[Federal Register Volume 66, Number 82 (Friday, April 27, 2001)]
[Notices]
[Pages 21202-21222]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 01-10227]



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Part II





Department of Energy





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Western Area Power Administration



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Central Valley Project and California-Oregon Transmission Project--Rate 
Order No. WAPA-95; Notice

Federal Register / Vol. 66, No. 82 / Friday, April 27, 2001 / 
Notices

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DEPARTMENT OF ENERGY

Western Area Power Administration


Central Valley Project and California-Oregon Transmission 
Project--Rate Order No. WAPA-95

AGENCY: Western Area Power Administration, DOE.

ACTION: Notice of rate order.

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SUMMARY: Western Area Power Administration's Administrator has 
confirmed and approved Rate Order No. WAPA-95 and Rate Schedules CV-
F10, CV-FT4, CV-NFT4, CV-TPT5, CV-NWT2, CV-RFS2, CV-EID2, CV-SPR2, CV-
SUR2, CV-PSS2, CV-SCS1, COTP-FT2, and COTP-NFT2. These rate schedules 
place into effect provisional rates for the Central Valley Project 
(CVP) firm power and transmission services, ancillary services, power 
scheduling service, and scheduling coordinator service, and the 
California-Oregon Transmission Project (COTP) transmission services of 
the Western Area Power Administration (Western). The provisional rates 
will be in effect for an interim period 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 repay required investment in the 
allowable period.

DATES: The provisional rates will be effective the first day of the 
first full billing period beginning on or after April 1, 2001, until 
FERC confirms, approves, and places them into effect on a final basis. 
These rates will stay in effect through December 31, 2004, or until 
other rates replace them.

FOR FURTHER INFORMATION CONTACT: Ms. Debbie Dietz, Rates Manager, 
Western Area Power Administration, Sierra Nevada Customer Service 
Region, 114 Parkshore Drive, Folsom, CA 95630-4710, (916) 353-4453, e-
mail <a href="/cdn-cgi/l/email-protection#85e1e1ece0f1ffc5f2e4f5e4abe2eaf3"><span class="__cf_email__" data-cfemail="680c0c010d1c12281f091809460f071e">[email protected]</span></a>.

SUPPLEMENTARY INFORMATION: The Deputy Secretary of Energy approved the 
existing Rate Schedules CV-F9 for CVP commercial firm power, CV-FT3, 
CV-NFT3, CV-TPT4, and CV-NWT1 for CVP transmission services, CV-RFS1, 
CV-EID1, CV-SPR1, CV-SUR1 for CVP ancillary services, CV-PSS1 for power 
scheduling service, and COTP-FT1 and COTP-NFT1 for COTP transmission 
services on September 19, 1997 (Rate Order No. WAPA-77, 62 FR 50924, 
September 29, 1997). FERC confirmed and approved the rate schedules on 
January 8, 1998, under FERC Docket No. EF97-5011-000 (82 FERC 
para.62,006). The existing rate schedules became effective October 1, 
1997, for the period ending September 30, 2002.
    Rate Schedule CV-F10 supersedes Rate Schedule CV-F9. Under Rate 
Schedule CV-F9, the composite rate on April 1, 2001, is 18.56 mills per 
kilowatthour (mills/kWh). The provisional rates for CVP firm power in 
Rate Schedule CV-F10 will result in an overall composite rate of 20.08 
mills/kWh on April 1, 2001. This results in an increase of about 8 
percent when compared with the existing CVP commercial firm power rates 
under Rate Schedule CV-F9.
    Western also developed provisional rates for CVP firm power with 
the transmission revenue requirement removed from the CVP firm power 
revenue requirement. These rates are also in Rate Schedule CV-F10. 
These rates will apply if Western joins the California Independent 
System Operator (CAISO) or a Regional Transmission Organization (RTO) 
and if the CAISO or RTO uses Western's transmission revenue requirement 
to develop a regional transmission rate. The provisional rates for CVP 
firm power with the transmission revenue requirement removed in Rate 
Schedule CV-F10 will result in an overall composite rate of 18.51 
mills/kWh on April 1, 2001. This results in a decrease of less than 1 
percent when compared with the existing CVP commercial firm power rates 
under Rate Schedule CV-F9. In addition, both sets of CVP firm power 
provisional rates include any charges or credits associated with the 
creation, termination, or modification to any tariff, contract, or 
schedule approved or accepted by FERC, under which Western take service 
will be passed through to the appropriate customers.
    Rate Schedules CV-FT4, CV-NFT4, CV-TPT5, and CV-NWT2 replace Rate 
Schedules CV-FT3, CV-NFT3, CV-TPT4, and CV-NWT1, respectively. 
Provisional formula rates developed for CVP transmission services are 
consistent with FERC Order No. 888. Under Rate Schedules CV-FT3 and CV-
NFT3, the CVP transmission services rates on April 1, 2001, are $0.51/
kWmonth for firm service and 1.00 mill/kWh for nonfirm service. On 
April 1, 2001, the provisional formula rate in Rate Schedule CV-FT4 
results in an estimated rate of $.70/kWmonth for firm CVP transmission 
service, a 37-percent increase when compared with the existing rate. 
Based on an Open Access Transmission Tariff Service Agreement to 
provide transmission service in the future, on October 1, 2001, the 
provisional formula rate in Rate Schedule CV-FT4 results in an 
estimated rate of $.56/kWmonth for CVP firm transmission service. On 
April 1, 2001, the provisional formula rate in Rate Schedule CV-NFT4 
results in a rate of 1.00 mill/kWh for CVP nonfirm transmission 
service, which is the same rate as the existing rate. If the rates 
resulting from the proposed formula rate are higher than other 
transmission rates in California, firm or nonfirm transmission service 
for 1 year or less may be sold at lower rates. The provisional rate for 
transmission of CVP power by others in Rate Schedule CV-TPT5 is a pass 
through cost and results in no change from the existing Rate Schedule 
CV-TPT4 on April 1, 2001.
    The provisional formula rate for network integration transmission 
service in Rate Schedule CV-NWT2 will be the same as the existing 
formula rate for network integration transmission service under Rate 
Schedule CV-NWT1.
    The existing transmission rates include costs for scheduling, 
system control and dispatch service and reactive supply and voltage 
control service. The transmission provisional formula rates include the 
costs of these services.
    The provisional rates in Rate Schedule CV-RFS2, effective April 1, 
2001, for monthly regulation and frequency response service will result 
in a 69-percent increase for the same service when compared to the 
existing monthly rate under Rate Schedule CV-RFS1. The provisional 
rates for regulation and frequency response service are: monthly--
$2.496/kWmonth, weekly--$.574/kWweek, and daily--$.082/kWday. The 
weekly and daily rates are derived from the monthly rate.
    The provisional formula rate for energy imbalance service under 
Rate Schedule CV-EID2 will be the same as the existing formula rate for 
energy imbalance service under Rate Schedule CV-EID1.
    The provisional rates in Rate Schedule CV-SPR2, effective April 1, 
2001, for monthly spinning reserve service will result in a 118-percent 
increase for the same service when compared to the existing monthly 
rate under Rate Schedule CV-SPR1. The provisional rates for spinning 
reserve service are: monthly--$2.946/kWmonth, weekly--$.672/kWweek, 
daily--$.096/kWday, and hourly--$.0040/kWh. The weekly, daily, and 
hourly rates are derived from the monthly rate.
    The provisional rates in Rate Schedule CV-SUR2, effective April 1, 
2001, for monthly supplemental reserve

[[Page 21203]]

service will result in a 96-percent increase for the same service when 
compared to the existing monthly rate under Rate Schedule CV-SUR1. The 
provisional rates for supplemental reserve service are: monthly--
$2.491/kWmonth, weekly--$.574/kWweek, daily--$.082/kWday, and hourly--
$.0034/kWh. The weekly, daily, and hourly rates are derived from the 
monthly rates.
    The provisional rate for power scheduling service in Rate Schedule 
CV-PSS2 is $76.65 per hour. This results in a 1-percent increase 
compared to the existing rate in Rate Schedule CV-PSS1 of $75.80 per 
hour on April 1, 2001.
    Scheduling coordinator service is a new service. The provisional 
rate for scheduling coordinator service is $76.65 per hour and is 
designed to recover only the cost incurred for providing the service.
    Rate Schedules COTP-FT2 and COTP-NFT2 replace Rate Schedules COTP-
FT1 and COTP-NFT1. Provisional formula rates developed for COTP firm 
and nonfirm transmission services are consistent with FERC Order No. 
888. The estimated rates from the provisional formula rate in Rate 
Schedule COTP-FT2 for firm transmission service for Western's share of 
the COTP will result in a 30-percent decrease in the summer, a 16-
percent decrease in the winter, and a 25-percent decrease in the spring 
compared to the existing rate of $1.34/kWmonth in Rate Schedule COTP-
FT1 on April 1, 2001. The estimated rates from the provisional formula 
rate for COTP firm transmission service beginning in April 2001 are: 
summer--$.94/kWmonth, winter--$1.12/kWmonth, and spring--$1.00/kWmonth. 
The estimated rates from the provisional formula rate in Rate Schedule 
COTP-NFT2 for COTP nonfirm transmission service will result in a 11-
percent decrease in the summer, a 6-percent increase in the winter, and 
a 6-percent decrease in the spring compared to the existing rate in 
Rate Schedule COTP-NFT1 of 1.45 mills/kWh on April 1, 2001. The 
estimated rates from the provisional formula rate for COTP nonfirm 
transmission service beginning April 2001 are: summer--1.29 mills/kWh, 
winter--1.54 mills/kWh, and spring--1.37 mills/kWh.

Provisional Rates for CVP Firm Power

    On December 13, 2000, Western provided updates to the proposed CVP 
firm power rates. There were no updates to any of the other rates 
proposed by Western.
    The CVP firm power rates include Project Dependable Capacity 
support purchase costs and pass through of FERC-accepted or -approved 
costs or credits. Western also updated the Revenue Adjustment Clause 
(RAC). The limit for the RAC credit and surcharge is $20 million, $10 
million for the October to December 2004 period, plus any purchase or 
exchange power contract adjustments.
    Western developed two sets of provisional firm power rates. One set 
of rates includes the transmission revenue requirement, and the other 
set of rates removes the transmission revenue requirement. Both sets 
are designed to recover an annual revenue requirement that includes 
investment repayment, interest, purchase power costs, operation and 
maintenance (O&M) expense, and FERC-accepted or -approved charges or 
credits. Western used a cost-of-service study to divide the projected 
annual revenue requirement for firm power between capacity and energy. 
Based on this study, the capacity revenue requirement includes: (1) 100 
percent of capacity purchase costs; (2) 50 percent of the investment 
repayment; (3) 50 percent of the interest expense; (4) 50 percent of 
the O&M expense allocated to power; and (5) 100 percent of CVP and COTP 
transmission expense. Projected CVP and COTP transmission revenue and 
50 percent of projected CVP project use revenue reduce the annual costs 
that make up the capacity revenue requirement. The energy revenue 
requirement includes: (1) 100 percent of energy purchase costs; (2) 50 
percent of the investment repayment; (3) 50 percent of the interest 
expense; and (4) 50 percent of the O&M expense allocated to power. 
Projected surplus power revenue and 50 percent of projected CVP project 
use revenue reduce the annual costs that make up the energy revenue 
requirement.
    For the provisional power rates with the transmission revenue 
requirement removed, Western used a cost-of-service study to divide the 
projected annual revenue requirement for firm power between capacity 
and energy. Based on this study, the capacity revenue requirement 
includes: (1) 100 percent of capacity purchase costs; (2) 50 percent of 
the investment repayment; (3) 50 percent of the interest expense; and 
(4) 50 percent of the O&M expense allocated to power. Fifty percent of 
the projected CVP project use revenue reduces the annual costs that 
make up the capacity revenue requirement. The energy revenue 
requirement includes: (1) 100 percent of energy purchase costs; (2) 50 
percent of the investment repayment; (3) 50 percent of the interest 
expense; and (4) 50 percent of the O&M expense allocated to power. 
Projected surplus power revenue and 50 percent of the projected CVP 
project use revenue reduce the annual costs that make up the energy 
revenue requirement. Additionally, under both sets of CVP firm power 
rates, Western will also pass through to each appropriate customer any 
charges or credits associated with the creation, termination, or 
modification to any tariff, contract, or schedule accepted or approved 
by FERC under which Western takes service.
    Rate Schedule CV-F9 and Rate Schedule CV-F10 include adjustment 
clauses for power factors, low voltage losses, and revenue.

Power Factor Adjustment

    The power factor adjustment is a low power factor (LPF) charge that 
applies when the customer does not maintain a calculated 95 percent or 
greater power factor.

Low Voltage Loss Adjustment

    The low voltage loss adjustment applies to the billed amounts for 
low voltage CVP firm power deliveries on the Pacific Gas and Electric 
Company (PG&E) system.

Revenue Adjustment

    The RAC provides for a comparison between the projected net 
revenues in the rate adjustment power repayment study (PRS) to the 
actual net revenues. If the actual net revenue is more than the 
projected net revenue, CVP firm power customers receive a credit. If 
actual net revenue is less than the projected net revenue, CVP firm 
power customers may pay a surcharge, if needed, to make a minimum 
investment payment. The limit for the RAC credit or surcharge is $20 
million, $10 million for the October to December 2004 period, plus any 
purchase or exchange power contract adjustments during the fiscal year 
(FY) for which the RAC is being calculated. The RAC is calculated 
annually and the associated distribution of the RAC credit or surcharge 
occurs during a 9-month period on power bills issued January through 
September. For customers whose RAC credits cannot be fully credited 
through nine equal monthly amounts, Western has the option to increase 
the RAC credit during August and September. The first RAC calculation 
under the provisional rates will be based on the net revenue for FY 
2001, including revenues and expenses for October 2000 to March 2001, 
which is outside of the rate adjustment period. A RAC will be 
calculated for October through December 2004. The RAC credit or 
surcharge for October through

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December 2004 is applied to the April to September 2005 bills.

Provisional Formula Rates for CVP Transmission Services

    A revenue requirement that recovers: (1) the costs for facilities 
that support the transfer capability of the CVP transmission system 
(excluding generation facilities and radial lines); (2) the 
nonfacilities costs allocated to transmission; and (3) any 
transmission-related costs incurred by Western due to electric industry 
restructuring or other changes in the industry is the basis for the 
provisional formula rates in Rate Schedules CV-FT4 and CV-NFT4 for CVP 
firm and nonfirm transmission services. Western will revise as of April 
30 of each year the rates from the provisional formula rates based on 
updated data. In addition to the annual update on April 30 of each 
year, Western will also revise the rates if there is a change in the 
numerator or denominator that results in a firm transmission rate 
change of at least $.05/kWmonth. The provisional formula rates include 
Western's cost for scheduling, system control and dispatch service and 
reactive supply and voltage control service needed to support the 
transmission service. The provisional formula rates apply to existing 
CVP firm transmission service and future point-to-point transmission 
service. If the rates from the provisional formula rates are higher 
than other transmission rates in California, firm or nonfirm 
transmission service for 1 year or less may be sold at lower rates.

Provisional Rate for Transmission of CVP Power by Others

    Western will pass on to the appropriate customer any transmission 
service costs it incurs for delivering CVP power over a third party's 
transmission system. The provisional rate in Rate Schedule CV-TPT5 will 
be adjusted automatically as third party transmission costs are 
adjusted.

Provisional Formula Rate for Network Integration Transmission 
Service

    If Western offers network integration transmission service, it will 
be consistent with FERC Order No. 888. The provisional formula rate for 
network integration transmission service is the product of the network 
customer's load ratio share times \1/12\ of the annual network 
transmission revenue requirement. The load ratio share is the network 
customer's hourly load coincident with Western's monthly CVP 
transmission system peak, minus the coincident peak for all firm CVP 
point-to-point transmission service, plus the reserved capacity of all 
firm point-to-point transmission service customers. A revenue 
requirement that recovers: (1) the costs for facilities that support 
the transfer capability of the CVP transmission system (excluding 
generation facilities and radial lines); (2) the nonfacilities costs 
allocated to transmission; and (3) any transmission-related costs 
incurred by Western due to electric industry restructuring or other 
changes in the industry is the basis for the provisional formula rate 
for network integration transmission service. The provisional formula 
rate includes Western's cost for scheduling, system control and 
dispatch service and reactive supply and voltage control service needed 
to support the transmission service.

Provisional Rates for Ancillary Services

    Western will offer six ancillary services consistent with FERC 
Order No. 888. Two of the ancillary services--scheduling, system 
control and dispatch service and reactive supply and voltage control 
service--are included with the sale of CVP and/or COTP transmission 
services. The appropriate transmission services rates include the costs 
for these two ancillary services. Subject to availability, Western will 
offer regulation and frequency response, energy imbalance, spinning 
reserve, and supplemental reserve services. Except for the two 
ancillary services provided with the sale of CVP and/or COTP 
transmission services, the basis for availability and type of ancillary 
services is excess resources at the time the service is requested.

Provisional Rate for Power Scheduling Service

    The power scheduling service schedules resources to meet load and 
reserve requirements. The provisional rate for power scheduling service 
is designed to recover only the cost to supply the service.

Provisional Rate for Scheduling Coordinator Service

    Scheduling coordinator service is a new service. It includes 
scheduling, real-time dispatching, and financial settlements with the 
CAISO and/or power exchanges. The provisional rate for scheduling 
coordinator service is designed to recover only the cost to supply the 
service.

Provisional Formula Rates for COTP Transmission Services

    A revenue requirement that recovers: (1) Western's share of costs 
for facilities that support the transfer capability of the COTP; (2) 
Western's share of the nonfacilities costs allocated to transmission; 
and (3) any transmission-related costs that Western incurs due to 
electric industry restructuring or other changes in the industry is the 
basis for the provisional formula rates in Rate Schedules COTP-FT2 and 
COTP-NFT2 for COTP firm and nonfirm transmission services. The rates 
from the provisional formula rate will be updated each season to 
coincide with the changes in the California-Oregon Intertie transfer 
capability. The provisional formula rates include Western's cost for 
scheduling, system control and dispatch service and reactive supply and 
voltage control needed to support the transmission service. The 
provisional formula rates apply to existing COTP firm and nonfirm 
transmission service and future point-to-point transmission service. If 
the rates from the provisional formula rate are higher than other 
transmission rates in California, firm or nonfirm transmission service 
for 1 year or less may be sold at lower rates.

Procedural Requirements

    The provisional rates for CVP firm power and transmission services, 
ancillary services, power scheduling service, scheduling coordinator 
service, and COTP transmission services are developed under the 
Department of Energy Organization Act (42 U.S.C. 7101-7352.), through 
which the power marketing functions of the Secretary of the Interior 
and the Bureau of Reclamation under the Reclamation Act of 1902 (ch. 
1093, 32 Stat. 388), 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 that specifically apply 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 Western's Administrator; and (2) the authority to 
confirm, approve, and place into effect on a final basis, to remand, or 
to disapprove such rates to FERC. In Delegation Order No. 0204-172, 
effective November 24, 1999, the Secretary of Energy delegated the 
authority to confirm, approve, and place such rates into effect on an 
interim basis to the Deputy Secretary. On April 10, 2001, by Amendment 
No. 4 to Delegation Order No. 0204-108, the Secretary of Energy 
delegated to Western's Administrator the authority to confirm, approve, 
and place into effect

[[Page 21205]]

on an interim basis the rates in the Central Valley Project and 
California-Oregon Transmission Project-Rate Order No. WAPA-95.
    Western followed the DOE procedures for Public Participation in 
Power and Transmission Rate Adjustments and Extensions (10 CFR part 
903) to develop these provisional rates.
    Rate Order No. WAPA-95, confirming, approving, and placing the 
proposed CVP firm power and transmission services, ancillary services, 
power scheduling service, and scheduling coordinator service rates, and 
the COTP transmission services rates into effect on an interim basis, 
is issued. New Rate Schedules CV-F10, CV-FT4, CV-NFT4, CV-TPT5, CV-
NWT2, CV-RFS2, CV-EID2, CV-SPR2, CV-SUR2, CV-PSS2, CV-SCS1, COTP-FT2, 
and COTP-NFT2 will be submitted promptly to FERC for confirmation and 
approval on a final basis.

    Dated: April 13, 2001.
Michael S. Hacskaylo,
Administrator.

Order Confirming, Approving, and Placing the Central Valley Project 
Firm Power, Transmission Services, Ancillary Services, Power 
Scheduling Service, and Scheduling Coordiantor Service Rates, and 
the California-Oregon Transmission Project Transmission Services 
Rates Into Effect on an Interim Basis

    These rates are developed under the Department of Energy 
Organization Act (42 U.S.C. 7101-7352), through which the power 
marketing functions of the Secretary of the Interior and the Bureau of 
Reclamation under the Reclamation Act of 1902 (ch. 1093, 32 Stat. 388), 
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 that specifically apply to the project 
involved, were transferred to and vested in the Secretary of Energy 
(Secretary).
    By Amendment No. 3 to Delegation Order No. 0204-108, published 
November 10, 1993 (58 FR 59716), the Secretary delegated (1) the 
authority to develop long-term power and transmission rates on a 
nonexclusive basis to Western's Administrator; and (2) the authority to 
confirm, approve, and place into effect on a final basis, to remand, or 
to disapprove such rates to the FERC. In Delegation Order No. 0204-172, 
effective November 24, 1999, the Secretary delegated the authority to 
confirm, approve, and place such rates into effect on an interim basis 
to the Deputy Secretary. On April 10, 2001, by Amendment No. 4 to 
Delegation Order No. 0204-108, the Secretary of Energy delegated to 
Western's Administrator the authority to confirm, approve, and place 
into effect on an interim basis the rates in the Central Valley Project 
and California-Oregon Transmission Project-Rate Order No. WAPA-95. 
Existing DOE procedures for public participation in power and 
transmission rate adjustments are found in 10 CFR part 903. Procedures 
for approval of Power Marketing Administration rates are found in 18 
CFR part 300.

Acronyms and Definitions

    As used in this rate order, the following acronyms and definitions 
apply:

----------------------------------------------------------------------------------------------------------------
 
----------------------------------------------------------------------------------------------------------------
 
Administrator..........................................  The Administrator of the Western Area Power
                                                          Administration.
Ancillary Services.....................................  Those services necessary to support the transfer of
                                                          electricity while maintaining reliable operation of
                                                          the transmission system following good utility
                                                          practice. Federal Energy Regulatory Commission Order
                                                          No. 888, Docket Nos. RM95-8-000 and RM94-7-001, issued
                                                          April 24, 1996, generally describe ancillary services.
CAISO..................................................  The California Independent System Operator Corporation.
                                                          A state chartered, nonprofit corporation that controls
                                                          the transmission facilities of all participating
                                                          transmission owners and dispatches certain generating
                                                          units and loads.
COI....................................................  The California-Oregon Intertie. It is three 500-
                                                          kilovolt lines linking California and Oregon making up
                                                          the California-Oregon Transmission Project and Pacific
                                                          Alternating Current Intertie transmission lines. The
                                                          Western Systems Coordinating Council establishes the
                                                          seasonal transfer capability for the California-Oregon
                                                          Intertie.
COTP...................................................  The California-Oregon Transmission Project. A 500-
                                                          kilovolt transmission project in which Western has
                                                          part ownership.
CRD....................................................  Contract rate of delivery. The maximum amount of
                                                          capacity made available to a preference customer for a
                                                          period specified under a contract.
CVP....................................................  The Central Valley Project. 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.
Capacity...............................................  The electric capability of a generator, transformer,
                                                          transmission circuit or other equipment. It is
                                                          expressed in kilowatts.
Capacity Rate..........................................  The rate that states the charge for capacity. It is
                                                          expressed in dollars per kilowatt and applied to each
                                                          kilowatt delivered to each customer.
Composite Rate.........................................  The rate for firm power. The annual revenue requirement
                                                          for firm power divided by the total annual energy
                                                          sales. It is expressed in mills per kilowatthour and
                                                          used for comparison purposes.
Contract 2947A.........................................  Contract No. 14-06-200-2947A, as amended. The Western
                                                          Area Power Administration's contract with the Pacific
                                                          Gas and Electric, Southern California Edison, and San
                                                          Diego Gas and Electric companies for extra high
                                                          voltage transmission and exchange service.
Contract 2948A.........................................  Contract No. 14-06-200-2948A, as amended. The Pacific
                                                          Gas and Electric Company's contract with the Western
                                                          Area Power Administration for the sale, interchange,
                                                          and transmission of power.
Corps..................................................  United States Army Corp of Engineers.
Customer...............................................  An entity with a contract and receiving service from
                                                          the Western Area Power Administration's Sierra Nevada
                                                          Customer Service Region.
DLL....................................................  Designated load level. The simultaneous load level at
                                                          which the Western Area Power Administration buys
                                                          capacity from the Pacific Gas and Electric Company at
                                                          the lower of two capacity rates under Contract No. 14-
                                                          06-200-2948A.
DOE Order RA6120.2.....................................  An order dealing with power marketing administration
                                                          financial reporting and repayment criteria.
EA2....................................................  Energy Bank Account No. 2 between the Western Area
                                                          Power Administration and the Pacific Gas and Electric
                                                          Company under Contract No. 14-06-200-2948A.

[[Page 21206]]

 
Energy.................................................  Measured in terms of the work it is capable of doing
                                                          over a period of time. It is expressed in
                                                          kilowatthours.
Energy Rate............................................  The rate that states the charge for energy. It is
                                                          expressed in mills per kilowatthour and applied to
                                                          each kilowatthour delivered to each customer.
FY.....................................................  Fiscal year. October 1 to September 30.
Firm...................................................  A type of product and/or service 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).
kV.....................................................  Kilovolt. The electrical unit of measure of electric
                                                          potential that equals 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 equals
                                                          one thousand watts.
kWh....................................................  Kilowatthour. The electrical unit of energy that equals
                                                          one thousand watts in one hour.
kWmonth................................................  Kilowattmonth. The electrical unit of the monthly
                                                          amount of capacity.
Load Factor............................................  The ratio of average load in kilowatts supplied during
                                                          a specified period to the peak or maximum load in
                                                          kilowatts occurring in that period.
MW.....................................................  Megawatt. The electrical unit of capacity that equals
                                                          one million watts or one thousand kilowatts.
Mill...................................................  A monetary denomination of the United States that
                                                          equals one tenth of a cent or one thousandth of a
                                                          dollar.
Mills/kWh..............................................  Mills per kilowatthour. The unit of charge for energy.
NEPA...................................................  National Environmental Policy Act of 1969 (42 U.S.C.
                                                          4321 et seq.).
Net Revenue............................................  Revenue remaining after paying all annual expenses.
Nonfirm................................................  A type of product and/or service that may not be
                                                          available at the time requested by the customer.
Northwest..............................................  Northwest United States, including Oregon and
                                                          Washington.
PDC....................................................  Project Dependable Capacity. A negotiated amount of
                                                          capacity and associated energy available from the CVP
                                                          under contract 2948A.
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.
Preference.............................................  The requirements of Reclamation law which state 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 under the Rural Electrification Act of 1936
                                                          (Reclamation Project Act of 1939, section 9(c), 43
                                                          U.S.C. 485h(c)).
Project Use............................................  Power used to operate Central Valley Project
                                                          facilities, pursuant to Reclamation law.
Provisional Rates......................................  Rates the Deputy Secretary of Energy has confirmed,
                                                          approved, and placed in effect on an interim basis.
Rate Brochure..........................................  A November 17, 2000, document prepared for public
                                                          distribution that explains the rationale and
                                                          development of the rates in this rate order.
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.
Secretary..............................................  Secretary of the United States Department of Energy.
Sierra Nevada Region...................................  The Sierra Nevada Customer Service Region of the
                                                          Western Area Power Administration.
Western................................................  United States Department of Energy, Western Area Power
                                                          Administration.
Withdrawable...........................................  Power that may be withdrawn under certain conditions.
----------------------------------------------------------------------------------------------------------------

Effective Date

    The provisional rates will take effect on the first day of the 
first full billing period beginning on or after April 1, 2001, and will 
be in effect pending FERC's approval of them or substitute final rates. 
The approved rates will stay in effect through December 31, 2004, or 
until superseded.

Public Notice and Comment

    Western followed 10 CFR part 903, Procedures for Public 
Participation in Power and Transmission Rate Adjustments and 
Extensions, in developing these rates. The steps Western took to 
involve interested parties in the rate development process are:
    1. The proposed rate adjustment started on August 25, 2000, with a 
letter to all CVP preference customers and interested parties 
announcing an informal rate workshop on August 31, 2000. Two additional 
informal rate meetings were held on September 20, 2000, and October 5, 
2000, in Folsom, California, to discuss Western's proposed rates. 
Western explained the rationale for the rate adjustment, presented rate 
designs and methodologies, and answered questions.
    2. A Federal Register notice published on November 8, 2000 (65 FR 
66989), officially announced the proposed rates for the CVP and COTP, 
started the public consultation and comment period, and announced the 
public information and public comment forums.
    3. On November 13, 2000, Western's Sierra Nevada Customer Service 
Region sent a letter to all CVP preference customers and interested 
parties announcing the times and locations for two public forums.
    4. On November 17, 2000, 1 p.m., Western held a public information 
forum in Folsom, California. Western gave detailed explanations of the 
proposed rates for the CVP and COTP, supplied a list of issues that 
could change the proposed rates, answered questions, and gave notice 
that it would supply additional information at the public comment 
forum. A rate brochure and handout were made available.
    5. On December 13, 2000, 1 p.m., Western held a public comment 
forum in Folsom, California. Western presented updated proposed rates 
for CVP firm power, gave a detailed explanation of the updates to the 
proposed rates, answered questions, and distributed information about 
the updated rates. Western then gave the public an opportunity to 
comment for the record. Two representatives made oral comments.
    6. Western received four comment letters during the consultation 
and comment period, which ended December 29, 2000. Western considered 
all comments received during the comment period.

[[Page 21207]]

Project Description

    Initially authorized by Congress in 1935, CVP is a large water and 
power system that covers about one-third of the state of California. 
Legislation set the purposes of CVP in priority as: (1) Improvement of 
navigation; (2) river regulation; (3) flood control; (4) irrigation; 
and (5) power. The CVP Improvement Act of 1992 added fish and wildlife 
as a priority between irrigation and power.
    The CVP is within the Central Valley and Trinity River basins of 
California. It includes 18 dams and reservoirs with a total storage 
capacity of 13 million acre-feet. The system includes 615 miles of 
canals, 5 pumping facilities, 10 powerplants with a maximum operating 
capability of about 2,021 MW, about 946 circuit-miles of high voltage 
transmission lines, 15 substations, and 16 communication sites. 
Reclamation operates the water control and delivery system and all of 
the powerplants except the San Luis Unit, which the State of California 
operates for Reclamation.
    The Emergency Relief Appropriations Act of 1935 authorized 
Reclamation to build the CVP, including Shasta and Keswick Dams on the 
Sacramento River. The initial authorization included powerplants at 
Shasta and Keswick Dams along with high voltage transmission lines to 
transmit power from Shasta and Keswick Powerplants to the Tracy Pumping 
Plant and to integrate Federal hydropower into other electric systems.
    Additional CVP facilities were authorized by Congress through a 
series of laws. The American River Division was authorized in 1944 and 
includes the Folsom Dam and Powerplant and the Nimbus Dam and 
Powerplant on the American River. The Trinity Dam and Powerplant, Judge 
Francis Carr Powerplant, and Spring Creek Powerplant were authorized as 
part of the Trinity River Divison in 1955. The San Luis Unit was 
authorized in 1960 and includes the B. F. Sisk San Luis Dam and San 
Luis Reservoir, O'Neill and Dos Amigos Pumping Plants, and William R. 
Gianelli Pump-Generator. In 1962, Congress authorized for integration 
into CVP New Melones, which is a Corps project.
    In 1964, Congress authorized the 500-kV Intertie. Western has a 400 
MW entitlement of transmission capacity on the Intertie. On July 31, 
1967, Reclamation (Western's predecessor), PG&E, the Southern 
California Edison Company, and the San Diego Gas & Electric Company 
entered into Contract 2947A to coordinate the operation of the Intertie 
to transmit electric power between the Northwest and the Pacific 
Southwest.
    In marketing Federal hydroelectric power generated from the CVP, 
Western currently has 80 preference and 34 project use customers 
serving an estimated 2 million people.
    In 1967, PG&E and Reclamation (Western's predecessor) executed 
Contract 2948A, allowing for the sale, interchange, and transmission of 
electric capacity and energy between Western and PG&E. Contract 2948A 
also includes provisions for integrating power generated from the CVP 
with Western's 400 MW of entitlement on the Intertie. The contract also 
states PG&E will support a maximum simultaneous demand of 1,152 MW for 
preference customers through 2004. If CVP power cannot meet obligations 
to preference customers, Contract 2948A gives Western the right to 
purchase capacity and energy from PG&E to meet those requirements. Any 
energy in excess of project use loads and Western's obligations to 
preference customers can be sold to PG&E through an energy 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. Types of preference customers include: (1) Irrigation and 
water districts; (2) public utility districts; (3) municipalities; (4) 
Federal agencies; (5) State agencies; and (6) rural electric 
cooperatives.
    Each preference customer's CRD includes firm long-term power 
allocations, and may include withdrawable allocations that are 
currently allocated to, but unused by, another customer. For this rate 
adjustment, it is assumed that all customer withdrawable CRDs can be 
withdrawn in the event the maximum simultaneous demand of 1,152 MW in 
Contract 2948A is exceeded.
    Western's preference customer maximum simultaneous demand of 1,152 
MW excludes project use loads. 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. Despite the simultaneous demand limit, Western has 
contractual obligations to serve about 1,502 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-mile, 500-kV transmission project that 
electrically interconnects the Northwest to California with the third 
alternating current intertie. Operational since March 1993, COTP 
interconnects with the transmission systems of the Northwest at Captain 
Jack Substation and with the Pacific Southwest by its connection near 
the Tesla Substation to the existing Intertie. Project owners include 
Western and several non-Federal participants.

Power Repayment Study

    Western prepares a power repayment study (PRS) each FY to decide if 
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 including DOE Order RA6120.2, and authorizing 
legislation. The CVP rate adjustment PRS reflects an increase in 
customer load, purchase power costs, Reclamation O&M costs, and CVP and 
COTP transmission and CVP project use revenues. It also reflects the 
suspension in Western's Northwest purchase power contracts. The PRS 
shows enough revenue to pay all annual costs, including interest 
expense, and repays investment in the allowable period.

Transmission Cost-of-Service Study

    The CVP and COTP firm and nonfirm transmission provisional formula 
rates consist of two components. Component 1 recovers the cost of the 
CVP transmission system and COTP. Component 2 is any transmission-
related costs incurred by Western due to electric industry 
restructuring or other industry changes. A cost-of-service study 
determines component 1. The CVP transmission system and COTP have 
separate cost-of-service studies that are used for the firm and nonfirm 
provisional formula rates. The studies identify the costs associated 
with facilities that support the transfer capability of the CVP 
transmission system and COTP, excluding generation facilities and 
radial lines.
    There are two primary reasons for the increase in transmission 
costs in the CVP cost-of-service study. One reason is facilities that 
support the transfer capability of the CVP transmission system 
(excluding generation facilities and radial lines) are included as 
transmission. The second reason is the increase in transmission O&M 
expenses. O&M not directly charged to a facility is charged to 
transmission based on a ratio of transmission plant to total plant.
    The transmission costs from the COTP cost-of-service study have not 
changed

[[Page 21208]]

significantly. However, the termination of a contractual obligation to 
provide standby transmission service increased the amount of capacity 
available for sale. The amount of COTP capacity used in component 1 of 
the formula rate will change with the seasonal transfer capability of 
the COI.

Existing and Provisional Rates

CVP Firm Power

    The provisional rates for CVP firm power are designed to recover an 
annual revenue requirement that includes the investment repayment, 
interest, purchase power costs, O&M expenses, and any charges or 
credits associated with the creation, termination, or modification to 
any tariff, contract, or schedule approved or accepted by FERC under 
which Western takes service.
    Western also developed provisional rates for CVP firm power with 
the transmission revenue requirement removed. These rates would apply 
if Western joins the CAISO or an RTO and if the CAISO or RTO uses the 
transmission revenue requirement to develop a regional transmission 
rate. Western has not made a decision on joining the CAISO or RTO. The 
decision to join the CAISO or an RTO is not part of this rate 
adjustment process. These rates are also designed to recover an annual 
revenue requirement that includes investment repayment, interest, 
purchase power, O&M expense, and any charges or credits associated with 
the creation, termination, or modification to any tariff, contract, or 
schedule accepted or approved by FERC.
    A comparison of the existing rates and both sets of provisional 
rates for CVP firm power are in the next two tables.

 Comparison of Existing and Provisional Rates, CVP Firn Power With The Transmission Revenue Requirement Included
----------------------------------------------------------------------------------------------------------------
                                                             Existing Rates
                        Rate Period                         (Effective 04/01/    Provisional     Percent Change
                                                             01 to 09/30/01)        Rates
----------------------------------------------------------------------------------------------------------------
Composite Rate (mills/kWh):
    04/01/01 to 09/30/01..................................             18.56             20.08                8
    10/01/01 to 09/30/02..................................  ................             23.83               28
    10/01/02 to 09/30/03..................................  ................             24.63               33
    10/01/03 to 09/30/04..................................  ................             24.73               33
    10/01/04 to 12/31/04..................................  ................             30.83               66
Capacity Rate ($/kWmonth):
    04/01/01 to 09/30/01..................................              3.81              3.44              (10)
    10/01/01 to 09/30/02..................................  ................              3.73               (2)
    10/01/02 to 09/30/03..................................  ................              3.89                2
    10/01/03 to 09/30/04..................................  ................              3.86                1
    10/01/04 to 12/31/04..................................  ................              3.80  ................
Energy Rate (mills/kWh):
    04/01/01 to 09/30/01..................................             10.51             14.01               33
    10/01/01 to 09/30/02..................................  ................             17.68               68
    10/01/02 to 09/30/03..................................  ................             18.22               73
    10/01/03 to 09/30/04..................................  ................             18.38               75
    10/01/04 to 12/31/04..................................  ................             24.97             138
----------------------------------------------------------------------------------------------------------------
Note: In addition to the provisional firm power rates above, any charges or credits associated with the
  creation, termination, or modification to any tariff, contract, or schedule accepted by FERC will be passed
  through to the appropriate customer(s).


 Comparison of Existing and Provisional Rates, CVP Firm Power With The Transmission Revenue Requirement Removed
----------------------------------------------------------------------------------------------------------------
                                                             Existing Rates
                        Rate Period                         (Effective 04/01/    Provisional     Percent Change
                                                             01 to 09/30/01)        Rates
----------------------------------------------------------------------------------------------------------------
Composite Rate (mills/kWh):
    04/01/01 to 09/30/01..................................             18.56             18.51  ................
    10/01/01 to 09/30/02..................................  ................             22.48               21
    10/01/02 to 09/30/03..................................  ................             23.26               25
    10/01/03 to 09/30/04..................................  ................             23.41               26
    10/01/04 to 12/31/04..................................  ................             29.47               59
Capacity Rate ($/kWmonth):
    04/01/01 to 09/30/01..................................              3.81              2.55              (33)
    10/01/01 to 09/30/02..................................  ................              2.91              (24)
    10/01/02 to 09/30/03..................................  ................              3.08              (19)
    10/01/03 to 09/30/04..................................  ................              3.05              (20)
    10/01/04 to 12/31/04..................................  ................              2.92              (23)
Energy Rate (mills/kWh):
    04/01/01 to 09/30/01..................................             10.51             14.01               33
    10/01/01 to 09/30/02..................................  ................             17.68               68
    10/01/02 to 09/30/03..................................  ................             18.18               73
    10/01/03 to 09/30/04..................................  ................             18.38               75
    10/01/04 to 12/31/04..................................  ................             24.97             138
----------------------------------------------------------------------------------------------------------------
Note: Customers are required to buy transmission at an additional cost under these rates. In addition to the
  provisional firm power rates above, any charges or credits associated with the creation, termination, or
  modification to any tariff, contract, or schedule accepted by FERC will be passed through to the appropriate
  customer(s).


[[Page 21209]]

CVP Transmission Services and Transmission of CVP Power by Others

    The provisional formula rate for CVP firm transmission includes two 
components.
[GRAPHIC] [TIFF OMITTED] TN27AP01.000

Component 1 =transmission revenue requirement CVP capacity + total 
transmission capacity under long-term contracts
Component 1 is the ratio of Western's transmission revenue requirement 
(less revenue credits) to the sum of the maximum operating capacity 
under normal operating conditions of the northern CVP powerplants (CVP 
capacity) and the total transmission capacity under long-term contract 
between Western and other parties. The Northern CVP powerplants are 
Judge Francis Carr, Folsom, Keswick, Nimbus, Shasta, Spring Creek, and 
Trinity. Western will revise the rate from component 1 of the 
provisional formula rate based on updated data as of April 30 of each 
year. Western will also revise the rate from component 1 if there is a 
change in the numerator or denominator that results in a rate change of 
at least $.05/kWmonth.
    Component 2 is for any transmission-related costs incurred by 
Western due to electric industry restructuring or other industry 
changes. The costs in component 2, as well as any changes to these 
costs, will be passed on to each appropriate transmission customer.
    The provisional formula rates for CVP transmission services are 
based on a revenue requirement that recovers: (1) The costs of 
facilities that support the transfer capability of the CVP transmission 
system (excluding generation facilities and radial lines); (2) the 
nonfacilities costs allocated to transmission; and (3) any 
transmission-related costs incurred by Western due to electric industry 
restructuring or other changes in the industry. The provisional formula 
rate includes Western's cost for scheduling, system control and 
dispatch service and reactive supply and voltage control service needed 
to support the transmission service. The provisional formula rates 
apply to existing CVP firm and nonfirm transmission services and future 
point-to-point transmission services. If the rates from the provisional 
formula rates are higher than other transmission rates in California, 
then firm or nonfirm transmission service for 1 year or less may be 
sold at lower rates. The provisional rate for transmission of CVP power 
by others is a pass through cost, which is the same as the existing 
rate. This table compares the existing and the estimated rates from the 
provisional formula rates for CVP transmission services and for 
transmission of CVP power by others.

      Comparison of Existing and Provisional Formula Rates CVP Firm and Nonfirm Transmission Rate Schedules
----------------------------------------------------------------------------------------------------------------
                                                                                Estimated rates
                                                              Existing rates       from the       Percent rates
                        Rate period                          (effective 04/01/    provisional         change
                                                              01 to 09/30/01)    formula rates
----------------------------------------------------------------------------------------------------------------
Firm ($/kWmonth):
    04/01/01 to 09/30/01...................................              0.51              0.70               37
    10/01/01 to 04/30/02...................................  ................              0.56               10
Nonfirm (mills/kWh):
    04/01/01 to 04/30/02...................................              1.00              1.00  ...............
----------------------------------------------------------------------------------------------------------------


     Comparison of Existing and Provisional Formula Rates Transmission of CVP Power by Others Rate Schedule
----------------------------------------------------------------------------------------------------------------
                                    Existing rate (effective
            Rate period               04/01/01 to 09/30/01)       Provisional rate           Percent change
----------------------------------------------------------------------------------------------------------------
04/01/01 to 12/31/04..............  Pass through Cost.......  Pass through Cost.......  Not Applicable.
----------------------------------------------------------------------------------------------------------------

Network Integration Transmission Service

    If Western offers network integration transmission service, it will 
be made available consistent with FERC Order No. 888. The provisional 
formula rate for network integration transmission service includes two 
components. Component 1 is the product of the network customer's load 
ratio share, times \1/12\ of the annual network transmission revenue 
requirement. The load ratio share is the network customer's hourly load 
coincident with Western's monthly CVP transmission system peak, minus 
the coincident peak for all firm CVP point-to-point transmission 
service, plus the reserved capacity of all firm point-to-point 
transmission service customers. Component 2 is any transmission-related 
costs incurred by Western due to electric industry restructuring or 
other industry changes. The costs in component 2, as well as any 
changes to these costs, will be passed through to each appropriate 
transmission customer as part of the network integration transmission 
revenue requirement. The provisional formula rate for network 
integration transmission service is based on a revenue requirement that 
recovers: (1) the cost for facilities that support the

[[Page 21210]]

transfer capability of the CVP transmission system (excluding 
generation facilities and radial lines); (2) the nonfacilities costs 
allocated to transmission; and (3) any transmission-related costs 
incurred by Western due to electric industry restructuring or other 
industry changes. The provisional formula rate includes Western's cost 
for scheduling, system control and dispatch service and reactive supply 
and voltage control service needed to support the transmission service.

Ancillary Services

    Western will offer six ancillary services consistent with FERC 
Order No. 888. Two of the ancillary services will be supplied with the 
sale of CVP and/or COTP transmission services. These are scheduling, 
system control and dispatch, and reactive supply and voltage control 
services. The remaining four ancillary services are regulation and 
frequency response, energy imbalance, spinning reserve, and 
supplemental reserve. Availability and type of ancillary service will 
be based on excess resources at the time the service is requested, 
except for the two ancillary services supplied in conjunction with the 
sale of CVP and/or COTP transmission services. The appropriate 
transmission services rates include costs for scheduling, system 
control and dispatch service and reactive supply and voltage control 
service. The major factor for the increase in the spinning reserve, 
supplemental reserve, and regulation and frequency response services 
rates is the increase in Reclamation power O&M expenses. This table 
compares the existing and the provisional rates.

      Comparison of Existing and Provisional Ancillary Services Rates CVP Ancillary Service Rate Schedules
----------------------------------------------------------------------------------------------------------------
                                                                                                        Percent
           Ancillary service type                   Existing rates             Provisional rates         change
----------------------------------------------------------------------------------------------------------------
Scheduling, System Control and Dispatch      Appropriate transmission     Appropriate transmission            NA
 Service.                                     rates include Western's      rates include Western's
                                              cost.                        cost.
Reactive Supply and Voltage Control Service  Appropriate transmission     Appropriate transmission            NA
                                              rates include Western's      rates include Western's
                                              cost.                        cost.
Regulation and Frequency Response Service..  Monthly: $1.48/kWmonth.....  Monthly: $2.496/kWmonth....         69
                                             Weekly: $.336/kWweek.......  Weekly: $0.574/kWweek......         71
                                             Daily: $.048/kWday.........  Daily: $0.082/kWday........         71
Energy Imbalance Service...................  Within Limits of Deviation   Within Limits of Deviation          NA
                                              Band: Accumulated            Band: Accumulated
                                              deviations are to be         deviations are to be
                                              corrected or eliminated      corrected or eliminated
                                              within 30 days. Any net      within 30 days. Any net
                                              deviations that are are to   deviations that are are to
                                              accumulated at the end of    accumulated at the end of
                                              the month (positive or       the month (positive or
                                              negative) are to be          negative) are to be
                                              exchanged with like hours    exchanged with like hours
                                              of energy or charged at      of energy or charged at
                                              the composite rate then in   the composite rate then in
                                              effect for CVP firm power.   effect for CVP firm power.
                                             Outside Limits of Deviation  Outside Limits of Deviation
                                              Band: Positive Deviations--  Band: Positive Deviations--
                                              The greater of no charge,    The greater of no charge,
                                              or any additional cost       or any additional cost
                                              incurred. Negative           incurred. Negative
                                              Deviations--during on-peak   Deviations--during on-peak
                                              hours is the greater of 3    hours is the greater of 3
                                              times the composite rate     times the composite rate
                                              then in effect for CVP       then in effect for CVP
                                              firm power or any            firm power or any
                                              additional cost incurred.    additional cost incurred.
                                              During off-peak hours is     During off-peak hours is
                                              the greater of the           the greater of the
                                              composite rate then in       composite rate then in
                                              effect for CVP firm power    effect for CVP firm power
                                              or any additional cost       or any additional cost
                                              incurred.                    incurred.
Spinning Reserve Service...................  Monthly: $1.35/kWmonth.....  Monthly: $2.946/kWmonth....        118
                                             Weekly: $.3024/kWweek......  Weekly: $0.672/kWweek......        121
                                             Daily: $.0432/kWdayHourly:   Daily: $0.096/kWday........        122
                                              $.0018/kWh.                 Hourly: $0.0040/kWh........        122
Supplemental Reserve Service...............  Monthly: $1.27/kWmonth.....  Monthly: $2.491/kWmonth....         96
                                             Weekly: $.2856/kWweek......  Weekly: $0.574/kWweek......        100
                                             Daily: $.0408/kWday........  Daily: $0.082/kWday........        100
                                             Hourly: $.0017/kWh.........  Hourly: $0.0034/kWh........        100
----------------------------------------------------------------------------------------------------------------

Power Scheduling Service

    Western supplies power scheduling service for the scheduling of 
resources to meet load and reserve requirements. The provisional rate 
of $76.65 per hour will apply to the estimated time for each customer's 
service. The rate is designed to recover only the cost incurred for 
supplying the service.

Scheduling Coordinator Service

    Scheduling coordinator service is a new service for scheduling, 
real-time dispatching, and financial settlements with the CAISO and/or 
power exchanges. The provisional rate of $76.65 per hour will apply to 
the estimated time for each customer's service. The rate is designed to 
recover only the cost incurred for supplying the service.

Provisional Formula Rates for COTP Transmission Services

    The provisional formula rate for COTP transmission includes two 
components.
[GRAPHIC] [TIFF OMITTED] TN27AP01.005


[[Page 21211]]


    Component 1 is the ratio of the transmission revenue requirement 
(less revenue credits) to Western's share of COTP seasonal capacity. 
Western will update the rate from component 1 at least 15 days before 
the start of each season. Seasonal definitions for summer, winter, and 
spring are June through October, November through March, and April 
through May, respectively.
    Component 2 is any transmission-related costs incurred by Western 
due to electric industry restructuring or other industry changes. The 
costs in component 2, as well as any changes to these costs, will be 
passed on to each appropriate transmission customer.
    The provisional rates for COTP transmission service are based on a 
revenue requirement that recovers: (1) Western's share of costs for 
facilities that support the transfer capability of the COTP; (2) 
Western's share of the nonfacilities costs allocated to transmission; 
and (3) any transmission-related costs incurred by Western due to 
electric industry restructuring or other changes in the industry. The 
provisional formula rates include Western's cost for scheduling, system 
control and dispatch service and reactive supply and voltage control 
service needed to support the transmission service. The provisional 
formula rates apply to existing COTP firm and nonfirm transmission 
services and future point-to-point transmission services. If the 
estimated rates from the provisional formula rates are higher than 
other transmission rates in California, firm or nonfirm transmission 
service for 1 year or less may be sold at lower rates. No generation 
resources or loads are directly connected to the COTP, so network 
integration transmission service is not offered for the COTP.
    This table compares the existing and estimated rates from the 
provisional formula rates for transmission services for Western's share 
of the COTP.

             Comparison of Existing and Provisional Formula Rates, COTP Transmission Rate Schedules
----------------------------------------------------------------------------------------------------------------
                                                    Existing      Estimated Rates from Provisional      Percent
                   Rate Period                       Rates                 Formula Rates                 change
----------------------------------------------------------------------------------------------------------------
Firm Transmission Rate ($/kWmonth):
    04/01/01 to 03/31/02.........................       1.34  Summer--.94............................       (30)
                                                              Winter--1.12...........................       (16)
                                                              Spring--1.00...........................       (25)
Nonfirm Transmission Rate (mills/kWh):
    04/01/01 to 03/31/02.........................       1.45  Summer--1.29...........................       (11)
                                                              Winter--1.54...........................          6
                                                              Spring--1.37...........................        (6)
----------------------------------------------------------------------------------------------------------------

Certification of Rates

    Western's Administrator certified that the provisional rates for 
CVP firm power, CVP transmission services, transmission of CVP power by 
others, network integration transmission service, ancillary services, 
power scheduling service, scheduling coordinator service, and COTP 
transmission services are the lowest possible rates consistent with 
sound business principles. The provisional rates were developed under 
administrative policies and applicable laws.

Discussion

CVP Firm Power

    According to Reclamation law, Western must establish power rates 
sufficient to recover operation, maintenance, and purchase power 
expenses, and repay the Federal Government's investment. Rates must 
also recover interest expenses on the unpaid balance of facilities' 
investments, replacements and additions, and certain nonpower costs in 
excess of the irrigation users' ability to repay.
    A FERC order issued January 8, 1998, confirmed and approved the 
existing CVP commercial firm power rates for October 1, 1997, through 
September 30, 2002. Under Rate Schedule CV-F9 for FY 2001, the 
composite rate is 18.56 mills/kWh, the base energy rate is 10.51 mills/
kWh, and the capacity rate is $3.81/kWmonth. The provisional rates for 
CVP firm power result in an overall composite rate increase of about 8 
percent on April 1, 2001. On a composite rate basis, the provisional 
rates increase during the rate case period compared to the existing 
rates due primarily to increased purchased power costs. To use CVP 
power resources to their maximum benefit, Western supports CVP 
generation with capacity and energy purchases mainly from PG&E. The 
provisional rates increase after April to September 2001 due to the 
depletion of EA2 in September 2001. The increases in FY 2002 and FY 
2003 are due to increases in prices for short-term purchases and power 
from PG&E. In FY 2004, these increases are offset by decreases in O&M 
and other expenses. The significant increase in rates during October 
through December 2004 recovers short-term power purchase costs for PDC 
support due to lower CVP generation during those months. Western will 
also pass through to each appropriate customer any charges or credits 
associated with the creation, termination, or modification to any 
tariff, contract, or schedule accepted or approved by FERC.
    The provisional rates for CVP firm power with the transmission 
revenue requirement removed in Rate Schedule CV-F10 will result in an 
overall composite rate of 18.51 mills/kWh on April 1, 2001. This 
results in a change of less than 1 percent when compared with the 
existing rates under Rate Schedule CV-F9.
    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 is used to 
recover the CVP power generation cost, which reflects its actual costs 
associated with providing power to all CVP customers.
    The existing rates under Rate Schedule CV-F9 reflect a 5-year 
average split of 46 percent to capacity and 54 percent to energy. Both 
sets of provisional rates are based on allocating the total annual CVP 
revenue requirement split between capacity and energy in this way:
    1. For the rates that include the transmission revenue requirement, 
the capacity revenue requirement includes 100 percent of capacity 
purchase costs, 100 percent of CVP and COTP

[[Page 21212]]

transmission expense, and 50 percent of the annual CVP investment 
repayment, interest expense, and power O&M expense allocated to power. 
Projected CVP and COTP transmission revenue and 50 percent of projected 
CVP project use revenue reduce the annual costs that make up the 
capacity revenue requirement. The capacity revenue requirement for the 
rates that have the transmission revenue requirement removed is the 
same, except the CVP and COTP transmission expense and revenue are 
excluded from the calculation.
    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 power. Projected 
surplus power revenue and 50 percent of projected CVP project use 
revenue reduce annual costs that make up the energy revenue 
requirement.
    3. Western will pass through to each appropriate customer any 
charges or credits associated with the creation, termination, or 
modification to any tariff, contract, or schedule accepted or approved 
by FERC under which Western takes service.
    The resulting percentage splits for the provisional rates with the 
transmission revenue requirement included vary from 19 percent 
allocated to capacity during October 1, 2004, through December 31, 
2004, to 30 percent allocated to capacity in FY 2001, primarily due to 
changes in purchase power costs each year. The average split for the 
rate period is 25 percent to capacity and 75 percent to energy. This 
table is the annual percentage splits between the capacity and energy 
revenue requirements.

    Energy/Capacity Splits With the Transmission Revenue Requirement
                                Included
------------------------------------------------------------------------
                                                  Capacity      Energy
               Effective period                  (percent)    (percent)
------------------------------------------------------------------------
04/01/01-9/30/01..............................           30           70
10/01/01-9/30/02..............................           26           74
10/01/02-9/30/03..............................           26           74
10/01/03-9/30/04..............................           26           74
10/01/04-12/31/04.............................           19           81
                                               -------------------------
Average for the 5 periods.....................           25           75
------------------------------------------------------------------------

    The resulting percentage splits for the provisional rates with the 
transmission revenue requirement removed vary from 15 percent allocated 
to capacity during October 1, 2004, through December 31, 2004, to 24 
percent allocated to capacity in FY 2001, primarily due to changes in 
purchase power costs each year. The average split for the rate period 
is 21 percent to capacity and 79 percent to energy. This table is the 
annual percentage splits between the capacity and energy revenue 
requirements.

Energy/Capacity Splits With The Transmission Revenue Requirement Removed
------------------------------------------------------------------------
                                                  Capacity      Energy
               Effective period                  (percent)    (percent)
------------------------------------------------------------------------
04/01/01-9/30/01..............................           24           76
10/01/01-9/30/02..............................           21           79
10/01/02-9/30/03..............................           22           78
10/01/03-9/30/04..............................           21           79
10/1/04-12/31/04..............................           15           85
                                               -------------------------
Average for the 5 periods.....................           21           79
------------------------------------------------------------------------

Power Factor Adjustment

    The power factor adjustment under existing Rate Schedule CV-F9 will 
continue and is included in the provisional rates for CVP firm power. 
The low power factor charge (LPF charge) will continue to encourage 
preference customers to monitor and maintain power factors at 95 
percent or greater. Western will continue the existing LPF charge under 
Rate Schedule CV-F10, which includes a rate of $2.50/kvar for 
additional kvar required to raise the customer's power factor to 95 
percent. The $2.50/kvar rate is 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 computed power factor used to decide 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. As recorded at the 
customer's point of delivery, the measured on-peak power factor is 
equal to the power factor measured during a customer's maximum peak 
demand for each month. If multiple occurrences of the same peak demand 
occur, 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-F9 will 
continue and is included in the provisional rates for CVP firm power. A 
loss adjustment factor of 1.035 will be applied to the billed amounts 
for low voltage CVP power deliveries on PG&E's system under Contract 
2948A.

[[Page 21213]]

Revenue Adjustment Clause

    The RAC provides for a comparison between the projected net 
revenues in the rate adjustment PRS to the actual net revenues. If the 
actual net revenue is more than the projected net revenue, CVP 
preference customers receive a credit. If actual net revenue is less 
than the projected net revenue, CVP preference customers may pay a 
surcharge, if needed, to make a minimum investment payment. The limit 
for the annual RAC credit or surcharge is $20 million, plus any 
purchase or exchange power contract adjustments during the FY for which 
the RAC is being calculated. The RAC is calculated annually and the 
associated distribution of the RAC credit or surcharge occurs during a 
9-month period on power bills issued January through September. For 
customers whose RAC credits cannot be fully credited through nine equal 
monthly amounts, Western has the option to increase the RAC credit 
during August and September. The FY 2001 RAC calculation will be based 
on the net revenue for FY 2001, including revenues and expenses for 
October 2000 to March 2001, which is outside of the rate adjustment 
period. A RAC will be calculated for October through December 2004. The 
maximum RAC credit or surcharge for October through December 2004 is 
$10 million plus any purchase or exchange power contract adjustments 
applied to the April to September 2005 bills.

CVP Transmission Services and Transmission of CVP Power by Others

    Provisional formula rates developed for CVP firm and nonfirm 
transmission services are consistent with FERC Order No. 888. The 
estimated rate from the provisional formula rate for firm CVP 
transmission service on April 1, 2001, is $0.70/kWmonth, a 37-percent 
increase from the existing rate of $0.51/kWmonth under Rate Schedule 
CV-FT3. Based on an Open Access Transmission Tariff service agreement 
to supply CVP transmission service in the future, on October 1, 2001, 
the estimated rate from the provisional formula rate in Rate Schedule 
CV-FT4 will be $.56/kWmonth. The estimated rate resulting from the 
formula rate for CVP nonfirm transmission service will be 1.00 mills/
kWh, which is the same as the existing rate under Rate Schedule CV-
NFT3. There are two primary reasons for the increase in CVP firm 
transmission rates. The first reason is including in the transmission 
revenue requirement the costs associated with facilities that support 
the transfer capability of the CVP transmission system (excluding 
generation facilities and radial lines). The second reason is the 
increase in transmission O&M expenses. O&M not directly charged to a 
facility is charged to transmission based on a ratio of transmission 
plant to total plant.
    Western will pass on to the CVP customer transmission service costs 
Western incurs in the delivery of CVP power over a third party's 
transmission system. Annual transmission pass through 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 service to preference customers.

Network Integration Transmission Service

    If Western offers network integration transmission service, it will 
be consistent with FERC Order No. 888. Due to existing contractual 
arrangements, Western may not be able to supply network integration 
transmission service; however, a formula rate is included in case 
Western offers the service.

Ancillary Services

    Western allocates most of its power resources to preference 
entities under long-term commitments; therefore, availability and type 
of ancillary service will be based on excess resources at the time the 
service is requested, except for the two ancillary services supplied 
with the sale of CVP and/or COTP transmission services. The appropriate 
transmission services rates include costs for scheduling, system 
control and dispatch and reactive supply and voltage control services.
    The provisional rates for ancillary services are designed to 
recover the costs for these services. The primary reason for the 69-
percent increase in the monthly regulation and frequency response 
service rate, 118-percent increase in the monthly spinning reserve 
rate, and 96-percent increase in the monthly supplemental reserve 
service rate is the increase in the Reclamation O&M expenses. Standards 
and practices used in the electric utility industry are the basis for 
the provisional rate for energy imbalance service. Western used a 
detailed cost-of-service study for developing the provisional rates for 
regulation and frequency response, spinning reserve, and supplemental 
reserve services. These rates are based on the costs of CVP facilities 
used in supplying the service. The CVP facilities used to supply 
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 Powerplant and the W. R. Gianelli pump-
generator, which makes them unavailable for supplying the services.

Power Scheduling Service

    Western supplies power scheduling service for scheduling resources 
to meet load and reserve requirements. The provisional rate for power 
scheduling service is designed to recover only the cost incurred by 
Western for supplying the service. This results in a 1-percent increase 
compared to the existing rate in Rate Schedule CV-PSS1 of $75.80 per 
hour on April 1, 2001. The provisional rate includes two cost 
components. The first is the FY 2000 hourly cost for dispatcher and/or 
scheduler resources, escalated for the rate adjustment period to 
calculate an average hourly cost. The second is an hourly cost for 
equipment necessary to supply the service.

Scheduling Coordinator Service

    Scheduling coordinator service is a new service offered by Western 
that allows for scheduling, real-time dispatching, and financial 
settlements with the CAISO and/or power exchanges. The rate is designed 
to recover only the cost incurred for supplying the service. The 
provisional rate includes two cost components. The first is the FY 2000 
hourly cost for scheduling, dispatching, settlements, supervisory 
control and data acquisition, and other resources, escalated for the 
rate adjustment period to calculate an average hourly cost. The second 
is an hourly cost for equipment necessary to supply the service.

COTP Transmission Services

    Provisional formula rates developed for COTP firm and nonfirm 
transmission services are consistent with FERC Order No. 888. The 
estimated rates from the provisional formula rate for firm transmission 
service for Western's share of the COTP will result in a 30-percent 
decrease in the summer, a 16-percent decrease in the winter, and a 25-
percent

[[Page 21214]]

decrease in the spring compared to the existing rate of $1.34/kWmonth 
on April 1, 2001. The estimated rates from the provisional formula rate 
for COTP firm transmission service for April 1, 2001, through March 31, 
2002, are: summer--$.94/kWmonth, winter--$1.12/kWmonth, and spring--
$1.00/kWmonth. The estimated rates from the provisional formula rate 
for nonfirm COTP transmission service will result in an 11-percent 
decrease in the summer, a 6-percent increase in the winter, and a 6-
percent decrease in the spring compared to the existing rate of 1.45 
mills/kWh on April 1, 2001. The estimated rates from the provisional 
formula rates for COTP nonfirm transmission service for April 1, 2001, 
through March 31, 2002, are: summer--1.29 mills/kWh, winter--1.54 
mills/kWh, and spring--1.37 mills/kWh. In the previous rate case, 
Western developed COTP rates based on the entire transfer capability of 
the COI, which is 4,800 MW. However, due to the variability of the COI 
transfer capability, which impacts Western's share of the COTP capacity 
available for sale, Western developed formula rates for COTP 
transmission services. The primary factor for the decrease in the firm 
and nonfirm COTP rates is the termination of a contractual obligation 
to provide standby transmission service which increases the capacity 
available for sale.

Statement of Revenue and Related Expenses

    The following table gives a summary of revenues and expenses for 
the existing 5-year rate period and the provisional rate period.

                                         CVP Cost Evaluation Rate Period
                                [Revenues and Expenses, in thousands of dollars]
----------------------------------------------------------------------------------------------------------------
                                                                                 Provisional rates
                                                              Existing rates FY   April 1, 2001--
                                                                 1998-FY 2002      December 2004     Difference
 
----------------------------------------------------------------------------------------------------------------
      Total revenues........................................            824,651            928,925      104,274
                                                             ---------------------------------------------------
Revenue distribution:
    O&M.....................................................            216,776            187,600      (29,176)
    Purchase power..........................................            390,689            609,623      218,934
    Transmission............................................             80,335             57,229      (23,106)
    Interest................................................             54,536             21,486      (33,050)
    Other...................................................              9,073             13,568        4,495
    Investment repayment....................................             73,242             39,419      (33,823) 
----------------------------------------------------------------------------------------------------------------
Note: The revenues and expenses for the existing rates are for 5 years. Those for the provisional rates are for
  3 years and 9 months.

    The following table provides a summary of the average annual 
revenues and expenses for the existing and provisional rate periods.

                                  CVP Comparison of Cost Evaluation Rate Period
                         [Average Annual Revenues and Expenses, in thousands of dollars]
----------------------------------------------------------------------------------------------------------------
                                                                Existing rates   Provisional rates
                                                                average annual     average annual    Difference
----------------------------------------------------------------------------------------------------------------
      Total Revenues........................................            164,930            247,713       82,783
                                                             ---------------------------------------------------
Revenue distribution:
    O&M.....................................................             43,355             50,027        6,672
    Purchase power..........................................             78,138            162,566       84,428
    Transmission............................................             16,067             15,261         (806)
    Interest................................................             10,907              5,730       (5,177)
    Other...................................................              1,815              3,618        1,803
    Investment repayment....................................             14,648             10,512       (4,136)
----------------------------------------------------------------------------------------------------------------

Basis for Rate Development

    The existing rates for CVP commercial firm power, CVP transmission 
services, transmission of CVP power by others, network transmission 
service, ancillary services, and power scheduling service in Rate 
Schedules CV-F9, CV-FT3, CV-NFT3, CV-TPT4, CV-NWT1, CV-RFS1, CV-EID1, 
CV-SPR1, CV-SUR1, and CV-PSS1, expire September 30, 2002. Scheduling 
coordinator service is a new service offered by Western. The rate 
adjustment contains rates that replace the existing rates and adds a 
rate for the new service. The adjusted rates reflect increases in 
customers' CVP power purchases, purchase power costs, and Reclamation 
O&M costs. The adjusted rates also reflect the pass through of FERC-
accepted or -approved costs or credits, and changes in transmission 
rate methodology. The provisional rates will provide sufficient revenue 
to pay all annual costs, including interest expense and FERC-accepted 
or -approved costs or credits, and repayment of required investment in 
the allowable period. The provisional rates are scheduled to go in 
effect on April 1, 2001, and remain in effect through December 31, 
2004.
    The provisions for power factor adjustment, low voltage loss 
adjustment, and revenue adjustment are part of the provisional rates 
for CVP firm power. The provisions and methodologies for power factor 
adjustment and low voltage loss adjustment are not being modified and 
will remain as specified in Rate Schedule CV-F9. The methodology for 
revenue adjustment has been modified to reflect the expanded limit for 
the RAC credit or surcharge of $20 million, $10 million for October to 
December 2004, plus any purchase power or exchange contract adjustments 
during the FY for which the RAC is being calculated.

[[Page 21215]]

Update to the Proposed Rates

    During the public process, changes were made to the proposed rates 
for CVP firm power. On November 17, 2000, during the public information 
forum, Western told all interested parties of its intent to update the 
proposed CVP firm power rates. Western presented these updates to the 
proposed rates at the December 13, 2000, public comment forum. The 
updates are detailed below.

Firm Power

    1. Western added purchase power costs required to support PDC. 
Western expects PDC support purchases to occur in the rate case period 
due to recent purchases made for that purpose.
    2. Western has suspended its Northwest purchase power contracts. As 
a result, Western will be buying more capacity from PG&E at the DLL and 
will also be buying more energy from PG&E. The contract suspensions 
also cause EA2 to be depleted in September 2001.
    3. Western will also pass any charges or credits associated with 
the creation, termination, or modification to any tariff, contract, or 
schedule accepted or approved by FERC.
    4. Western updated PG&E rates for capacity and energy based on 
current agreements. Western also increased the capacity purchased under 
the DLL.
    5. Western also made adjustments to data in the firm power rate 
design model to reconcile that data to the data in the PRS and CVP 
transmission rate cost-of-service study.
    6. In the RAC limit, Western included exchange energy contract 
language.
    After the public process was complete it was necessary to change 
the CVP power repayment study as was contemplated during the December 
13, 2000, public comment forum. This change is due to purchase power 
costs for PDC support for October 2000 through March 2001. As a result 
of this change, there is less net revenue and slightly higher interest 
expense for the rate adjustment period, but all costs are recovered and 
repayment criteria met within the allowable timer limits. No changes 
were made to composite power rates. The energy and capacity rates 
changed slightly due to the change in net revenue and interest expense.

Comments

    During the public consultation and comment period, Western received 
5 written comments from 4 customers on the rate adjustment. In 
addition, two customer representatives commented during the December 
13, 2000, public comment forum. All comments received by the end of the 
public consultation and comment period, December 29, 2000, were 
reviewed and considered in this rate order.

Written comments were received from the following sources: City of 
Redding (California), Trinity County Public Utility District 
(California), City of Roseville (California), Sacramento Municipal 
Utility District (California)

    Comments received addressed the CVP energy rates, forecasted market 
rates, RAC limits, simplification of CVP firm power rate structure, 
pass through of FERC-approved charges or credits, power rates with the 
transmission revenue requirement removed, CAISO pass through costs, and 
CVP transmission rates. The following summarizes comments received and 
Western's responses to those comments. Specific comments are used for 
clarification where necessary.

CVP Power Rates

    Comment: Allowing adjustment without limitation to CVP energy rates 
leaves the customer with no ability to predict its Western costs. The 
rates should be developed using contractual conditions as they exist 
today. Under that premise, Western's major wholesale power costs are 
predictable enough that unlimited changes to the energy rate are 
unnecessary. If at some point in the future a significant change occurs 
to Western's cost structure, Western should implement another rate 
case.
    Response: The comment addresses a rate proposal that was discussed 
during the informal process and was not part of the proposed or updated 
proposed rates for CVP firm power.
    Comment: The forecasted market rates for Western's long-term 
Northwest contracts are too high.
    Response: The suspension of the Northwest contracts for the rate 
adjustment period was included in the updates to the proposed rates. 
This comment is not relevant to the updated proposed rates.
    Comment: The annual RAC limit of $20 million ($10 million for 
October through December 2004) plus any adjustment to Western's 
purchased power contract expenses is not appropriate. This RAC limit 
provides no assurance of maximum cost to customers and no guidance to 
Western on a reasonable range of operating cost variance. Western 
should develop a hedging strategy for PDC support purchases to keep 
Western within a RAC limit of $20 million.
    Response: Western is willing to work with the customers on 
developing a hedging strategy for PDC support purchases. As part of the 
updates to the proposed rates, Western added language to the RAC limit 
to allow for exchanges of power in addition to purchases of power, 
which should aid in limiting Western's exposure to market prices for 
PDC support. Due to the many factors outside of Western's control that 
can contribute to the need for PDC support purchases, Western feels it 
is prudent to retain the updated proposed RAC limit. These factors 
include changes in project water deliveries due to environmental 
requirements, project use pumping, and unscheduled maintenance outages. 
Maintaining the updated proposed RAC limit ensures timely repayment of 
project expenses and capital investment.
    Comment: A rate schedule without tiered capacity or energy rates or 
the Annual Energy Rate Alignment (AERA) is appreciated. There is no 
legitimate purpose for Western to apply an AERA once EA2 is depleted.
    Response: Western simplified the rate structure because the benefit 
of using the tiered rates and AERA is negligible, given the condition 
of the electric power industry.

Pass Through of FERC-Approved Charges and Credits

    Comment: The pass through of FERC-approved charges or credits is 
unacceptable. The pass through results in an unlimited right to change 
CVP power rates and makes it impossible to predict Western power costs. 
If there is a material change in the expected overall purchase power 
costs to Western, Western should initiate another rate case. If the 
cumulative effect of all FERC pass through costs increases Western's 
composite rates by more than 10 percent, Western should complete a new 
rate case within 6 months.
    Response: Western feels it is necessary to include the pass through 
of FERC-approved charges or credits in the updated proposed rates 
because of Western's exposure to changes in FERC-approved charges or 
credits under its existing contracts that support Western's power 
marketing program. In the recent past, there has been an increase in 
Western costs that were approved by FERC subject to refund. Western 
needs to recover FERC-approved charges or refund credits from its 
customers in a timely manner to ensure appropriate repayment of project 
expenses and capital investment. Additionally, adopting this comment 
could impact our ability to finance our purchase power program. Western 
understands customers' concerns about the inability to predict 
Western's costs and will make every effort to notify the

[[Page 21216]]

customers of pending changes to Western's costs due to FERC actions. 
FERC-approved charges or credits can go into effect within 60 days. 
Western cannot complete a rate case in that time. When FERC makes a 
final determination on costs paid by Western under its existing 
contracts, Western will evaluate the need for another rate case.

CAISO/Electric Utility Restructuring

    Comment: It is premature for Western to set rate policy that 
speculates on Western's joining the CAISO or an RTO, or the pass 
through of costs that may exist after Western joins an CAISO or an RTO.
    Response: Western's decision to join the CAISO or an RTO is not 
part of this rate process. However, Western believes it is prudent to 
develop rates that would accommodate Western's joining the CAISO or an 
RTO, particularly in light of FERC Order No. 2000. The pass through of 
CAISO- or RTO-related costs can occur independent of Western's decision 
to join or not to join the CAISO or an RTO. For example, in June 2000 
FERC approved, subject to refund, payment of Reliability Service costs 
that are CAISO-related costs, by Western customers.

CVP Transmission Service Rates

    Comment: The rate increase up to $.70/kW-month and then down to 
$.56/kW-month is not appropriate and creates rate shock for the 
transmission customers. There has been no real change in the 
transmission service or addition to transmission facilities to justify 
the rate increase. The rate increase results from the reclassification 
of a significant portion of existing CVP facilities from the generation 
category to the transmission category. Western should limit the 
increase to 10 percent, which is supported by FERC precedent. Western 
should levelize the rate impact.
    Response: Western reviewed the function of CVP facilities as part 
of the development of the transmission rate. Facilities that support 
the transfer capability of the transmission system were included in the 
transmission revenue requirement. Facilities that did not, such as 
generation tie lines and radial lines, were not included in the 
transmission revenue requirement. As a result of this review, there 
were only a few substations for which transmission costs were adjusted. 
The annual cost component for capital investment changed by less than 
$500,000 from the current transmission rates to the proposed 
transmission rates. The main reason for the increase in the CVP 
transmission rates is the increase in transmission O&M expenses. The 
transmission O&M expenses consist of O&M expenses directly charged to 
transmission facilities and non-direct charged O&M expenses. The non-
direct charged O&M is allocated based on a ratio of transmission plant 
to total plant. This treatment of O&M expenses is consistent with 
utility industry standards and accepted by FERC. Increasing the rate by 
10 percent or levelizing the rate is not consistent with a formula rate 
and would not meet the comparability standard set by FERC. A levelized 
rate would result in Western charging transmission customers less than 
what it charges itself for transmission service. Western believes the 
CVP transmission rate design meets the spirit and intent of FERC Order 
No. 888.

Environmental Compliance

    In compliance with the NEPA of 1969, 42 U.S.C. 4321, et seq.; 
Council on Environmental Quality Regulations, 40 CFR parts 1500-1508; 
and DOE NEPA Regulations, 10 CFR part 1021, Western determined this 
action is categorically excluded from the preparation of an 
environmental assessment or an environmental impact statement.

Determination Under Executive Order 12866

    Western has an exemption from centralized regulatory review under 
Executive Order 12866. This notice is not required to be cleared by the 
Office of Management and Budget.

Regulatory Flexibility Analysis

    The Regulatory Flexibility Act of 1980 (5 U.S.C. 601, et seq.) 
requires Federal agencies to perform a regulatory flexibility analysis 
if a final rule is likely to have a significant economic impact on a 
substantial number of small entities and there is a legal requirement 
to issue a general notice of proposed rulemaking. Western has 
determined this action does not require a regulatory flexibility 
analysis since it is a rulemaking of particular applicability involving 
rates or services applicable to public property.

Small Business Regulatory Enforcement Fairness Act

    Western determined this rule is exempt from congressional 
notification requirements under 5 U.S.C. 801 because the action is a 
rulemaking of particular applicability relating to rates or services 
and involves matters of procedure.

Availability of Information

    Information about this rate adjustment, including PRS, comments, 
letters, memorandums, and other supporting material made or kept by 
Western used to develop the provisional rates, is available for public 
review. This information is in the Power Marketing Manager's office, 
Sierra Nevada Customer Service Region, Western Area Power 
Administration, 114 Parkshore Drive, Folsom, California.

Submission to the Federal Energy Regulatory Commission

    The provisional rates herein confirmed, approved, and placed into 
effect, together with supporting documents, will be submitted to FERC 
for confirmation and final approval.

Order

    In view of the foregoing and under the authority delegated to me by 
the Secretary of Energy, I confirm and approve on an interim basis, 
effective April 1, 2001, Rate Schedules CV-F10, CV-FT4, CV-NFT4, CV-
TPT5, CV-NWT2, CV-RFS2, CV-EID2, CV-SPR2, CV-SUR2, CV-PSS2, CV-SCS1, 
COTP-FT2, and COTP-NFT2 for the Central Valley Project and for the 
California-Oregon Transmission Project, for the Western Area Power 
Administration. On April 10, 2001, by Amendment No. 4 to Delegation 
Order No. 0204-108, the Secretary of Energy delegated to Western's 
Administrator the authority to confirm, approve, and place into effect 
on an interim basis the rates in the Central Valley Project and 
California-Oregon Transmission Project-Rate Order No. WAPA-95. The rate 
schedules will remain in effect on an interim basis, pending FERC 
confirmation and approval of them or substitute rates on a final basis 
through December 31, 2004.

Dated: April 13, 2001.
Michael S. Hacskaylo,
Administrator.

Rate Schedule CV-F10

(Supersedes Schedule CV-F9)

Central Valley Project

Schedule of Rates for Firm Power

Effective

    The first day of the first full billing period beginning on or 
after April 1, 2001, through December 31, 2004.

Available

    Within the marketing area served by the Sierra Nevada Customer 
Service Region.

Applicable

    To the firm power customers for general power service.

[[Page 21217]]

Character and Conditions of Service

    Alternating current, 60 hertz, three-phase, delivered and metered 
at the voltages and points established by contract.

Monthly Rates With Transmission Revenue Requirement Included

----------------------------------------------------------------------------------------------------------------
                Period                             Capacity                              Energy
----------------------------------------------------------------------------------------------------------------
04/01/01-09/30/01.....................  $3.44/kWmonth.................  14.01 mills/kWh.
10/01/01-09/30/02.....................  $3.73/kWmonth.................  17.68 mills/kWh.
10/01/02-09/30/03.....................  $3.89/kWmonth.................  18.22 mills/kWh.
10/01/03-09/30/04.....................  $3.86/kWmonth.................  18.38 mills/kWh.
10/01/04-12/31/04.....................  $3.80/kWmonth.................  24.97 mills/kWh.
----------------------------------------------------------------------------------------------------------------

    The table below contains rates with the transmission revenue 
requirement removed from the firm power revenue requirement. These 
rates would apply if Western joins the California Independent System 
Operator (CAISO) or Regional Transmission Organization (RTO) and if the 
CAISO or RTO uses the transmission revenue requirement to develop a 
regional transmission rate.

Monthly Rates With Transmission Revenue Requirement Removed

----------------------------------------------------------------------------------------------------------------
                Period                             Capacity                              Energy
----------------------------------------------------------------------------------------------------------------
04/01/01-09/30/01.....................  $2.55/kWmonth.................  14.01 mills/kWh.
10/01/01-09/30/02.....................  $2.91/kWmonth.................  17.68 mills/kWh.
10/01/02-09/30/03.....................  $3.08/kWmonth.................  18.18 mills/kWh.
10/01/03-09/30/04.....................  $3.05/kWmonth.................  18.38 mills/kWh.
10/01/04-12/31/04.....................  $2.92/kWmonth.................  24.97 mills/kWh.
----------------------------------------------------------------------------------------------------------------

Pass Through of FERC-Accepted or -Approved Charges or Credits

    Any charges or credits associated with the creation, termination, 
or modification to any tariff, contract, or schedule accepted or 
approved by FERC, under which Western takes service, will be passed on 
to each appropriate customer. These FERC-accepted or -approved charges 
or credits are applicable to both sets of capacity and energy rates 
described above.
    When possible, Western will pass through directly to the 
appropriate customer the FERC-accepted or -approved charges or credits 
in the same manner Western is charged or credited. If the FERC-accepted 
or -approved charges or credits cannot be passed through directly to 
the appropriate power customer, the charges or credits will be passed 
through using the CVP firm power rate design methodology. The rate 
design consists of the following allocation of costs. The capacity 
revenue requirement includes 100 percent of capacity purchase costs, 
100 percent of CVP and COTP transmission expense, and 50 percent of the 
annual investment repayment, interest expense, and O&M expense 
allocated to power. These annual costs are reduced by the projected CVP 
and COTP transmission revenues and 50 percent of the projected CVP 
project use revenue to determine the capacity revenue requirement. The 
capacity revenue requirement for the rates that have the transmission 
revenue requirement removed is the same, except the CVP and COTP 
transmission expense and revenue are excluded from the calculation. The 
energy revenue requirement for both sets of proposed rates includes 100 
percent of energy purchase costs and 50 percent of the annual 
investment repayment, interest expense, and O&M expense allocated to 
power. These annual costs are reduced by 50 percent of the projected 
project use revenues and the projected revenue from surplus power sales 
to determine the energy revenue requirement.

Billing

    Demand: The rates listed above for capacity will be the charge per 
kilowatt (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.

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, the overrun will be billed at 10 times the 
applicable rates above.
For Revenue Adjustment
    The following method 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:

If ANR > PNR then 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:

If ANR  PNR and  0 then 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:

If ANR  PNR and > 0 then S = MIP - ANR (if ANR > MIP, S = 0)
Where:

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

    If the actual net revenue is greater than the minimum investment 
payment, there is no surcharge.

[[Page 21218]]

    3. The maximum RAC credit or surcharge is $20 million, $10 million 
for October through December 2004, plus the amount of purchase or 
exchange power contract adjustments used in recording associated 
expense.
    4. The RAC credit or surcharge will be allocated to each CVP firm 
power customer based on the proportion of the customer's billed 
obligation to Western for CVP firm capacity and energy to the total 
billed obligation for all CVP firm power customers for CVP firm 
capacity and energy for the RAC calculation period.
    5. For purposes of the RAC computation, the following terms are 
defined:
    5.1  Actual Net Revenue--The recorded net revenue.
    5.2  Annual Deficit--The amount of recorded annual expenses, 
including interest, exceeding recorded annual revenues.
    5.3  Minimum Investment Payment--The lesser of 1 percent of the 
recorded unpaid investment balance at the end of the FY prior to the 
RAC calculation period, or the projected net revenue.
    5.4  Projected Net Revenue--The annual net revenue available for 
investment repayment projected in the rate adjustment power repayment 
study (PRS) during the FY that RAC is being calculated (see Table 1).
    5.5  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. For customers whose RAC credits 
cannot be fully credited through nine equal monthly amounts, Western 
may increase the RAC credit on the August and September power bills. 
For October 1 through December 31, 2004, see item 6 below.
    5.6  RAC Calculation Period--The last recorded FY (October 1 
through September 30). For October 1 through December 31, 2004, see 
item 6 below.
    5.7  Recorded Net Revenue--The annual net revenue available for 
repayment recorded in the PRS for the FY the RAC is being calculated.
    5.8  RAC will be calculated for FY 2001, even though the October 
2000 to March 2001 portion of the FY is outside the rate case period. 
The revenues and expenses for FY 2001 will be used to determine the RAC 
for FY 2001.
    6. A RAC will be calculated for October through December 2004. It 
will be allocated to each CVP firm power customer consistent with the 
procedure in item 4 above. The resulting RAC credit or surcharge will 
be applied to power bills issued from April to September 2005, if the 
customer has a power contract with Western during 2005. If the customer 
does not, Western will issue a bill or check for the October to 
December 2004 RAC surcharge or credit in April 2005.

  Table 1.--Projected Net Revenue Available for Investment Repayment for
                        Revenue Adjustment Clause
------------------------------------------------------------------------
                                                           Projected net
                         Period                               revenue
------------------------------------------------------------------------
October 1, 2000-September 30, 2001......................      $4,923,466
October 1, 2001-September 30, 2002......................      11,887,939
October 1, 2002-September 30, 2003......................      10,426,583
October 1, 2003-September 30, 2004......................      12,905,190
October 1, 2004-December 31, 2004.......................       1,737,596
------------------------------------------------------------------------

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 stated in the contract.
For Power Factor Adjustment
    The customer must maintain a power factor at all points of 
measurement between 95 percent lagging and 95 percent leading. The low 
power factor (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 in Table 2. The kvar rate in the LPF 
charge is $2.50 per kvar.

                    Table 2.--Low Power Factor Charge
------------------------------------------------------------------------
                                                                  LPF
                   Calculated power factor                       Charge
                                                                 ($/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 and below...............................................       1.38
------------------------------------------------------------------------

    The rules and limitations of the LPF charge are as follows:
    1. 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.
    2. The measured on-peak power factor equals the power factor 
measured during the customer's maximum peak demand for each month, as 
recorded at the customer's point of delivery. If there are 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 the total 
information from the points of delivery. The monthly average and on-
peak power factors are those recorded for CVP power only.
    3. The upper limit for both the monthly average and measured on-
peak power factors is 95 percent. Customers will receive no credit for 
operating between 100 percent and 95 percent power factors.

[[Page 21219]]

    4. The LPF charge will apply to calculated power factors less than 
95 percent, lagging or leading.
    5. Customers with a monthly maximum peak demand less than or equal 
to 50 kW will not be subject to the LPF charge.
    6. Western may waive the LPF charge for good cause in whole or in 
part.

Rate Schedule CV-FT4

(Supersedes Schedule CV-FT3)

Schedule of Rate for Firm Transmission Service

Effective

    The first day of the first full billing period beginning on or 
after April 1, 2001, through December 31, 2004.

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 receipt 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. It 
includes scheduling, system control and dispatch service and reactive 
supply and voltage control service needed to support the transmission 
service.

Formula Rate

    The formula rate for firm CVP transmission has two components.
    Component 1 is the following formula:
    [GRAPHIC] [TIFF OMITTED] TN27AP01.001
    

    Where:
TRR = Transmission Revenue Requirement--the costs associated with 
facilities that support the transfer capability of the CVP transmission 
system, excluding generation facilities and radial lines. These costs 
include investment cost, interest expense, and operation and 
maintenance (O&M) expense, less revenue credits.
CVPc = CVP Capacity--the sum of the maximum operating capacity of the 
Northern CVP powerplants under normal operating conditions. Northern 
CVP powerplants are Judge Francis Carr, Folsom, Keswick, Nimbus, 
Shasta, Spring Creek, and Trinity.
TTc = Total Transmission Capacity--the total transmission capacity 
under long-term contract between Western and other parties.

Component 2 is any transmission-related costs incurred by Western due 
to electric industry restructuring or other industry changes associated 
with providing CVP transmission service. The costs in component 2, and 
any changes to these costs, will be passed through to each appropriate 
transmission customer.
    Western will revise the rate from component 1, as of April 30 of 
each year, based on previous year's annual financial data available. In 
addition to the annual update on April 30 of each year, Western will 
also revise the rate from component 1 if there is a change in the 
numerator or denominator that results in a rate change of at least $.05 
per kilowattmonth. Customers will be notified of the rate change 30 
days before the first bill is issued using the changed rates.
    If the rates from the formula rate are higher than other 
transmission rates in California, transmission service for 1 year or 
less may be sold at a lower rate.

Billing

    The rate from the formula rate listed above will be applied monthly 
to the maximum amount of capacity reserved, payable whether used or 
not.

Adjustments

For Losses
    Losses incurred from the transmission and delivery of power under 
this rate schedule will be accounted for as agreed to by the parties.

Rate Schedule CV-NFT4

(Supersedes Schedule CV-NFT3)

Schedule of Rate for Nonfirm Transmission Service

Effective

    The first day of the first full billing period beginning on or 
after April 1, 2001, through December 31, 2004.

Available

    Within the marketing area served by the Sierra Nevada Customer 
Service Region.

Applicable

    To nonfirm 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 delivery on the CVP system as agreed to by the parties.

Character and Conditions of Service

    Transmission service on an intermittent basis for three-phase 
alternating current at 60 hertz, delivered and metered at the voltages 
and points of delivery. It includes scheduling, system control and 
dispatch service and reactive supply and voltage control service needed 
to support the transmission service.

Formula Rate

    The formula rate for nonfirm CVP transmission has two components. 
Component 1 is the following formula:
[GRAPHIC] [TIFF OMITTED] TN27AP01.002


Where:
TRR = Transmission Revenue Requirement--the costs associated with 
facilities that support the transfer capability of the CVP transmission 
system, excluding generation facilities and radial lines. These costs 
include investment cost, interest expense, and operation and 
maintenance (O&M) expense, less revenue credits.
CVPe = CVP energy--the energy associated with the maximum operating 
capacity of the Northern CVP powerplants under normal operating 
conditions. Northern CVP powerplants are Judge Francis Carr, Folsom, 
Keswick, Nimbus, Shasta, Spring Creek, and Trinity.
TTe = Total Transmission energy--the energy associated with the total 
transmission capacity under long-term contract between Western and 
other parties.

Component 2 is any transmission-related costs incurred by Western due 
to electric industry restructuring or other industry changes associated 
with providing CVP transmission service. The costs in component 2, as 
well as any changes to these costs, will be passed through to each 
appropriate transmission customer.
    Western will revise the rate from component 1, as of April 30 of 
each year, based on previous year's annual financial data available. 
Western will also revise the rate from component 1 if there is a change 
in component 1 of the CVP firm transmission rate of at least $.05 per 
kilowattmonth. Customers will be notified of the rate change 30 days 
before the first bill is issued using the changed rates.
    If the rates from the formula rate are higher than other 
transmission rates in

[[Page 21220]]

California, transmission service for 1 year or less may be sold at a 
lower rate.

Billing

    The rate resulting from the formula rate listed above will be 
applied to each kWh delivered at the point of delivery, as specified in 
the service contract.

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-TPT5

(Supersedes Schedule CV-TPT4)

Schedule of Rate for Transmission of CVP Power by Others

Effective

    The first day of the first full billing period beginning on or 
after April 1, 2001, through December 31, 2004.

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.

Formula Rate

    When Western incurs costs for using transmission facilities, other 
than its own, in supplying service under a customer's power sales 
contract, the customer will pay all costs, including transmission 
losses, incurred in the delivery of power. For billing purposes, 
transmission losses will be added to the meter readings of the capacity 
and energy delivered to the customer under the customer's power sales 
agreement with Western. For power deliveries under Contract No. 14-06-
200-2948A (Contract 2948A) on the Pacific Gas and Electric Company's 
system, the transmission losses charged to the customer will be those 
losses that are in excess of the ``at or above 44-kilovolt'' 
transmission losses specified by Contract 2948A.

Rate Schedule CV-NWT2

(Supersedes Schedule CV-NWT1)

Schedule of Rate for Network Integration Transmission Service

Effective

    The first day of the first full billing period beginning on or 
after April 1, 2001, through December 31, 2004.

Available

    Within the marketing area served by the Sierra Nevada Customer 
Service Region.

Applicable

    To customers who receive network integration 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. It 
includes scheduling, system control and dispatch service and reactive 
supply and voltage control service needed to support the transmission 
service.

Formula Rate

    The formula rate for network transmission service consists of two 
components.
    Component 1 is the product of the network customer's load ratio 
share times \1/12\ of the annual network transmission revenue 
requirement. The load ratio share is the network customer's hourly load 
coincident with Western's monthly CVP transmission system peak, minus 
the coincident peak for all firm CVP (including reserved capacity) 
point-to-point transmission service, plus the reserved capacity of all 
firm point-to-point transmission service customers. The network 
transmission revenue requirement is the cost associated with facilities 
that support the transfer capability of the CVP transmission system, 
excluding generation facilities and radial lines.
    Component 2 is for any transmission-related costs incurred by 
Western due to electric industry restructuring or other industry 
changes associated with providing network integration transmission 
service. The costs in component 2, as well as any changes to these 
costs, will be passed through to each appropriate transmission customer 
as part of the network integration transmission revenue requirement.

Billing

    Billing determinants for the formula rate 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 as stated in the 
service agreement.

Rate Schedule CV-RFS2

(Supersedes Schedule CV-RFS1)

Schedule of Rates for Regulation and Frequency Response Service

Effective

    The first day of the first full billing period beginning on or 
after April 1, 2001, through December 31, 2004.

Available

    Within the marketing area served by the Sierra Nevada Customer 
Service Region.

Applicable

    To customers receiving regulation and frequency response service.

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: $2.496 per kilowattmonth.
    Weekly: $0.574 per kilowattweek.
    Daily: $0.082 per kilowattday.

Billing

    The rates listed above will be applied to the maximum service 
amount in kilowatts agreed to in the service agreement, payable whether 
used or not.

Rate Schedule CV-EID2

(Supersedes Schedule CV-EID1)

Schedule of Rate for Energy Imbalance Service

Effective

    The first day of the first full billing period beginning on or 
after April 1, 2001, through December 31, 2004.

Available

    Within the marketing area served by the Sierra Nevada Customer 
Service Region.

Applicable

    To customers receiving energy imbalance service.

[[Page 21221]]

Character and Conditions of Service

    Energy imbalance service supplies 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.

Formula Rate

Within Limits of Deviation Band
    Accumulated deviations are to be corrected or eliminated within 30 
days. Any net deviations 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 firm power then in effect.
Outside Limits of Deviation Band
    1. Positive Deviations--the greater of no charge, or any additional 
cost incurred.
    2. Negative Deviations--during on-peak hours, the greater of three 
times the rate for CVP firm power or any additional cost incurred. 
During off-peak hours, the greater of the rate for CVP firm power or 
any additional cost incurred.

Billing

    The billing determinants for the above formula rate will be 
specified in the service agreement.

Rate Schedule CV-SPR2

(Supersedes Schedule CV-SPR1)

Schedule of Rates for Spinning Reserve Service

Effective

    The first day of the first full billing period beginning on or 
after April 1, 2001, through December 31, 2004.

Available

    Within the marketing area served by the Sierra Nevada Customer 
Service Region.

Applicable

    To customers receiving spinning reserve service.

Character and Conditions of Service

    Spinning reserve service supplies capacity that is available the 
first 10 minutes to take load and is synchronized with the power 
system.

Rates

    Spinning Reserve Service Charge:
    Monthly: $2.946 per kilowattmonth.
    Weekly: $0.672 per kilowattweek.
    Daily: $0.096 per kilowattday.
    Hourly: $0.0040 per kilowatthour.

Billing

    The rates listed above will be applied to the maximum service 
amount in kilowatts agreed to in the service agreement, payable whether 
used or not.

Rate Schedule CV-SUR2

(Supersedes Schedule CV-SUR1)

Schedule of Rates for Supplemental Reserve Service

Effective

    The first day of the first full billing period beginning on or 
after April 1, 2001, through December 31, 2004.

Available

    Within the marketing area served by the Sierra Nevada Customer 
Service Region.

Applicable

    To customers receiving supplemental reserve service.

Character and Conditions of Service:

    Supplemental reserve service supplies capacity that is not 
synchronized with the power system but can be available to serve load 
within 10 minutes.

Rates

    Supplemental Reserve Service Charge:
    Monthly: $2.491 per kilowattmonth.
    Weekly: $0.574 per kilowattweek.
    Daily: $0.082 per kilowattday.
    Hourly: $0.0034 per kilowatthour.

Billing:

    The rates listed above will be applied to the maximum service 
amount in kilowatts agreed to in the service agreement, payable whether 
used or not.

Rate Schedule CV-PSS2

(Supersedes Schedule CV-PSS1)

Schedule of Rate for Power Scheduling Service

Effective

    The first day of the first full billing period beginning on or 
after April 1, 2001, through December 31, 2004.

Available

    Within the marketing area served by the Sierra Nevada Customer 
Service Region.

Applicable

    To customers receiving power scheduling service.

Character and Conditions of Service

    Power scheduling service provides for the scheduling of resources 
to meet loads and reserve requirements.

Rate

    $76.65 per hour.

Billing

    The rate listed above will be applied as stated in the service 
agreement.

Rate Schedule CV-SCS1

Schedule of Rate for Scheduling Coordinator Service

Effective

    The first day of the first full billing period beginning on or 
after April 1, 2001, through December 31, 2004.

Available

    Within the marketing area served by the Sierra Nevada Customer 
Service Region.

Applicable

    To customers receiving scheduling coordinator service.

Character and Conditions of Service

    Scheduling Coordinator service provides for the scheduling, real-
time dispatching, and financial settlements with the California 
Independent System Operator and/or power exchanges.

Rate

    $76.65 per hour.

Billing

    The rate listed above will be applied as stated in the service 
agreement.

Rate Schedule COTP-FT2

(Supersedes Schedule COTP-FT1)

Schedule of Rate for Firm Transmission Service

Effective

    The first day of the first full billing period beginning on or 
after April 1, 2001, through December 31, 2004.

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 California-Oregon Transmission Project (COTP) at points of receipt 
with other systems and transmitted and delivered to points of delivery 
on the COTP 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. It 
includes scheduling, system control and dispatch service and

[[Page 21222]]

reactive supply and voltage control service needed to support the 
transmission service.

Formula Rate

    The formula rate for COTP firm transmission includes two 
components.
    Component 1 is the following formula:
    [GRAPHIC] [TIFF OMITTED] TN27AP01.003
    
Where:

TRR = Transmission Revenue Requirement--Western's share of the costs 
associated with facilities that support the transfer capability of the 
COTP. These costs include investment cost, interest expense, operation 
and maintenance (O&M) expense, less revenue credits.
COTPsc = COTP seasonal capacity--Western's share of capacity under the 
then current California-Oregon Intertie transfer capability for the 
season. Seasonal definitions for summer, winter, and spring are June 
through October, November through March, and April through May, 
respectively.

Western will update component 1 at least 15 days before the start of 
each season. Notification of rate changes will occur through the 
posting of the rate on the open access same time information system.
    Component 2 is any transmission-related costs incurred by Western 
due to electric industry restructuring or other industry changes 
associated with providing COTP transmission service. The costs in 
component 2, as well as any changes to these costs, will be passed 
through to each appropriate transmission customer.
    If the rates from the formula rate are higher than other 
transmission rates in California, transmission service for 1 year or 
less may be sold at a lower rate.

Billing

    The rates listed above will be applied monthly to the maximum 
amount of capacity reserved, payable whether used 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-NFT2

(Supersedes Schedule COTP-NFT1)

Schedule of Rate for Nonfirm Transmission Service

Effective

    The first day of the first full billing period beginning on or 
after April 1, 2001, through December 31, 2004.

Available

    Within the marketing area served by the Sierra Nevada Customer 
Service Region.

Applicable

    To nonfirm transmission service customers where power is received 
into the California-Oregon Transmission Project (COTP) 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 as agreed to by the parties.

Character and Conditions of Service

    Transmission service on an intermittent basis for three-phase, 
alternating current at 60 hertz, delivered and metered at the voltages 
and points of delivery. It includes scheduling, system control and 
dispatch service and reactive supply and voltage control service needed 
to support the transmission service.

Rate

    The formula rate for COTP nonfirm transmission includes two 
components.
    Component 1 is the following formula:
    [GRAPHIC] [TIFF OMITTED] TN27AP01.004
    
Where:

TRR = Transmission Revenue Requirement--Western's share of the costs 
associated with facilities that support the transfer capability of the 
COTP. These costs include investment cost, interest expense, operation 
and maintenance expense, less revenue credits.
COTPe = Energy associated with COTP Seasonal Capacity--the energy 
associated with Western's share of capacity under the then current 
California-Oregon Intertie (COI) transfer capability for the season. 
Seasonal definitions for summer, winter, and spring are June through 
October, November through March, and April through May, respectively.

Western will update component 1 at least 15 days before the start of 
each season. Notification of rate changes will occur through the 
posting of the rate on the open access same time information system.
    Component 2 is any transmission-related costs incurred by Western 
due to electric industry restructuring or other industry changes 
associated with providing COTP transmission service. The costs in 
component 2, as well as any changes to these costs, will be passed 
through to each appropriate transmission customer.
    If the rates resulting from the formula rate are higher than other 
transmission rates in California, transmission service for 1 year or 
less may be sold at a lower rate.

Billing

    The rates listed above will be applied to each kilowatthour 
delivered at the point of delivery, as specified in the service 
contract.

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. 01-10227 Filed 4-26-01; 8:45 am]
BILLING CODE 6450-01-P


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