[Federal Register Volume 62, Number 188 (Monday, September 29, 1997)]
[Notices]
[Pages 50924-50941]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 97-25746]


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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for a 5-year period ending September 30, 2002, or until superseded.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

[[Page 50925]]

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

[[Page 50926]]

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.

[[Page 50927]]

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

[[Page 50928]]

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.<SUP>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  ...........
------------------------------------------------------------------------
<SUP>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.                                                                 
<SUP>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:

ANR<PNR and<0; S=MIP+AD

Where:

ANR=Actual Net Revenue
PNR=Projected Net Revenue
MIP=Minimum Investment Payment
AD=Annual Deficit
S=Surcharge

    2.2  If the actual net revenue is positive, the surcharge will 
equal the minimum investment payment less the actual net revenue, 
represented by the following formula:

ANR<PNR and>0; 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