 155 Z/ 155
1990 138 12 151 Z/ 151
1991 159 14 173 Z/ 173
1992 160 14 175 Z/ 175
1993 162 15 177 2/ 177
1994 168 15 182 -1 183
1995 170 15 186 1 186
1996 174 16 189 1 191
1997 179 16 195 1 197
1998 185 17 201 2 203
1999 190 17 207 3 210
2000 196 18 214 3 217
2001 202 18 220 4 224
2002 209 19 228 4 232
2003 216 19 236 5 240
2004 223 20 243 5 248
2005 230 21 251 6 257
2006 238 21 260 7 266
2007 246 22 268 7 276
2008 254 23 277 8 285
2009 262 23 285 9 295
* Compound Annual Growth Rate: 1978-88 = 8.0%
1989-09 = 3.3%
1/ Total demand (Col. 6) excludes reserves.
2/ Effects of present load management are included in Total
Customer Demand (Col. 2) .
Draft: EUC Recommended: 2/7/91
rc/r/9 39
TABLE 9
CITY OF REDDING
1990 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 T/ 339
1980 402 28 430 T/ 430
1981 431 30 461 T/ 461
1982 443 39 482 _T/ 482
1983 437 30 466 1/ 466
1984 435 29 464 T/ 464
1985 483 29 512 T/ 512
1986 484 31 515 T/ 515
1987 507 34 541 T/ 541
1988 542 24 566 1/ 566
1989 569 46 615 T/ 615
1990 580 35 615 T/ 615
1991 638 41 679 T/ 679
j 1992 660 43 703 _T/ 703
1993 688 45 733 0 733
1994 716 47 762 1 763
1995 741 48 789 1 789
1996 766 50 816 1 816
1997 789 51 840 1 841
1998 811 53 864 1 865
1999 835 54 889 1 890
2000 859 56 915 1 916
2001 885 57 942 1 943
2002 915 59 974 1 975
2003 944 61 1005 1 1006
2004 973 63 1036 1 1037
2005 1004 65 1070 1 1071
2006 1037 67 1104 2 1106
2007 1069 69 1139 2 1140
2008 1101 72 1172 2 1174
2009 1132 74 1206 2 1208
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* Compound Annual Growth Rates: 1978-88 = 6. 9%
1989-09 = 3 . 4%
2/ Effects of present load management are included in Total
Customer Use (Col. 2 ) .
Draft: EDC Recommended: 2/7/91
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CITY OF REDDING
1990 POWER RESOURCE PLAN
COINCIDENT PEAK DEMAND
40o HISTORIC PROJECTED
37s
,..
TOTAL OfJWJD (H(-GROVYM) I /
.................... •t' ............. i
I /
325
~ TulAL DEWWD
300
FUTURE LOAD AIA►iAGFLFNr
275 .......... r .............250
i
TOTAL NET CUSTOMER DEMAND
ca
175 •: : /
/
so =1'
��'qm a�
ttt.
:...
2s y-f
CouufaAL
100 i
:
•:
. .
75 �
s: = ........
50
............
................
............. i..........*.. **.*,,** I
RF�SDEITU,L
:.
0
78 80 85 90 95 2000 05 9
YEARS ENDING JUNE 30th �'or
RJ mom
FIGURE 21 pwl
42 nsir►
CITY OF REDDING
1990 POWER RESOURCE PIAN
i ELECTRIC ENERGY NEED
HISTORIC PROJECTED
1800
,�� ! /1
:{': MAL ENERGY (HI-GROWN)
1600 I
r
1500
I ......... i t I
?QUL ENERGY REQUiRBAENT /
1400 f
1300 ! MIRE LMD MANAGE),IENT
1200
.............
1100 .... . .. :.•.•::.
iuiu r
t
900
:r: TOTAL NET (ENERGY SALES
800 Z�o
t9 700 :{. // O1fifR QASSES
/
600 I
*: t '
400 _ .....:. .:.. ... I COWIERgA1
...........
�/�/� ..:... ................
.AN ..............{•.:::::::.•:::.•:
200
100 : : I i
:. i
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78 80 85 90 95 2000 05 09
YEARS ENDING JUNE 30th
arr m
71GURE 7 Imp
43 lLECTAMM
maim
V. RESOURCE `CONSIDERATIONS
Development of power resources to meet customer needs is a
complex process under which the Electric Utility must try to
mesh economic, reliability, and environmental goals listed in
Section II of this plan. Several factors must be evaluated.
As detailed below, these include economics, diversity,
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autonomy, resource type, whether adequate interutility support
and reserves are available, and transmission.
A. Economics
Several factors affect the economics of a resource. Among
them are:
1. Fixed Costs
The fixed costs of a resource are those that are
incurred regardless of how much power is produced. The
most notable fixed cost is debt service on the capital
required to build a project. In general, a resource' s
fixed costs are expressed in $ per kW-year or $ per kW-
month.
2 . Variable Costs
The variable costs of a resource are those that result
from the amount of power produced. The most
significant variable cost is usually fuel. Depending
upon how a fuel supply contract is structured, fuel
cost during a time period when a resource does not
produce power could be zero. Variable costs are
expressed on a per-kWh basis.
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3 . Fuel Supply
' The viability of many resources depends on the future
availability and cost of fuel. Resources that utilize
a fuel with a history of large price fluctuations or
supply interruptions are not as attractive as those
with more stable fuel supplies.
4. Cost Escalation
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j For most resources, some or all of the associated costs
escalate in time. This is especially true under
purchase contracts where costs are often escalated
using either fixed percentages or a widely accepted
published index (e.g. , Producer Price Index) . Fixed
percentages allow both buyer and seller to precisely
forecast future contract prices but these future prices
may not accurately reflect future market conditions.
Conversely, although published indices can often track
future market conditions, they may not be accurately
forecasted. City-owned resources also have escalating
costs. In addition to fuel costs, such costs as
operation and maintenance must be forecasted. To do
this, certain assumptions for cost escalation must be
made.
5 . Summer Dependable Capacity
In Redding, electric utility customer demand is highest
during the summer. The amount of power a resource can
reliably generate during peak customer demand periods
determines its dependable capacity. For example, some
hydro projects that generate inexpensive energy during
high river flow conditions but generate little during
the City' s summer peak have lower dependable capacities
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than `resources such as
gas-fired combustion turbines,
which can usually generate at full load.
6 . Reliability
Resources with a history of unexpected outages or an
unreliable fuel supply are not as valuable as those
that can be depended on for nearly continuous
operation.
7 . Useful Life
Resources that can continue operation without major
capital improvements, long past the time when the
associated debt is retired, are economically more
attractive than those which cannot. Hydroelectric
projects are a good example of this type of resource.
8. Ability To Schedule
Customer electrical requirements vary with time of day
or week. Resources that can be scheduled to "follow
load" are capable of reducing or increasing their
generation coincident with these fluctuating customer
requirements. Some resources are not capable of
following load and thus often produce excess energy.
If the City has too many of these types of resources,
it may have to sell this excess energy at below cost.
Resources that can increase output during on-peak hours
and decrease output during off-peak hours are usually
more economical than those that cannot vary their
output.
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9 . (:ontingencies/Risks
Some resources such as geothermal projects , have higr
development risks where high investment may be requires
to drill exploratory steam holes without any guarantee
of eventual usable steam. Others may require
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substantial environmental mitigation and thus entail
financial risk. Contingencies such as these car
greatly affect the cost/benefit relationship for a
particular resource type.
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10 . Capacity-Related Charges
Under most wholesale purchase contracts,
i capacity-related 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
i 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 otherwise would incur significant
capital expenditures (debt service) throughout the year
to supply peak capacity only a few times each year.
For example, some rate schedules require that up to 94%
of the cost for capacity supplied in a summer month
must also be paid for in the other it months even if
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1 power is not delivered during those 11 months.
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Residual capacity charges are becoming increasingly
popular as the costs for new capacity continues to
rise. This factor will become more important in the
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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
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development of power
projects and load management
programs which minimize capacity-related charges.
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B. Diversity
Resource diversity is a measure of a utility' s ability to
meet its customers ' electrical requirements under a variety
of conditions and at a minimum of risk. A diverse resource
mix generally includes some resources designed to operate
at a fixed level for long periods and some designed to vary
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their operational levels as customer demand varies. A
diverse mix also implies resources based on varying types
of technology and/or fuel supply.
Diversity helps ensure a utility' s rates are not impacted
greatly by fluctuation in the cost of just one resource
type. Without diversity, a utility may be forced to
significantly raise its rates if there are significant
increases in the cost of power from a particular resource
type. For example, the City presently relies primarily on
power purchased from Western. Therefore, the City' s
diversity is currently low. When Western recently imposed
a 300% rate increase, the City had no choice but to pass
significant rate increases on to retail customers. To
I avoid this in the future, diversity necessarily will be an
important consideration in the development of City
resources.
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C. Autonomy
The City is one of a few public power entities in
California that is not directly interconnected to a major
IOU system. As a result, one other goal in developing
f power resources for the City is to remain independent from
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constraining arrangements which preclude the City from
taking advantage of other resources. The existing PG&E
contract is an example of such a restrictive arrangement.
The contract automatically terminates if Redding utilizes
a power resource other than PG&E or Western.
In the future, by developing alternatives from a number of
1 sources, the City will be able to retain its flexibility
and independence, and therefore retain its autonomy.
D. Types of Resources
A host of environmental, technical, contractual, and
political issues must be addressed for every possible
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resource. The following discussion addresses some of the
key considerations for most industry-accepted electric
power resources:
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1 . Hydroelectric Pumped Storage Projects
Hydroelectric pumped storage units, though basically
net energy users, are designed to supply power during
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. Pumped storage
units also act as good generation management tools.
Because they provide an off-peak load source, they tend
to make a utility' s overall load characteristics
smoother. In doing so, they also provide for more
efficient non-cyclic operation of the utility' s other
resources.
2 . Other Hydroelectric Projects
New large hydroelectric projects are virtually
impossible to construct because most environmentally
acceptable sites are already in use. Small
hydroelectric projects have also inherited their share
of environmental siting problems. The availability of
local sites and their ability to produce summer
dependable capacity, however, help keep some small
hydro projects potentially attractive.
3 . Cogeneration/Independent Power Projects
In the last several years, cogeneration and independent
power projects have been popular among venture
capitalists. Cogeneration projects usually entail an
industrial process where both steam and electricity are
produced from heat. The steam is usually used on site,
sold to the local utility, or a combination of both.
IPPs produce power only, sell all power to a
Draft: EDC Recommended: 2/7/91
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contracting utility, and derive power from many
different sources.
During the early 1980s, private developer interest was
due primarily to Public Utility Regulatory Policy Act
(PURPA) mandates that required utilities to purchase
all qualified cogeneration output at the utilities
"avoided cost" which was generally higher than market
value. Recently, however, several developers have
proposed projects that benefit both the utility and the
developer, independent of PURPA.
! In the early and mid-1980s, cogeneration/IPP plants
developed at a rapid rate with entrepreneurs taking
advantage of PG&E' s high "avoided cost" purchase
contract. Since PG&E has established a waiting list
for transmission capacity and subsequently reduced
j their "avoided cost" purchase rates, many of the
cogeneration/IPP markets are looking toward the City to
make electricity sales. Over 100 developers have
investigated the possibilities of supplying power to
Redding, a few of which appear very promising.
4 . Purchased Power Contracts
Purchased power contracts serve many purposes. These
can vary from a straight purchase of firm and non-firm
energy to the purchase of standby service. With the
construction of the COTP, the City will be able to
f enter into purchase contracts with several other
utilities. Although power contracts reduce the need
for the City to make capital expenditures, they usually
have lower long-term economic benefits than developing
new power projects.
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5. Biomass Projects
Biomass projects typically use products such as wood
waste, agricultural waste, or municipal solid waste.
'
Although some of these
g projects tend to utilize new
technology, they are becoming increasingly popular as
they become economically competitive with other
resources. However, they may have significant fuel
1 supply and air pollution difficulties to resolve.
6 . Fossil Fuel Projects
a. Coal
Coal projects remain a viable resource option
where purchase into an existing plant is possible.
+ However, the CEC has exclusive siting jurisdiction
over all proposed generating plants greater than
50MW located in the state of California. The
state has identified certain "preferred"
technologies and gives them preference in siting.
Coal is not a "preferred" technology and as a
matter of state policy, there is no support for
the construction and operation of a coal-fired
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plant in California. In light of this , 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.
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b. 011
Oil is not a viable source of power. Concerns
about both reliability and cost of supply and air
quality make this source unattractive.
C. Natural Gas
' Natural gas can play an important role in meeting
future capacity needs. However, because
pollutant
levels in the Redding area are approaching or, in
some cases, have surpassed state standards, new
natural gas-fired projects will necessarily
undergo close environmental scrutiny. Most
utilities in California are significantly relying
on natural gas-fired projects to meet their future
power needs. There are primarily three different
types of natural gas-fired projects:
i. Combustion turbines are relatively inexpensive
to construct, but are expensive to operate.
They are designed to operate for relatively
short periods of time and to respond quickly
during emergencies. They are ideally suited
for use as peaking or reserve units. The
injection of steam reduces air quality
concerns and increases the efficient operating
range of a combustion turbine.
ii. Gas-fired boilers have the advantage of
increased efficiency over a wider range of
output than combustion turbines. However,
gas-fired boilers have a higher installed cost
.� than a combustion turbine.
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I iii. Combined cycle projects have high efficiency
within a narrow operating band. However,
i combustion turbines areP referred over
combined cycled projects when significant
j cycling of the project is needed. Gas-fired
boilers are preferred when wide operating
ranges are needed.
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' d. Alternative Fuels
' Fuels such as butane, propane, and alcohol also are a
possibility for future power sources and can be burned
in the same manners available for natural gas. They
also represent an opportunity for the City to reduce
' its dependence on the more traditional organic fuel
sources.
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7. Demand Side Projects
Demand side projects represent a low-cost, pollution-
free method of meeting future utility customer needs.
Programs that help customers to conserve energy as well
as shift power usage to off-peak periods will help keep
i the City' s power costs at a minimum. The City is
currently working with some of its larger customers on
conservation/load management efforts. Expansion of
these efforts is expected in the near future.
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8 . Fuel Cells
Fuel cells are expected to soon be able to provide a
fast, environmentally clean way to add small increments
of generating capacity 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 higher than most other City
options.
9. Nuclear Projects
Through membership in M-S-R, the City was offered
22 . 5MW of firm capacity from the Arizona Nuclear Power
Project. In June, 1982, City voters passed a
referendum prohibiting City involvement in the project.
The City is, therefore, constrained from considering
future participation in nuclear power projects.
10. Geothermal Projects
Because of a limited known supply of accessible steam,
the potential for geothermal projects is limited.
Known production areas have become saturated with
y wells. Recent indications of health hazards associated
with working in and around steam fields and plants, as
well as recent reductions in generation from several
existing projects, are becoming major concerns for the
industry.
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11. Solar,
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Power derived from solar technology may be worthy of
further study. Although the cost to produce power from
sunshine has continued to decrease, it remains
significantly higher than the cost of other resources.
Solar projects which have been built to meet electric
utility load have relied on government grants and tax
incentives that are currently not available.
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12. Wind Projects
With the implementation of PURPA, there was much
development of wind projects in the early 1980s. More
recently, however, as the tax credits have dwindled,
the research and development support for this
technology has diminished. In the local region,
dependable winds seldom occur during peak electrical
load periods. At best, for the foreseeable future,
this technology could supply only nondependable energy.
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E. Transmission
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Currently, Redding' s Electric Utility operates as an island
within the transmission systems of PG&E and Western.
Redding' s electric system is interconnected with Western
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but is not interconnected with PG&E. Therefore, any power
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Redding receives from PG&E' s system must be received by
Western at Tracy Substation near the Bay Area, and then
delivered by Western from Tracy to Keswick or Airport
Substation. Potential resources that may seem to be close
to Redding may be, contractually very far, if the
resource' s interconnection is with PG&E. The cost to wheel
power through both PG&E' s and Western' s transmission
! systems is usually too high to warrant further
consideration of these resources. Access to transmission
j lines greatly enhances Redding' s ability to utilize
i alternative power resources.
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With construction of the COTP, Redding eventually will be
able to receive up to 44MW of power from the California-
Oregon border to the Olinda Substation, near Cottonwood,
for delivery by Western to Redding. Similarly, Redding
! will eventually be able to receive up to 44MW of power from
the southern terminus of the COTP, near the Bay Area, to
the Olinda Substation. The COTP agreements provide for
Redding to be able to transmit power over PG&E' s system
I between PG&E' s Midway Substation, near Bakersfield, to the
southern terminus of the COTP.
The City is also a participant (via its membership in
i M-S-R) in the Mead-Phoenix, Mead-Adelanto, Adelanto-Lugo,
and Palo Verde-Devers transmission projects. Participation
in these projects will enable the City to participate in
purchase, sales, and exchange arrangements with other
utilities in the southwestern United States. It also will
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1 provide the City with leverage in negotiating prices for
resources delivered from the Pacific Northwest over the
COTP.
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I F. Reserve Requirements
Every electric utility strives to provide dependable
1 electric service to its customers. A utility' s failure to
meet customer loads due to insufficient capacity will
result in a variety of economic and technical problems.
Therefore, utilities must plan for and develop sufficient
reserves to meet customer load requirements.
Within the utility industry, there are several important
standards that generally determine reserve requirements.
One such standard is to maintain a Loss Of Load Probability
(LOLP) of not more than one day ( 24 continuous hours) in
i ten years. Such a standard requires that the combination
of generating and power purchase capacities must exceed
customer loads at all times except for one day in ten
years. All uncertainties such as weather, forced and
planned outages, and other factors such as routine
maintenance must be included. Utilities employ several
strategies to provide sufficient reserves to reduce LOLP,
however, the reserves of most utilities are divided into
two major types.
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1 . Planning Reserves
Planning reserves in the utility industry are typically
150-20% of system annual 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
ioutages.
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A 2. Spinning Reserves
Spinning reserves in the utility industry are typically
3%-10% of system peak demand. Spinning reserves are
designed to account for sudden loss of existing
1
generation. If, under emergency situations, existing
generation is lost, spinning reserves are used to
quickly (within a few minutes) replace the sudden loss
in generation.
3 . Redding' s Reserves
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In developing its resources, Redding must ensure enough
are developed to meet not only its expected load, but
also its reserve requirements. A reserve margin equal
to the amount of load serving capacity the City could
lose during a single outage event ( largest single
contingency) was utilized in the 1990 Plan to determine
the City' s future need for reserves. This strategy
provided a total of planning and spinning reserves
between 18%-31% over the 20-year forecast period.
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G. Interutility Support
Interutility support contracts can support a utility' s
resources by providing for such services as spinning and
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planning reserves, voltage and frequency control, emergency
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power and firming power. Both spinning and planning
reserves have been previously discussed. Voltage and
frequency are a means of measuring the quality of the
electric power delivered to customers. Voltage and
frequency control services are sometimes exchanged between,
or purchased from, utilities to help ensure quality service
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to the customer. Firming or back-up arrangements are
sought when one utility has a particular project which, for
various reasons (e.g. , hydro conditions) , may not be
capable of supplying its rated capacity at all times.
Under these circumstances, the buyer of firming service
selects the desired level of service (MW) and then pays for
it on a periodic basis, regardless of whether the service
is actually utilized during that period.
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H. Pooling
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Pooling resources is another option for meeting City
electric needs. Power pools afford the various
participants an opportunity to lower power costs. For
example, with multiple participants, a project can be
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a upsized to a point where economies of scale take effect.
Other pools enable different utilities to take advantage of
load diversity. An example of this would be the
summer/winter load diversity among Pacific
Northwest/Pacific Southwest utilities. In the summer, when
utilities in the Southwest are peaking, Northwest utilities
{ often have excess to sell at prices lower than Southwest
utilities ' incremental power costs. The opposite is true
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in winter. Finally, pools allow utilities to share
resources to provide for reserves and emergency power.
I . Analysis
The complete process of analyzing potential electric
resources is simplified by using detailed computer modeling
techniques. Computer modeling is used by the Electric
Department staff to forecast hourly load and variable cost
to meet the load, over a wide range of scenarios of load
growth and resource mix. Computer modeling is used to
combine hourly operating costs with the Electric
Department' s forecasted financing needs and other fixed
costs. By assigning probabilities to several significant
assumptions , and by combining the assumption into many
scenarios, computer models assess the expected overall
risks and benefits of a given resource. Forecasted
electric rates during the life of a resource are compared
to forecasted rates without that same resource to determine
its ultimate value to the City' s electric customers.
When a resource is first identified, it is usually vaguely
described. A general analysis of the resource is made each
time the resource is further defined. Such subsequent
analyses are usually more detailed than the previous
because more is known about the resource. These analyses
3
1 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 initial criteria used to decide if future
investigations are warranted is whether the City' s electric
customers are projected to be economically better off, in
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terms of .present value dollars spent on, electricity over
the first ten years due to the addition of a given
resource. If, after preliminary review of a resource, the
resource does not meet this criterion, further
consideration is normally not warranted.
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' The ten-year initial criterion stems from the fact that
virtually all power from new resources costs more in the
first few years of operation than power purchased from
another utility. Another utility has the near-term
advantage of being able to sell power available from older
generators constructed with old capital. However, within
a few years, some resources become competitive with
purchases from another utility because that utility has
constructed even newer projects, the costs of which are
included in the utility' s charges for power.
As long as a resource meets the "ten year" criterion,
studies are performed, analyses made, and negotiations
continued until the resource becomes completely formulated
and a final City commitment is required. Prior to a final
City commitment, the risk/benefit analysis described above
is completed over a wide range of scenarios that might
occur during the resource ' s expected life. These scenarios
quantify the range of uncertainty of the project' s
economics due to uncertain variables such as future fuel
prices and load growth. In this manner, the potential
i outcomes that are better and worse than expected are
quantified and the decisionmakers can balance the expected
benefits with the potential risks of a project. In
addition to the detailed analysis described above, an
investigation of the unquantifiable or intangible risks and
benefits of the resource is made.
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9 The five-member elected City Council is the final authority
( subject to a referendum by Redding citizens) for approving
electric resource commitments. Prior to any presentation
to the City Council, however, is a review of staff' s
a analysis by the EUC, and perhaps a committee of the EUC.
The EUC is a committee of seven citizen volunteers who are
appointed by the City Council.
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VI . RECOMMENDED POWER RESOURCE DEVELOPMENT PLAN
The following plan is recommended to meet the City' s power
requirements through fiscal year 2009 . This plan is flexible
and is intended to provide general guidance on how to meet the
City' s future power requirements. A number of future resource
scenarios could result from the recommended plan. The purpose
! of this plan is to provide a
perspective on how future
decisions regarding a particular power resource may affect
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i subsequent decisions and the overall cost and reliability of
the City' s electric system.
The plan consists of 11 recommendations as follows:
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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 them
by developing more economical power resources. As noted in
Section V, it is possible that capacity-related charges may
make supplemental power purchases from PG&E quite costly.
Therefore, the City should continue to develop economic
j resources that reduce its dependence on PG&E supplemental
power and thereby reduce electric cost to its customers.
By pursuing alternatives, the City provides PG&E an
incentive to maintain its prices as low as possible.
B. Pursue Arrangements to Shape Loads and Resources
The City should continue to develop arrangements that can
provide on-peak capacity and a use or market for excess
energy during periods of lower demand.
Draft: EUC Recommended: 2/7/91
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The following is a list of the most promising alternatives:
O Scheduling of power from Western
O Peaking capacity purchases
O Pacific Northwest peaking capacity purchases
O Capacity-for-energy exchange agreements
O Spring Creek Pumped Storage Project
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O Large interruptible customers
O Independent power producers
O Demand side management programs
O Supplemental power purchase contract with PG&E
O Sale of excess energy to Western
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O Other possible suppliers and purchasers.
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
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on-peak capacity and energy. The pumped storage project
will also allow the City to use off-peak energy that is
1 often available at attractive rates from other utilities.
Finally, by maintaining a minimum pool in the upper
reservoir, the project may be able to provide some of the
necessary reserve requirements for the City' s other
projects.
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Draft: EDC Recommended: 2/7/91
9 rc/r/9 65
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D. Pursue Development Negotiations with Independent Power
Producers
With the demise of tax credits and the ability under PURPA
to sell power to IOUs at above market rates, IPPs have
turned toward publicly owned utilities to market their
products. Since mid-1989, the City has received an average
1 of one inquiry per week from various IPPs with proposals to
sell either power or a project to Redding. These proposals
have been reviewed as described in Section VI . Currently,
five appear to be viable. IPPs represent a variety of
technologies and operational requirements and many possess
the requisite expertise to bring their projects to
fruition. The City should continue to pursue development
of these IPPs. In addition to meeting City power needs,
they help to stimulate the Redding area economy by lowering
City power costs and providing local jobs.
E. Pursue Transmission Access
For the City to have free access to economical power,
transmission rights must be obtained. The City is
presently a 6 . 4% member of IANC, the project manager of the
COTP. The COTP includes upgrading and construction of new
transmission facilities from the Pacific Northwest to
i Central California. Groundbreaking for the project took
place on October 15, 1990. The COTP will eventually
provide the City access to 44MW of power from the Pacific
Northwest. The City' s interest in the COTP south of
Redding will enable Redding to make power transactions with
+ other California utilities. Redding, through its
membership in M-S-R and TAMC, is developing access to
1 connect its San Juan entitlement to the COTP. The City
should continue to explore possible transmission access.
Transmission access is the fundamental first step in
Draft: EDC Recommended: 2/7/91
rc/r/9 66
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enabling opportunities for power arrangements with remote
utilities and accessing remote generation projects.
F. Enhance Relationships with Western
Since Western is the City' s primary source of power and is
the City' s transmission link to other utilities, it is
important to maintain and enhance working relationships
with Western. Contracts are currently under 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.
G. 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 power
contracts with other utilities in the Pacific Northwest.
When Redding utilizes another resource, its current
contract with PG&E will terminate. Even so, Redding may
need to purchase support services or additional
supplemental power. Redding should negotiate a contract
with PG&E provided that it does not restrict Redding' s
resource development and that it allows Redding to purchase
services from PG&E should PG&E offer services that are, in
the long-term, more economical than other alternatives.
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Draft: EDC Recommended: 2/7/91
rc/r/9 67
H. Pursue Natural Gas-fired Resources
Natural gas fired projects will play a vital role in
meeting the future needs of most electric utilities
throughout California. Natural gas fired projects are
attractive in California because of current California
environmental regulations, the cost to construct a natural
as fired
� g project, and the common belief that natural gas
j will be in abundant supply for a long time to come.
Redding should pursue the development of natural gas fired
i electric generation by acquiring economical natural gas
supplies and gas transportation rights. If access to
economical natural gas is obtained, Redding could burn the
natural gas on a Redding-owned combustion turbine, or use
the natural gas supply to enhance the economics of an IPP
Y
project.
I . Pursue Economic Hydroelectric Projects
Two small-to-medium size hydroelectric power projects
remain available for development by the City. The projects
can be developed using proven technology and can provide
i additional direct construction benefits for the local
economy. Three hydroelectric projects in various states of
development are listed in Table 10. The Whiskeytown
Project is operational. The other two hydroelectric
projects are the Lake Redding Project3 and the Lake Red
Bluff Project.
J. Pursue Conservation and Load Management Programs
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As the City' s Energy Conservation and Load Management
(ECLM) programs are implemented, the City' s ability to
3 See footnote on Page 3.
Draft: EUC Recommended: 2/7/91
rc/r/9 6 8
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avoid exceptional summer peaks will ' increase. The
increasing costs of new power resources will make various
ECLM programs more cost effective. Electric loads in the
City that can be safely and efficiently reduced during peak
demand periods will directly benefit City ratepayers
through lower costs from avoided supplemental power
purchases. Redding should consider implementing ECLM
programs that provide an economic alternative to
investments in new generation resources. Besides various
+ regulatorily-mandated ECLM programs, several programs may
t
j provide benefits to the citizens of Redding beyond lower
electric bills.
K. Selectively Participate in Resource Projects
Whenever the overall economics are favorable and the
diversity of power supply can be enhanced, the City may
wish to participate in projects with other utilities. When
pooled with other utilities, as the San Juan Project is
with M-S-R, a project may offer flexibility in energy
deliveries.
Table 10 provides a summary of the City' s projected loads and
one resource development scenario that is consistent with the
recommended plan. The resource development scenario lists
those resources included in the City' s 1989 submittal of a
20-year forecast of resources to the CEC.
The City' s contract with Western expires after the calendar
year 2004. At this time, any projections beyond that year are
I
very uncertain. For the purpose of preparing Table 10 , it was
assumed the City' s Western allocation will continue through
2009. More should be known about the validity of this
assumption after Western has completed its 1994 Remarketing
Plan, a process which began in 1989 . The City should become
Draft: EDC Recommended: 2/7/91
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prepared • for the consequences of not receiving a total
reallocation of Western' s resources in 2004 and the
consequences of not developing some or all of the undeveloped
resources identified in Table 10.
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Following Table 10 are several figures that illustrate the
projected loads and resource mix as provided to the CEC in
1989. Figure ( 4) illustrates that with a slight exception in
1993 and 1994, the forecasted resources will be capable of
exceeding the City' s capacity needs through 2008, including the
need to maintain a 15% planning reserve per WSCC requirements.
Capacity additions are normally accomplished in discrete
increments, thus excess capacity is normally available from
time to time over a utility' s long-term planning horizon.
Although Figure ( 4) shows a few slight shortfalls of capacity
in 2009, significant shortfalls could occur if one or more of
the proposed projects are not built or if Redding experiences
load growth similar to what it has experienced over the past
several years. Under the high load growth scenario, the
resources depicted in Figure ( 4) would not meet Redding' s
capacity needs by 2004 even if construction of the Spring Creek
Pumped Storage Project' s second phase was accelerated.
Figure ( 5 ) illustrates that the resources depicted would
generate sufficient energy to meet the City' s requirements,
assuming low load growth. Most of the energy shown in excess
of the low load growth needs will be used to meet pumping or
exchange obligations. However, if Redding' s increases in
energy requirements are consistent with those experienced in
recent years, the scenario illustrated in Figure ( 4) indicates
that the City will not have sufficient energy to meet the
pumping requirements of the Spring Creek Pumped Storage Project
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by 1995 and could not meet energy requirements of Redding' s
customers by 2001 .
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Draft: EUC Recc®ended: 2/7/91
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The pie charts depicted in Figures ( 6 & 7) §how 'the extent to
which the resources are projected to be utilized to meet the
City' s energy requirements. This is in contrast to the bar
charts in Figures ( 4 & 5 ) where total energy availability is
shown. Figure ( 6) considers a low load growth scenario, and
shows that by 2009, Western would meet 52% of our energy needs
i if Redding' s allocation does not change. Figure ( 6 ) considers
a high load growth and shows a 7% shortfall in Redding' s energy
needs by 2003 .
The decision on which capacity resources to use will vary from
day to day, depending on the current operational cost of each
resource (e.g. , the lower the current cost of pumping energy,
the more the Spring Creek Pumped Storage Project will be
utilized) . Throughout the course of a given year, the
percentage of Redding demands on any particular resource will
vary dramatically. Therefore, any attempt to produce figures
to illustrate capacity utilization similar to Figures ( 6 & 7)
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' would be misleading.
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It should be re-emphasized that Figures ( 4, 5 , 6, 7 ) are
illustrations of one scenario only, a scenario that contains
much flexibility. This scenario does not imply a commitment to
develop any one type of resource. over time, some of the
resources depicted in Figures ( 4, 5 , 6, 7) may be replaced by
other yet-unidentified resources. Figures ( 8 & 9) illustrate
the relationship between committed resources and projected
capacity and energy requirements. The committed resources as
noted are Western, the M-S-R/BPA agreement, the San Juan coal-
fired project and the Whiskeytown Hydroelectric Project.
The City is currently in the process of filling the shortfalls
illustrated in Figures ( 8 & 9) . However, while these
"shortfalls" indicate a need to secure additional firm
resources, they also indicate a certain flexibility in the
I Draft: EDC Recaanended: 2/7/91
rc/r/9 71
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City' s resource planning process. This flexibility enables the
City to "play the market" until such time a commitment to a
particular resource becomes a sound management decision. Thus,
if the City is able to secure a resource with reliability and
costs lower than the non-committed resources shown in Figures
( 4, 5 , 6 , 7 ) enough flexibility exists to displace the non-
committed resources with the newly secured ones.
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rc/r/9 7 2
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TABLE 10
CITY OF REDDING
1990 RESOURCE PLAN
RECOMMENDED PLAN
Fiscal Year 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000
----------------------------------------------------------------------------------------
ENERGY (GWH)
REQUIREMENTS
--------------
Retail 679 703 733 763 789 816 841 865 890 916
Avail. for Whlsle 245 250 263 316 288 213 193 182 206 218
-------------- --- --- --- ---- ---- ---- ---- ---- ---- ----
TOTAL 924 952 996 1079 1078 1029 1034 1046 1096 1134
ENERGY (GWH)
RESOURCES
--------------
Western 571 584 597 603 614 622 621 619 620 618
San Juan 127 127 127 127 127 127 127 127 127 127
d Whiskeytown 8 8 8 8 8 8 8 8 8 8
Spring Creek 0 0 0 0 0 -18 -17 -18 -16 -24
Lake Redding' 0 0 0 0 0 0 0 0 94 94
Lake Red Bluff 0 0 0 0 0 0 0 0 0 46
Northwest Imports 0 0 44 51 55 45 62 63 61 60
{ Southwest Imports 108 108 108 108 72 18 0 0 0 0
IPPs 0 0 47 181 201 226 232 247 202 204
Other Purchases 109 124 64 0 0 0 0 0 0 0
-------------- --- --- --- ---- ---- ---- ---- ---- ---- ----
TOTAL 924 952 996 1079 1078 1029 1034 1046 1096 1134
CAPACITY (MW)
REQUIREMENTS
--------------
Customer Demand 173 175 177 183 186 191 197 203 210 217
Reserves 0 0 23 18 64 60 61 55 62 61
Reserves(%tot) 0% 0% 13% 10% 34% 32% 32% 27% 29% 28%
Contract Exp. 1 1 1 0 0 0 0 0 0 0
--------------- --- --- --- --- --- --- --- --- --- ---
TOTAL 174 175 201 201 251 251 258 258 272 279
CAPACITY (MW)
I RESOURCES
---------------
Western 116 116 116 116 116 116 116 116 116 116
Whiskeytown 1 1 1 1 1 1 1 1 1 1
Spring Creek 0 0 0 0 50 50 50 50 50 50
Lake Redding s 0 0 0 0 0 0 0 0 14 14
Lake Red Bluff 0 0 0 0 0 0 0 0 0 7
Northwest Imports 0 0 22 22 22 22 29 29 29 29
IPPs 0 0 62 62 62 62 62 62 62 62
Other Purchases 57 59 0 0 0 0 0 0 0 0
--------------- --- --- --- --- --- --- --- --- --- ---
TOTAL 174 175 201 201 251 251 258 258 272 279
a See footnote on Page 3.
' s See footnote on Page 3.
Draft: EUC Recommended: 2/7/91
rc/r/9 7 3
TABLE 10 (Cont. )
CITY OF REDDING
1990 RESOURCE PLAN
RECOMMENDED PLAN
----------------------------------------------------------------------------------------
Fiscal Year 2001 2002 2003 2004 2005 2006 2007 2008 2009
j ----------------------------------------------------------------------------------------
' ENERGY (GWH)
REQUIREMENTS
------------
Retail 943 975 1006 1037 1071 1106 1140 1174 1208
Available for Whlsle 261 232 204 138 130 116 102 93 73
--------------- ---- ---- ---- ---- ---- ---- ---- ---- ----
TOTAL 1205 1208 1210 1175 1201 1222 1242 1267 1281
J
ENERGY (GWH)
RESOURCES
------------
Western 619 618 616 616 618 619 621 622 624
San Juan 127 127 127 127 127 127 127 127 127
j Whiskeytown 8 8 8 8 8 8 8 8 8
Spring Creek -8 -19 -23 -30 -26 -27 -25 -26 -28
Lake Redding` 94 94 94 94 94 94 94 94 94
Lake Red Bluff 46 46 46 46 46 46 46 46 46
Northwest Imports 63 62 53 -17 -16 -14 -12 -5 -3
Southwest Imports 0 0 0 0 0 0 0 0 0
IPPS 256 271 288 330 350 368 382 399 408
Other Purchases 0 0 0 0 0 0 1 1 4
----------------- ---- ---- ---- ---- ---- ---- ---- ---- ----
TOTAL 1205 1208 1210 1175 1201 1222 1242 1267 1281
CAPACITY (MW)
REQUIREMENTS
-------------
Customer Demand 224 232 240 248 257 266 276 285 295
Reserves 55 47 88 81 72 63 53 44 34
Reserves(%tot) 25% 20% 37% 32% 28% 24% 19% 15% 12%
Contract Exp. 0 0 0 0 0 0 0 0 0
--------------- --- --- --- --- --- --- --- --- ---
TOTAL 279 279 329 329 329 329 329 329 329
CAPACITY (MW)
RESOURCES
-------------
Western 116 116 116 116 116 116 116 116 116
Whiskeytown 1 1 1 1 1 1 1 1 1
Spring Creek 50 50 100 100 100 100 100 100 100
Lake Redding' 14 14 14 14 14 14 14 14 14
Lake Red Bluff 7 7 7 7 7 7 7 7
Northwest Imports 29 29 29 29 29 29 29 29 29
IPPS 62 62 62 62 62 62 62 62 62
Other Purchases --0 --0 --0 --0 --0. 0 --0 --0 --0
----------------- ---
TOTAL 279 279 329 329 329 329 329 329 329
e See footnote on page 3.
See footnote on page 3.
Draft: EDC Recommended: 2/7/91
rc/r/9 7 4
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I
FIGURE 4
75
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FIGliRE 6
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FIGURE 9
80
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APPENDIX A
FUTURE RESOURCES
SECTION
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I . RESOURCES TO WHICH CITY IS COMMITTED
A. Whiskeytown
B. San Juan
C. COTP
'I D. BPA Power Purchase Contract
II . RESOURCES UNDER ACTIVE CONSIDERATION
A. Spring Creek Pumped Storage Project
B. Generic IPP
C. Lake Red Bluff
D. Pacific Northwest Generic Purchases
E. Mead-Phoenix Transmission Line Project
F. Mead-Adelanto Transmission Line Project
G. Adelanto-Lugo Transmission Project
H. Palo Verde-Devers Transmission Line No. 2
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Draft: EDC Recommended: 2/7/91
rc/r/9 1
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I .A. WHISKEYTOWN HYDROELECTRIC PROJECT
! Location:
At the USBR Whiskeytown Dam on Clear Creek, in Shasta County,
California.
Status:
Started operation on January 16, 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:
Operational date January 1986
Maximum capacity 3 . 24MW
Summer dependable capacity 0. 8MW
Average annual generation 8,200, 000kWh
Average annual oil savings 15, 000 barrels
Costs:
Development costs $ 250,000
j Civil and mechanical $3 ,950, 000
1 Environmental mitigation -0- -
Total capital cost
(does not include financing costs) $4,200,000
Average net cost through FY90 (mills/kWh)
( includes financing costs) 60
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i Draft: EDC Recommended: 2/7/91
rc/r/9 2
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I .B. SAN JUAN PROJECT
In November 1982 , M-S-R purchased an option on 28 . 80 of San Juan
! Unit No. 4 located in New Mexico, 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.
1 M-S-R and the Tucson Electric Power Company (TEP) entered into an
Interconnection Agreement (Agreement) which 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 Palo Verde
Switchyard or the Westwing Switchyard. The Agreement also provides
the terms of the sale of energy by TEP to M-S-R through 1995.
M-S-R and Public Service Company of New Mexico (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 Juan Unit No. 4. The transfer was
completed on December 31, 1983. The EPPA also provides for the
sale of 73 . 530, approximately 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. 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.
Only interruptible transmission will be available to M-S-R prior to
the mid-1990s. M-S-R plans to have firm transmission in place by
April 30, 1995 when the EPPA expires.
Expected power delivery date 1995
Maximum capacity at Redding 19. 2MW
Summer dependable capacity 19. 2MW
Average annual generation 130 , 000 , 000 kWh
Average annual oil savings 235, 000
Approximate first year costs (mills/kWh) 95
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Draft: EDC Recommended: 2/7/91
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I .C. CAL• IFORZNIA-OREGON TRANSMISSION PROJECT (COTP)
Total Capacity/ (Available to City) : 1600MW/ + ( ( 43 . 3MW)
i Project Cost 1990 $/ (Cost to City) : $405 ,000,000/ ( $12, 000,000)
Date of completion: 1993
Location: From a point near Malin, Oregon to Tracy, California
i
' Comments.
The linewould open up purchase opportunities with the Pacific
Northwest. Construction began in October 1990. The project
manager is the Transmission Agency of Northern California (TANG) .
Redding is a member of TANC and M-S-R, both of which 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.
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Draft: EUC Recommended: 2/7/91
rc/r/9 4
I .D. BONNEVILLE POWER ADMINISTRATION CONTRACT
Description:
In October 1989, M-S-R entered into a contract with the Bonneville
Power Administration (BPA) to buy firm capacity and energy from the
Pacific Northwest. The contract begins when the COTP is completed,
and deliveries will be made using this new line. The contract will
terminate 20 years after completion of the COTP.
Expected Delivery Date: 1993
Amount of Power:
Redding' s share of capacity and energy under the contract is:
Maximum Minimum Maximum
Capacity Energy Energy
Through July 1996 15MW 65.7GWH 107 . 5GWH
After July 1996 22. 5MW 98. 6GWH 159.7GWH
Cost:
The contract rates are based upon BPA' s surplus firm power rates as
filed with FERC. The estimated beginning rates are approximately
$5.75/kW-mo, take or pay, for capacity and 30 mills/kWh for energy.
These rates are expected to escalate annually with an average
compound growth rate of 6%.
Exchange Provisions:
As required under the contract, BPA has the right to convert the
agreement from a firm sale to an exchange when the Pacific
Northwest reaches a load and resource balance and surplus firm
energy is no longer available. Under the exchange, no monetary
payments are made. Instead, M-S-R would receive peaking capacity
in the summer. Any energy used by M-S-R with the peaking capacity
would be returned to BPA within 24 hours during the off-peak hours.
In exchange for the summer peaking capacity, M-S-R would provide
BPA energy in the winter based on an exchange ratio of 1200 MWH/MW
spread out in equal weekly increments. The amount of capacity
available to Redding will not change when or if the contract
converts to an exchange.
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Draft: EOC Recommended: 2/7/91
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II .A. PROPOSED SPRING CREEK PUMPED STORAGE PROJECT
Location-
On Spring Creek, west of Keswick Reservoir, Shasta County,
California.
Status:
" The FERC license application was filed on May 31, 1989.
Supplemental information was filed in November 1989 and February
1990. FERC rejected the City' s license application on July 6 ,
1990. The City appealed FERC' s decision one month later and this
appeal is still pending. FERC' s action on the City' s appeal is
expected in the spring of 1991.
Physical:
Project size 2,612 acres
Powerhouse size Underground cavern
501W x 901H x 2201L
Number of units Three
Type of turbine Francis reversible
pump/turbine
Size of generators 58MVA
Head 1 ,155 '
Maximum powerhouse Flow 1,200 cfs
Power Output:
Expected operational date 1995
i Maximum capacity 100MW
Summer dependable capacity 100MW
Average annual generation* N/A
! Average flow-through generation 14GWH
Costs: ( 1995 Dollars)
Permit process (to date) $ 1,200,000
Total cost for permit process (est. ) $ 1,700,000
Civil and mechanical $104,400,000
Total capital cost $206,100, 000
' Approximate Cost ( $/kW) $2, 057
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Miscellaneous:
a ( 1) Cost provided in draft FERC license application as prepared by
j Black & Veatch.
Pumped storage projects use more energy to pump than they
produce.
Draft: EUC Recommended: 2/7/91
' rc/r/9 6
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II .B. GENERIC INDEPENDENT POWER PROJECT
Location•
In or near Redding, in Shasta County, California.
Status•
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Several proprietary negotiations are ongoing.
Physical:
Project size 50-75MW
Number of units 2-4
Size of boilers N/A
Size of turbine generator N/A
Power Output:
Expected operational date 1993
j Maximum capacity 75MW
Average Annual Generation 150,000, OOOkWh
Average annual oil savings 274 ,000 barrels
Costs: ( 1985 dollars)
Permit process (to date) $ N/A
Total cost for permit process (est. ) $ N/A
Civil & mechanical $ N/A
Approximate 1st-year cost (mills/kWh) 40-80
Miscellaneous:
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N/A - Not available at this time.
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Draft: EDC Recommended: 2/7/91
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II .D. PROPOSED LAKE RED BLUFF HYDROELECTRIC 'PROJECT
Location:
At the existing Red Bluff Diversion Dam on the Sacramento River, in
Tehama County, California.
Status:
On May 23 , 1990 , FERC' s Director of the Office of Hydropower
Licensing issued an order denying Redding' s licensing application
for the subject project, stating the project is inconsistent with
1 fish and wildlife management efforts in the area. Redding appealed
this order on June 22, 1990 on both substantive and procedural
grounds. This matter is currently under review at FERC and a
decision is not expected until mid-1991.
Physical-
Project size 40 acres
Powerhouse size 70 ' X 150 '
Number of units two
Type of turbine Kaplan bulb
Size of generators 4 , OOOkVA
1 Head 11 '
Maximum powerhouse flow 9,000 cfs
Power Output:
Expected operational date 1999
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
w
Approximate 1st-year cost
(mills/kWh) 104
,
Miscellaneous:
( 1) Project' s power production curve closely follows City' s load
curve.
( 2) Cost estimates provided in a 1983 report from Sverdrup &
Parcel.
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Draft: EUC Recommended: 2/7/91
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II.E. PACIFIC NORTHWEST GENERIC PURCHASES
Discussion:
With the completion of the COTP, Redding will have access to three
500kV transmission lines to the Pacific Northwest to wheel power in
addition to that provided by the BPA contract. If Redding leaves
approximately one-third of its COTP capacity available for spot or
non-firm opportunities, all firm deliveries could be delivered even
if one of the transmission lines were to be taken out of service.
Firm Power:
Power from the BPA contract will not utilize two-thirds of
d Redding' s COTP allocation. Approximately 7. 5MW of additional
transmission capacity will be available to support firm power
a purchases. Preliminary discussions are currently taking place with
Pacific Northwest utilities interested in serving this need. It is
anticipated that firm power might be obtained at beginning rates of
approximately $7/kW-mo for capacity and 30 mills for energy when
power deliveries are expected in 1993 .
' Non-Firm Power:
Other than planning for transmission line outages, there is another
good reason for reserving approximately 14MW (one-third of
Redding' s COTP transmission capacity) for spot or non-firm
opportunities in the Pacific Northwest. There is a very active
market in which utilities in the Western United States buy and
sell, occasionally for very attractive rates, spot energy on a day-
to-day or hour-to-hour basis. It is also possible to sign a
contract with someone to make an amount of non-firm energy
available over some period of time at rates reflecting the non-firm
market. Preliminary discussions are currently taking place with
iPacific Northwest utilities who may be interested in guaranteeing
non-firm energy sales. Alternatively, Redding may not enter the
spot market until the COTP is completed.
Costs:
It is anticipated that spot energy can be obtained at rates
beginning near 18 mills/kWh when power deliveries are expected in
1993 .
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II�
Draft: EUC Recommended: 2/7/91
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i
1
II .F. MEAD-PHOENIX TRANSMISSION LINE PROJECT'
Total Capacity/(available to City) : 1 ,300MW/ ( 22 . 5MW)
Project Cost ( 1990 $ ) / (cost to City) : $325,000 , 000/ ( 5 , 625,000 )
Date of Completion: 1/1/95
Location: Between Phoenix, Arizona and Southern Nevada
Comments.
1 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
j project.
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II.G. MEAD-ADELANTO TRANSMISSION PROJECT
Total Capacity/ (Available to City) : 1, 200MW/ ( 31. 5MW)
Project Cost 1990 $/ (Cost to City) : $224,000, 000/( $5,880,750)
Additional liability for system modification to SCE' s system:
$80,000,000 to $120, 000,000 Project Cost
1 Additional liability to City: $900,000 to $1, 350,000
Date of Completion: 1/1/95
Location: Between Southern Nevada and the Los Angeles area
`.
Comments:
This project was developed as an alternative to the McCullough-
Victorville Project which is no longer under consideration. 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.
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Draft: EUC Reco®ended: 2/7/91
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I
1 .
II .H. ADELANTO-LUGO TRANSMISSION LINE PROJECT
Total Capacity/ (Available to City) : 2 , 000 MW/ ( 31 . 5 MW)
Project Cost ( 1990 $/Cost to City) : $30 ,000,000/ ( $465, 000)
Date of Completion: 1/1/95
Location: Between Adelanto Substation and Lugo Substation,
generally northeast of Los Angeles, CA
Comments
j This Project is necessary to connect the Mead-Adelanto Transmission
1 Project with Southern California Edison' s system.
II .I . PALO VERDE-DEVERS TRANSMISSION LINE NO. 2
Total Capacity/ (available to City) : 1 ,200MW/ ( 22. 5MW)
Project Cost ( 1990$ ) /(Cost to City) : $251, 000, 000/ ( 4,706 , 360)
Date of completion: Uncertain (Probably
{ Post 1997)
iLocation: 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 re-evaluation 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.
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Draft: EDC Recommended: 2/7/91
rc/r/9 1 1
APPENDIX B
ACRONYMS
i
ACRONYM LIST
ACID Anderson-Cottonwood Irrigation District
ACLM Air Conditioning Load Management (Program)
APPA American Public Power Association
BPA Bonneville Power Administration
CCPA Central California Power Agency
CEC California Energy Commission
CFM Common Forecasting Methodology
CMUA California Municipal Utilities Association
COTP California-Oregon Transmission Project
CVP Central Valley Project
DWR Department of Water Resources
ECLM Energy Conservation/Load Management
FERC Federal Energy Regulatory Commission
GWH Gigawatthour
IOU Investor-Owned Utility (e.g. , PG&E, SCE)
IPP Independent Power Producer
i KGRA Known Geothermal Resource Area
KWH Kilowatthour
LADWP Los Angeles Department of Water & Power
LOLP Loss of Load Probability
MID Modesto Irrigation District
M-S-R Modesto-Santa Clara-Redding Power Agency
MSW Municipal Solid Waste
MW Megawatt
NCPA Northern California Power Agency
PG&E Pacific Gas & Electric Company
PP&L Pacific Power & Light Company
PURPA Public Utility Regulatory Policy Act
PUC Public Utilities Commission
RCS Residential Conservation Service
SCE Southern California Edison Company
SDGE San Diego Gas and Electric Company
{ SMUD Sacramento Municipal Utility District
SPLM Swimming Pool Load Management (Program)
STEP Shave the Energy Peak (Program)
TANC Transmission Agency of Northern California
USBR U.S. Bureau of Reclamation
WAPA Western Area Power Administration
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