Central Valley Project and California-Oregon Transmission ProjectWAPA-77
Federal RegisterSep 29, 1997
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DEPARTMENT OF ENERGY
Western Area Power Administration
Central Valley Project and California-Oregon Transmission
Project--WAPA-77
AGENCY: Western Area Power Administration, DOE.
ACTION: Notice of rate order.
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SUMMARY: Notice is given of the confirmation and approval by the Deputy
Secretary of the Department of Energy (DOE) of Rate Order No. WAPA-77
and Rate Schedules CV-F9, CV-FT3, CV-NFT3, CV-TPT4, CV-NWT1, CV-PSS1,
CV-RFS1, CV-EID1, CV-SPR1, CV-SUR1, COTP-FT1, and COTP-NFT1 placing
provisional rates for the Central Valley Project (CVP) commercial firm
power and transmission services, power scheduling service, and
ancillary services of the Western Area Power Administration (Western),
and placing provisional rates for the California-Oregon Transmission
Project (COTP) transmission services into effect on an interim basis.
The provisional rates, will remain in effect on an interim basis until
the Federal Energy Regulatory Commission (FERC) confirms, approves, and
places them into effect on a final basis or until they are replaced by
other rates. The provisional rates will provide sufficient revenue to
pay all annual costs, including interest expense, and repayment of
required investment within the allowable period.
DATES: The provisional rates will be placed into effect on an interim
basis on October 1, 1997, and will be in effect until FERC confirms,
approves, and places the provisional rates in effect on a final basis
for a 5-year period ending September 30, 2002, or until superseded.
FOR FURTHER INFORMATION CONTACT: Ms. Zola Jackson, Power Marketing
Manager, Western Area Power Administration, Sierra Nevada Customer
Service Region, 114 Parkshore Drive, Folsom, CA 95630-4710, Telephone
(916) 353-4421 or Mr. Joel K. Bladow, Power Marketing Liaison Office,
Room 8G-027, 1000 Independence Avenue SW., Washington, DC 20585-0001,
Telephone (202) 586-5581.
SUPPLEMENTARY INFORMATION: The Deputy Secretary of Energy, approved the
existing Rate Schedule CV-F8 for CVP commercial firm power on September
19, 1995 (Rate Order No. WAPA-72, 60 FR 52671, October 10, 1995) and
FERC confirmed and approved the rate schedule on March 14, 1996, under
FERC Docket No. EF95-5012-000 (74 FERC para. 62,136). The existing Rate
Schedule CV-F8 became effective on October 1, 1995, for the period
ending April 30, 1998, and is being superseded by Rate Schedule CV-F9.
Under Rate Schedule CV-F8, the composite rate on October 1, 1997, is
26.50 mills per kilowatt-hour (mills/kWh), the base energy rate is
16.93 mills/kWh, the energy tier rate is 26.48 mills/kWh, and the
capacity rate is $4.58 per kilowatt-month (kW-month). The provisional
rates for CVP commercial firm power in Rate Schedule CV-F9 will result
in an overall composite rate of 20.95 mills/kWh on October 1, 1997, and
will result in a decrease of approximately 21 percent when compared
with the existing CVP commercial firm power rates under Rate Schedule
CV-F8.
The Acting Assistant Secretary of Energy, approved the existing
Rate Schedules CV-FT2, CV-NFT2, and CV-TPT3 for CVP transmission
services, and the existing Rate Schedule CV-PC1 for peaking capacity
service on April 12, 1993 (Rate Order No. WAPA-59, 58 FR 35933, July 2,
1993), and FERC confirmed and approved the rate schedules on September
22, 1993, under FERC Docket No. EF93-5011-000 (64 FERC para. 61,332).
The existing rate schedules became effective on May 1, 1993, for the
period ending April 30, 1998. Rate Schedule CV-PC1 is being terminated
effective October 1, 1997. Rate Schedules CV-FT2, CV-NFT2, and CV-TPT3
are being superseded by Rate Schedules CV-FT3, CV-NFT3, and CV-TPT4.
Under Rate Schedules CV-FT2 and CV-NFT2, the CVP transmission firm and
non-firm services rates on October 1, 1997, are $0.43 per kW-month for
firm service and 1.23 mills/kWh for non-firm service. On October 1,
1997, the provisional rates in Rate Schedules CV-FT3 and CV-NFT3 will
be $0.51 per kW-month for firm CVP transmission service, an 18.6
percent increase when compared with the existing rate, and 1.00 mill/
kWh for non-firm CVP transmission service, an 18.7 percent decrease
when compared with the existing rate. The provisional rate for
transmission of CVP power by others in Rate Schedule CV-TPT4 is a
direct pass through cost and will result in no change on October 1,
1997, when compared with the existing rate under Rate Schedule CV-TPT3.
Since the COTP went into operation in 1993, Western has sold COTP
transmission services on a short-term basis using rates approved by the
Administrator of Western. Rate schedules are being promulgated for COTP
firm and non-firm transmission services to be consistent with FERC
Order No. 888. The provisional rates for firm transmission service for
Western's share of the COTP will result in 9.9 percent (FY 1998) and
34.0 percent (FY 1999 through FY 2002) reductions in the existing rate
of $2.03 per kW-month. The provisional rates are $1.83 per kW-month for
FY 1998 and $1.34 per kW-month for FY 1999 through FY 2002. The
provisional rates for non-firm COTP transmission service will result in
21.2 percent (FY 1998) and 47.8 percent (FY 1999 through FY 2002)
reductions in the existing rate of 2.78 mills/kWh. The provisional
rates are 2.19 mills/kWh for FY 1998 and 1.45 mills/kWh for FY 1999
through FY 2002.
Power scheduling service, network transmission service, and
ancillary services are new services. The provisional rates are designed
to recover only the cost incurred for providing the services.
Provisional Rates for CVP Commercial Firm Power
The provisional rates for CVP commercial firm power are designed to
recover an annual revenue requirement that includes the investment
repayment, interest, purchase power, and operation and maintenance
expense. A cost of service study was used to allocate the
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projected annual revenue requirement for commercial firm power between
capacity and energy. Based on this study the capacity revenue
requirement includes 100 percent of capacity purchase costs, 50 percent
of the CVP investment repayment, interest expense, and power operation
and maintenance expense allocated to commercial power, and 100 percent
of purchased transmission service expense. These annual costs are
reduced by the projected revenue from sales of CVP transmission to
determine the capacity revenue requirement. The energy revenue
requirement includes 100 percent of energy purchase costs and 50
percent of the CVP investment repayment, interest expense, and power
operation and maintenance expense allocated to commercial power. These
annual costs are reduced by the projected revenue from sales of surplus
power to determine the energy revenue requirement.
The provisional rates will also include an Annual Energy Rate
Alignment (AERA). The AERA will be applied to energy purchases from
Western under Rate Schedule CV-F9 at or above an average annual load
factor of 80 percent, calculated at the end of each fiscal year. The
AERA will provide revenues to cover the increased costs of purchased
energy. The AERA is the difference between the estimated rate for
short-term energy purchases used in the cost of service study for CVP
commercial firm power and the provisional CVP energy rate. The AERA is
in addition to the provisional CVP energy rate and replaces the
existing energy tier rate in Rate Schedule CV-F8.
Adjustment Clauses Associated With the Provisional Rates for CVP
Commercial Firm Power
Adjustments for power factors, low voltage losses, and revenue were
included in Rate Schedule CV-F8, and will be continued in Rate Schedule
CV-F9.
Power Factor Adjustment
The power factor adjustment is included in Rate Schedule CV-F9. The
low power factor charge or LPF Charge is a charge that will be applied
when the customer does not maintain a calculated 95 percent or greater
power factor.
Low Voltage Loss Adjustment
A 1.035 loss adjustment factor will be applied to the billed
amounts for low voltage CVP commercial firm power deliveries on the
Pacific Gas and Electric system.
Revenue Adjustment
The revenue adjustment clause or RAC, is included in Rate Schedule
CV-F9. The RAC, tracks variances in future revenues and expenses, and
lessens the probability of significant revenue surplus or deficit to
the CVP repayment. The methodology for computing the RAC is a
comparison of estimated total revenues less estimated total expenses to
actual total revenues less actual total expenses.
Provisional Rates for CVP Transmission Services
The provisional rates in Rate Schedules CV-FT3 and CV-NFT3 for CVP
transmission services are based on a revenue requirement that recovers:
(1) The CVP transmission system costs for facilities associated with
providing all transmission services; and (2) the non-facility costs
allocated to transmission services. These provisional firm and non-firm
CVP transmission service rates include the costs for scheduling, system
control and dispatch service, and reactive supply and voltage control
service needed to provide the transmission service. The provisional
rates are applicable to existing firm and non-firm CVP transmission
services and future point-to-point transmission services. The rates
charged for firm and non-firm CVP transmission services for a period of
one year or less will be no higher than the provisional rates.
Provisional Rate for Transmission of CVP Power by Others
Transmission service costs incurred by Western in the delivery of
CVP power over a third party's transmission system to a CVP customer,
will be directly passed through to that CVP customer. The provisional
rate in Rate Schedule CV-TPT4 is proposed to be automatically adjusted
as third party transmission costs are adjusted.
Provisional Rate Formula for Network Transmission Service
Network transmission service, if offered by Western, will be made
available consistent with FERC Order No. 888. Due to existing
contractual arrangements and not being a control area operator for the
CVP, Western may not be able to provide network transmission service
but has included a rate formula in case Western offers the service. The
provisional rate formula includes the costs for scheduling, system
control and dispatch service, and reactive supply and voltage control
service needed to provide network transmission service.
Provisional Rate for Power Scheduling Service
Power scheduling is a new service being offered by Western that
provides for the scheduling of resources to meet loads and reserve
requirements. The provisional rate for power scheduling service is
designed to recover only the cost incurred for providing the service.
Provisional Rates for Ancillary Services
Western will provide six ancillary services consistent with FERC
Order No. 888. Of the six ancillary services offered by Western, two
will be provided in conjunction with the sale of CVP and/or COTP
transmission services. These are scheduling, system control and
dispatch service, and reactive supply and voltage control service. The
remaining four ancillary services, regulation and frequency response
service, energy imbalance service, spinning reserve service, and
supplemental reserve service will be offered subject to availability.
The availability and type of ancillary service will be determined based
on excess resources available at the time the service is requested,
except for the two ancillary services provided in conjunction with the
sale of CVP and/or COTP transmission services. The costs associated
with scheduling, system control and dispatch service, and for reactive
supply and voltage control service are included in the appropriate
transmission services rates.
Provisional Rates for COTP Transmission Services
The provisional rates in Rate Schedules COTP-FT1 and COTP-NFT1 for
COTP transmission services include a revenue requirement that recovers
the costs associated with: (1) Western's participation in the COTP; and
(2) scheduling, system control and dispatch service, and reactive
supply and voltage control service needed to provide the transmission
service. The rates are applicable to existing firm and non-firm COTP
transmission services and future point-to-point transmission services.
The rates charged for firm and non-firm COTP transmission services for
a period of one year or less will be no higher than the provisional
rates.
The provisional rates for CVP commercial firm power and
transmission services, power scheduling service, ancillary services,
and for COTP transmission services are developed pursuant to the
Department of Energy Organization Act (42 U.S.C. 7101 et seq.), through
which the power marketing functions of the Secretary of the Interior
and the Bureau of
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Reclamation under the Reclamation Act of 1902 (43 U.S.C. 371 et seq.),
as amended and supplemented by subsequent enactments, particularly
section 9(c) of the Reclamation Project Act of 1939 (43 U.S.C.
485h(c)), and other acts specifically applicable to the project
involved, were transferred to and vested in the Secretary of Energy.
By Amendment No. 3 to Delegation Order No. 0204-108, published
November 10, 1993, (58 FR 59716), the Secretary of Energy delegated:
(1) The authority to develop long term power and transmission rates on
a nonexclusive basis to the Administrator of Western; (2) the authority
to confirm, approve, and place such rates into effect on an interim
basis to the Deputy Secretary of Energy; and (3) the authority to
confirm, approve, and place into effect on a final basis, to remand, or
to disapprove such rates to the FERC. Existing DOE procedures for
public participation in power rate adjustments are located at 10 CFR
Part 903, effective on September 18, 1985 (50 FR 37835).
The Procedures for Public Participation in Power and Transmission
Rate Adjustments and Extensions, 10 CFR part 903, have been followed by
Western in the development of these provisional rates.
Rate Order No. WAPA-77, confirming, approving, and placing the
proposed CVP commercial firm power and transmission services rates,
power scheduling service, ancillary services, and the COTP transmission
services rates into effect on an interim basis, is issued, and the new
Rate Schedules CV-F9, CV-FT3, CV-NFT3, CV-TPT4, CV-NWT1, CV-PSS1, CV-
RFS1, CV-EID1, CV-SPR1, CV-SUR1, COTP-FT1, and COTP-NFT1 will be
submitted promptly to FERC for confirmation and approval on a final
basis.
Dated: September 19, 1997.
Elizabeth A. Moler,
Deputy Secretary.
Order Confirming, Approving, and Placing the Central Valley Project;
Commercial Firm Power and Transmission Services Rates, Power Scheduling
Service and Ancillary Services Rates, and the California-Oregon
Transmission Project Transmission Services Rates Into Effect on an
Interim Basis
October 1, 1997.
These rates are developed pursuant to the Department of Energy
Organization Act (42 U.S.C. 7101 et seq.), through which the power
marketing functions of the Secretary of the Interior and the Bureau of
Reclamation under the Reclamation Act of 1902 (43 U.S.C. 371 et seq.),
as amended and supplemented by subsequent enactments, particularly
section 9(c) of the Reclamation Project Act of 1939 (43 U.S.C.
485h(c)), and other acts specifically applicable to the project
involved, were transferred to and vested in the Secretary of the
Department of Energy (DOE).
By Amendment No. 3 to Delegation Order No. 0204-108, published
November 10, 1993 (58 FR 59716), the Secretary of Energy delegated: (1)
The authority to develop long term power and transmission rates on a
nonexclusive basis to the Administrator of the Western Area Power
Administration; (2) the authority to confirm, approve, and place such
rates into effect on an interim basis to the Deputy Secretary of
Energy; and (3) the authority to confirm, approve, and place into
effect on a final basis, to remand, or to disapprove such rates to the
Federal Energy Regulatory Commission (FERC). Existing DOE procedures
for public participation in power rate adjustments are located at 10
CFR part 903.
Acronyms and Definitions
As used in this rate order, the following acronyms and definitions
apply:
Administrator: The Administrator of Western Area Power Administration.
AERA: Annual energy rate alignment. An energy rate applied at the end
of each fiscal year to all energy purchases under Rate Schedule CV-F9
at or above an annual load factor of 80 percent.
Ancillary Services: Those services necessary to support the transfer of
electricity while maintaining reliable operation of the transmission
system in accordance with good utility practice. Ancillary services are
generally described in Federal Energy Regulatory Commission Order No.
888, Docket Nos. RM95-8-000 and RM94-7-001, issued April 24, 1996.
California-Oregon Transmission Project (COTP): The 500-kilovolt
transmission project in which Western has part ownership.
Capacity: The electric capability of a generator, transformer,
transmission circuit or other equipment. It is expressed in kW.
Capacity Rate: The rate which sets forth the charges for capacity. It
is expressed in $ per kW-month and applied to each kW delivered to each
customer.
Central Valley Project (CVP): A multipurpose Federal water development
project extending from the Cascade Range in northern California to the
plains along the Kern River south of the City of Bakersfield.
Composite Rate: The rate for commercial firm power and is the total
annual revenue requirement for capacity and energy divided by the total
annual energy sales. It is expressed in mills/kWh and used for
comparison purposes.
Contract 2947A: Western's contract with Pacific Gas and Electric,
Southern California Edison, and San Diego Gas and Electric Companies
for extra high voltage transmission and exchange service; Contract No.
14-06-200-2947A, as amended.
Contract 2948A: Pacific Gas and Electric Company's contract with
Western for the sale, interchange and transmission of power; Contract
No. 14-06-200-2948A, as amended.
Corps: United States Army Corps of Engineers.
CRD: Contract rate of delivery. The maximum amount of capacity made
available to a preference customer for a period specified under a
contract.
Customer: An entity with a contract and receiving service from
Western's Sierra Nevada Region.
DOE: United States Department of Energy.
DOE Order RA6120.2: An order dealing with power marketing
administration financial reporting and rate making procedure.
EA2: Energy Bank Account No. 2 between Western and PG&E under Contract
2948A.
Energy: Measured in terms of the work it is capable of doing over a
period of time. It is expressed in kWh.
Energy Rate: The rate which sets forth the charges for energy. It is
expressed in mills/kWh and applied to each kWh delivered to each
customer.
Energy Tier Rate: Existing energy rate in Rate Schedule CV-F8 applied
to energy sales at a 70 percent and higher monthly load factor.
FERC: Federal Energy Regulatory Commission.
Firm: A type of product and/or service that is available at the time
requested by the customer.
First Preference Customer: An entity qualified to use preference power
within a county of origin (Trinity, Calaveras and Tuolumne) as
specified under the Trinity River Division Act of August 12, 1955 (69
Stat. 719), and the Flood Control Act of 1962 (76 Stat. 1180).
FY: Fiscal year; October 1 to September 30.
Interior: United States Department of the Interior.
Intertie: Pacific Northwest-Pacific Southwest Intertie.
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kV: Kilovolt--the electrical unit of measure of electric potential that
equal one thousand volts.
kvar: Kilovolt-ampere reactive--the electrical unit of measurement for
reactive power in a circuit that equals one thousand volt-amperes.
kW: Kilowatt--the electrical unit of capacity that equal one thousand
watts.
kW-month: The electrical unit of the monthly amount of capacity.
kWh: Kilowatt-hour--the electrical unit of energy that equals one
thousand watts in one hour.
Load Factor: The ratio of average load in kW supplied during a
designated period to the peak or maximum load in kW occurring in that
period.
LPF Charge: Low power factor charge.
Mill: A monetary denomination of the United States that equal one tenth
of a cent or one thousandth of a dollar.
Mills/kWh: Mills per kilowatt-hour--the unit of charge for energy.
MW: Megawatt--the electrical unit of capacity that equal one million
watts or one thousand kilowatts.
NEPA: National Environmental Policy Act of 1969 (42 U.S.C. 4321 et
seq.).
Net Revenue: Revenue remaining after paying all annual expenses.
Non-Firm: A type of product and/or service that is not always available
at the time requested by the customer.
Northwest: Northwest United States.
O&M: Operation and maintenance.
PG&E: Pacific Gas and Electric Company.
Power: Capacity and energy.
Power Factor: The ratio of real to apparent power at any given point
and time in an electrical circuit. Generally it is expressed as a
percentage ratio.
Power Scheduling Service: A service that provides for the scheduling of
resources to meet loads and reserve requirements.
Preference: The requirements of Reclamation law which provide that
preference in the sale of Federal power shall be given to
municipalities and other public corporations or agencies and also to
cooperatives and other nonprofit organizations financed in whole or in
part by loans made pursuant to the Rural Electrification Act of 1936
(Reclamation Project Act of 1939, section 9(c), 43 U.S.C. 485h(c)).
Project Use: Power as defined by Reclamation law and/or used to operate
CVP facilities.
Provisional Rates: Rates which have been confirmed, approved, and
placed in effect on an interim basis by the Deputy Secretary of the
Department of Energy.
PRS: Power repayment study.
RAC: Revenue Adjustment Clause.
Rate Brochure: A document prepared for public distribution explaining
the rationale and background of the rate proposal contained in this
rate order dated March 25, 1996.
Reclamation: United States Department of the Interior, Bureau of
Reclamation.
Reclamation Law: A series of Federal laws. Viewed as a whole, these
laws create the originating framework in which the Western Area Power
Administration markets power.
Revenue Requirement: The revenue required to recover O&M expenses,
purchase power and transmission service expenses, interest, deferred
expenses, and repayment of Federal investments, or other assigned
costs.
Sierra Nevada Region: The Sierra Nevada Customer Service Region of
Western Area Power Administration.
Secretary: Secretary of Energy.
Western: United States Department of Energy, Western Area Power
Administration.
Withdrawable: Power that may be withdrawn under certain conditions.
Effective Date
The new rates will become effective on an interim basis on the
first day of the first full billing period beginning on or after
October 1, 1997, and will be in effect pending FERC's approval of them
or substitute rates on a final basis for a 5-year period ending
September 30, 2002, or until superseded.
Public Notice and Comment
The Procedures for Public Participation in Power and Transmission
Rate Adjustments and Extensions, 10 CFR part 903, have been followed by
Western in the development of these rates. The following summarizes the
steps Western took to ensure involvement of interested parties in the
rate process:
1. The proposed rate adjustment was initiated on May 1, 1996, when
a letter announcing the first of four informal customer workshops was
mailed to all CVP customers. The first workshop was held on May 13,
1996, in Folsom, California. Sequential workshops were held on August
21, October 25, and December 17, 1996, in Folsom, California. At these
informal workshops, Western explained the rationale for the rate
adjustment, presented rate designs and methodologies, and answered
questions.
2. A Federal Register notice was published on March 4, 1997 (62 FR
9763), officially announcing the proposed rates for the CVP and COTP,
initiating the public consultation and comment period, and announcing
the public information and public comment forums.
3. On March 7, 1997, letters were mailed from Western's Sierra
Nevada Regional Office to all CVP preference customers and interested
parties transmitting the Federal Register notice of March 4, 1997, and
announced the times and locations for the two public forums.
4. On March 25, 1997, beginning at 9 a.m. PST, the public
information forum was held at Western's Sierra Nevada Regional Office
in Folsom, California. At the public information forum Western provided
detailed explanations of the proposed rates for the CVP and COTP,
provided a list of issues that could change the proposed rates, and
answered questions. Notice was given that additional information would
be provided at the public comment forum. A rate brochure and an
information handout were provided at the forum.
5. On April 24, 1997, beginning at 9 a.m. PDT, the public comment
forum was held at Western's Sierra Nevada Regional Office in Folsom,
California. At the start of the forum, Western presented the updated
rates for the CVP and COTP, provided a detailed explanation of the
changes to the proposed rates, and answered questions. A handout
containing information regarding the updated rates was provided. After
providing this information, Western gave the public an opportunity to
comment for the record. Three representatives made oral comments.
6. Twelve comment letters were received during the consultation and
comment period. The consultation and comment period ended June 2, 1997.
All formally submitted comments have been considered in the preparation
of this rate order.
Project History
The CVP is a large water and power system, initially authorized by
Congress in 1935, which covers approximately one-third of the State of
California. Legislatively defined purposes set the priorities for the
CVP as: (1) River regulation; (2) improvement of navigation; (3) flood
control; (4) irrigation; (5) domestic uses; and (6) power. In addition,
the CVP Improvement Act of 1992 added fish and wildlife habitat as a
priority to the list of CVP purposes.
The CVP is located within the Central Valley and Trinity River
basins of California. The CVP includes 18 dams and reservoirs with a
total storage capacity of 13 million acre-feet. The system includes 615
miles of canals, 5
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pumping facilities, 11 powerplants with a maximum operating capability
of about 2,044 MW, approximately 948 circuit-miles of high voltage
transmission lines, 15 substations, and 23 communication sites.
Reclamation operates the water control and delivery system and all of
the powerplants with the exception of the San Luis Unit, which is
operated by the State of California for Reclamation.
The Emergency Relief Appropriations Act of 1935 initially
authorized the CVP to be constructed by Reclamation to include Shasta
Dam on the Sacramento River in the north and Friant Dam on the San
Joaquin River in the south. Located between these are the Tracy Pumping
Plant; the Delta-Mendota, Contra Costa, Friant-Kern, and Madera canals;
and the Delta Cross Channel. Powerplants at Shasta and Keswick dams
were also included in the initial authorization, along with high
voltage transmission lines designed to transmit power from Shasta and
Keswick powerplants to the Tracy pumps, and to integrate the Federal
hydropower into other electric systems.
In 1944, Congress authorized the American River Division, to be
constructed by the Corps. This Division included Folsom Dam and
Powerplant, Nimbus Dam and Powerplant, and the Sly Park Unit, all
located on the American River. In 1949, the Division was reauthorized
for integration into the CVP.
The Trinity River Division was authorized by Congress in 1955 to
include Trinity Dam and Powerplant, Lewiston Dam and Powerplant, and
the Lewiston Fish Facilities, all located on the Trinity River. The
Trinity Division also includes Judge Francis Carr Powerplant,
Whiskeytown Dam, and the Spring Creek Powerplant.
The San Luis Unit, including the B.F. Sisk San Luis Dam and San
Luis Reservoir, San Luis Canal, Coalinga Canal, O'Neill and Dos Amigos
pumping plants, and William R. Gianelli Pump-Generator, was authorized
by Congress in 1960.
In 1965, Congress authorized construction of the Auburn-Folsom
South Unit as an addition to the CVP. This unit included four subunits,
three of which have been constructed; the Foresthill, Folsom-Malby, and
Folsom South Canal subunits. Funding to complete the construction of
the Auburn Dam, Reservoir and Powerplant, which is part of the fourth
subunit, has not been authorized by Congress.
Congress authorized the San Felipe Division in 1967, and the Allen
Camp Unit in 1976.
Three Corps projects, Buchannan, Hidden, and New Melones, were
authorized for integration into the CVP in 1962. Black Butte, another
Corps project completed in the 1960's, was added to the CVP in 1970 by
the Black Butte Integration Act.
In 1964, Congress authorized the 500-kV Intertie, of which Western
has a 400 MW entitlement of transmission capacity. On July 31, 1967,
Western, PG&E, Southern California Edison Company, and San Diego Gas &
Electric Company entered into Contract 2947A, as amended, to coordinate
the operation of the Intertie for the purpose of transmitting electric
power between the Northwest and the Pacific Southwest.
Western, in marketing the Federal hydroelectric power generated
from the CVP, currently has 80 CVP preference and 34 CVP project use
customers, serving an estimated two million people.
In 1967, PG&E and Western executed Contract 2948A. This contract
provides for the sale, interchange, and transmission of electric
capacity and energy between Western and PG&E. Contract 2948A also
includes provisions for the integration of power generated from the CVP
with the 400 MW of entitlement on the Intertie. The contract also
provides that PG&E will support a maximum simultaneous demand of 1,152
MW for the preference customers through 2004. If CVP power cannot meet
obligations to the preference customers, Contract 2948A provides
Western with the right to purchase capacity and energy from PG&E to
meet those requirements. Any energy in excess of Western's obligations
to preference customers can be sold to PG&E through a banking provision
in the contract. The energy made available under this banking
arrangement allows Western to supplement CVP generation to meet
preference customer load.
Power generated from the CVP is first dedicated to project use. The
remaining power is allocated to various preference customers in
California. Preference customers consist of: (1) Irrigation and water
districts; (2) public utility districts; (3) municipalities; (4)
Federal agencies; (5) State agencies; (6) rural electric cooperatives;
(7) local and suburban passenger transportation entities; and (8) joint
power authorities.
Each preference customer's CRD is composed of firm long-term power
allocations, and may include withdrawable allocations that are
currently allocated, but unused by another customer. For this rate
adjustment it is assumed that all customer withdrawable CRDs can be
withdrawn in the event the load level of 1,152 MW set forth in Contract
2948A is exceeded.
Western's preference customer load level is limited under Contract
2948A to a maximum simultaneous demand, excluding project loads, of
1,152 MW. The maximum simultaneous demand is the sum of each preference
customer's demand for CVP power at a coincidental moment, adjusted to
the load center at the Tracy Switchyard. Notwithstanding the
simultaneous demand limit, Western has contractual obligations to serve
approximately 1,470 MW of firm CRD to its preference customers. This
level of CRD can be served because of the diversity in customers'
loads.
The COTP is a 342-miles long 500-kV transmission project that
electrically interconnects the Northwest to California with what is
called the Third AC Intertie. Operational since March 1993, the COTP
interconnects with the transmission systems of the Northwest at the
Captain Jack Substation, and with the Pacific Southwest by its
connection near the Tesla Substation to the existing Intertie. The
project owners include Western as well as several non-Federal
participants.
Power Repayment Study
Power repayment studies are prepared each fiscal year to determine
if power revenues will be sufficient to pay, within the prescribed time
periods, all costs assigned to the CVP power function. Repayment
criteria are based on law, policies, and authorizing legislation. DOE
Order RA6120.2, section 12b, requires that:
In addition to the recovery of the above costs (operation and
maintenance and interest expenses) on a year-by-year basis, the
expected revenues are at least sufficient to recover: (1) Each dollar
of power investment at Federal hydroelectric generating plants within
50 years after they become revenue producing, except as otherwise
provided by law; plus, (2) each annual increment of Federal
transmission investment within the average service life of such
transmission facilities or within a maximum of 50 years, whichever is
less; plus, (3) the cost of each replacement of a unit of property of a
Federal power system within its expected service life up to a maximum
of 50 years; plus, (4) each dollar of assisted irrigation investment
within the period established for the irrigation water users to repay
their share of construction costs.
CVP Transmission Service Rate Study
Transmission service rates are charged to CVP customers receiving
transmission services over the CVP
[[Page 50929]]
system for the transmission of non-CVP power. A transmission service
rate study was prepared to ensure that transmission service rates are
based on the cost of service of the CVP transmission system.
A review of the CVP transmission service rate study indicated that
the existing firm and non-firm CVP transmission service rates under
Rate Schedules CV-FT2 and CV-NFT2, needed to be adjusted. The
provisional rate for firm CVP transmission service is $0.51 per kW-
month, an 18.6 percent increase from the existing rate of $0.43 per kW-
month. The provisional rate for non-firm CVP transmission service is
1.00 mill/kWh, an 18.7 percent reduction in the existing 1.23 mills/kWh
rate. The change in the firm CVP transmission service rate is due to
increases in transmission facilities costs and in the basis for
assigning miscellaneous and non-facility investment and O&M costs to
transmission to better reflect costs associated with transmission for
all users. The change in the non-firm CVP transmission service rate is
primarily due to a change in the load factor used in determining the
denominator in the rate calculation. The same revenue requirement is
used in determining the firm and non-firm CVP transmission service
rates.
Existing and Provisional Rates
CVP Commercial Firm Power
The provisional rates for CVP commercial firm power are designed to
recover an annual revenue requirement that includes the investment
repayment, interest, purchase power, and O&M expenses. The provisional
rates will also include an AERA. The AERA will be applied to energy
purchases from Western under Rate Schedule CV-F9 at or above an average
annual load factor of 80 percent, calculated at the end of each fiscal
year. The AERA will provide revenues to cover the increased costs of
purchased energy. The AERA is in addition to the provisional CVP energy
rate and replaces the existing energy tier rate.
A comparison of the existing and provisional rates for CVP
commercial firm power follows:
Comparison of Existing and Provisional Rates
------------------------------------------------------------------------
CVP Commercial firm power rate schedule
-------------------------------------------------------------------------
Existing Percent
(effective change from
Effective period 10/01/97 to Provisional existing
04/30/98) rate
------------------------------------------------------------------------
Composite Rate (mills/kWh):
10/01/97 to 04/30/98......... 26.50 20.95 (21)
05/1/98 to 09/30/98.......... ........... 20.95 (21)
10/01/98 to 09/30/99......... ........... 19.31 (27)
10/01/99 to 09/30/00......... ........... 19.31 (27)
10/01/00 to 09/30/01......... ........... 18.56 (30)
10/01/01 to 09/30/02......... ........... 20.08 (24)
Capacity Rate ($ per kW-month):
10/01/97 to 04/30/98......... 4.58 5.03 10
5/1/98 to 09/30/98........... ........... 5.03 10
10/01/98 to 09/30/99......... ........... 4.37 (5)
10/01/99 to 09/30/00......... ........... 4.31 (6)
10/01/00 to 09/30/01......... ........... 3.81 (17)
10/01/01 to 09/30/02......... ........... 4.02 (12)
Energy Rate (mills/kWh):
10/01/97 to 04/30/98......... 16.93 10.31 (39)
05/1/98 to 09/30/98.......... ........... 10.31 (39)
10/01/98 to 09/30/99......... ........... 10.06 (41)
10/01/99 to 09/30/00......... ........... 10.19 (40)
10/01/00 to 09/30/01......... ........... 10.51 (38)
10/01/01 to 09/30/02......... ........... 11.58 (32)
AERA Rate (mills/kWh) supersedes
existing energy tier rate in
Rate Schedule CV-F8.1
10/01/97 to 04/30/98......... (\2\) 2.86 ...........
05/1/98 to 09/30/98.......... (\2\) 2.86 ...........
10/01/98 to 09/30/99......... (\2\) 3.57 ...........
10/01/99 to 09/30/00......... (\2\) 3.92 ...........
10/01/00 to 09/30/01......... (\2\) 4.09 ...........
10/01/01 to 09/30/02......... (\2\) 3.53 ...........
------------------------------------------------------------------------
1 The existing energy tier rate under Rate Schedule CV-F8 is 26.48 mills/
kWh and is effective for the period October 1, 1997, to April 30,
1998.
2 None.
CVP Transmission Services and Transmission of CVP Power by Others
A comparison of the existing and provisional rates for CVP
transmission services and for transmission of CVP power by others
follows:
[[Page 50930]]
Comparison of Existing and Provisional Rates
------------------------------------------------------------------------
CVP Transmission rate schedules
-------------------------------------------------------------------------
Existing Percent
(effective change from
Effective period 10/01/97 to Provisional existing
04/30/98) rate
------------------------------------------------------------------------
Firm Transmission Rate ($ per kW-
month);
10/01/97 to 04/30/98......... 0.43 0.51 18.6
05/1/98 to 09/30/02.......... ........... 0.51 18.6
Non-Firm Transmission Rate (mills/
kWh):
10/01/97 to 04/30/98......... 1.23 1.00 (18.7)
05/1/98 to 09/30/02.......... ........... 1.00 (18.7)
Transmission of CVP Power by
Others Rate Schedule:
10/01/97 to 04/30/98......... (\1\) (\1\) (\2\)
05/1/98 to 09/30/02.......... (\1\) (\1\) (\2\)
------------------------------------------------------------------------
\1\ Pass through cost.
\2\ Not applicable.
Network Transmission Service
The provisional rate formula for network transmission service, if
offered by Western, is the product of the network customer's load ratio
share times one twelfth (\1/12\) of the annual network transmission
revenue requirement. The load ratio share is based on the network
customer's hourly load, including its designated network load not
physically interconnected with the CVP transmission system, coincident
with Western's monthly CVP transmission system peak minus coincident
peak usage of all firm CVP (including reserved capacity) point-to-point
transmission service. The provisional network transmission service rate
formula includes the cost for scheduling, system control and dispatch
service, and reactive supply and voltage control services associated
with the transmission service. The provisional rate is effective for
the period beginning October 1, 1997, through September 30, 2002.
Power Scheduling Service
Power scheduling service is a new service being offered by Western
that provides for the scheduling of resources to meet load and reserve
requirements. The provisional rate for power scheduling service is
$75.80 per hour and will be applied based on an estimated time to
provide the service to each customer receiving the service. The
provisional rate is effective for the period beginning October 1, 1997,
through September 30, 2002.
Ancillary Services
Of the six ancillary services offered by Western, two will be
provided in conjunction with the sale of CVP and/or COTP transmission
services. These are scheduling, system control and dispatch service,
and reactive supply and voltage control service. The remaining four
ancillary services, regulation and frequency response service, energy
imbalance service, spinning reserve service, and supplemental reserve
service will be offered subject to availability. The availability and
type of ancillary service will be determined based on excess resources
available at the time the service is requested, except for the two
ancillary services provided in conjunction with the sale of CVP and/or
COTP transmission services. The provisional rates and descriptions for
the six ancillary services are as follow:
Provisional Rates
------------------------------------------------------------------------
Ancillary services rate schedules
-------------------------------------------------------------------------
Ancillary service type Rate
------------------------------------------------------------------------
Scheduling, System Control and Dispatch Included in appropriate
Service--is required to schedule the transmission rates.
movement of power through, out of,
within, or into a control area.
Reactive Supply and Voltage Control Included in appropriate
Service--is reactive power support transmission rates.
provided from generation facilities
that is necessary to maintain
transmission voltages within
acceptable limits of the system.
Regulation and Frequency Response Monthly: $1.48 per kW-month;
Service--providing generation to match Weekly: $0.3360 per kW-week;
resources and loads on a real-time Daily: $0.0480 per kW-day.
continuous basis. Rate will be applied
to resources reserved for this
service.
Energy Imbalance Service--is provided Within Limits of Deviation
when a difference occurs between the Band: Accumulated deviations
scheduled and actual delivery of are to be corrected or
energy to a load or from a generation eliminated within 30 days. Any
resource within a control area over a net deviations that are
single month. Hourly deviation (MW) is accumulated at the end of the
the net scheduled amount of energy for month (positive or negative)
the hour minus the hourly net metered are to be exchanged with like
(actual delivered) amount. hours of energy or charged at
the composite rate for CVP
commercial firm power, then in
effect.
Outside Limits of Deviation
Band: (i) Positive Deviations--
no charge, lost to the system.
(ii) Negative Deviations--
during on-peak hours, the
greater of 3 times the
composite.
Rate for CVP commercial firm power, Effect, or any additional cost
then in. incurred. During off-peak
hours, the greater of the
composite rate for CVP
commercial firm power, then in
effect, or any additional cost
incurred.
[[Page 50931]]
Spinning Reserve Service--is providing Monthly: $1.35 per kW-month;
capacity that is available the first Weekly: $0.3024 per kW-week;
ten minutes to take load and is Daily: $0.0432 per kW-day;
synchronized with the power system. Hourly: $0.0018 per kWh.
Rate will be applied to resources
reserved for this service.
Supplemental Reserve Service--is Monthly: $1.27 per kW-month;
providing capacity that is not Weekly: $0.2856 per kW-week;
synchronized, but can be available to Daily: $0.0408 per kW-day;
serve loads within ten minutes. Rate Hourly: $0.0017 per kWh.
will be applied to resources reserved
for this service.
------------------------------------------------------------------------
Provisional Rates for COTP Transmission Services
A comparison of the existing and provisional rates for transmission
services for Western's share of the COTP follows:
Comparison of Existing and Provisional Rates
------------------------------------------------------------------------
COTP Transmission rate schedules
-------------------------------------------------------------------------
Percent
Effective Period Existing Provisional change
------------------------------------------------------------------------
Firm Transmission Rate ($ per kW-
month):
10/01/97 to 09/30/98......... 2.03 1.83 (9.9)
10/01/98 to 09/30/02......... 2.03 1.34 (34.0)
Non-Firm Transmission Rate (mills/
kWh):
10/01/97 to 09/30/98......... 2.78 2.19 (21.2)
10/01/98 to 09/30/02......... 2.78 1.45 (47.8)
------------------------------------------------------------------------
Certification of Rate
Western's Administrator has certified that the CVP commercial firm
power, CVP transmission services, transmission of CVP power by others,
network transmission service, power scheduling service, and ancillary
services rates, and COTP transmission services rates placed into effect
on an interim basis herein are the lowest possible rates consistent
with sound business principles. The provisional rates have been
developed in accordance with administrative policies and applicable
laws.
Discussion
CVP Commercial Firm Power
According to Reclamation law, Western must establish power rates
sufficient to recover operation, maintenance, and purchased power
expenses, and repay the Federal government's investment in generation
and transmission facilities. Rates must also be set to cover interest
expenses on the unpaid balance of facilities' investments, replacements
and additions, and certain non-power costs in excess of the irrigation
users' ability to repay.
The existing CVP commercial firm power rates were confirmed and
approved by FERC for the period October 1, 1995 through April 30, 1998,
in a FERC Order issued March 14, 1996. Under Rate Schedule CV-F8 for
the FY 1998, the composite rate on October 1, 1997, is 26.50 mills/kWh,
the base energy rate is 16.93 mills/kWh, the energy tier rate is 26.48
mills/kWh, and the capacity rate is $4.58 per kW-month. The provisional
rates for CVP commercial firm power will result in an overall composite
rate decrease of approximately 21 percent on October 1, 1997, when
compared to the existing FY 1998 CVP commercial firm power rates in
Rate Schedule CV-F8. On a composite rate basis, the proposed rates
continue to decrease in four years of the 5-year period ending
September 30, 2002. The renegotiation and termination of several long
term firm purchase power contracts are the major factors contributing
to this decrease.
The provisional rates consist of a capacity rate, an energy rate,
and an annual energy rate alignment. The AERA will be an additional
cost for energy purchases from Western under Rate Schedule CV-F9 at or
above an average annual load factor of 80 percent, calculated at the
end of each fiscal year. The AERA will provide revenues to cover the
increased costs of purchased energy needed to meet the higher levels of
sales. The AERA is the difference between the estimated rate for short-
term energy purchases used in the cost of service study for CVP
commercial firm power and the provisional CVP energy rate, as shown
below.
------------------------------------------------------------------------
CVP
Estimated commercial
purchase firm AERA
Fiscal year rate energy (mills/
(mills/ rate kWh)
kWh) (mills/
kWh)
------------------------------------------------------------------------
1998.................................. 13.17 10.31 2.86
1999.................................. 13.63 10.06 3.57
2000.................................. 14.11 10.19 3.92
2001.................................. 14.60 10.51 4.09
2002.................................. 15.11 11.58 3.53
------------------------------------------------------------------------
The AERA provides risk mitigation for the assumptions used in the
cost of service study for CVP commercial firm power. If the estimated
purchase costs are too low and customers increase their energy
purchases from Western, then the AERA will provide additional revenues
to cover the increased costs of energy. The AERA applies to only those
customers who purchase energy from Western under Rate Schedule CV-F9 at
or above an average annual load factor of 80 percent. The AERA is in
addition to the provisional CVP energy rate and replaces the existing
energy tier rate in Rate Schedule CV-F8. The billing for the AERA will
be based on the customer's average annual load factor and will occur at
the end of each fiscal year, based on the following formula:
AERA=(Total kWh-(ALF * Hours in fiscal year * 0.7999)) * AERA rate
Where:
AERA=Annual Energy Rate Alignment
kWh=Energy purchased from Western during a fiscal year.
[[Page 50932]]
ALF=Average of monthly billed capacity purchased from Western during a
fiscal year.
An example of AERA billing follows:
Example of AERA Billing for FY 1998
Assumption: Average of monthly billed capacity purchased from
Western during the FY 1998 is 50 MW and the total annual energy
purchased from Western is 394,200,000 kWh.
Calculation of energy below 80 percent load factor:
50,000 kW x 8,760 hours x 0.7999=350,356,200 kWh
Energy at or above 80 percent load factor billed at AERA rate:
394,200,000 kWh-350,356,200 kWh=43,843,800 kWh
43,843,800 kWh x 2.86 mills/kWh0=$125,393.27
In order to utilize the CVP power resources to their maximum
benefit, Western supports CVP generation with capacity and energy
purchases, mainly from Northwest resources and PG&E. The cost of the
CVP power generation is split equally between the capacity and energy
revenue requirements. The amount of capacity and energy available from
the CVP hydroelectric system varies widely because of hydrologic
conditions. These conditions can also impact the value of the capacity
and energy. Due to this variability, an equal split between the
capacity and energy revenue requirements for recovery of the cost of
the CVP power generation is reflective of its actual costs associated
with providing power to all CVP customers.
Currently, the existing rates under Rate Schedule CV-F8 reflect a
split of 35 percent capacity and 65 percent energy. The provisional
rates for CVP commercial firm power are based on the total annual CVP
revenue requirement being allocated between capacity and energy in the
following manner:
1. The capacity revenue requirement includes 100 percent of
capacity purchase costs, 100 percent of purchased transmission service
expense, and 50 percent of the annual CVP investment repayment,
interest expense, and power O&M expense allocated to commercial power.
These annual costs are reduced by the projected revenue from CVP
transmission sales to determine the capacity revenue requirement.
2. The energy revenue requirement includes 100 percent of energy
purchase costs and 50 percent of the annual CVP investment repayment,
interest expense, and power O&M expense allocated to commercial power.
These annual costs are reduced by the projected revenue from surplus
power sales to determine the energy revenue requirement.
The resulting percentage splits between the capacity and energy
revenue requirements for the provisional rates varies from 51 percent
allocated to capacity in FY 1998 to 42 percent allocated to capacity in
FY 2002 due to changes in costs and revenues each year. The average
split for the 5-year period is 46 percent to capacity and 54 percent to
energy. The annual percentage splits between the capacity and energy
revenue requirements are as follow:
------------------------------------------------------------------------
Capacity Energy
Effective period (percent) (percent)
------------------------------------------------------------------------
10/1/97--9/30/98.................................. 51 49
10/1/98--9/30/99.................................. 48 52
10/1/99--9/30/00.................................. 47 53
10/1/00--9/30/01.................................. 43 57
10/1/01--9/30/02.................................. 42 58
5-year average.................................... 46 54
------------------------------------------------------------------------
Power Factor Adjustment
The power factor adjustment under existing Rate Schedule CV-F8 will
continue and is included with the provisional rates for CVP commercial
firm power. The low power factor charge or LPF Charge, will continue to
encourage preference customers to monitor their power factors and
maintain them at 95 percent or greater. Western will continue the
existing LPF Charge under Rate Schedule CV-F9, which includes a rate of
$2.50 per kvar for additional kvar required to raise the customer's
power factor to 95 percent. The $2.50 per kvar rate represents the
estimated cost of Western purchasing and installing equipment to
increase a customer's power factor plus an additional charge to
encourage customers to monitor poor power factors. The LPF Charge will
be applied when the customer does not maintain a calculated 95 percent
or greater power factor.
The customer's calculated power factor used to determine if a
charge will be assessed is the arithmetic mean of the customer's
measured monthly average power factor and the measured monthly on-peak
power factor, rounded to the nearest whole percent with 0.5 percent or
greater rounded to the next higher percent. The measured on-peak power
factor is equal to the power factor measured during a customer's
maximum peak demand for each month, as recorded at the customer's point
of delivery. In the event of multiple occurrences of the same peak
demand, the lowest associated power factor will be used. The measured
average power factor will be the average power factor for the billing
month. Those customers with multiple meter points will be charged for
the ``totalizer'' of the multiple meter points. The monthly on-peak and
average power factors are those recorded for CVP power only.
Low Voltage Loss Adjustment
The low voltage adjustment under existing Rate Schedule CV-F8 will
continue and is included in the provisional rates for CVP commercial
firm power. A 1.035 loss adjustment factor will be applied to the
billed amounts for low voltage CVP power deliveries on PG&E's system
under Contract 2948A.
Revenue Adjustment
The revenue adjustment clause or RAC, tracks variances in future
revenues and expenses, and lessens the probability of significant
revenue surplus or deficit to the CVP repayment. The methodology for
computing the RAC is a comparison of estimated total revenues less
estimated total expenses to actual total revenues less actual total
expenses. If the actual net revenue is more than the estimated net
revenue, CVP preference customers receive a credit. If actual net
revenue is less than the estimated net revenue, CVP preference
customers may have a surcharge, if needed to make a minimum investment
payment. The limit for surcharges is $20 million. The limit for credits
is $20 million plus the amount of EA2 credit or other purchase power
contract adjustments used during the fiscal year for which the RAC is
being calculated. The RAC is a carryover from Rate Schedule CV-F8.
CVP Transmission Services and Transmission of CVP Power by Others
The provisional rate for firm CVP transmission service is $0.51 per
kW-month, an 18.6 percent increase from the existing rate of $0.43 per
kW-month under Rate Schedule CV-FT2. The provisional rate for non-firm
CVP transmission service is 1.00 mill/kWh, an 18.7 percent reduction in
the existing 1.23 mills/kWh rate under Rate Schedule CV-NFT2. The
change in the firm CVP transmission service rate is due to increases in
transmission facilities costs and in the basis for assigning
miscellaneous and non-facility O&M costs to transmission to better
reflect costs associated with transmission for all users. The change in
the non-firm CVP transmission service rate is primarily due to a change
in the load factor used in determining the denominator in the rate
calculation. The same revenue requirement is used in
[[Page 50933]]
determining the firm and non-firm CVP transmission service rates.
The provisional rates for CVP transmission services are based on a
revenue requirement that recovers: (1) The CVP transmission system
costs for facilities associated with providing all transmission
services; and (2) the non-facility costs allocated to transmission
service. These provisional firm and non-firm CVP transmission service
rates include the costs for scheduling, system control and dispatch
service, and reactive supply and voltage control service needed to
provide the transmission service. If scheduling, system control and
dispatch service, and reactive supply and voltage control service are
not provided by Western, the customers will be given credit for the
cost associated with these services, as agreed by the parties. The
provisional rates are applicable to existing firm and non-firm CVP
transmission services and future point-to-point transmission services.
The rates charged for firm and non-firm CVP transmission services for a
period of one year or less will be no higher than the provisional
rates.
Transmission service costs incurred by Western in the delivery of
CVP power over a third party's transmission system to a CVP customer,
will be directly passed through to that CVP customer. Both annual
revenues and expenses are included in the PRS to account for all
charges, even though the net effect is zero. Transmission pass through
revenues and expenses are estimated using existing customer load
forecasts and project use requirements, and applicable transmission
service rates. Transmission pass through revenues and expenses
primarily consist of payments to PG&E for transmission services to
preference and project use loads, and payments to the Sacramento
Municipal Utility District for transmission services to preference
customers.
Network Transmission Service
Network transmission service is a new service and, if offered by
Western, will be made available consistent with FERC Order No. 888. Due
to existing contractual arrangements and not being a control area
operator for the CVP, Western may not be able to provide network
transmission service but has included a rate formula in case Western
offers the service. The provisional rate formula for network
transmission service is based on a revenue requirement that recovers
the CVP transmission system costs for facilities associated with
providing all transmission services and the non-facility costs
allocated to transmission service. The provisional rate formula
includes the costs for scheduling, system control and dispatch service,
and reactive supply and voltage control service needed to provide the
network transmission service.
Power Scheduling Service
Power scheduling is a new service being offered by Western that
provides for the scheduling of resources to meet loads and reserve
requirements. The provisional rate for power scheduling service is
designed to recover only the cost incurred by Western for providing the
service. The provisional rate includes two cost components. The first
cost component is the FY 1997 hourly cost for dispatcher and/or
scheduler resources, escalated for the rate adjustment period of FY
1998 through FY 2002 to obtain an average hourly cost. The second cost
component is an estimated hourly cost for equipment necessary in
providing the service.
Ancillary Services
Ancillary services are new services and, if offered by Western,
will be made available consistent with FERC Order No. 888. Of the six
ancillary services offered by Western, two will be provided in
conjunction with the sale of CVP and/or COTP transmission services.
These are scheduling, system control and dispatch service, and reactive
supply and voltage control service. The remaining four ancillary
services, regulation and frequency response service, energy imbalance
service, spinning reserve service, and supplemental reserve service
will be offered subject to availability. Western's sales of ancillary
services are subject to the availability of its power resources because
Western allocates most of its power resources to preference entities
under long-term commitments. The availability and type of ancillary
service will be determined based on excess resources available at the
time the service is requested.
The provisional rates for ancillary services are designed to
recover only the costs associated with providing the service(s). The
costs for providing scheduling, system control and dispatch service,
and reactive supply and voltage control service are included in the
provisional transmission services rates. The provisional rate for
energy imbalance service is based on standards and practices used in
the electric utility industry. For the provisional rates for regulation
and frequency response, spinning reserve, and supplemental reserve
services, Western used a detailed cost of service study to determine
these rates, which are based on CVP facilities that are used in
providing the service(s). Only those CVP facilities costs are
considered in the determination of rates for regulation and frequency
response, spinning reserve, and supplemental reserve services. The CVP
facilities that are used in providing regulation and frequency
response, spinning reserve, and supplemental reserve services are the
Shasta, Folsom, Trinity, New Melones, Spring Creek, and Judge F. Carr
powerplants. The Nimbus and Keswick powerplants are not available
because of river run conditions. There are no governors at the O'Neill
and San Luis powerplants, which makes them unavailable for providing
the services.
COTP Transmission Services
Since the COTP went into operation in 1993, Western has sold COTP
transmission services on a short-term basis using rates approved by the
Administrator. Rate schedules are being promulgated for COTP firm and
non-firm transmission services to be consistent with FERC Order No.
888. The provisional rates for firm transmission service for Western's
share of the COTP are $1.83 per kW-month for FY 1998 and $1.34 per kW-
month for FY 1999 through FY 2002. These rates for firm COTP
transmission service result in 9.9 percent (FY 1998) and 34.0 percent
(FY 1999 through FY 2002) reductions in the existing rate of $2.03 per
kW-month. The provisional rates for non-firm COTP transmission service
are 2.19 mills/kWh for FY 1998 and 1.45 mills/kWh for FY 1999 through
FY 2002. These rates for non-firm COTP transmission service result in
21.2 percent (FY 1998) and 47.8 percent (FY 1999 through FY 2002)
reductions in the existing rate of 2.78 mills/kWh. These rates are
lower than the existing rates for COTP firm and non-firm transmission
services due to reduced costs for and the terminations of some
contracts for COTP transmission capacity.
The provisional rates for COTP transmission services includes a
revenue requirement that recovers the costs associated with: (1)
Western's participation in the COTP; and (2) scheduling, system control
and dispatch service, and reactive supply and voltage control service
needed to provide the transmission service. If scheduling, system
control and dispatch service, and reactive supply and voltage control
service are not provided by Western, the customers will be given credit
for the cost associated with these services, as agreed by the parties.
The provisional rates are applicable to existing firm and non-firm COTP
transmission services and future point-to-point transmission
[[Page 50934]]
services. The rates charged for firm and non-firm COTP transmission
services for a period of one year or less will be no higher than the
provisional rates.
Statement of Revenue and Related Expenses
The following table provides a summary of revenues and expenses for
the 5-year provisional rate period and the 3-year existing rate period.
CVP Cost Evaluation Rate Period Revenues and Expenses ($1,000)
----------------------------------------------------------------------------------------------------------------
Provisional Existing
rate PRS FY rate PRS FY Difference
1998-02 1996-98
----------------------------------------------------------------------------------------------------------------
Total Revenues................................ 824,651 609,954 Not Applicable See Note below.
Revenue Distribution:
O&M....................................... 216,776 105,521 Note: The revenues and expenses for
the provisional rates are for 5
years. Those for the existing rates
are for 3 years. Therefore, the
difference is not applicable.
Purchase Power............................ 390,689 407,804
Transmission.............................. 80,335 45,098
Interest.................................. 54,536 29,933
Other..................................... 9,073 0
Investment Repayment...................... 73,242 21,598
Capitalized Expenses...................... 0 0
Prior-Year Adjustment..................... 0 0
----------------------------------------------------------------------------------------------------------------
The following table provides a summary of the average annual
revenues and expenses for the provisional and existing rate periods.
CVP Comparison of Cost Evaluation Rate Period Average Annual Revenues
and Expenses ($1,000)
------------------------------------------------------------------------
Provisional Existing
rate rate
average average Difference
annual annual
------------------------------------------------------------------------
Total Revenues............. 164,930 203,318 (38,388)
--------------------------------------
Revenue Distribution:
O&M.......................... 43,355 35,174 8,181
Purchase Power............... 78,138 135,935 (57,797)
Transmission................. 16,067 15,033 (1,034)
Interest..................... 10,907 9,978 (929)
Other........................ 1,815 0 1,815
Investment Repayment......... 14,648 7,199 7,449
Capitalized Expenses......... 0 0 ...........
Prior-Year Adjustment........ 0 0 ...........
------------------------------------------------------------------------
Basis for Rate Development
The existing rates for CVP commercial firm power, CVP transmission
services and transmission of CVP power by others in Rate Schedules CV-
F8, CV-FT2, CV-NFT2, and CV-TPT3 expire April 30, 1998. Reduced costs
for and the terminations of some of Western's power purchase and COTP
transmission contracts have occurred. Power scheduling, network
transmission, and ancillary services are new services being offered by
Western. The proposed rate adjustment is needed to put into place
rates, which will replace the existing rates, that reflect reduced
purchase power expenses due to a decrease in customers' CVP power
purchases, reduced costs of transmission contracts, current methodology
in rate design, and to provide rates for new services. The provisional
rates will provide sufficient revenue to pay all annual costs,
including interest expense, and repayment of required investment within
the allowable period. The provisional rates are scheduled to go in
effect on October 1, 1997, to correspond with the start of the Federal
fiscal year, and will remain in effect through September 30, 2002.
The provisions for power factor adjustment, low voltage loss
adjustment, and revenue adjustment are part of the provisional rates
for CVP commercial firm power. The provisions and methodologies for
these adjustments are not being modified and will remain as specified
in Rate Schedule CV-F8.
Comments
During the public consultation and comment period, Western received
12 written comments on the rate adjustment. In addition, three customer
representatives commented during the April 24, 1997 public comment
forum. All comments received by the end of the public consultation and
comment period, June 2, 1997, were reviewed and considered in the
preparation of this rate order.
Written comments were received from the following sources:
Bookman-Edmonston Engineering, Inc. (California)
Calaveras Public Power Agency (California)
National Aeronautics and Space Administration, Ames Research Center
(California)
Northern California Power Agency (California)
City of Palo Alto (California)
City of Redding (California)
City of Roseville (California)
Sacramento Municipal Utility District (California)
City of Santa Clara (California)
Trinity County Board of Supervisors (California)
Trinity County Public Utilities District (California)
[[Page 50935]]
Tuolumne Public Power Agency (California)
The comments received in correspondence dealt with the CVP
commercial firm power rate design, specifically, the capacity and
energy split for revenue recovery and the AERA, the CVP transmission
service rate design, separate county-of-origin rate, and the RAC. All
comments supported Western's efforts to reduce the rates. The following
is a summary of the comments received by the end of the consultation
and comment period and Western's responses to those comments. The
comments and responses, paraphrased for brevity are presented below.
Specific comments are used for clarification where necessary.
CVP Commercial Firm Power (Capacity and Energy Revenue Requirement
Split)
The following comments relate to the change in CVP rate design from
recovering 35 percent of the revenue requirement from capacity and 65
percent from energy, to capacity and energy revenue requirement
percentage splits that varies from 51 percent allocated to capacity in
FY 1998 to 42 percent allocated to capacity in FY 2002.
Comments: Five customers commented that they want the provisional
rates for CVP commercial firm power to reflect a true cost of service
allocation by including investment payment, interest expense, and O&M
expense in the capacity revenue requirement. This would result in a
capacity and energy revenue requirement split of 70 percent allocated
to capacity and 30 percent allocated to energy. Three of the customers
commented that they support a ``phasing-in'' approach in achieving a
rate design toward the ``true cost of service'' allocation of 70
percent capacity and 30 percent energy. Two other customers commented
that they also support the phasing-in approach, but want a split closer
the existing rate design in the first year and eventually moving toward
a split of 50 percent capacity and 50 percent energy. A representative
that represents a coalition of fourteen agricultural CVP power
customers, commented that it prefers the existing allocation split, but
supports the proposed splits in the provisional rates as an effective
balance among Western's customers.
Responses: Western believes its proposed revenue requirement
percentage splits between capacity and energy reflects a ``true cost of
service'' allocation. The cost of the CVP power generation is split
equally between the capacity and energy revenue requirements. The
amount of capacity and energy available from the CVP hydroelectric
system varies widely because of hydrologic conditions. These conditions
can also impact the value of the capacity and energy. Due to this
variability, Western believes that an equal split between the capacity
and energy revenue requirements for recovery of the cost of the CVP
power generation is reflective of its actual costs associated with
providing power to all CVP customers. However, in order to utilize the
CVP power resources to their maximum benefit, Western supports the CVP
generation with capacity and energy purchases, mainly from Northwest
resources and from PG&E. Therefore, capacity purchase costs are
allocated to capacity and energy purchase costs are allocated to
energy. Western believes that all CVP customers benefit from this
marketing approach and should pay for these benefits. Because the CVP
costs vary annually, the percentage splits also vary annually.
In response to comments relating to ``phasing-in'' the change in
the capacity and energy revenue requirement split, Western believes
that it is inappropriate for this rate adjustment period. The annual
changes in the revenue requirement splits reflect the change in annual
costs for providing firm power service.
Comment: One customer commented that the rates being generated are
for the benefit of the high load factor customers, and put the low load
factor customers at a significant disadvantage. Also, this customer
commented that it does not like the financial burden of supplemental
thermal energy spread to all customers, since high load factor
customers benefit from this arrangement. This customer wants to
``unbundle'' the cost of thermally generated supplemental energy from
the cost of CVP hydroelectric power.
Response: Western markets power based on a pool of resources, all
of which can be used to serve firm power contractual loads. It is
Western's position that Western has an obligation to meet all its
contractual commitments. The provisional rates reflect Western's actual
costs associated with providing power to all CVP customers, not an
individual customer's consumption of capacity or energy. All resources
necessary to supply the total CVP commercial power obligation are
considered in each kWh and kW of power sales. This results in a
homogenous and nondiscriminatory rate design. The generalization that
high load factor customers cause the purchase of energy in excess of
CVP generation, while low load factor customer do not, is inaccurate.
The annual CVP generation follows a pattern of high generation in the
spring and summer months, and low generation in the fall and winter
months. If low load factor customers were to peak significantly and
have high loads in a fall or winter month, a substantial portion of the
energy served by Western for such loads is likely from purchased power.
CVP Commercial Firm Power (AERA)
The following comments relate to the CVP annual energy rate
alignment, which is an additional cost for firm energy purchases at or
above an average load factor of 80 percent.
Comments: Two customers want to eliminate the AERA. They argued
that given the conservatism of the forecasts used to develop the rates,
the AERA is equivalent to ``wearing both a belt and suspenders''. One
other customer wants a redefinition of the AERA to, ``* * * is equal to
the pass-through energy costs above the CVP commercial firm energy
rate.''
Responses: Western is adopting the change in the definition of the
AERA to, ``* * * the difference between the estimated rate for short
term energy purchases used in the cost of service study for CVP
commercial firm power and the provisional CVP energy rate.'' The AERA
provides risk mitigation for the purchase rate assumptions used in this
rate adjustment. If the estimated purchase costs are too low and
customers increase their energy purchases from Western, then the AERA
will provide additional revenues to cover the increased costs of
energy. The AERA will be an additional cost for energy purchases from
Western at or above an average annual load factor of 80 percent. The
AERA replaces the existing energy tier rate and is designed to reduce
the impact of purchasing additional CVP support energy on all
customers. The AERA applies to only those customers who purchase energy
from Western at or above an average annual load factor of 80 percent.
CVP Transmission Services Rates
The following comments relate to the provisional rates for CVP
transmission services.
Comment: Three customers commented that the costs of non-
transmission items and certain customer specific items in Western's
plant-in-service study should not be included as part of the rates
development. These customers believe that these items have been either
paid for through other sources of funds or paid entirely by a
particular customer, and therefore
[[Page 50936]]
should not be charged to all CVP customers. Examples of items, which
the customers gave to be excluded from the calculations are Roseville
Substation and COTP lands.
Response: Western reviewed the costs allocated under the non-
facility specific O&M and concluded that the some costs allocated for
COTP lands was incorrect. This amount totaling $4,060 was omitted from
the final rate calculation. In response to the Roseville Substation,
there were no plant-in-service costs allocated in the rate calculation,
however, there were costs associated with interest expense at an 8.875
percent rate. The interest expense was revised, as explained below.
Comments: Three customers commented that certain interest expenses
for various transmission facilities, those with higher interest rates,
have been either retired or paid off by Western. It is their
understanding that as a result of the 1992-93 settlement between
Western and PG&E, Western was not able to refund the large cash
settlement from PG&E through the RAC process, and therefore Western
used some of the refund to purchase down some of the higher interest
loans. These customers believe that it is inappropriate to be charged
for interest obligations which do not exist. The three customers want
the rate calculations to be based on only the actual interest rates for
costs remaining, or be based on average system-wide interest costs.
Responses: Western reviewed the costs included in the plant-in-
service study and determined that there was an error in the interest
rate calculation for the facilities listed as plant in service (P-I-S).
This error has been corrected, and as a result, all interest expenses
for repaid investment was excluded from the transmission rate study.
The interest associated with the Roseville Substation mentioned above
was also excluded. Western applied interest to P-I-S facilities at the
interest rates applicable to each project. When a specific interest
rate was not identified, a 3.0 percent rate was applied. The average
interest rate applied to P-I-S facilities in the CVP transmission rate
study calculates to be 3.08 percent.
In order to recognize the P-I-S paid through transmission revenue,
Western made an adjustment to account for repayment of transmission
investment that have been made during FY 1993 to FY 1997 as follows:
1. The total investment amount for this rate adjustment was reduced
by the total payment on investment for five years of the 50-year
repayment period of the 1993 rate adjustment.
2. The remaining investment payment amount from the 1993 rate
adjustment was amortized over 45 years.
3. The remainder of the total investment for this rate adjustment
that was not included in the 1993 rate adjustment was amortized for 50
years, to calculate an annual payment for these investments. The result
was deducted from the annual payment.
Comment: Two customers recommended that since the provisional rates
represent a net 20 percent increase in the existing CVP transmission
services rates, which is a significant change, a ``phasing-in''
approach would be better for them to have time to adjust. Also, this
phasing-in approach would allow time to evaluate the possible impacts
from the future California's Independent System Operator on
transmission usage and costs.
Response: Western believes that the CVP transmission rates
accurately reflect the cost of providing CVP transmission service.
Therefore, Western will not be implementing a ``phasing-in'' period for
the provisional CVP transmission services rates.
Comment: Three customers recommended a formation of a customer
group to work with Western on the tracking, monitoring and allocating
of Western's transmission expenses.
Response: At several meetings during the informal public process,
Western discussed with the preference customers the transmission rate
costs and rate design methodology. The comment recommending a formation
of a customer group to work with Western on the tracking, monitoring,
and allocating of Western's transmission expenses is outside the scope
of this rate adjustment and public process.
County of Origin Rate for First Preference Customers
The following comments relate to inquiries for a separate county of
origin rate for first preference customers.
Comments: Four customers commented that they believe there must be
a county of origin rate for first preference customers and encourage
Western to recognize the need to ``treat first preference customers in
a unique manner, since they are legislated recipients of CVP power''.
These customers want Western to establish a first preference county of
origin rate which is reflective of the actual cost of power generation
from CVP facilities in those counties. One customer commented that in
the past, they have ``been penalized by having to pay for purchased
power to meet other customers' load requirements' and that they have
been ``deprived of most of the first preference benefits.'' Another
customer argued that ``the rights granted by Congress to them should be
met first before other Western customers receive extra services'' and
that the provisional rates are ``many times higher than the rates
contemplated by Congress as partial mitigation''.
Responses: The Flood Control Act of 1962 authorized construction of
the New Melones Project and specifically granted first preference to
preference customers in Calaveras and Tuolumne counties, in a quantity
to the extent needed but not to exceed 25 percent of such additional
CVP energy resulting from the construction of the New Melones Project
power facility and its integration into the CVP system. The Act of
August 12, 1955 authorized construction of the Trinity River Division
and granted a similar first preference to preference customers in
Trinity County, to the extent of 25 percent of such additional energy
available from the CVP power system as a result of the construction of
the Trinity River Project, as integrated into the CVP system, and who
are ready, able and willing to enter into contracts for the energy.
The Acts entitled the preference customers in those counties who
are ready, able and willing to enter contracts with Western to a first
preference in the purchase of CVP energy to the extent needed, but not
to exceed 25 percent and under certain conditions. The authorizing
legislation also provides that the Trinity and New Melones projects be
integrated and coordinated, from both a financial and an operational
standpoint, with the operation of other features of the CVP. In Trinity
County v. Harrington the court determined first preference customers
are not entitled to preferential rates based on the operating costs of
Trinity and New Melones projects alone, as opposed to operating costs
of the CVP system as a whole. The provisional rates for CVP commercial
firm power are based on the operation costs of the CVP system as whole,
and will be applied to all CVP customers who purchase CVP power from
Western. In addition, since the CVP power service provided to first
preference customers is the same as that provided to other customers
who receive CVP power, the provisional rates for CVP commercial firm
power charged to other CVP customers will be the same for the first
preference customers.
Other Comments
The following comments relate to the RAC, project use power,
allocation of
[[Page 50937]]
multipurpose joint costs, EA2, energy tier rate, and general rate
design.
Comment: The RAC distribution should be reset for each 6-month
period rather than the 9-month period. This would enable Western to
adjust revenues for wholesale customers more promptly.
Response: The annual maximum RAC credit is $20 million plus the use
of EA2 credit from PG&E and/or other adjustments from purchase power
contracts. Limiting the distribution of the RAC to 6 months would make
it difficult to refund the maximum RAC credit allowed. Using a 9 month
distribution ensures most, if not all customers, will receive maximum
benefit from the RAC calculation.
Comment: Allocating larger portions of multipurpose joint costs to
the CVP power customers must be stopped because it impairs Western's
efforts to remain competitive in the new restructured California's
electric market.
Response: The Bureau of Reclamation is responsible for the
allocation of CVP multipurpose costs. Comments pertaining to the
allocation of these costs should be directed to Reclamation during
their public participation process on the CVP cost allocation.
Comment: Western needs to rethink its use of the EA2 energy based
on its recent discussions with PG&E and work closely with the customers
on this matter.
Response: Future use of EA2 can be impacted by many variables, some
of which can not be evaluated at this time because information is not
available. An example would be the possible impact on EA2 from the
divesture of PG&E's generation. Western has based its projections for
EA2 usage on the information currently available. The RAC is available
to cover possible changes in the costs associated with EA2.
Comment: Project use customers have underpaid Western for project
use power during past years in an amount between $15-20 million.
Request that Western increase project use revenue collection to bring
such balance to zero by the end of this 5-year rate adjustment period.
Also request that the project use additional revenue be included in the
initial setting of Western's rates, instead of allowing the additional
revenue to roll through the RAC.
Response: The amount owed by the project use customers is still
being determined. Western is anticipating full payment by December
2004, however the exact timing and magnitude of payments from the
project use customers is not known. Given this uncertainty, Western
believes it is prudent to exclude any estimated amount in the
provisional rates. Any payments made will flow through the annual RAC
calculation.
Comments: The proposed CVP energy component of the rates appears
marginally competitive. Western should set the rates based on a ``high
use'' scenario instead of the ``average use'' scenario. This will give
lower rates and the scheduling customers will more likely utilize CVP
power. In the event that CVP energy delivery is less than planned, the
RAC would be used to meet revenue requirement. It would highly be
unlikely that the $20 million RAC limit for revenue recovery would
cause a revenue shortfall if rates are based on very high usage and
lower than average usage occurred. Western should adopt a higher energy
use basis in the derivation of rates.
Responses: In developing the provisional rates, Western performed
studies that considered maximum, minimum and average use (power sales)
scenarios based on historical sales. The results of these studies
indicated that the maximum sales or high sales scenario was not
justifiable because of the magnitude of increase from the FY 1996
recorded amounts for firm commercial power sales. The average sales
scenario was an appropriate transition given the historical sales
levels and the change to the power rates contained in this rate
adjustment. Due to the volatility of the electric industry, the $20
million RAC limit may not be sufficient to cover the assumptions of
average versus maximum power sales if the actual costs are
substantially higher that those projected in this rate adjustment.
Comment: Western's energy forecast for FY 1999 is wrong and the
proposed rates undercuts the 1999 market energy rates by over 50
percent. Believes this will have customers purchasing energy as much as
possible from Western, thus depleting the EA2 energy and cause a clamor
by the high load factor customers for Western to get back into
procuring supplemental thermal energy.
Response: The studies Western performed in developing the
provisional rates indicate that the EA2 energy will be available
throughout the 5-year rate adjustment period. In fact, there is a
balance remaining in EA2 after the 5-year period.
Comment: A customer commented it liked the tiered energy rate
arrangement since it represented Western's effort toward ``marginal
cost'' pricing and caused a reduction in consumption of Western's
supplemental thermal energy. This customer recommends that Western
adopts a rate form like the existing tier rate and establish a tier
rate at the 2.2 to 2.4 cents per kWh range for energy sales over 70
percent load factor.
Response: Western performed an analysis that considered the
implementation of an energy tier rate. The methodology and the
assumptions used were the same as those used in developing the existing
energy tier rate. The result of this analysis indicated that the
difference between the base and energy tier rates was minimal.
Therefore, Western decided an energy tier rate will not be implemented
for this rate adjustment.
Environmental Compliance
In compliance with the National Environmental Policy Act of 1969,
42 U.S.C. 4321 et seq.; the Council on Environmental Quality
Regulations for implementing NEPA (40 CFR parts 1500 through 1508); and
the DOE NEPA Implementing Procedures and Guidelines (10 CFR part 1021),
Western has determined that this action is categorically excluded from
the preparation of an environmental assessment or an environmental
impact statement.
Determination Under Executive Order 12866
DOE has determined that this is not a significant regulatory action
because it does not meet the criteria of Executive Order 12866, 58 FR
51735. Western has an exemption from centralized regulatory review
under Executive Order 12866; accordingly, no clearance of this notice
by the Office of Management and Budget is required.
Availability of Information
Information regarding this rate adjustment, including power
repayment studies, comments, letters, memorandums, and other supporting
material made or kept by Western for the purpose of developing the
provisional rates, is available for public review in the Sierra Nevada
Regional Office, Western Area Power Administration, Office of the Power
Marketing Manager, 114 Parkshore Drive, Folsom, California 95630, and
the Power Marketing Liaison Office, Room 8G-027, 1000 Independence
Avenue SW., Washington, DC 20585.
Submission to the Federal Energy Regulatory Commission
The rates herein confirmed, approved, and placed into effect on an
interim basis, together with supporting documents, will be submitted to
FERC for confirmation and approval on a final basis.
[[Page 50938]]
Order
In view of the foregoing and pursuant to the authority delegated to
me by the Secretary of Energy, I confirm and approve on an interim
basis, effective October 1, 1997, Rate Schedules CV-F9, CV-FT3, CV-
NFT3, CV-TPT4, CV-NWT1, CV-PSS1, CV-RFS1, CV-EID1, CV-SPR1, CV-SUR1,
COTP-FT1, and COTP-NFT1 for the Central Valley Project and for the
California-Oregon Transmission Project of the Western Area Power
Administration. The rate schedules will remain in effect on an interim
basis, pending confirmation and approval on a final basis by the
Federal Energy Regulatory Commission, through September 30, 2002, or
until superseded.
Dated: September 19, 1997.
Elizabeth A. Moler,
Deputy Secretary.
Rate Schedule CV-F9
(Supersedes Schedule CV-F8)
Central Valley Project
Schedule of Rates for Commercial Firm Power
Effective: October 1, 1997.
Available: Within the marketing area served by the Sierra Nevada
Customer Service Region.
Applicable: To the commercial firm power customers for general
power service supplied through one meter, at one point of delivery,
unless otherwise provided by in the service agreement.
Character and Conditions of Service: Alternating current, 60 hertz,
three-phase, delivered and metered at the voltages and points
established by contract.
------------------------------------------------------------------------
Capacity Energy AERA (mills/
Monthly rates: Period (kW=Month) (mills/kWh) kWh)
------------------------------------------------------------------------
10/01/97-09/30/98................ $5.03 10.31 2.86
10/01/98-09/30/99................ 4.37 10.06 3.57
10/01/99-09/30/00................ 4.31 10.19 3.92
10/01/00-09/30/01................ 3.81 10.51 4.09
10/01/01-09/30/02................ 4.02 11.58 3.53
------------------------------------------------------------------------
Billing: Demand: The rates listed above for capacity will be the
charge per kW of billing demand. The billing demand is the highest 30-
minute integrated demand measured or scheduled during the month up to,
but not in excess of, the delivery obligation under the power sales
contract.
Energy: The rates listed above for energy will be a charge per kWh
for all energy use up to, but not in excess of, the maximum kWh
obligation of the United States during the month as established under
the power sales contract.
Annual Energy Rate Alignment (AERA): The rates listed above for
AERA will be an additional charge per kWh for energy purchases at or
above an average annual load factor of 80 percent, calculated at the
end of each Federal fiscal year (September 30). The AERA is in addition
to the CVP energy rate. The billing for the AERA will be based on the
following formula:
AERA=(Total kWh-(ALF * Hours in fiscal year * 0.7999)) * AERA rate
Where:
AERA=Annual Energy Rate Alignment
kWh = Energy purchased from Western during a fiscal year.
ALF=Average of monthly billed capacity purchased from Western during a
fiscal year.
Adjustments
Billing for Unauthorized Overruns. For each billing period in which
there is a contract violation involving an unauthorized overrun of the
contractual obligation for capacity and/or energy, such overrun will be
billed at 10 times the applicable rates above.
For Revenue Adjustment. The following methodology will be used for
the revenue adjustment clause (RAC) calculation:
1. If the actual net revenue is greater than the projected net
revenue for the RAC calculation period, a revenue credit will be
allocated during the RAC adjustment period. The credit will equal the
difference between the actual net revenue and projected net revenue,
represented by the following formula:
ANR>PNR; C=ANR-PNR
Where:
ANR=Actual Net Revenue
PNR=Projected Net Revenue
C=Credit
2. If actual net revenue is less than the projected net revenue for
the RAC calculation period, a revenue surcharge will be allocated
during the RAC adjustment period.
2.1 If the actual net revenue is negative, the surcharge will be
equal to the minimum investment payment plus the annual deficit,
represented by the following formula:
ANR0; S=MIP-ANR (if ANR>MIP, S=0)
Where:
ANR=Actual Net Revenue
PNR=Projected Net Revenue
MIP=Minimum Investment Payment
S=Surcharge
Provided, that if the actual net revenue is greater than the
minimum investment payment, the surcharge will be equal to zero.
3. The maximum RAC credit allocation will equal $20 million plus
the amount of the Pacific Gas and Electric Company refund credit
applied to Western power bills for the fiscal year, or other purchase
power contract adjustments used in recording associated expense.
4. The maximum allocation for a RAC surcharge will not exceed $20
million.
5. The RAC credit or surcharge will be allocated to each CVP
commercial firm power customer based on the proportion of the
customer's billed obligation to Western for CVP commercial firm
capacity and energy to the total billed obligation for all CVP
commercial firm power customers for CVP commercial firm capacity and
energy for the RAC calculation period.
6. For purposes of the RAC calculation, the following terms are
defined:
6.1 Actual Net Revenue--The recorded net revenue.
6.2 Annual Deficit--The amount the recorded annual expenses, including
interest, exceeding recorded annual revenues.
6.3 Minimum Investment Payment--The lesser of 1 percent of the
recorded
[[Page 50939]]
unpaid investment balance at the end of the prior fiscal year that the
RAC is being calculated, or the projected net revenue.
6.4 Projected Net Revenue--The annual net revenue available for
investment repayment projected in the PRS for the rate case during the
fiscal year that the RAC is being calculated (see Table 1).
6.5 RAC Adjustment Period--The period January 1 through September 30,
following the RAC calculation period when credits or surcharges will be
applied to the power bills.
6.6 RAC Calculation Period--The last recorded fiscal year (October 1
through September 30).
6.7 Recorded Net Revenue--The annual net revenue available for
repayment recorded in the PRS for the fiscal year that the RAC is being
calculated.
7. Subject to modification by a superseding rate schedule, the
final RAC will be allocated to the customers during the period January
1, 2003, to September 30, 2003.
Table 1.--Projected Net Revenue Available for Investment Repayment for
Revenue Adjustment Clause
------------------------------------------------------------------------
Period Projected net revenue
------------------------------------------------------------------------
October 1, 1997-September 30, 1998........ $5,522,851
October 1, 1998-September 30, 1999........ 9,534,973
October 1, 1999-September 30, 2000........ 12,196,514
October 1, 2000-September 30, 2001........ 17,039,731
October 1, 2001-September 30, 2002........ 28,948,352
------------------------------------------------------------------------
For Transformer Losses
If delivery is made at transmission voltage but metered on the low
voltage side of the substation, the meter readings will be increased to
compensate for transformer losses as provided for in the contract.
For Power Factor Adjustment
The customer will be required to maintain a power factor at all
points of measurement between 95 percent lagging and 95 percent
leading. The low power factor charge (LPF Charge) will be applied when
the customer does not maintain a 95 percent or greater power factor.
The charge for additional kilovolt-ampere reactive (kvar) required to
raise the customer's power factor to 95 percent will be calculated by
multiplying the customer's monthly maximum peak demand by the LPF
Charge for the customer's calculated power factor as provided in the
Table 2. The kvar rate in the LPF Charge is $2.50 per kvar.
Table 2.--Low Power Factor Charge
------------------------------------------------------------------------
LPF
charge
Calculated power factor ($ per
kW)
------------------------------------------------------------------------
0.95.......................................................... $0.00
0.94.......................................................... 0.09
0.93.......................................................... 0.17
0.92.......................................................... 0.24
0.91.......................................................... 0.32
0.90.......................................................... 0.39
0.89.......................................................... 0.46
0.88.......................................................... 0.53
0.87.......................................................... 0.60
0.86.......................................................... 0.66
0.85.......................................................... 0.73
0.84.......................................................... 0.79
0.83.......................................................... 0.86
0.82.......................................................... 0.92
0.81.......................................................... 0.99
0.80.......................................................... 1.05
0.79.......................................................... 1.12
0.78.......................................................... 1.18
0.77.......................................................... 1.25
0.76.......................................................... 1.32
0.75 & below.................................................. 1.38
------------------------------------------------------------------------
The rules and limitations of the LPF Charge are as follow:
(a) The calculated power factor used to determine if a charge will
be assessed is the arithmetic mean of the customer's measured monthly
average power factor and their measured monthly on-peak power factor,
rounded to the nearest whole percent with 0.5 percent or greater
rounded to the next higher percent.
(b) The measured on-peak power factor is equal to the power factor
measured during the customer's maximum peak demand for each month, as
recorded at the customer's point of delivery. In the event of multiple
occurrences of the same peak demand, the lowest associated power factor
will be used. The measured average power factor will be the average
power factor for the billing month. If the customer has multiple points
of delivery, the power factor will be determined from totalized
information from the points of delivery. The monthly average and on-
peak power factors are those recorded for CVP power only.
(c) The upper limit for both the monthly average and measured on-
peak power factors is 95 percent. No credit will be given for customers
operating between 100 percent and 95 percent power factors.
(d) The LPF Charge will be applicable to calculated power factors
less than 95 percent, lagging or leading.
(e) Customers that have a monthly maximum peak demand less than or
equal to 50 kW will not be subject to the LPF Charge.
(f) Western may waive the LPF Charge for good cause in whole or in
part.
Rate Schedule CV-FT3
(Supersedes Schedule CV-FT2)
Central Valley Project
Schedule of Rate for Firm Transmission Service
Effective: October 1, 1997.
Available: Within the marketing area served by the Sierra Nevada
Customer Service Region.
Applicable: To firm transmission service where power is received
into the CVP system at points of interconnection with other systems and
transmitted and delivered to points of delivery on the CVP system as
agreed to by the parties.
Character and Conditions of Service: Transmission service for
three-phase alternating current at 60 hertz, delivered and metered at
the voltages and points of delivery. Transmission service includes
scheduling, system control and dispatch service, and reactive supply
and voltage control service needed to support the transmission service
provided.
Rate: Firm Transmission Service Charge: $0.51 per kW-month.
Billing: The rate listed above will be applied monthly to the
maximum amount of capacity reserved, payable whether utilized or not.
Adjustments
For Losses
Losses incurred in connection with the transmission and delivery of
power under this rate schedule will be accounted for as agreed to by
the parties.
Rate Schedule CV-NFT3
(Supersedes Schedule CV-NFT2)
Central Valley Project
Schedule of Rate for Non-Firm Transmission Service
Effective: October 1, 1997.
Available: Within the marketing area served by the Sierra Nevada
Customer Service Region.
Applicable: To non-firm transmission service where power is
received into the CVP system at points of receipt with other systems
and transmitted and delivered, subject to the availability of
transmission capacity, to points of
[[Page 50940]]
delivery on the CVP system as agreed to by the parties.
Character and Conditions of Service: Transmission service on an
intermittent basis for capacity, three-phase alternating current at 60
hertz, delivered and metered at the voltages and points of delivery.
Transmission service includes scheduling, system control and dispatch
service, and reactive supply and voltage control service needed to
support the transmission service provided.
Rate: Non-firm Transmission Service Charge: 1.00 mill per kWh.
Billing: The rate listed above will be applied monthly to the
maximum amount of capacity reserved, payable whether utilized or not.
Adjustments
For Losses
Losses incurred in connection with the transmission and delivery of
power under this rate schedule will be accounted for as agreed to by
the parties.
Rate Schedule CV-TPT4
(Supersedes Schedule CV-TPT3)
Central Valley Project
Schedule of Rate for Transmission of CVP Power by Others
Effective: October 1, 1997.
Available: Within the marketing area served by the Sierra Nevada
Customer Service Region.
Applicable: To power service customers of the CVP who require
transmission service by a third party to receive power sold by Western.
Character and Conditions of Service: Transmission service for
three-phase alternating current at 60 hertz, delivered and metered at
the voltages and points of delivery as agreed to by the parties.
Rate Formula: When Western utilizes transmission facilities, other
than its own, in providing service under a customer's power sales
contract, and costs are incurred by Western for the use of such
facilities, the customer will pay all costs, including transmission
losses, incurred in the delivery of such power. The transmission losses
chargeable to the customer will be those losses which are in excess of
the ``at or above 44-kV'' transmission losses specified by Contract No.
14-06-200-2948A. For billing purposes, transmission losses will be
added to the meter readings of the power and energy delivered to the
customer under the customer's power sales agreement with Western.
Rate Schedule CV-NWT1
Central Valley Project
Schedule of Rate for Network Transmission Service
Effective: October 1, 1997.
Available: Within the marketing area served by the Sierra Nevada
Customer Service Region.
Applicable: To customers of the CVP who receive network
transmission service, subject to the availability of transmission
capacity, to points of delivery specified in the service agreement.
Character and Conditions of Service: Transmission service for
three-phase alternating current at 60 hertz, delivered and metered at
the voltages and points of delivery. Transmission service includes
scheduling, system control and dispatch service, and reactive supply
and voltage control service needed to support the transmission service
provided.
Rate Formula: The rate formula for network transmission service is
the product of the network customer's load ratio share times one
twelfth (\1/12\) of the annual network transmission revenue
requirement. The load ratio share is based on the network customer's
hourly load, including its designated network load not physically
interconnected with the CVP transmission system, coincident with the
monthly CVP transmission system peak minus the coincident peak for all
firm CVP (including reserved capacity) point-to-point transmission
service.
Billing: Billing determinants for the rate formula above will be as
specified in the service agreement.
Adjustments
For Losses
Losses incurred in connection with the transmission and delivery of
power under this rate schedule will be accounted for in accordance with
the service agreement.
Rate Schedule CV-PSS1
Schedule of Rate for Power Scheduling Service
Effective: October 1, 1997.
Available: Within the marketing area served by the Sierra Nevada
Customer Service Region.
Applicable: To customers receiving power scheduling service from
Western.
Character and Conditions of Service: Power scheduling service
provides for the scheduling of resources to meet loads and reserve
requirements.
Rate: $75.80 per hour.
Billing: The rate listed above will be applied to the number of
hours required by Western staff to perform the power scheduling
service. A power scheduling service charge will be specified in the
service agreement.
Rate Schedule CV-RFS1
Central Valley Project
Schedule of Rates for Regulation and Frequency Response Service
Effective: October 1, 1997.
Available: Within the marketing area served by the Sierra Nevada
Customer Service Region.
Applicable: To customers receiving regulation and frequency
response service from Western.
Character and Conditions of Service: Regulation and frequency
response service provides generation to match resources and loads on a
real-time continuous basis.
Rates: Regulation and Frequency Service Charge: Monthly: $1.48 per
kW-month; Weekly: $0.3360 per kW-week; Daily: $0.0480 per kW-day.
Billing: The rates listed above will be applied to the maximum
service amount in kilowatts agreed to in the service agreement, payable
whether utilized or not.
Rate Schedule CV-EID1
Central Valley Project
Schedule of Rate for Energy Imbalance Service
Effective: October 1, 1997.
Available: Within the marketing area served by the Sierra Nevada
Customer Service Region.
Applicable: To customers receiving energy imbalance service from
Western.
Character and Conditions of Service: Energy imbalance service
provides energy when a difference occurs between the scheduled and
actual delivery of energy to a load or from a generation resource
within a control area over a single month. The hourly deviation, in
megawatt units, is the net scheduled amount of energy for the hour
minus the hourly net metered (actual delivered) amount.
Rates Formula
Within Limits of Deviation Band
Accumulated deviations are to be corrected or eliminated within 30
days. Any net deviations that are accumulated at the end of the month
(positive or negative) are to be exchanged with like hours of energy or
charged at the composite rate for CVP commercial firm power, then in
effect.
Outside Limits of Deviation Band
(i) Positive Deviations--no charge, lost to the system.
[[Page 50941]]
(ii) Negative Deviations--during on-peak hours, the greater of (1)
3 times the composite rate for CVP commercial firm power, then in
effect; or (2) any additional cost incurred. During off-peak hours, the
greater of (1) the composite rate for CVP commercial firm power, then
in effect; or (2) any additional cost incurred.
Billing: The billing determinants for the above rates formula will
be specified in the service agreement.
Rate Schedule CV-SPR1
Central Valley Project
Schedule of Rates for Spinning Reserve Service
Effective: October 1, 1997.
Available: Within the marketing area served by the Sierra Nevada
Customer Service Region.
Applicable: To customers receiving spinning reserve service from
Western.
Character and Conditions of Service: Spinning reserve service
provides capacity that is available the first ten minutes to take load
and is synchronized with the power system.
Rates: Spinning Reserve Service Charge: Monthly: $1.35 per kW-
month; Weekly: $0.3024 per kW-week; Daily: $0.0432 per kW-day; Hourly:
$0.0018 per kWh.
Billing: The rates listed above will be applied to the maximum
service amount in kilowatts agreed to in the service agreement, payable
whether utilized or not.
Rate Schedule CV-SUR1
Central Valley Project
Schedule of Rates for Supplemental Reserve Service
Effective: October 1, 1997.
Available: Within the marketing area served by the Sierra Nevada
Customer Service Region.
Applicable: To customers receiving supplemental reserve service
from Western.
Character and Conditions of Service: Supplemental reserve service
provides capacity that is not synchronized with the power system, but
can be available to serve load within ten minutes.
Rates: Supplemental Reserve Service Charge: Monthly: $1.27 per kW-
month; Weekly: $0.2856 per kW-week; Daily: $0.0408 per kW-day; Hourly:
$0.0017 per kWh.
Billing: The rates listed above will be applied to the maximum
service amount in kilowatts agreed to in the service agreement, payable
whether utilized or not.
Rate Schedule COTP-FT1
California-Oregon Transmission Project
Schedule of Rates for Firm Transmission Service
Effective: October 1, 1997.
Available: Within the marketing area served by the Sierra Nevada
Customer Service Region.
Applicable: To firm transmission service customers where power is
received into the COTP system at points of interconnection with other
systems and transmitted and delivered to points of delivery on the COTP
system as agreed to by the parties.
Character and Conditions of Service: Transmission service for
three-phase alternating current at 60 hertz, delivered and metered at
the voltages and points of delivery. Transmission service includes
scheduling, system control and dispatch service, and reactive supply
and voltage control service needed to support the transmission service
provided.
Rates: October 1, 1997--September 30, 1998: $1.83 per kW-month.
October 1, 1998--September 30, 2002: $1.34 per kW-month.
Billing: The rates listed above will be applied monthly to the
maximum amount of capacity reserved, payable whether utilized or not.
Adjustments
For Losses
Losses incurred in connection with the transmission and delivery of
power under this rate schedule will be accounted for as agreed to by
the parties.
Rate Schedule COTP-NFT1
California-Oregon Transmission Project
Schedule of Rates for Non-Firm Transmission Service
Effective: October 1, 1997.
Available: Within the marketing area served by the Sierra Nevada
Customer Service Region.
Applicable: To non-firm transmission service customers where power
is received into the COTP system at points of receipt with other
systems and transmitted and delivered, subject to the availability of
transmission capacity, to points of delivery on the COTP system as
agreed to by the parties.
Character and Conditions of Service: Transmission service on an
intermittent basis for capacity, three-phase alternating current at 60
hertz, delivered and metered at the voltages and points of delivery.
Transmission service includes scheduling, system control and dispatch
service, and reactive supply and voltage control service needed to
support the transmission service provided.
Rates: October 1, 1997-September 30, 1998: 2.19 mills per kWh;
October 1, 1998-September 30, 2002: 1.45 mills per kWh.
Billing: The rates listed above will be applied monthly to the
maximum amount of capacity reserved, payable whether utilized or not.
Adjustments
For Losses
Losses incurred in connection with the transmission and delivery of
power and energy under this rate schedule will be accounted for as
agreed to by the parties.
[FR Doc. 97-25746 Filed 9-26-97; 8:45 am]
BILLING CODE 6450-01-P
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