[Federal Register Volume 69, Number 233 (Monday, December 6, 2004)]
[Notices]
[Pages 70510-70536]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 04-26628]



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Part II





Department of Energy





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Western Area Power Administration



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The Central Valley Project, the California-Oregon Transmission Project, 
the Pacific Alternating Current Intertie, and Information on the Path 
15 Transmission Upgrade-Rate Order No. WAPA-115; Notice

  Federal Register / Vol. 69, No. 233 / Monday, December 6, 2004 / 
Notices  

[[Page 70510]]


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DEPARTMENT OF ENERGY

Western Area Power Administration


The Central Valley Project, the California-Oregon Transmission 
Project, the Pacific Alternating Current Intertie, and Information on 
the Path 15 Transmission Upgrade-Rate Order No. WAPA-115

AGENCY: Western Area Power Administration, DOE.

ACTION: Notice of rate order.

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SUMMARY: The Deputy Secretary of Energy confirmed and approved Rate 
Order No. WAPA-115, which includes Rate Schedules CV-F11, CPP-1, CV-T1, 
CV-NWT3, COTP-T1, PACI-T1, CV-TPT6, CV-SPR3, CV-SUR3, CV-RFS3, and CV-
EID3, placing formula rates for power, transmission, and ancillary 
services for the Central Valley Project (CVP), transmission service on 
the California-Oregon Transmission Project (COTP), transmission service 
on the Pacific Alternating Current Intertie (PACI), and third-party 
transmission into effect on an interim basis. The Rate Order also 
provides information on the Western Area Power Administration's 
(Western) entitlement on the Path 15 Transmission Upgrade. The 
provisional formula rates will be in effect until the Federal Energy 
Regulatory Commission (Commission) confirms, approves, and places them 
into effect on a final basis or until they are replaced by other rates. 
The provisional formula rates will provide sufficient revenue to pay 
all annual costs, including interest expense, and repayment of power 
investment and irrigation aid, within the allowable periods.

DATES: Rate Schedules CV-F11, CPP-1, CV-T1, CV-NWT3, COTP-T1, PACI-T1, 
CV-TPT6, CV-SPR3, CV-SUR3, CV-RFS3, and CV-EID3 will be placed into 
effect on January 1, 2005, and will be in effect until the Commission 
confirms, approves, and places the rate schedules in effect on a final 
basis through September 30, 2009, or until the rate schedules are 
superseded.

FOR FURTHER INFORMATION CONTACT: Mr. James D. Keselburg, Regional 
Manager, Sierra Nevada Customer Service Region, Western Area Power 
Administration, 114 Parkshore Drive, Folsom, CA 95630-4710, (916) 353-
4418, or Ms. Debbie Dietz, Rates Manager, Sierra Nevada Customer 
Service Region, Western Area Power Administration, 114 Parkshore Drive, 
Folsom, CA 95630-4710, (916) 353-4453, e-mail [email protected].

SUPPLEMENTARY INFORMATION: Under Amendment No. 4 to Delegation Order 
No. 0204-108, the Administrator of Western approved the existing Rate 
Schedule CV-F10 for CVP firm power, Rate Schedules CV-FT4, CV-NFT4, CV-
TPT5, CV-NWT2, COTP-FT2, and COTP-NFT2 for transmission, and Rate 
Schedules CV-RFS3, CV-EID3, CV-SPR3, and CV-SUR3 for CVP ancillary 
services on April 14, 2001, (Rate Order No. WAPA-95, April 27, 2001). 
The Commission confirmed and approved the rate schedules on August 14, 
2001, in FERC Docket No. EF01-5011-000. The existing rate schedules are 
effective from April 1, 2001, through December 31, 2004.
    The provisional rates include a new transmission service for the 
PACI (Rate Schedule PACI-T1). The Rate Order also provides information 
on Western's entitlement on the Path 15 Transmission Upgrade. Western 
intends to turn over operational control of Western's entitlement on 
the Path 15 Transmission Upgrade to the California Independent System 
Operator (CAISO). As a result, the CAISO tariff and rates will apply to 
this service.
    The existing firm power Rate Schedule CV-F10 is being superseded by 
Rate Schedule CV-F11. Under Rate Schedule CV-F10, the energy rate is 
24.97 per mills/kilowatthour (mills/kWh) and the capacity rate is $3.80 
per kilowattmonth (kWmonth). The composite rate is 30.83 mills/kWh. On 
December 31, 2004, the 1994 Power Marketing Plan expires. The 2004 
Power Marketing Plan goes into effect January 1, 2005, and does not 
offer the same type of power service that is available under the 1994 
Power Marketing Plan.
    Under the 2004 Power Marketing Plan, each Preference Customer 
(except First Preference Customers) that has signed a Base Resource 
contract is a Base Resource Customer and is allocated a percentage of 
the Base Resource. Base Resource is primarily CVP and Washoe Project 
power output remaining after meeting project use, First Preference, and 
other operational requirements.
    A First Preference Customer is defined in the 2004 Power Marketing 
Plan as a Preference Customer and/or a Preference entity (an entity 
qualified to use, but not using, Preference power) within a county of 
origin (Trinity, Calaveras, and Tuolumne) as specified under the 
Trinity River Division Act (69 Stat. 719) and the New Melones project 
provisions of the Flood Control Act of 1962 (76 Stat. 1173, 1191-1192).
    The Base Resource and First Preference power provisional formula 
rates use percentages to recover the estimated power revenue 
requirement for January through September 2005 of $30 million, of which 
$1,110,000 will be recovered from the First Preference Customers and 
$28,890,000 will be recovered from the Base Resource Customers. These 
rates also include pass-through language for Host Control Area (HCA) 
and the Commission or other regulatory body credits or charges.
    Under the 2004 Power Marketing Plan, a Customer's load can be met 
through First Preference, Base Resource, and/or Custom Product Power. 
Custom Product Power is power that is purchased to meet a Customer's 
load and may include long- and short-term purchases at various rates. 
All costs associated with Custom Product Power will be recovered 
through a formula rate in Rate Schedule CPP-1 that passes through the 
cost of the purchase to a specific Customer(s).
    Rate Schedule CV-T1 supersedes Rate Schedules CV-FT4 and CV-NFT4, 
and CV-NWT3 supersedes Rate Schedule CV-NWT2. The existing and 
provisional formula rates for CVP transmission service include the 
costs for scheduling, system control and dispatch service, and reactive 
supply and voltage control from generation sources service. Provisional 
formula rates developed for CVP, COTP, and PACI transmission services 
are consistent with FERC Order No. 888.
    The third-party transmission service rate schedule allows Western 
to pass through any costs it incurs for delivery of Western power over 
a third party's transmission system. The provisional formula rate for 
third-party transmission service in Rate Schedule CV-TPT6 is the same 
as the existing formula rate in CV-TPT5, with the exception of pass-
through language for HCA and any Commission or other regulatory body 
charges or credits.
    On January 1, 2005, under the provisional formula rate in Rate 
Schedule CV-T1, the CVP firm and non-firm transmission rates are the 
same. A change from the existing to the provisional formula rate is the 
pass-through of HCA charges or credits. A comparison of the estimated 
monthly and hourly rates from the provisional formula rate to the 
existing firm and non-firm rates is shown in the table below.

[[Page 70511]]



 Comparison of Existing and Estimated Rates From the Provisional Formula
                      Rate CVP Transmission Service
------------------------------------------------------------------------
                                                  Estimated
                                               rates from the
                                     Existing    provisional    Percent
                                      rates     formula rate     change
                                               (effective 1/1/
                                                     05)
------------------------------------------------------------------------
CVP Firm Transmission Rate ($/          $0.57           $1.03         81
 kWmonth).........................
CVP Non-Firm Transmission Rate           1.00            1.40         40
 (mills/kWh)......................
------------------------------------------------------------------------

    The provisional formula rate for CVP network integration 
transmission service (Rate Schedule CV-NWT3) is the same as the 
existing formula rate for this service with the exception of the pass 
through of any HCA charges or credits.
    On January 1, 2005, under the provisional formula rate in Rate 
Schedule COTP-T1, the COTP firm and non-firm transmission rates are the 
same. A change from the existing formula rate to the provisional 
formula rate is the inclusion of pass-through language for HCA credits 
or charges. A comparison of the estimated monthly and hourly rates from 
the provisional formula rate to the existing firm and non-firm rates is 
provided in the table below.

 Comparison of Existing and Estimated Rates From the Provisional Formula
                     Rates COTP Transmission Service
------------------------------------------------------------------------
                                                  Estimated
                                               rates from the
                                     Existing    provisional    Percent
                                      rates     formula rates    change
                                               (effective 1/1/
                                                     05)
------------------------------------------------------------------------
COTP Firm Transmission Rate ($/
 kWmonth):
  Spring..........................      $0.73           $1.87        156
  Summer..........................      $0.53           $1.87        253
  Winter..........................      $0.66           $1.88        185
COTP Non-Firm Transmission Rate
 (mills/kWh):
  Spring..........................       1.00            2.55        155
  Summer..........................       0.72            2.54        253
  Winter..........................       0.91            2.59        185
------------------------------------------------------------------------

    PACI transmission service is a new service. Under the provisional 
formula rate in Rate Schedule PACI-T1, the firm and non-firm 
transmission rates are the same and include pass-through language for 
HCA and Commission or other regulatory body charges or credits. Under 
the provisional formula rate, the estimated monthly rates are $0.45/
kWmonth for spring, summer, and winter. The estimated hourly PACI 
transmission rates are 0.61 mills/kWh for spring and summer and 0.62 
mills/kWh for winter.
    Western has not developed a separate rate for Western's entitlement 
on the Path 15 Transmission Upgrade, as Western intends to turn over 
operational control of Western's entitlement on the Path 15 
Transmission Upgrade to the CAISO. The CAISO tariff and rates shall 
apply to Western's entitlement on the Path 15 Transmission Upgrade. 
Western has provided information on the treatment of revenue associated 
with its entitlement on the Path 15 Transmission Upgrade as part of 
this Rate Order.
    Rate Schedules CV-RFS3, CV-EID3, CV-SPR3, and CV-SUR3 supersede 
Rate Schedules CV-RFS2, CV-EID2, CV-SPR2, and CV-SUR2, respectively. 
Provisional formula rates developed for the CVP ancillary services 
contain pass-through language for HCA and Commission or other 
regulatory body charges or credits. A comparison of existing rates to 
the estimated rates from the provisional formula rates is shown in the 
table below.

      Comparison of Existing and Estimated Rates From the Provisional Formula Rates CVP Ancillary Services
----------------------------------------------------------------------------------------------------------------
                                                                  Rate from the provisional
       Ancillary service type              Existing rates               formula rates               Change
----------------------------------------------------------------------------------------------------------------
Scheduling and System Control and    Included in the             Included in the             N/A.
 Dispatch Service.                    appropriate transmission    appropriate transmission
                                      rates.                      rates.
Reactive Supply and Voltage Control  Included in the             Included in the             N/A.
 Service.                             appropriate transmission    appropriate transmission
                                      rates.                      rates.
Spinning Reserve Service...........  $2.946 per kWmonth........  Prices consistent with      Varies.
                                                                  CAISO market.
Non-Spinning Reserve Service.......  $2.491 per kWmonth........  Prices consistent with      Varies.
                                                                  CAISO market.
Regulation and Frequency Response    $2.496 per kWmonth........  $2.57 per kWmonth.........  3%.
 Service.

[[Page 70512]]

 
Energy Imbalance Service...........  Within Limits of Deviation  Within Limits of Deviation  ...................
                                      Band: Accumulated           Band: There is no
                                      deviations are to be        financial charge for
                                      corrected or eliminated     deviations (energy)
                                      within 30 days. Any net     within the bandwidth.
                                      deviations that are
                                      accumulated at the end of
                                      the month (positive or
                                      negative) are to be
                                      exchanged in like hours
                                      of energy or charged at
                                      the composite rate then
                                      in effect for CVP firm
                                      power.
                                     Outside Limits of           Outside the Limits of the   ...................
                                      Deviation Band: Positive    Deviation Band: Positive
                                      Deviations                  Deviations
                                      (overdelivery)--the         (overdelivery)--for any
                                      greater of no charge, or    hourly average positive
                                      any additional cost         deviation, the amount of
                                      incurred. Negative          deviation outside the
                                      Deviations                  bandwidth is lost to the
                                      (underdelivery)--during     system. Negative
                                      on-peak hours the greater   Deviations
                                      of three times the          (underdelivery)--for any
                                      composite rate then in      hourly average negative
                                      effect for CVP firm power   deviation, the amount of
                                      or any additional cost      deviation outside the
                                      incurred. During off-peak   bandwidth is charged at
                                      hours the greater of the    the greater of 150
                                      composite rate then in      percent of market price
                                      effect for CVP firm power   or actual cost.
                                      or any additional cost
                                      incurred.
----------------------------------------------------------------------------------------------------------------

    This Rate Order also includes a change in the Revenue Adjustment 
Clause (RAC) for the existing CVP Firm Power Rate (CV-F10) that would 
allow Western to make lump-sum payments to Customers for their share of 
the fiscal year (FY) 2004 RAC credit, if applicable. The change also 
delays calculation of the October through December 2004 RAC until all 
unmet obligations under existing contracts associated with business 
that occurred prior to January 1, 2005, are resolved.
    By Delegation Order No. 00-037.00, effective December 6, 2001, the 
Secretary of Energy delegated: (1) The authority to develop power and 
transmission rates to Western's Administrator, (2) the authority to 
confirm, approve, and place such rates into effect on an interim basis 
to the Deputy Secretary of Energy, and (3) the authority to confirm, 
approve, and place into effect on a final basis to remand or to 
disapprove such rates to the Commission. Existing DOE procedures for 
public participation in power rate adjustments (10 CFR 903) were 
published on September 18, 1985.
    Under Delegation Order Nos. 00-037.00 and 00-001.00A, 10 CFR 903, 
and 18 CFR 300, I hereby confirm, approve, and place Rate Order No. 
WAPA-115, the CVP power, CVP ancillary services, CVP, COTP, and PACI 
transmission service formula rates into effect on an interim basis. The 
new Rate Schedules CV-F11, CPP-1, CV-T1, CV-TPT6, CV-NWT3, COTP-T1, 
PACI-T1, CV-RFS3, CV-EID3, CV-SPR3, and CV-SUR3 will be promptly 
submitted to the Commission for confirmation and approval on a final 
basis.

    Dated: November 18, 2004.
Kyle E. McSlarrow,
Deputy Secretary.

Order Confirming, Approving, and Placing the Central Valley Project 
Power Rates, the Central Valley Project, the California-Oregon 
Transmission Project, and the Pacific Alternating Current Intertie 
Transmission Rates and the Central Valley Project Ancillary Services 
Rates Into Effect on an Interim Basis, and Providing Information on the 
Path 15 Transmission Upgrade

    This rate was established in accordance with section 302 of the DOE 
Organization Act, (42 U.S.C. 7152). This Act transferred to and vested 
in the Secretary of Energy the power marketing functions of the 
Secretary of the Department of the Interior and the Bureau of 
Reclamation (Reclamation) under the Reclamation Act of 1902 (ch. 1093, 
32 Stat. 388), as amended and supplemented by subsequent laws, 
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.
    By Delegation Order No. 00-037.00, effective December 6, 2001, the 
Secretary of Energy delegated: (1) The authority to develop power and 
transmission rates to Western's Administrator, (2) the authority to 
confirm, approve, and place such rates into effect on an interim basis 
to the Deputy Secretary of Energy, and (3) the authority to confirm, 
approve, and place into effect on a final basis, to remand or to 
disapprove such rates to the Commission. Existing DOE procedures for 
public participation in power rate adjustments (10 CFR 903) were 
published on September 18, 1985.

Acronyms and Definitions

    As used in this Rate Order, the following acronyms and definitions 
apply:

1994 Power Marketing Plan: The 1994 CVP Power Marketing Plan (57 FR 
45782 and 58 FR 34579).
2004 Power Marketing Plan: The 2004 CVP Power Marketing Plan (64 FR 
34417) effective January 1, 2005.
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 
provider's transmission system in accordance with standard utility 
practice.
Base Resource: The Central Valley and Washoe Project power output and 
existing power purchase contracts extending beyond 2004, as determined 
by Western to be available for marketing, after meeting the 
requirements of Project Use and First Preference Customers, and any 
adjustments for maintenance, reserves, transformation losses, and 
certain ancillary services.
CAISO: The California Independent System Operator is a Commission-
regulated, State-chartered, nonprofit corporation, and the control area 
operator of most of California's transmission grid.
COI: The California-Oregon Intertie consists of three 500-kilovolt 
lines linking California and Oregon, the California-Oregon Transmission 
Project, and the Pacific Alternating Current Intertie. The Western

[[Page 70513]]

Electricity Coordinating Council establishes the seasonal transfer 
capability for the California-Oregon Intertie.
COI Rating Seasons: COI rating seasons are: summer, June through 
October; winter, November through March; and spring, April through May.
COTP: The California-Oregon Transmission Project. A 500-kilovolt 
transmission project in which Western has part ownership.
CPPA: The Calaveras Public Power Agency is a First Preference Customer 
located in Calaveras County, California.
CVP: The Central Valley Project is 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, California.
Capacity: The electric capability of a generator, transformer, 
transmission circuit, or other equipment expressed in kilowatts.
Capacity Rate: The rate which sets forth the charges for capacity. It 
is expressed in dollars per kWmonth.
Commission: The Federal Energy Regulatory Commission.
Component 1: Part of a formula rate which is used to recover the costs 
for a specific service or product.
Component 2: Any charges or credits associated with the creation, 
termination, or modification to any tariff, contract, or rate schedule 
accepted or approved by the Commission or other regulatory body that 
will be passed on to each appropriate Customer. The Commission or other 
regulatory body accepted or approved charges or credits apply to the 
service to which this rate methodology applies. When possible, Western 
will pass through directly to the appropriate Customer, the Commission 
or other regulatory body accepted or approved charges or credits in the 
same manner Western is charged or credited. If the Commission or other 
regulatory body accepted or approved charges or credits cannot be 
passed through directly to the appropriate Customer in the same manner 
Western is charged or credited, the charges or credits will be passed 
through using Component 1 of the applicable formula rate.
Component 3: Any charges or credits from the HCA applied to Western for 
providing this service that will be passed through directly to the 
appropriate Customer in the same manner Western is charged or credited, 
to the extent possible. If the HCA charges or credits cannot be passed 
through to the appropriate Customer in the same manner Western is 
charged or credited, the charges or credits will be passed through 
using Component 1 of the applicable formula rate.
Composite Rate: The rate for firm power that is the total annual 
revenue requirement for capacity and energy divided by the total annual 
energy sales. It is expressed in mills/kWh and used for comparison 
purposes.
Contract 2947A: Contract No. 14-06-200-2947A, as amended, is Western's 
contract with the Pacific Gas and Electric (PG&E), the Southern 
California Edison, and the San Diego Gas and Electric (SDG&E) companies 
for extra high-voltage transmission and exchange service.
Contract 2948A: Contract No. 14-06-200-2948A is the Integration 
Contract between PG&E and Western. The contract provides for 
integrating Western's resources with PG&E's and requires PG&E to serve 
the combined PG&E/Western load with the integrated resource. The 
contract also requires PG&E to provide wheeling of the power to Western 
Customers on PG&E's system.
Custom Product Power: Power purchased by Western to meet a Customer's 
load.
Customer: An entity with a contract that receives service from the 
Western's Sierra Nevada Customer Service Region (SNR).
DOE: United States Department of Energy.
DOE Order RA 6120.2: A DOE order outlining power marketing 
administration financial reporting and ratemaking procedures.
Energy Rate: The rate which sets forth the charges for energy. It is 
expressed in mills/kWh and applied to each kWh delivered to each 
Customer.
ETCs: Existing Transmission Contracts. Long-term contracts for CVP 
transmission between Western and other parties, including contracts 
that predate the Open Access Transmission Tariff (OATT) and point-to-
point transmission service under the OATT.
FERC: The Federal Energy Regulatory Commission (to be used when 
referencing Commission orders).
First Preference: A Customer or 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. 1173, 1191-
1192).
FRN: Federal Register notice.
FY: Fiscal Year. October 1 through September 30.
HCA: Host Control Area. The control area in which SNR has a contractual 
arrangement to operate as a Sub-Control Area.
kV: Kilovolt. The electrical unit of measure of electric potential that 
equals 1,000 volts.
kW: Kilowatt. The electrical unit of capacity that equals 1,000 watts.
kWh: Kilowatthour. The electrical unit of energy that equals 1,000 
watts in 1 hour.
kWmonth: Kilowattmonth. The electrical unit of the monthly amount of 
capacity.
Load: The amount of electric power or energy delivered or required at 
any specified point(s) on a transmission or distribution system.
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.
MW: Megawatt. The electrical unit of capacity that equals 1 million 
watts or 1,000 kilowatts.
NITS: Network Integrated Transmission Service.
O&M: Operation and maintenance.
OATT: Open Access Transmission Tariff.
PACI: Pacific Alternating Current Intertie. A 500-kV transmission 
project of which Western owns a portion of the facilities.
Path 15 Transmission Upgrade: A transmission project consisting of 
approximately 84 miles of new 500-kV transmission line in California's 
western San Joaquin Valley, starting at the existing Los Banos 
Substation near Los Banos in Merced County and extending generally 
south southeastward to the existing Gates Substation near Coalinga in 
Fresno County.
PG&E: The Pacific Gas and Electric Company.
Power: Capacity and energy.
Preference: The provisions of Reclamation Law which require Western to 
first make Federal power available to certain entities. For example, 
section 9(c) of the Reclamation Project Act of 1939 states 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 (43 
U.S.C. 485h(c)).
Provisional Rate: A rate which has been confirmed, approved, and placed 
into effect on an interim basis by the Deputy Secretary.

[[Page 70514]]

PRS: Power repayment study.
RAC: Revenue Adjustment Clause. A provision in the existing CVP firm 
power rate schedule (CV-F10) that compares actual net revenue to 
projected net revenue from the ratesetting PRS on an FY basis.
Rate Brochure: A document dated May 2004 explaining the rationale and 
background for the rates contained 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 under which Western markets 
power.
SCA: Sub-Control Area. Western's contract-based sub-control area within 
the Sacramento Municipal Utility District's control area.
SCC: The Sierra Conservation Center is a First Preference Customer 
located in Tuolumne County, California.
SNR: The Sierra Nevada Customer Service Region of Western.
TPPA: The Tuolumne Public Power Agency is a First Preference Customer 
located in Tuolumne County, California.
TPUD: The Trinity Public Utilities District is a First Preference 
Customer located in Trinity County, California.
Washoe Project: A Reclamation project located in the Lahontan Basin in 
west-central Nevada and east-central California.

Effective Date

    The new interim rates will take effect on January 1, 2005, and will 
remain in effect until September 30, 2009, pending approval by the 
Commission on a final basis.

Public Notice and Comment

    Western followed the Procedures for Public Participation in Power 
and Transmission Rate Adjustments and Extensions, 10 CFR 903, in 
developing these rates. The steps Western took to involve interested 
parties in the rate process were:
    1. The proposed rate adjustment process began April 25, 2003, when 
Western mailed a notice announcing an informal meeting to all SNR 
Customers and interested parties.
    2. Western held an informal meeting on May 14, 2003, in Folsom, 
California. At this informal meeting, Western explained the need for 
the rate adjustment, presented conceptual rate designs and 
methodologies, and answered questions. As a result of this meeting, 
Western received more than 180 comments and questions from interested 
parties. Western publicly posted these comments and questions with 
Western's responses on Western's Web site at http://www.wapa.gov/sn/initiatives/post2004/rates/ in August 2003.
    3. On May 7, 2004, Western mailed letters to all SNR Preference 
Customers and interested parties notifying them of the Proposed Rates 
Federal Register notice due to be published on or around May 13, 2004.
    4. A Federal Register notice published on May 12, 2004 (69 FR 
26370), announced the proposed rates for CVP, COTP, and PACI, began the 
public consultation and comment period, and announced the public 
information and public comment forums.
    5. On May 12, 2004, Western mailed letters to all SNR Preference 
Customers and interested parties transmitting the Federal Register 
notice (69 FR 26370) and reiterating the dates and locations of the 
public information and comment forums.
    6. On May 18, 2004, Western held a public information forum at the 
Folsom Community Center in Folsom, California. Western provided 
detailed explanations of the proposed rates for CVP, COTP, and PACI and 
a list of issues that could change the proposed rates. Western provided 
Rate brochures and informational (slide) handouts.
    7. On June 3, 2004, Western mailed letters to all SNR Preference 
Customers and interested parties transmitting the Web site address to 
obtain copies of the slides used during the public information forum 
and providing instructions on how to receive a copy of the Rate 
Brochure.
    8. As a result of the public information forum, several Customers 
requested meetings to ask clarifying questions of the proposed rates. 
Western met with the following Customers and/or their representatives 
on the dates indicated below. Notes from these meetings are included in 
the record.

Calaveras Public Power Agency, June 3, 2004
City of Shasta Lake, June 17, 2004
Northern California Power Agency (representing cities of Palo Alto, 
Roseville, Lodi, and Santa Clara (dba Silicon Valley Power), Port of 
Oakland, and Alameda Power and Telecom), June 3, 2004
Redding Electric, June 8, 2004 (via telephone) and June 16, 2004
Roseville Electric, June 1, 2004
Trinity Public Utility District, June 3, 2004
Tuolumne Public Power Agency, June 3, 2004
City of Santa Clara (dba Silicon Valley Power), July 30, 2004
Department of Energy (via telephone), August 10, 2004

    9. In addition to the above meetings, Western communicated 
clarifying information on the proposed rates with the following 
Customers. This information is included in the record.

Calpine Corporation, California
City of Palo Alto, California
City of Shasta Lake, California
Duncan, Weinberg, Genzer and Pembroke, PC, Washington, DC
East Contra Costa Irrigation District, California
Energy Security Analysis, Inc., Massachusetts
Lassen Municipal Utility District, California
Northern California Power Agency, California
Redding Electric, California
Roseville Electric, California
Sierra Conservation Center, California
Turlock Irrigation District, California

    10. On June 17, 2004, Western held a comment forum to give the 
public an opportunity to comment for the record. Eight individuals 
commented at this forum.
    11. On July 28, 2004, Western published a letter updating the 
revenue requirements for Component 1 of the proposed formula rates for 
regulation and frequency response and spinning and non-spinning reserve 
services. This letter was sent to all interested parties by mail and 
electronic mail. The letter was also posted on Western's Web site at 
http://www.wapa.gov/sn/initiatives/Post2004/rates/.
    12. Western received 27 comment letters during the consultation and 
comment period, which ended on August 10, 2004. All comments received 
prior to the close of the consultation and comment period have been 
considered in preparing this Rate Order. All written comments received 
are posted on Western's Web site at http://www.wapa.gov/sn/initiatives/
Post2004/rates/.

Comments

    Written comments were received from the following organizations:

Alameda Power and Telecom, California
Bella Vista Water District, California
Bay Area Municipal Transmission Group, California
Calaveras Public Power Agency, California
Calpine Corporation, California
City of Biggs, California
City of Gridley, California
City of Healdsburg, California
City of Lodi, California
City of Lompoc, California
City of Palo Alto, California

[[Page 70515]]

City of Santa Clara (dba Silicon Valley Power), California
City of Ukiah, California
Lassen Municipal Utility District, California
Modesto Irrigation District, California
Moffett Federal Airfield, California
NASA-Ames Research Center, California
Northern California Power Agency (representing the Turlock Irrigation 
District, the Bay Area Rapid Transit District, Placer County Water 
Agency, Truckee-Donner Public Utility District, the Lassen Public 
Utility District, the Plumas-Sierra Rural Electric Cooperative, the 
Port of Oakland, and the cities of Alameda, Biggs, Gridley, Lodi, 
Redding, Lompoc, Healdsburg, Ukiah, Palo Alto, and Roseville), 
California
Pittsburg Power Company, California
Plumas-Sierra Rural Electric Cooperative, California
Port of Oakland, California and Water Resources Pooling Authority 
(representing the Arvin-Edison Water Storage District, Banta-Carbona 
Irrigation District, Byron-Bethany Irrigation District, Cawelo Water 
District, Glenn-Colusa Irrigation District, James Irrigation District, 
Lower Tule River Irrigation District, Princeton-Codora-Glenn Irrigation 
District, Provident Irrigation District, Reclamation District 108, 
Santa Clara Valley Water District, Sonoma County Water Agency, West 
Stanislaus Irrigation District, Westlands Water District, and the West 
Side Irrigation District), California
Redding Electric, California
Roseville Electric, California
Sacramento Municipal Utility District, California
Trinity Public Utility District, California
Tuolumne Public Power Agency, California

    Representatives of the following organizations made oral comments:

Bay Area Municipal Transmission Group (consisting of the cities of 
Alameda Power and Telecom, Silicon Valley Power, and the City of Palo 
Alto), California
City of Palo Alto, California
City of Roseville, California
City of Santa Clara (dba Silicon Valley Power), California
Power and Water Resources Pooling Authority, California
Modesto Irrigation District, California
Redding Electric, California
Sacramento Municipal Utility District, California

Project Description

    Initially authorized by Congress in 1935, the CVP is a large water 
and power system that covers about one-third of the State of 
California. Legislation set the purposes of the 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 mitigation as a priority above power and added fish and 
wildlife enhancement as a priority equal to 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, 7 pumping facilities, 11 powerplants with a maximum operating 
capability of about 2,074 MW, about 852 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 Rivers and Harbors Act of 1937 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 Whiskeytown Dam and Spring Creek 
Powerplant were authorized as part of the Trinity River Division in 
1955 and allocated up to 25 percent of the resulting energy to Trinity 
County for use within Trinity County. The San Luis Unit authorized in 
1960, includes the B. F. Sisk San Luis Dam, San Luis Reservoir and 
William R. Gianelli Pump-Generating Plant, O'Neill Pump-Generating 
Plant, and Dos Amigos Pumping Plant. The Rivers and Harbors Act of 1962 
authorized the New Melones Project and allocated up to 25 percent of 
the resulting energy to Calaveras and Tuolumne counties for use within 
the counties.
    Western's SNR markets the surplus hydropower generation of the CVP 
and Washoe Project. Since 1967, under the terms of Contract 2948A with 
PG&E, CVP resources, along with other Western resources, have been 
integrated with PG&E resources. PG&E serves the combined PG&E/Western 
loads with the integrated resources.
    PG&E has informed Western that it plans to terminate Contract 2948A 
on December 31, 2004. In anticipation of this eventuality, Western has 
worked with its Customers to develop and implement the 2004 Power 
Marketing Plan. The 2004 Power Marketing Plan was published in the 
Federal Register, (64 FR 34417) on June 25, 1999. It established the 
criteria for marketing CVP and Washoe Project power output for a 20-
year period beginning on January 1, 2005, and ending on December 31, 
2024.
    The Base Resource is a fundamental component and the primary power 
product marketed through the 2004 Power Marketing Plan. Under previous 
marketing plans, Preference Customers received a fixed capacity and 
load factored energy allocation. Under the 2004 Power Marketing Plan, 
Preference Customers (other than First Preference) receive an allocated 
percentage of the Base Resource. The Base Resource is defined as the 
CVP and Washoe Project power output and any existing power purchase 
contracts extending beyond 2004, determined by Western to be available 
for marketing after meeting the requirements of project use and First 
Preference Customers, and any adjustments for maintenance, reserves, 
transformation losses, and certain ancillary services. In 2000, each 
CVP Customer (other than First Preference Customers) signed a contract 
with Western that specifies how Base Resource power will be made 
available under the 2004 Power Marketing Plan.
    In marketing Federal hydroelectric power generated from the CVP, 
Western currently has 77 Preference and 38 project use Customers 
serving the equivalent of the annual electrical needs of 790,000 
California households.
    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, (6) rural electric cooperatives, 
and (7) Native American tribes.
    According to the 2004 Power Marketing Plan, Western will market the 
Base Resource alone or in combination with custom products. One type of 
custom product is Custom Product Power, which is power supplied by 
Western to meet a Customer's load.
    In 1964, Congress authorized construction of the 500-kV Pacific

[[Page 70516]]

Northwest-Pacific Southwest Alternating Current Intertie. On July 31, 
1967, Reclamation (Western's predecessor), PG&E, the Southern 
California Edison Company, and SDG&E entered into Contract 2947A, an 
extra high-voltage transmission service and exchange agreement for the 
northern portion of the PACI. Under Contract 2947A, Western has a 400-
MW entitlement of transmission capacity on the PACI. Contract 2947A 
terminates on December 31, 2004. A replacement agreement for Contract 
2947A is being developed in a Commission process.
    The COTP is a jointly owned 342-mile, 500-kV transmission line that 
connects the Captain Jack Substation in southern Oregon to Tracy/Tesla 
Substation in central California. Operational since March 1993, COTP 
provides a third high-voltage intertie between the Pacific Northwest 
and California. COTP owners other than Western are non-Federal 
participants.

Power Repayment Study

    Western prepares a PRS each FY to determine if revenues will be 
sufficient to repay, within the required time, all costs assigned to 
the commercial power function. Repayment criteria are based on law, 
applicable policies including DOE Order RA 6120.2, and authorizing 
legislation.

Existing and Provisional Power Rates and Revenue Requirement

    The 2004 Power Marketing Plan does not offer the same type of power 
service that was available under the 1994 Power Marketing Plan. Under 
the 1994 Power Marketing Plan, each Customer was allocated a contract 
rate of delivery (an amount of capacity) with associated energy, and 
the Customer was allowed to use up to that amount of capacity in any 
hour. The total monthly energy was determined based on the Customer's 
load factor. Under the 2004 Power Marketing Plan, Base Resource and 
First Preference power is primarily CVP hydrogeneration available 
subject to water conditions and operating constraints.
    Under the 2004 Power Marketing Plan, the power revenue requirement 
for First Preference and Base Resource power includes O&M, purchased 
power for project use and First Preference Customer loads, interest 
expense, annual expenses (including any other statutorily required 
costs or charges), investment repayment for the CVP, and the Washoe 
Project annual power revenue requirement that remains after project use 
loads are met. Revenues from project use, transmission, ancillary 
services, and other services are applied to the total power revenue 
requirement, and the remainder is collected from Base Resource and 
First Preference Customers.
    The Base Resource and First Preference power provisional formula 
rates recover a power revenue requirement through percentages for First 
Preference and Base Resource Customers. Base Resource Customer 
percentages were established through the public process for the 2004 
Power Marketing Plan. The First Preference Customers' percentages to be 
used for billing purposes were developed as part of this rate process.
    Under the 2004 Power Marketing Plan, a Customer's load can be met 
through First Preference, Base Resource, and/or Custom Product Power. 
Custom Product Power may include long- and short-term purchases at 
various rates. The existing rates do not have a parallel service. All 
costs associated with Custom Product Power will be recovered through a 
formula rate that passes through the cost of the purchase to a specific 
Customer(s). Such costs could include Western's scheduling costs and 
Components 2 and 3, as well as the cost of the power. A further 
discussion of the power revenue requirement and Custom Product Power is 
provided in the power revenue requirement discussion section later in 
this document.

                  Comparison of Existing Rates and Provisional Formula Rates for Western Power
----------------------------------------------------------------------------------------------------------------
                                                               Provisional formula
           Power service                  Existing rate               rate                  Percent change
----------------------------------------------------------------------------------------------------------------
Contract Rate of Delivery..........  30.83 mills/kWh.......  N/A...................  N/A.
Base Resource and First Preference.  N/A...................  Percent of Annual       N/A.
                                                              Power Revenue
                                                              Requirement.
Custom Product Power...............  N/A...................  Pass Through..........  N/A.
----------------------------------------------------------------------------------------------------------------

Cost-of-Service Study

    Western prepared a detailed cost-of-service study to determine the 
revenue requirement that will be recovered through the CVP regulation 
and frequency response service formula rate and the CVP, COTP, and PACI 
transmission service formula rates. This combined cost-of-service study 
integrates all three transmission systems. Each CVP, COTP, and PACI 
facility was researched in order to determine its functional use. The 
costs for CVP, COTP, and PACI facilities that support the transfer 
capability of the transmission system (excluding generation ties and 
radial lines) are included in the respective transmission system's 
revenue requirement; whereas, the cost for facilities that support the 
generation capability of the CVP system (including generation ties and 
radial lines) are included in the CVP generation revenue requirement 
and are used in the regulation and frequency response service revenue 
requirement. The costs associated with the CVP are allocated to the 
transmission and generation functions, based on a ratio of transmission 
or generation plant to total plant.
    Western is using this study because it is more consistent with the 
methodology used in other Western regions. The costs allocated through 
the cost-of-service study include O&M, interest, and depreciation 
expenses. The cost-of-service study contains forecasted O&M and 
historical financial information, which is also in the PRS. Western's 
costs for scheduling, system control and dispatch service, and reactive 
supply and voltage control from generation sources service associated 
with the CVP, COTP, and PACI transmission service are included in and 
recovered through the respective transmission system's revenue 
requirement.

CVP Transmission

    The provisional formula rate for CVP firm and non-firm transmission 
service results in an estimated monthly rate of $1.03 per kWmonth for 
January through September 2005. The provisional formula rate for CVP 
transmission includes three components:
Component 1:
[GRAPHIC] [TIFF OMITTED] TN06DE04.000

Where:
    TRR = Transmission revenue requirement.
    TTc = Total transmission capacity under ETCs.

[[Page 70517]]

    NITSc = Average of 12-month coincident peaks of NITS Customers at 
the time of the monthly CVP transmission system peak. For rate design 
purposes, Western's use of the transmission system to meet its 
statutory obligations is treated as NITS.

    This formula rate also contains Components 2 and 3.
    The cost-of-service study determines the revenue requirement for 
Component 1 of this service. The rates from Component 1 of the 
provisional formula rate may be discounted for short-term sales. The 
estimated rates from the provisional formula rate are subject to change 
prior to the rate taking effect.

CVP NITS

    The estimated monthly revenue requirement for NITS effective 
January 1, 2005, is $1,021,712. The provisional formula rate for CVP 
NITS includes three components:
Component 1:
NITS Customer's monthly costs = NITS Customer's load ratio share times 
one-twelfth of the annual network TRR.

Where:
    NITS Customer's load ratio share = The NITS Customer's hourly load 
(including behind the meter generation minus the NITS Customer's hourly 
Base Resource) coincident with the monthly CVP transmission system peak 
minus the coincident peak for all firm CVP (including reserved 
transmission capacity) transmission service, expressed as a ratio.
    Annual network TRR = Total CVP transmission revenue requirement 
less ETC revenues.

    This formula rate also contains Components 2 and 3.
    The cost-of-service study determines the revenue requirement for 
Component 1 of this service. The provisional formula rate for CVP NITS 
is based on the same revenue requirement that is used in the CVP firm 
and non-firm transmission formula rate. The NITS estimated monthly 
revenue requirement is subject to change prior to the rates taking 
effect.

COTP Transmission

    The provisional formula rate results in estimated monthly rates for 
COTP firm and non-firm point-to-point transmission service of $1.87 per 
kWmonth for spring and summer and $1.88 per kWmonth for winter. The 
provisional formula rate for COTP firm and non-firm point-to-point 
transmission service consists of three components.
Component 1:
[GRAPHIC] [TIFF OMITTED] TN06DE04.001

    Component 1 is the ratio of the COTP seasonal transmission revenue 
requirement to Western's share of the COTP seasonal capacity (subject 
to curtailment). Western will update the rate resulting from Component 
1 at least 15 days before the start of each COI rating season.
    This formula rate also contains Components 2 and 3.
    The cost-of-service study determines the revenue requirement for 
Component 1 of this service. The COTP cost-of-service study identifies 
the costs associated with the facilities that support the transfer 
capability of the COTP transmission system only. The amount of COTP 
capacity used in Component 1 of the formula rate will change with the 
seasonal transfer capability of the COI. The rates from Component 1 of 
the provisional formula rate may be discounted for short-term sales. 
The estimated rates from the provisional formula rate are subject to 
change prior to the rate taking effect.

PACI Transmission

    PACI firm and non-firm transmission services are new services. The 
estimated rates from the formula rate for PACI firm and non-firm point-
to-point transmission are $0.45 per kWmonth for spring, summer, and 
winter. The provisional formula rate for PACI firm and non-firm point-
to-point transmission service consists of three components.
Component 1:
[GRAPHIC] [TIFF OMITTED] TN06DE04.002

    Component 1 is the ratio of the PACI seasonal transmission revenue 
requirement to Western's share of the PACI seasonal capacity (subject 
to curtailment). Western will update the rate resulting from Component 
1 at least 15 days before the start of each COI rating season.
    This formula rate also contains Components 2 and 3.
    The cost-of-service study determines the revenue requirement for 
Component 1 of this service. The PACI cost-of-service study identifies 
the costs associated with the facilities that support the transfer 
capability of the PACI transmission system. There are no existing rates 
for PACI transmission since it is currently covered under an existing 
contract. The amount of PACI capacity used in Component 1 of the 
formula rate will change with the seasonal transfer capability of the 
COI. The rates resulting from Component 1 of the provisional formula 
rate may be discounted for short-term sales. The estimated rates from 
the provisional formula rate are subject to change prior to the rate 
taking effect.

Third-Party Transmission

    The provisional formula rate for third-party transmission includes 
three components. The first component is equivalent to the existing 
formula rate and allows for Western to pass through costs it incurs for 
using a third party's transmission system. The provisional formula rate 
also contains Components 2 and 3.

Path 15 Transmission Upgrade

    Western is constructing the Path 15 Transmission Upgrade in 
conjunction with PG&E and Trans-Elect, Inc. Western will turn over 
operational control of its rights in the Path 15 Transmission Upgrade 
to the CAISO. Recovery of the transmission revenue requirement will be 
through the CAISO tariff and rates.

Existing and Provisional Transmission Rates

    A comparison of the existing rates and the estimated rates from the 
provisional

[[Page 70518]]

formula rates for CVP, COTP, and PACI transmission service follows:

 Comparison of Existing and Estimated Rates From the Provisional Formula Rates CVP, COTP, and PACI Transmission
                                                     Service
----------------------------------------------------------------------------------------------------------------
                                                                   Estimated rates from the
                                      Existing rates (Note 1)     provisional formula rates      Percent change
                                                                      (effective 1/1/05)
----------------------------------------------------------------------------------------------------------------
CVP Firm Transmission Rate ($/      $0.57                       $1.03                          81
 kWmonth).
CVP Non-Firm Transmission Rate      1.00                        1.40                           40
 (mills/kWh).
CVP NITS Monthly Revenue            N/A                         $1,021,712                     N/A
 Requirement.
Third-Party Transmission Rate.....  Pass Through                Pass Through                   N/A
COTP Firm Transmission Rate ($/
 kWmonth):
    Spring........................  $0.73                       $1.87                          156
    Summer........................  $0.53                       $1.87                          253
    Winter........................  $0.66                       $1.88                          185
COTP Non-Firm Transmission Rate
 (mills/kWh):
    Spring........................  1.00                        2.55                           155
    Summer........................  0.72                        2.54                           253
    Winter........................  0.91                        2.59                           185
PACI Firm Transmission Rate ($/
 kWmonth):
    Spring........................  N/A                         $0.45                          N/A
    Summer........................  N/A                         $0.45                          N/A
    Winter........................  N/A                         $0.45                          N/A
PACI Non-Firm Transmission Rate
 (mills/kWh):
    Spring........................  N/A                         0.61                           N/A
    Summer........................  N/A                         0.61                           N/A
    Winter........................  N/A                         0.62                           N/A
Path 15 Transmission Upgrade......  N/A                         Per CAISO Tariff               N/A
----------------------------------------------------------------------------------------------------------------
Note 1: NITS service not provided prior to 1/1/05.

    The estimated rates from the provisional formula rates are the same 
but are shown here as monthly and hourly rates for comparison to the 
existing firm and non-firm transmission rates. The increase in CVP 
transmission rates from the existing rate is primarily due to an 
increase in O&M costs and a change in Western's use of the CVP 
transmission system under the 2004 Power Marketing Plan. The increase 
in COTP transmission rates is primarily due to a decrease in Western's 
COTP capacity available for sale. The decrease in capacity occurs 
because of increased usage by DOE of a statutory entitlement at a rate 
which recovers only O&M costs.

Cost-of-Service Study--Ancillary Services

    Six ancillary services will be offered by Western. The costs for 
two of these ancillary services: (1) Scheduling, system control and 
dispatch and (2) reactive supply and voltage control service from 
generation sources, are included in the CVP, COTP, and PACI 
transmission revenue requirements. The remaining four ancillary 
services are (3) spinning reserve service, (4) non-spinning reserve 
service, (5) regulation and frequency response service, and (6) energy 
imbalance service.
    Western used the cost-of-service study to set a revenue requirement 
for Component 1 of the regulation and frequency response service. The 
provisional formula rate for this service is designed to recover only 
the costs associated with providing the service. The revenue 
requirement for regulation and frequency response service includes the 
CVP generation costs associated with providing the service and the non-
facility costs allocated to the service, as well as the cost of energy, 
capacity, or foregone generation that support regulation and frequency 
response service. This formula rate also contains Components 2 and 3.
    Spinning and non-spinning reserves will be sold at prices 
consistent with the CAISO market plus all costs incurred as a result of 
the sale, such as Western's scheduling costs and Components 2 and 3.

Existing Rates and the Provisional Ancillary Service Rates

    A comparison of the existing rates and the estimated rates under 
the provisional formula rates for ancillary services follows:

      Comparison of Existing and Estimated Rates from the Provisional Formula Rates CVP Ancillary Services
----------------------------------------------------------------------------------------------------------------
                                                                  Estimated rate under the
       Ancillary service type              Existing rates         provisional formula rates         Change
----------------------------------------------------------------------------------------------------------------
Scheduling and System Control and    Included in the             Included in the             N/A
 Dispatch Service.                    appropriate transmission    appropriate transmission
                                      rates.                      rates.
Reactive Supply Voltage Control      Included in the             Included in the             N/A
 Service.                             appropriate transmission    appropriate transmission
                                      rates.                      rates.
Spinning Reserve Service...........  $2.946 per kWmonth........  Prices consistent with      Varies
                                                                  CAISO market.
Non-Spinning Reserve Service.......  $2.491 per kWmonth........  Prices consistent with      Varies
                                                                  CAISO market.
Regulation and Frequency Response    $2.496 per kWmonth........  $2.57 per kWmonth.........  3%
 Service.

[[Page 70519]]

 
Energy Imbalance Service...........  Within Limits of Deviation  Within Limits of Deviation  ...................
                                      Band: Accumulated           Band: There is no
                                      deviations are to be        financial charge for
                                      corrected or eliminated     deviations (energy)
                                      within 30 days. Any net     within the bandwidth.
                                      deviations that are
                                      accumulated at the end of
                                      the month (positive or
                                      negative) are to be
                                      exchanged in like hours
                                      of energy or charged at
                                      the composite rate then
                                      in effect for CVP firm
                                      power.
                                     Outside Limits of           Outside the Limits of the   ...................
                                      Deviation Band: Positive    Deviation Band: Positive
                                      Deviations                  Deviations
                                      (overdelivery)--the         (overdelivery)--for any
                                      greater of no charge, or    hourly average positive
                                      any additional cost         deviation, the amount of
                                      incurred. Negative          deviation outside the
                                      Deviations                  bandwidth (MWh) is lost
                                      (underdelivery)--during     to the system. Negative
                                      on-peak hours the greater   Deviations
                                      of three times the          (underdelivery)--for any
                                      composite rate then in      hourly average negative
                                      effect for CVP firm power   deviation, the amount of
                                      or any additional cost      deviation outside the
                                      incurred. During off-peak   bandwidth (MWh) is
                                      hours the greater of the    charged at the greater of
                                      composite rate then in      150 percent of market
                                      effect for CVP firm power   price or actual cost.
                                      or any additional cost
                                      incurred.
----------------------------------------------------------------------------------------------------------------

Certification of Rates

    Western's Administrator certified that the provisional formula 
rates for First Preference, Base Resource, Custom Product Power, CVP, 
COTP, and PACI transmission and CVP ancillary services are the lowest 
possible rates consistent with sound business principles. The 
provisional formula rates were developed following administrative 
policies and applicable laws.

Power Revenue Requirement Discussion

    According to Reclamation Law, Western must establish rates 
sufficient to recover O&M, purchased power expenses, other annual 
expenses, interest expenses, and repayment of power investment and 
irrigation aid.
    The power revenue requirement for Base Resource and First 
Preference power includes the following expenses: annual investment 
repayment, purchases to firm the Base Resource and First Preference 
power deliveries for up to 2 hours, power purchased for project use and 
First Preference Customers, interest expense, O&M expense allocated to 
power, and the Washoe Project annual power revenue requirement that 
remains after project use loads are met. Revenues from project use, 
transmission, ancillary services, and other services are applied to the 
total power revenue requirement, and the remainder is collected from 
Base Resource and First Preference Customers. The power revenue 
requirement includes Components 2 and 3.

Statement of Revenue and Related Expenses

    The following table provides a summary of projected revenue and 
expense data from the PRS through the 4\3/4\-year provisional rate 
approval period. The table includes a comparison of existing rate data 
to provisional rate data and the difference.

        PRS Comparison of 4\3/4\ Year Rate Period (Jan 1, 2005-Sep 30, 2009), Total Revenues and Expenses
----------------------------------------------------------------------------------------------------------------
                                                                         Provisional
                                           Existing rate  (Note 1)         revenue
                                                    ($000)               requirement       Difference  ($000)
                                                                           ($000)
----------------------------------------------------------------------------------------------------------------
Total Revenues........................  N/A                                  $812,165  N/A
Revenue Distribution Annual Expenses:
    O&M...............................  N/A                                   343,555  N/A
    Purchased Power...................  N/A                                   244,063  N/A
    Interest..........................  N/A                                    30,786  N/A
  Other...............................  N/A                                   139,315  N/A
    Total Annual Expenses.............  N/A                                   757,719  N/A
Annual Principal Payments:
    Capitalized Expenses..............  N/A                                         0  N/A
    Original Project and Additions....  N/A                                    41,050  N/A
    Replacements......................  N/A                                    13,396  N/A
    Irrigation Aid....................  N/A                                         0  N/A
      Total Principal Payments........  N/A                                    54,446  N/A
      Total Revenue Distribution......  N/A                                   812,165  N/A
----------------------------------------------------------------------------------------------------------------
Note 1: The 2004 Power Marketing Plan does not offer the same type of power service that is available under the
  1994 Power Marketing Plan; hence, the existing rates could not be used under the 2004 Power Marketing Plan.

    Western will develop the power revenue requirement for First 
Preference and Base Resource power prior to the start of each FY. The 
power revenue requirement for the April through September period will 
be reviewed in March of each year (except March 2005). The review will 
analyze financial data from the October through February

[[Page 70520]]

period, to the extent information is available, as well as forecasted 
data for the March through September period. If there is a change of $5 
million or more, the power revenue requirement for the April through 
September period will be recalculated. A monthly power revenue 
requirement will be calculated by dividing each 6-month power revenue 
requirement by six. For the January through September 2005 period, a 
power revenue requirement will be calculated for a 9-month period 
instead of a year.

Provisional Formula Rate for First Preference Power

    To have a consistent billing process for Base Resource and First 
Preference Customers, a percentage will be developed for each First 
Preference Customer before the start of each FY based on the following 
formula:
[GRAPHIC] [TIFF OMITTED] TN06DE04.003

Where:
    FP Customer Load = A First Preference Customer's forecasted annual 
load (MWh).
    Gen = The forecasted annual CVP and Washoe Project generation 
(MWh).
    Power Purchases = Forecasted power purchase for project use and 
First Preference loads (MWh).
    Project Use = The forecasted annual project use load (MWh).

    For January through September 2005, the same formula will be used 
with data for the 9-month period instead of annual data.
    During March of each year (except March 2005), each First 
Preference Customer's percentage will be reviewed by Western. The 
review will take into account the actual and estimated current FY data 
used in the First Preference Customer's percentage formula. If 
Western's review results in a change in a First Preference Customer's 
percentage of more than one-half of 1 percent, the percentage will be 
revised for that First Preference Customer for the remainder of the 
current FY. The review will not occur in March 2005 because the 2004 
Power Marketing Plan will have been in effect for a very short period 
of time.
    Each First Preference Customer's monthly charges are determined by 
the following formula:

First Preference Customer's monthly costs = 6-month power revenue 
requirement divided by six, times the First Preference Customer's 
percentage.

    Starting with FY 2006, the First Preference Customers' share of the 
annual power revenue requirement is divided into two 6-month revenue 
requirements. The first 6-month revenue requirement will be collected 
from October through March and the second 6-month revenue requirement 
will be collected from April through September. The estimated April 
through September power revenue requirement will be reviewed by Western 
in March (with the exception of March 2005). Western's review will 
analyze financial data relating to the power revenue requirement for 
October through February, to the extent it is available, as well as 
forecasted data for March through September. If, as a result of 
Western's review, the power revenue requirement changes by $5 million 
or more, the April through September power revenue requirement will be 
revised.
    The power revenue requirement for January through September 2005 
will be divided by nine to determine a monthly power revenue 
requirement. Each First Preference Customer's percentage will be 
applied to the monthly power revenue requirement to determine each 
First Preference Customer's monthly costs. The estimated power revenue 
requirement for January through September 2005 is $30 million. The 
estimated First Preference Customers' revenue requirement for January 
through September 2005 is $1,110,000 (sum of all First Preference 
Customers' estimated percentages of 3.7 percent multiplied by the power 
revenue requirement for January through September 2005 of $30 million). 
The estimated power revenue requirement and First Preference Customers' 
percentages are subject to change prior to the rates taking effect.

Provisional Formula Rate for Base Resource

Base Resource Customer's monthly cost = Base Resource Customer's 
percentage times the Base Resource monthly revenue requirement.

    A Customer's Base Resource percentage may be adjusted as provided 
for in the contract; e.g., participation in the exchange program. After 
the First Preference Customers' share of the annual power revenue 
requirement has been determined, the remainder of the annual power 
revenue requirement is recovered from the Base Resource Customers. The 
Base Resource revenue requirement will be collected in two 6-month 
periods. For October through March, 25 percent of the Base Resource 
revenue requirement will be collected. For April through September, 75 
percent of the Base Resource revenue requirement will be collected. 
Allocating the Base Resource revenue requirement in this manner aligns 
the base resource revenue requirement with the Base Resource 
availability during the two 6-month periods. CVP generation is greater 
in the April through September period than the October through March 
period. The shifting of the Base Resource revenue requirement will help 
minimize monthly per unit cost variations for the Customers.
    A Base Resource monthly revenue requirement is calculated by 
dividing the Base Resource estimated 6-month revenue requirement by 
six. A Customer's Base Resource costs are independent of the Base 
Resource received. Base Resource energy not used by any Preference 
Customer will be sold, if possible, and the revenues will reduce the 
Base Resource revenue requirement. The revenues from the sale of 
surplus Base Resource will be applied to the estimated annual Base 
Resource revenue requirement for the following FY.
    The estimated power revenue requirement for January through 
September 2005 is $30 million and the estimated First Preference 
Customers' revenue requirement is $1,110,000; therefore, the estimated 
Base Resource revenue requirement is $28,890,000. The Base Resource 
revenue requirement will be allocated 25 percent to the 3-month period 
from January through March 2005 and 75 percent to the 6-month period, 
April through September 2005. For January through March 2005, the 
estimated Base Resource revenue requirement is $2,407,500 per month. 
For April through September 2005, the estimated Base Resource revenue 
requirement is $3,611,250 per month. The estimated Base Resource 
revenue requirement for January through September 2005 may change prior 
to the rate taking effect.

[[Page 70521]]

Provisional Formula Rate for Custom Product Power

    All costs associated with Custom Product Power will be recovered 
using a formula rate that passes through all costs of the purchase to a 
specific Customer(s). Such costs could include Western's scheduling 
costs and Components 2 and 3, as well as the cost of the power. Under 
the 2004 Power Marketing Plan, Custom Product Power is power supplied 
by Western to meet a Customer's load. Western may make Custom Product 
Power purchases for a group of Customers or for an individual Customer. 
Costs for Custom Product Power purchases that are funded in advance by 
the Customer(s) will be passed through to that Customer(s) based on the 
power forecasted to the Customer(s). Unless otherwise agreed to by 
Western, Custom Product Power funded in advance that is surplus to the 
load requirements of the Customer(s) will be sold. If the Customer(s) 
fails to have an account available to receive the proceeds from the 
sale of surplus Custom Product Power, the proceeds are forfeited to 
Western and will be applied to the Custom Product Power purchase cost 
for the Customer(s).
    If the Custom Product Power purchase is funded through 
appropriations, Federal reimbursable, or use of receipts authority, the 
cost of the Custom Product Power is passed through to the Customer(s) 
that have that power in their final schedules. Custom Product Power 
funded through appropriations, Federal reimbursable authority, or use 
of receipts authority that is surplus to the load of the Customer(s) 
will be sold. Proceeds from the sale of surplus Custom Product Power 
funded through use of receipts authority, Federal reimbursable 
authority, or appropriations will be applied to the Custom Product 
Power purchase cost for the Customer(s).

Change in RAC in Existing CVP Firm Power Rate Schedule CV-F10

    Western is changing the RAC for FY 2004. Under the existing CVP 
Firm Power Rate Schedule CV-F10, a RAC credit for FY 2004 would be 
applied in equal amounts to the nine power bills issued by Western from 
January through September 2005. Western is changing the RAC to allow 
Western to make lump-sum payments to Customers for their share of the 
FY 2004 RAC credit, as opposed to issuing credits in equal amounts to 
the power bills issued from January through September 2005. This change 
in the RAC will allow Western more flexibility as it moves to the 2004 
Power Marketing Plan. This change will not affect the calculation of 
the FY 2004 RAC or the determination of each Customer's share of the FY 
2004 RAC.
    For the October to December 2004 RAC, Western is changing the 
existing process of calculating the RAC and applying the resulting RAC 
credit or surcharge to the power bills issued from April through 
September 2005. Western will delay calculation of the October through 
December 2004 RAC so that any outstanding project use true-ups and any 
unmet obligations under existing contracts associated with business 
that occurred prior to January 1, 2005, can be included in the October 
through December 2004 RAC. Once this data is available, Western will 
calculate the October through December 2004 RAC using the existing 
methodology. This will likely delay the October through December 2004 
RAC until sometime in FY 2006. The resulting RAC credit or surcharge 
will be allocated among the power Customers taking firm power during 
October through December 2004 under the existing methodology. Western 
will initiate distribution of the RAC credit or surcharge within 60 
days of completing the RAC calculation. If the result was a RAC credit, 
at Western's discretion, Western will either credit the Customers' 
power bills to the extent possible, or Western will make a lump-sum 
payment to the Customers for their share of the RAC. If the result is a 
RAC surcharge, at Western's discretion, Western could collect the 
payment in equal installments over 9 months or as a lump sum.

Comments

    The comments and responses regarding changes in RAC procedure for 
CV-F10 and First Preference, Base Resource, and Custom Product Power 
formula rates, paraphrased for brevity when not affecting the meaning 
of the statement(s), are discussed below. Direct quotes from comment 
letters are used for clarification where necessary.
    A. Comment: Some of the First Preference Customers expressed 
concern that during several consecutive drought years, they would be 
paying for all of Western's costs that would normally be covered by 
revenues from the Base Resource. These Customers suggested an 
alternative methodology that affected both the First Preference and 
Base Resource Customers. The suggestion charged the First Preference 
Customers based on a percentage of repayment obligation as opposed to 
the receipt of energy or Base Resource percentage. Western could base 
the percentage of repayment obligation on some sort of average; e.g., 
long-term average, 5-year rolling average, or a single average water 
year.
    Response: Western considered these comments, reviewed the 
alternatives presented by the Customers, and evaluated several other 
scenarios that might mitigate the financial impacts experienced by the 
First Preference Customers. Western's analysis determined that the 
financial impacts experienced by the First Preference Customers are 
similar to those experienced by the Base Resource Customers. According 
to this analysis, the First Preference Customers do not pay a larger 
per unit cost. As a means of mitigating the First Preference Customers' 
concerns, Western reviewed estimated First Preference percentages in 
different hydrological years. As a result of this review, Western has 
determined a maximum percentage for each First Preference Customer: SCC 
1.39 percent, CPPA 3.49 percent, TPUD 9.21 percent, and TPPA 3.42 
percent. The maximum percentages were determined based on a critically 
dry year where there are hydrologic conditions that result in low CVP 
generation and, consequently, low levels of Base Resource. These 
maximum percentages are not used in instances where individual First 
Preference Customer percentages increase due to load growth. If a 
maximum percentage is used for determining a First Preference 
Customer's costs for more than 1 year, then Western will evaluate that 
First Preference Customer's percentage resulting from the formula rate 
versus the maximum percentage and make adjustments as appropriate.
    B. Comment: A First Preference Customer requested that Western 
consider converting its monthly fixed payment obligation to a per kWh 
rate with periodic adjustments. This conversion would better parallel 
its cash flow from its retail Customers.
    Response: While Western understands the complexity of managing cash 
flow with a variable power product, as is provided through the 2004 
Power Marketing Plan, Western intends to provide the Customer with 
sufficient information to calculate a per unit rate. Changing to a 
billing method using per unit cost versus a fixed payment obligation 
would not change the First Preference Customer's share of Western power 
costs. As stated earlier, Western will review the power revenue 
requirement every 6 months. The power revenue requirement will be 
changed in March only if it exceeds the $5 million threshold. As part 
of the record for the rate case, Western has provided estimated annual 
power revenue

[[Page 70522]]

requirements for January through September 2005 and FY 2006 through 
2009. Western has provided estimated percentages for all First 
Preference Customers for January through September 2005 and for FY 2006 
so that the First Preference Customers could use that data in 
developing their future budgets.
    C. Comment: Several Customers expressed concern regarding the 
disposition of proceeds from the sale of surplus Custom Product Power. 
The proposed formula rate for Custom Product Power indicated that the 
proceeds are forfeited to Western if a Customer fails to have an 
account available to receive the proceeds from such a sale. The 
Customers requested that Western change this language to allow for the 
proceeds to be applied to future Custom Product Power purchases on 
behalf of the Customer(s).
    Response: If Western receives the proceeds from the sale of surplus 
Custom Product Power, they will be applied to the current Custom 
Product Power cost for the Customer(s). Under its trust authority, 
Western cannot use these proceeds to fund future Custom Product Power 
purchases.
    D. Comment: A Customer indicated its support of Western's intention 
to better align the Base Resource monthly revenue requirement with CVP 
generation. The Customer thought this procedure would help reduce 
monthly per unit cost variations for Western's Customers.
    Response: Western notes the comment.
    E. Comment: A Customer ``applaud[ed] Western's efforts to 
separately track any costs associated with supplemental or custom 
products to ensure no cost shifting occurs with the Base Resource.''
    Response: Western notes the comment.

Provisional Formula Rate for CVP Firm and Non-Firm Transmission

    The provisional formula rate for CVP firm and non-firm transmission 
includes three components:
Component 1
[GRAPHIC] [TIFF OMITTED] TN06DE04.004

Where:
    TTc = Total transmission capacity under ETCs.
    NITSc = Average of 12-month coincident peaks of NITS Customers at 
the time of the monthly CVP transmission system peak. For rate design 
purposes, Western's use of the transmission system to meet its 
statutory obligations is treated as NITS.

    This provisional formula rate also contains Components 2 and 3.
    The rate from Component 1 will be used for CVP firm and non-firm 
transmission service. Western will revise the rate resulting from 
Component 1 of the provisional formula rate based on either of the 
following two conditions: (a) Updated financial data available in March 
of each year, and (b) a change in the numerator or denominator that 
results in a rate change of at least $0.05 per kWmonth. The estimated 
monthly rate resulting from Component 1 of the provisional formula rate 
for January through September 2005 has increased from $0.93 per kWmonth 
to $1.03 per kWmonth. The increase is primarily due to a correction in 
the classification of Western's rights on a third party's transmission 
system for CVP generation. The $1.03 per kWmonth rate is an 81 percent 
increase from the existing rate of $0.57 per kWmonth.
    The estimated hourly rate from Component 1 of the provisional 
formula rate for CVP transmission service for January through September 
2005 has increased from 1.30 mills/kWh to 1.40 mills/kWh for the same 
reason stated above. The 1.40 mills/kWh is a 40 percent increase from 
the existing CVP non-firm transmission service rate of 1.00 mill/kWh. 
The percentage increase for the estimated hourly rates is smaller than 
the percentage increase for estimated monthly rates because the 
existing CVP non-firm transmission rate was rounded up to 1.00 mill/
kWh. The increase in CVP transmission rates from the existing rate is 
primarily due to an increase in O&M costs and a change in Western's use 
of the CVP transmission system under the 2004 Power Marketing Plan. 
Under the 1994 Power Marketing Plan, Western was reserving transmission 
capacity based on the maximum output of directly connected CVP 
generating plants under normal operating conditions. Under the 2004 
Power Marketing Plan, Western's use of the CVP transmission system to 
meet its statutory obligations is treated as NITS for rate design 
purposes. The rates from Component 1 of the provisional formula rate 
may be discounted for short-term sales. The estimated rates from the 
provisional formula rate are subject to change prior to the rate taking 
effect.
    The provisional formula rate for CVP transmission service is based 
on a revenue requirement that recovers: (1) The CVP transmission system 
costs for facilities associated with providing transmission service, 
(2) the non-facility costs allocated to transmission service, (3) CVP 
generation costs for providing reactive supply and voltage control from 
generation sources, (4) Component 2, (5) Component 3, (6) any other 
statutorily required costs or charges, and (7) any other costs 
associated with transmission service, including uncollectible debt. 
Revenues from the sales of short-term transmission will offset the 
transmission revenue requirement.
    Component 1 of the provisional formula rate includes Western's cost 
for transmission scheduling, system control and dispatch service, and 
reactive supply and voltage control from generation sources service 
associated with the transmission service. The provisional formula rate 
applies to ETCs.

Provisional Formula Rate for CVP NITS

    The provisional formula rate for CVP NITS includes three 
components:
Component 1:
NITS Customer's monthly demand charge = NITS Customer's load ratio 
share times one-twelfth (\1/12\) of the annual network TRR.

Where:
    NITS Customer's load ratio share = The NITS Customer's hourly load 
(including behind the meter generation minus the NITS Customer's hourly 
Base Resource) coincident with the monthly CVP transmission system peak 
minus the coincident peak for all firm CVP (including reserved 
transmission capacity) transmission service, expressed as a ratio.
    Annual network TRR = Total CVP transmission revenue requirement 
less ETC revenues.

    The Annual Network TRR will be revised when the rate from Component 
1 of the CVP transmission rate under Rate Schedule CV-T1 is revised. 
This provisional formula rate also contains Components 2 and 3.
    The provisional formula rate for CVP NITS is based on a revenue 
requirement that recovers: (1) The CVP transmission system costs for 
facilities associated with providing transmission service, (2) the non-
facility costs allocated to transmission service, (3) CVP generation 
costs for providing reactive supply and voltage control from generation 
sources, (4) Component 2, (5) Component 3, (6) any other statutorily 
required costs or charges, and (7) any other costs associated with 
transmission service, including uncollectible debt. For January through 
September 2005, the estimated NITS monthly revenue requirement is 
$1,021,712. The

[[Page 70523]]

estimated monthly revenue requirement resulting from the provisional 
formula rate has increased to $1,021,712 from the estimated monthly 
revenue requirement in the proposed rates of $926,316. The increase is 
primarily due to a correction in the classification of Western's rights 
on a third party's transmission system for CVP generation. NITS was not 
provided prior to January 1, 2005, so there is no existing monthly 
revenue requirement for NITS.
    The provisional formula rate includes Western's cost for 
transmission scheduling, system control and dispatch service, and 
reactive supply and voltage control from generation sources service 
associated with the CVP NITS. The NITS estimated monthly revenue 
requirement is subject to change prior to the rates taking effect.

Provisional Formula Rate for Third-Party Transmission

    The provisional formula rate for third-party transmission includes 
three components:
    Component 1: Western will directly pass through any costs it incurs 
for using a third party's transmission system to the requesting 
Customer. Rates under this schedule are to be automatically adjusted as 
third-party transmission costs are adjusted.
    The formula rate for this service also contains Components 2 and 3.

Provisional Formula Rate for COTP Firm and Non-Firm Point-to-Point 
Transmission

    The provisional formula rate for COTP firm and non-firm 
transmission includes three components:
Component 1:
[GRAPHIC] [TIFF OMITTED] TN06DE04.005

    Component 1 is the ratio of the COTP seasonal transmission revenue 
requirement to Western's share of the COTP seasonal capacity (subject 
to curtailment). Western will update the rate from Component 1 at least 
15 days before the start of each COI rating season. The rate from 
Component 1 will be used for COTP firm and non-firm transmission 
service.
    This formula rate for this service also contains Component 2 and 3.
    A comparison of the estimated monthly rates from Component 1 of the 
provisional formula rate for COTP point-to-point transmission service 
to the COTP firm point-to-point transmission service existing rates are 
shown in the table below.

 Comparison of Existing Rates to Estimated Rates From Component 1 of the Provisional Formula Rate for COTP Firm
                                       Point-to-Point Transmission Service
----------------------------------------------------------------------------------------------------------------
                                                                          Estimated rates from the     Percent
                  Season                          Existing rate          provisional  formula rate     increase
----------------------------------------------------------------------------------------------------------------
Spring...................................  $0.73/kWmonth..............  $1.87/kWmonth..............          156
Summer...................................  $0.53/kWmonth..............  $1.87/kWmonth..............          253
Winter...................................  $0.66/kWmonth..............  $1.88/kWmonth..............          185
----------------------------------------------------------------------------------------------------------------

    A comparison of the estimated hourly rates from Component 1 of the 
provisional formula rate for COTP point-to-point transmission service 
to the COTP non-firm point-to-point transmission service existing rates 
are shown in the table below.

 Comparison of Existing Rates to Estimated Rates From Component 1 of the Provisional Formula Rate for COTP Non-
                                    Firm Point-to-Point Transmission Service
----------------------------------------------------------------------------------------------------------------
                                                                          Estimated rate from the      Percent
                  Season                          Existing rate          provisional  formula rate     increase
----------------------------------------------------------------------------------------------------------------
Spring...................................  1.00 mill/kWh..............  2.55 mills/kWh.............          155
Summer...................................  0.72 mill/kWh..............  2.54 mills/kWh.............          253
Winter...................................  0.91 mill/kWh..............  2.59 mills/kWh.............          185
----------------------------------------------------------------------------------------------------------------

    The minimal change in the estimated rates from Component 1 of the 
provisional formula rate is due to the variance in the number of hours 
in the COI rating season. The increase in the estimated rates from the 
provisional formula rate from the existing rates is primarily due to a 
decrease in Western's COTP capacity available for sale. The decrease in 
capacity occurs because of increased usage by the DOE of its statutory 
entitlement at a rate which recovers only O&M costs.
    The provisional formula rate for COTP firm and non-firm point-to-
point transmission service is based on a revenue requirement that 
recovers: (1) The COTP transmission system costs for facilities 
associated with providing transmission service, (2) the non-facility 
costs allocated to transmission service, (3) CVP generation costs for 
providing reactive supply and voltage control from generation sources 
service, (4) Component 2, (5) Component 3, (6) any other statutorily 
required costs or charges, and (7) any other costs associated with 
transmission service, including uncollectible debt.
    The provisional formula rate includes Western's cost for 
transmission scheduling, system control and dispatch service, and 
reactive supply and voltage control from generation sources service 
associated with COTP transmission. The provisional formula rate applies 
to COTP point-to-point transmission service. The rates from Component 1 
of the provisional formula rate may be discounted for short-term sales. 
The estimated rates from the provisional

[[Page 70524]]

formula rate are subject to change prior to the rate taking effect.

Provisional Formula Rate for PACI Firm and Non-Firm Transmission

    The provisional formula rate for PACI firm and non-firm 
transmission includes three components:
Component 1
[GRAPHIC] [TIFF OMITTED] TN06DE04.006

    Component 1 is the ratio of the PACI seasonal transmission revenue 
requirement to Western's share of the PACI seasonal capacity. Western 
will update the rate from Component 1 at least 15 days before the start 
of each COI rating season. The rate from Component 1 will be used for 
COTP firm and non-firm transmission service.
    This formula rate for this service also contains Components 2 and 
3.
    The estimated monthly and hourly rates resulting from Component 1 
of the provisional formula rate for PACI transmission service are shown 
in the table below.

  Estimated Rates From Component 1 of the Provisional Formula Rate for
                            PACI Transmission
------------------------------------------------------------------------
                                Estimated monthly
            Season                     rate        Estimated hourly rate
------------------------------------------------------------------------
Spring........................  $0.45/kWmonth....  0.61 mill/kWh.
Summer........................  $0.45/kWmonth....  0.61 mill/kWh.
Winter........................  $0.45/kWmonth....  0.62 mill/kWh.
------------------------------------------------------------------------

    The minimal change in the estimated seasonal rates from Component 1 
of the provisional formula rate is due to the variance in the number of 
hours in the COI rating season. There are no existing rates for PACI 
transmission since it is currently covered under an existing contract. 
The provisional formula rate for PACI transmission service is based on 
a revenue requirement that recovers: (1) The PACI transmission system 
costs for facilities associated with providing transmission service, 
(2) the non-facility costs allocated to transmission service, (3) CVP 
generation costs for providing reactive supply and voltage control from 
generation sources service, (4) Component 2, (5) Component 3, (6) any 
other statutorily required costs or charges, and (7) any other costs 
associated with transmission service, including uncollectible debt.
    The provisional formula rate includes Western's cost for 
transmission scheduling, system control and dispatch service, and 
reactive supply and voltage control from generation sources service 
associated with PACI transmission. The provisional formula rate applies 
to PACI point-to-point transmission service. The rates from Component 1 
of the provisional formula rate may be discounted for short-term sales. 
The estimated rates from the provisional formula rate are subject to 
change prior to the rate taking effect.

Path 15 Transmission Upgrade

    Western intends to turn over operational control of its rights on 
the Path 15 Transmission Upgrade to the CAISO under Amendment No. 48 of 
the CAISO Tariff. Transmission service for Western's rights on the Path 
15 Transmission Upgrade must be obtained under the terms and conditions 
established by the CAISO. Under Amendment No. 48, the CAISO remits to 
Western wheeling, congestion, and Firm Transmission Rights auction 
revenues associated with Western's rights on the Path 15 Transmission 
Upgrade. While Western is turning over its rights on the Path 15 
Transmission Upgrade under Amendment No. 48, Western desires to work 
with the CAISO to return revenues that are in excess of Western's costs 
associated with Western's use of the Path 15 Transmission Upgrade. As a 
result, if a significant overcollection occurs, Western will work with 
the CAISO on the treatment of the overcollection.

Comments

    The comments and responses regarding Western's entitlement on the 
Path 15 Transmission Upgrade, the CVP, COTP, and PACI firm and non-firm 
transmission, and CVP NITS formula rates, paraphrased for brevity when 
not affecting the meaning of the statement(s), are discussed below. 
Direct quotes from comment letters are used for clarification where 
necessary.
    A. Comment: A large number of Customers indicated that Western 
should consider developing transmission rates that result in comparable 
delivery costs for all Federal Customers. It was suggested that Western 
consolidate both Federal transmission costs and third-party 
transmission costs for delivering Base Resource energy when developing 
the CVP transmission revenue requirement. This consolidation would then 
allow for a sharing of costs between the Customers directly connected 
to the CVP transmission system, Customers that are not directly 
connected to the CVP transmission system, and any other users of the 
CVP transmission system. Another alternative was provided in the event 
that consolidation is not possible. That is, to provide the Customers 
that are not connected to the CVP transmission system relief by 
removing the CVP transmission costs from their Base Resource revenue 
requirement. By sharing costs, the Customers felt that all Customers 
would be treated equally and the legislative intent of limited 
development of the Federal transmission system would be preserved. 
Conversely, Western received several contrary opinions from Customers 
directly connected to the CVP transmission system. These Customers 
objected to the inequity of such a rate design.
    Response: The 2004 Power Marketing Plan states that each entity is 
ultimately responsible for obtaining its own delivery arrangements to 
load. Western believes payment of Base Resource delivery costs, 
including CVP and third-party transmission, by the Customer receiving 
the Base Resource is consistent with the 2004 Power Marketing Plan and 
the appropriate method to recover such costs.

[[Page 70525]]

    B. Comment: In Western's original proposal provided in May 2003, 
certain CAISO and PG&E charges were originally included in the 
transmission service for the PACI. Western's proposed rates presented 
in May 2004 excluded these costs from the PACI revenue requirement. 
Since the Commission process to negotiate the PG&E charges and 
potential credits for Western's transmission facilities is expected to 
continue well after these rates are implemented, and the Customer has 
no desire to have the rates increase as a result of these Commission-
sponsored negotiations, the Customer suggests including the potential 
credits in the revenue requirement.
    Response: Western understands the Customer's concern regarding the 
potential credits for Western's transmission facilities that could 
decrease the costs for delivering Western power on the PG&E system. 
Western does not have a method to estimate the amount of potential 
credits and will not receive these credits unless they are approved by 
the Commission. If Western were to reduce the third-party pass-through 
costs to reflect these credits prior to the Commission's approval, 
Western would not be collecting the full cost being charged to Western 
by PG&E.
    C. Comment: A comment asserted that the intent of the Federal 
legislation authorizing the PACI was that Western's Customers would pay 
costs that would not exceed the cost of Federal construction. To ensure 
that all Customers receive the benefit intended by the Federal 
legislation authorizing the PACI, certain Western power delivery costs 
should be included in the PACI annual revenue requirement. The Customer 
referred to Western's original May 2003 informal rates proposal 
containing this approach.
    Response: When Western proposed including third-party transmission 
costs in the PACI revenue requirement, PG&E had taken the position that 
Western's end-use Customers would have to pay PG&E's retail tariff 
costs (excluding energy costs) for delivery of Western power. Under 
that scenario, Western contemplated including third-party transmission 
costs in the PACI revenue requirement. In March 2004, PG&E filed with 
the Commission a wholesale distribution tariff rate for delivery of 
Western power to Western's end-use Customers. Western will pursue 
credit for its facilities in the Commission proceedings on PG&E's 
filing.
    D. Comment: Several Customers connected to the CVP transmission 
system asked that Western change the CVP transmission formula rate 
determinant from forecasted CVP generation to ``maximum output from the 
CVP Base Resource generation.'' The comment indicated that the proper 
recovery methodology for the capital investment and ongoing O&M 
expenses associated with transmission facilities represents a capacity 
related investment that is based upon a firm-peak delivery capability 
of facilities.
    Response: Western understands the Customers' concerns. Using the 
maximum operating capacity of the CVP northern power plants under 
normal operating conditions (annual peak) was appropriate under the 
1994 Power Marketing Plan, due to contractual obligations under 
Contract 2948A. The 2004 Power Marketing Plan does not offer the same 
type of power service that is available under the 1994 Power Marketing 
Plan. Under the 2004 Power Marketing Plan, Base Resource and First 
Preference power is primarily the output of the CVP, which varies month 
to month. Under the 2004 Power Marketing Plan, Western has changed its 
use of the CVP transmission system for the delivery of CVP northern 
power plants generation from an annual peak to monthly peaks for rate 
design purposes. Western's treatment of its statutory obligations in 
the CVP transmission rate design is consistent with the 2004 Power 
Marketing Plan and NITS under Western's OATT.
    E. Comment: A Customer informed Western of the significant 
financial impact the last increase in transmission rates had on its 
company and asked that Western charge all transmission Customers on the 
same basis to preserve equity and fairness. The Customer recommends 
that the proposed transmission rates be cost-based, allocated on cost 
causation principles, and recognize the transmission system investments 
made by Customers connected to the CVP transmission system. The 
Customer felt that Western's proposal to allocate transmission cost 
using a coincident peak billing determinant was discriminatory and 
unfairly shifted costs to contract transmission Customers.
    Response: Western in its last rate case, as in this rate case, uses 
a Commission-approved methodology of plant-based cost allocation. As 
demonstrated in the Rate Brochure, NITS and ETC Customers pay the same 
per unit cost. As mentioned in Western's response to the comment above, 
Western is marketing a different product under the 2004 Power Marketing 
Plan than was offered under the 1994 Power Marketing Plan. This change 
requires Western to use a different type of transmission service for 
CVP generation and changes the billing determinant in the formula rate. 
Under the OATT, Customers can choose the type of transmission service 
that best fits its needs, NITS or point-to-point.

Provisional Rates for Ancillary Services

    Western's costs for providing transmission scheduling, system 
control and dispatch service, and reactive supply and voltage control 
from generation sources service are included in the appropriate 
transmission revenue requirement.

Provisional Formula Rate for Spinning Reserve

    The provisional formula rate for spinning reserve is the price 
consistent with the CAISO market plus all costs incurred as a result of 
the sale of spinning reserves, such as Western's scheduling costs and 
Components 2 and 3.
    For Customers that have a contractual obligation to provide 
reserves to Western and do not fulfill that obligation, the penalty for 
nonperformance will be the greater of actual costs or 150 percent of 
the market price.
    Revenues from spinning reserve sales will offset the power revenue 
requirement. The cost for spinning reserve required to firm CVP 
generation for the current hour and the following hour is included in 
the power revenue requirement.
    Based on comments received, Western has modified its proposed rate 
to the provisional rate stated above. Western believes this addresses 
the comments regarding the spinning reserve proposed formula rate and 
provides a benefit to all power Customers of the ancillary services 
available from the CVP.

Provisional Formula Rate for Non-Spinning Reserve

    The provisional formula rate for non-spinning reserve is the price 
consistent with the CAISO market plus all costs incurred as a result of 
the sale of non-spinning reserves, such as Western's scheduling costs 
and Components 2 and 3.
    For Customers that have a contractual obligation to provide 
reserves to Western and do not fulfill that obligation, the penalty for 
nonperformance will be the greater of actual costs or 150 percent of 
the market price.
    Revenues from non-spinning reserve sales will offset the power 
revenue requirement. The cost for non-spinning reserve required to firm 
CVP generation

[[Page 70526]]

for the current hour and the following hour is included in the power 
revenue requirement. Based on comments received, Western has modified 
its proposed rate to the provisional rate stated above. Western 
believes this addresses the comments regarding the non-spinning reserve 
proposed formula rate and provides a benefit to all power Customers of 
the ancillary services available from the CVP.

Provisional Formula Rate for Regulation and Frequency Response Service

    The provisional formula rate for regulation and frequency response 
service includes three components:
Component 1
[GRAPHIC] [TIFF OMITTED] TN06DE04.007

    The revenue requirement includes: (1) The CVP generation costs 
associated with providing regulation and frequency response service, 
(2) the non-facility costs allocated to regulation and frequency 
response service, (3) Component 2, (4) Component 3, (5) any other 
statutorily required costs or charges, and (6) actual purchase costs. 
Western will revise the rate from Component 1 of the provisional 
formula rate based on either of the following two conditions: (a) 
updated financial data available in March of each year, and (b) a 
change in the rate of at least $0.25 per kWmonth.
    The annual regulating capacity is the total regulating capacity 
bandwidths provided by Western under the interconnected operations 
agreements with SCA members. The penalty for nonperformance by an SCA 
member who has committed to self-provide its regulating capacity 
requirement will be the greater of actual costs or 150 percent of the 
market price.
    This formula rate also contains Components 2 and 3.
    The regulation and frequency response service will be recovered 
from SCA members that have signed an interconnected operations 
agreement with Western. The revenues from regulation and frequency 
response service will be applied to the power revenue requirement. The 
estimated rate from the provisional formula rate is subject to change 
prior to the rate taking effect.

Provisional Formula Rate for Energy Imbalance Service

    The provisional formula rate for energy imbalance service includes 
three components:
    Component 1: If there is an hourly average negative deviation 
(underdelivery) outside the bandwidth, the amount of the deviation 
outside of the bandwidth will be charged at the greater of 150 percent 
of market price or actual cost. If there is an hourly average positive 
deviation outside the bandwidth, the amount of the deviation outside of 
the bandwidth is lost to the system.
    This formula rate also contains Components 2 and 3.
    Under the provisional formula rate, deviations outside the 
bandwidth are energy calculations done on an average hourly basis. 
There is no financial charge for deviations within the bandwidth. The 
energy imbalance rate will apply to SCA members that have signed an 
interconnected operations agreement with Western. The revenues from 
energy imbalance service will be applied to the power revenue 
requirement.

Comments

    The comments and responses regarding the spinning reserve, non-
spinning reserve, regulation and frequency response service, and energy 
imbalance service formula rates, paraphrased for brevity when not 
affecting the meaning of the statement(s), are discussed below. Direct 
quotes from comment letters are used for clarification where necessary.
    A. Comment: Several Customers indicated that the inclusion of 
purchases to support regulation and spinning and non-spinning reserve 
service was inappropriate given how Western expects to operate the SCA.
    Response: Western considered these comments and removed the 
estimate for the purchases from the revenue requirements. If actual 
purchase costs are incurred to support these services, these costs will 
be recovered through the appropriate formula rate.
    B. Comment: Several Customers expressed concern about the formula 
used to determine regulation capacity in the proposed rates. According 
to Western, this formula is used in practice by other wholesale 
utilities.
    Response: Western considered this comment, and the formula for 
determining regulation capacity is no longer part of the regulation and 
frequency response service formula rate. Regulating capacity will be 
determined as provided for in the interconnected operations agreement 
with Western.
    C. Comment: A large number of Customers commented that Western 
should consider providing a Base Resource share of ancillary service 
benefits regardless of control area restrictions. These Customers 
indicated that Western's proposal to sell surplus ancillary services at 
prices consistent with CAISO markets is discriminatory to Customers not 
connected to the CVP transmission system. Western's proposed formula 
rates allow for SCA members to receive ancillary services at cost. 
These Customers that are not connected to the CVP transmission system 
requested that Western remedy this discriminatory treatment of 
ancillary service sales to Customers not connected to the CVP 
transmission system by allowing proportionate access to these ancillary 
services to all of its Customers at similar rates prior to selling to 
the market.
    Response: Western has revised the formula rate for spinning and 
non-spinning reserve services from the proposed formula rates. As a 
result, spinning and non-spinning reserves are sold at a price 
consistent with the CAISO market regardless of whether a Customer is 
connected to the CVP transmission system. Due to existing scheduling 
constraints, Western is not able to provide regulation and frequency 
response and energy imbalance to Western Customers outside of the SCA/
HCA.
    D. Comment: A Customer suggested that Western should consider a 
higher penalty for underdeliveries for energy imbalance service. The 
Customer recommended that Western charge 300 percent of actual cost as 
opposed to the greater of 150 percent of market price or actual cost, 
as indicated in the proposed formula rate for this service.
    Response: Western understands the concern expressed by the 
Customer. Western believes that an increase to 300 percent may be more 
punitive than necessary. Western believes that actual cost or 150 
percent of market price is sufficient incentive for Customers to remain 
inside the bandwidth.
    E. Comment: A direct connected generation Customer noticed that the 
proposed formula rates did not have any crediting or offsetting 
mechanism for reactive supply and voltage control. The Customer 
requested that to the extent that Western compensates its own 
generation for providing the above services, then other Western 
Customers with generation that provide the same service must also be 
compensated.
    Response: Western understands the Customer's concerns. The 
provisional rates do not provide for a credit for reactive supply and 
voltage control from generation sources to any party, including 
Western.
    F. Comment: One Customer that is connected to the CVP transmission 
system requested that Western develop

[[Page 70527]]

provisions that would allow CVP transmission Customers to self-provide 
regulation and operating reserves.
    Response: Western had provisions in the proposed rates to allow 
crediting of self-provided ancillary services. Self-provision is 
included in the interconnected operations agreement and has been taken 
out of the provisional rates.
    F. Comment: A Customer indicated that the current proposed rates 
are several times higher than rates presented in 2003 and provided a 
table (see below). The Customer indicated that Western had not provided 
any explanation why the rates rose so dramatically since May 2003 and 
whether or not this volatility was expected to continue.

                                   Ancillary Service Per Unit Cost Comparison
----------------------------------------------------------------------------------------------------------------
                                                                                                       Percent
                 Service                      May 2003 per unit cost       May 2004 per unit cost      increase
----------------------------------------------------------------------------------------------------------------
Scheduling and System Control and          $60.00/E-tag...............  By contract................          N/A
 Dispatch.
Reactive Power and Voltage Control.......  $0.07/kWmonth..............  Assigned by transmission             N/A
                                                                         system.
Operating Reserve--Spinning..............  $0.31/kWmonth..............  $3.30/kWmonth..............          965
Operating Reserve--Supplemental Reserve    $0.19/kWmonth..............  $2.52/kWmonth..............         1226
 Service (non-spin).
Regulation and Frequency Response........  $0.40/kWmonth..............  $6.33/kWmonth..............         1483
----------------------------------------------------------------------------------------------------------------

    Response: Western's provisional rates for spinning and non-spinning 
reserve service are based on prices consistent with the CAISO markets. 
As such, the comparison above is no longer applicable. For regulation 
and frequency response service, as Western explained during the public 
information forum and accompanying slides, the increase in comparative 
rates for regulation and frequency response service was primarily due 
to increased O&M costs used in the cost-of-service study. In addition, 
Western used a Reclamation FY 2002 Ancillary Services Study to estimate 
hourly capacity amounts available from the CVP plants for regulation 
and frequency response service. These capacity amounts translated into 
purchase costs that were included in the estimated revenue requirements 
for the applicable services. In a letter to all interested parties on 
July 28, 2004, Western made a change to the revenue requirement for 
Component 1 of the formula rate for regulation and frequency response 
service. Western removed the purchase costs for regulation and 
frequency response service, and the appropriate revenue requirement was 
adjusted. This change in revenue requirement is documented in the table 
below. If purchase costs are incurred in providing of this service, 
these costs will be included in the next revision to the revenue 
requirement.

   Change in Revenue Requirement for Regulation and Frequency Response
                                 Service
------------------------------------------------------------------------
                                                              Revised
                                              Revenue         revenue
                 Service                    requirement     requirement
                                           with purchase      without
                                               costs      purchase costs
------------------------------------------------------------------------
Regulation with Frequency Response            $2,277,692        $905,613
 Service................................
------------------------------------------------------------------------

    Since the publication of this letter, the revenue requirement was 
further revised to $972,405. The estimated revenue requirement 
increased slightly as a result of an increase in the regulating 
capacity needed for SCA members. Based on the revised revenue 
requirement, a revised cost-of-service study, and the provisional 
formula rate for regulation and frequency response service, the 
estimated rate is now $2.57 per kWmonth, which represents a 3 percent 
increase from Western's regulation and frequency response service 
existing rate.

General Comments

    General comments and responses regarding operational 
considerations, power scheduling, and extension of the comment period, 
paraphrased for brevity when not affecting the meaning of the 
statement(s), are discussed below. Direct quotes from comment letters 
are used for clarification where necessary.

Operational Considerations

    A. Comment: A Customer was particularly concerned that an 
``operational decision [regarding control area participation] should 
not be made without consideration of the rate and cost impacts on the 
Customers. One of the criteria used by Western to make its operational 
decision was cost effectiveness.'' The Customer did not feel that the 
proposed rates demonstrated that the SCA is cost effective and 
Customers should not be forced to pay costs higher than the CAISO.
    Response: Rates for CVP power and power-related services are 
designed to recover the costs associated with providing the service. 
Customers have the option to self-provide spinning and non-spinning 
reserves and regulation and frequency response service, which gives 
them some flexibility to determine their own costs. The operational 
decision regarding Western's choice for joining a control area was set 
in a separate public process and is outside the scope of this public 
process.
    B. Comment: A number of Customers expressed an interest in Western 
initiating a process to find additional ways to enhance the Western 
SCA: to ameliorate the uncertainty and ambiguities associated with the 
termination of Contracts 2947A, 2948A, and related contracts; to assess 
and promote the ability to dynamically schedule with the Western SCA 
load not directly connected to the CVP transmission system; to 
investigate ways to develop a ``grid best'' structure with regard to 
Western and all its Customers; and to explore mechanisms to assure 
needed future capital expenditures for transmission and power supply 
are

[[Page 70528]]

provided in a timely manner. Another Customer asked that Western 
recognize that some Customers have existing agreements, like a metered 
subsystem, and should consider allowing these Customers to dynamically 
schedule their resources with the CAISO.
    Response: These comments are outside the scope of this public 
process. The termination of Contracts 2947A, 2948A, and other related 
contracts is being addressed in the Commission technical conferences 
with the affected parties.

Power Scheduling

    A. Comment: A number of Customers not directly connected to the CVP 
transmission system stated that they expected Western to minimize its 
costs by scheduling the CVP generation located in the CAISO's control 
area to Customers in the CAISO control area.
    Response: Western seeks to minimize costs for all activities 
relating to delivering Western power to its Customers. To the extent 
practicable, CVP generation in the CAISO control area will be scheduled 
to project use, First Preference, and Base Resource Customers in the 
CAISO control area.

Extension of the Comment Period

    A. Comment: Several Customers requested an extension of the comment 
period for this public process. These requests were made primarily 
because entities are interested in evaluating the ancillary service 
formula rates in association with the recently signed Sacramento 
Municipal Utility District (SMUD) and Western interconnection agreement 
and soon to be negotiated intra-SCA agreements between Western and SCA 
members.
    Response: Western understands the concern expressed by these 
Customers. Western has committed to providing updated revenue 
requirement and/or rate information on or before December 1, 2004, for 
all rates except COTP and PACI transmission. The COTP and PACI 
transmission rate information will be provided on or before December 
15, 2004, when the winter COI rating information should be available. 
Western cannot afford a delay in this rate process given that service 
must begin January 1, 2005.

Availability of Information

    Information about this rate adjustment, including power repayment 
studies, comments, letters, memorandums, and other supporting material 
made and kept by Western and used to develop the provisional rates, is 
available for public review in the Sierra Nevada Regional Office, 
Western Area Power Administration, located at 114 Parkshore Drive, 
Folsom, California.

Regulatory Procedure Requirements

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 that 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.

Environmental Compliance

    In compliance with the National Environmental Policy Act (NEPA) of 
1969, (42 U.S.C. 4321, et seq.); Council on Environmental Quality 
Regulations (40 CFR 1500-1508); and DOE NEPA Regulations (10 CFR 1021), 
Western has determined that this action is categorically excluded from 
preparing 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; accordingly, no clearance of this notice by the 
Office of Management and Budget is required.

Small Business Regulatory Enforcement Fairness Act

    Western has determined that 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.

Submission to the Federal Energy Regulatory Commission

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

Order

    In view of the foregoing and under the authority delegated to me, I 
confirm and approve on an interim basis, effective January 1, 2005, 
Rate Schedules CV-F11, CPP-1, CV-T1, CV-TPT6, CV-NWT3, COTP-T1, PACI-
T1, CV-RFS3, CV-EID3, CV-SPR3, and CV-SUR3 for the Central Valley and 
the California-Oregon Transmission Projects, and the Pacific 
Alternating Current Intertie of the Western Area Power Administration. 
The rate schedules shall remain in effect on an interim basis, pending 
the Commission's confirmation and approval of them or substitute rates 
on a final basis through September 30, 2009.

    Dated: November 18, 2004.
Kyle E. McSlarrow,
Deputy Secretary.

Rate Schedule CV-F11 (Supersedes Schedule CV-F10)

Central Valley Project; Schedule of Rates for Base Resource and First 
Preference Power

    Effective: January 1, 2005, through September 30, 2009.
    Available: Within the marketing area served by the Sierra Nevada 
Customer Service Region.
    Applicable: To the Base Resource (BR) and First Preference (FP) 
power Customers.
    Character and Conditions of Service: Alternating current, 60 hertz, 
three-phase, delivered and metered at the voltages and points 
established by contract. This service includes the Central Valley 
Project (CVP) transmission, spinning, and non-spinning reserve 
services.
    Power Revenue Requirement: Western will develop the Power Revenue 
Requirement (PRR) prior to the start of each fiscal year (FY). The PRR 
will be divided into two 6-month periods, October through March and 
April through September. A monthly PRR will be calculated by dividing 
each 6-month PRR by six. The PRR for the April through September period 
will be reviewed in March of each year (except March 2005). The review 
will analyze financial data from the October through February period, 
to the extent information is available, as well as forecasted data for 
the March through September period. If there is a change of $5 million 
or more, the PRR for the April through September period will be 
recalculated. For the January through September 2005 period, a monthly 
PRR will be calculated by dividing the PRR for that period by nine.
First Preference Power Formula Rate:
Component 1:

[[Page 70529]]

[GRAPHIC] [TIFF OMITTED] TN06DE04.008

FP Customer Charge = FP Customer Percentage x MRR

Where:
    FP Customer Load = An FP Customer's forecasted annual load in 
megawatthours (MWh).
    Gen = The forecasted annual CVP and Washoe generation (MWh).
    Power Purchases = Power purchases for project use and FP loads 
(MWh).
    Project Use = The forecasted annual project use loads (MWh).
    MRR = Monthly Power Revenue Requirement.

    Western will develop the FP Customer percentage prior to the start 
of each FY. During March of each FY (except March 2005), each FP 
Customer's percentage will be reviewed. If, as a result of the review, 
there is a change in the FP Customer's percentage of more than one-half 
of 1 percent, the percentage will be revised for the April through 
September period.
    The percentages in the table below are the maximum percentages for 
each FP Customer that will be applied to the MRR. The maximum 
percentages were determined based on a critically dry year where there 
are hydrologic conditions that result in low CVP generation and, 
consequently, low levels of BR. These maximum percentages are not used 
in instances where individual FP Customer percentages increase due to 
load growth. If these maximum percentages are used for determining the 
FP Customer's charges for more than 1 year, then Western will evaluate 
their percentage from the formula rate versus the maximum percentage 
and make adjustments as appropriate.

                    FP Customers' Maximum Percentages
------------------------------------------------------------------------
                                                            Maximum FP
                                                            customer's
                      FP customers                          percentage
                                                          applied to the
                                                                MRR
------------------------------------------------------------------------
Sierra Conservation Center..............................            1.39
Calaveras Public Power Agency...........................            3.49
Trinity Public Utility District.........................            9.21
Tuolumne Public Power Agency............................            3.42
                                                         ---------------
    Total...............................................           17.51
------------------------------------------------------------------------

    Below is a sample calculation for an FP Customer monthly charge for 
power.

              FP Customer Monthly Charge Sample Calculation
------------------------------------------------------------------------
  Example: First preference customer charge calculation
------------------------------------------------------------------------
FP Customer Load--MWh...................................          10,000
Washoe generation--MWh..................................           2,500
CVP generation--MWh.....................................       3,700,000
Project Use Load--MWh...................................       1,200,000
Project Use purchase--MWh...............................          47,000
FP Customer percentage..................................           0.39%
MRR.....................................................      $3,333,333
FP Customer monthly charge..............................         $13,000
------------------------------------------------------------------------

Component 2
    Any charges or credits associated with the creation, termination, 
or modification to any tariff, contract, or schedule accepted or 
approved by the Federal Energy Regulatory Commission (Commission) or 
other regulatory body will be passed on to each appropriate Customer. 
The Commission or other regulatory body accepted or approved charges or 
credits apply to the service to which this rate methodology applies.
    When possible, Western will pass through directly to the 
appropriate Customer, the Commission or other regulatory body accepted 
or approved charges or credits in the same manner Western is charged or 
credited. If the Commission or other regulatory body accepted or 
approved charges or credits cannot be passed through directly to the 
appropriate Customer, the charges or credits will be passed through 
using Component 1 of the FP power formula rate.
Component 3
    Any charges or credits from the Host Control Area (HCA) applied to 
Western for providing this service will be passed through directly to 
the appropriate Customer in the same manner Western is charged or 
credited, to the extent possible. If the HCA costs or credits cannot be 
passed through to the appropriate Customer in the same manner Western 
is charged or credited, the charges or credits will be passed through 
using Component 1 of the FP power formula rate.
BR Formula Rate
Component 1
BR Customer Charges = (BR RR x BR %)

Where:
    BR RR = BR Monthly Revenue Requirement
    BR % = BR percentage for each Customer as indicated in the BR 
contract after adjustments for hourly exchange energy.

    BR Customers will pay for exchange energy by adjusting the BR 
percentage that is applied to the BR RR. Adjustments to a Customer's BR 
percentage for seasonal exchanges will be reflected in the Customer's 
BR contract.
    An illustration of the adjustment to a Customer's BR percentage for 
hourly Exchange Energy (EE) is shown in the table below.

                                           Example of Base Resource Percentage Adjustments for Exchange Energy
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                           Customer's BR                   BR delivered
                       BR customer                         BR percentage  Hourly BR = 30   in excess of      Customers    (adjusting for    Revised BR
                                                           from contract        MWh            load        receiving EE         EE)         percentage
--------------------------------------------------------------------------------------------------------------------------------------------------------
Customer A..............................................              20               6               3               0               3              10
Customer B..............................................              10               3               0               1               4           13.33
Customer C..............................................              70              21               0               2              23           76.67
                                                         -----------------
    Total...............................................             100              30               3               3              30             100
--------------------------------------------------------------------------------------------------------------------------------------------------------

    After the FP Customers' share of the annual power revenue 
requirement has been determined, the remainder of the annual power 
revenue requirement is recovered from the BR Customers. The BR revenue 
requirement will be collected in two 6-month periods. For October 
through March, 25 percent of the BR revenue requirement will be

[[Page 70530]]

collected. For April through September, 75 percent of the BR revenue 
requirement will be collected.
    A BR RR is calculated by dividing the BR 6-month revenue 
requirement by six. The revenues from the sale of surplus BR will be 
applied to the annual BR RR for the following FY.
    For January through September 2005, the BR RR will be allocated 25 
percent to the 3-month period from January through March 2005 and 75 
percent to the 6-month period, April through September 2005.
Component 2
    Any charges or credits associated with the creation, termination, 
or modification to any tariff, contract, or schedule accepted or 
approved by the Commission or other regulatory body will be passed on 
to each appropriate Customer. The Commission or other regulatory body 
accepted or approved charges or credits apply to the service to which 
this rate methodology applies.
    When possible, Western will pass through directly to the 
appropriate Customer, the Commission or other regulatory body accepted 
or approved charges or credits in the same manner Western is charged or 
credited. If the Commission or other regulatory body accepted or 
approved charges or credits cannot be passed through directly to the 
appropriate Customer, the charges or credits will be passed through 
using Component 1 of the BR formula rate.
Component 3
    Any charges or credits from the HCA applied to Western for 
providing this service will be passed through directly to the 
appropriate Customer in the same manner Western is charged or credited, 
to the extent possible. If the HCA costs or credits cannot be passed 
through to the appropriate Customer in the same manner Western is 
charged or credited, the charges or credits will be passed through 
using Component 1 of the BR formula rate.
    Billing: Billing for BR and FP power will occur monthly using the 
respective formula rate.
    Adjustment for Losses: Losses will be accounted for under this rate 
schedule as stated in the service agreement.
    Adjustment for Audit Adjustments: Financial audit adjustments that 
apply to the revenue requirement under this rate schedule will be 
evaluated on a case-by-case basis to determine the appropriate 
treatment for repayment and cash flow management.

Rate Schedule CPP-1

Central Valley Project; Schedule of Rates for Custom Product Power

    Effective: January 1, 2005, through September 30, 2009.
    Available: Within the marketing area served by the Sierra Nevada 
Customer Service Region.
    Applicable: To Customers that contract with the Western Area Power 
Administration (Western) for Custom Product Power.
    Character and Conditions of Service: Alternating current, 60 hertz, 
three-phase, delivered and metered at the voltages and points 
established by contract.
    Formula Rate: The Customer will pay all costs incurred in the 
provision of Custom Product Power. These costs will be passed through 
to the Customer. The methodology used to calculate the amount of the 
pass through will be based on the type of funding used to purchase the 
Custom Product Power. Custom Product Power includes, but is not limited 
to, supplemental power and Base Resource (BR) firming power.
    Advance Funding: Costs for Custom Product Power funded in advance 
by the Customer(s) will be passed through to that Customer(s) based on 
the power forecasted for the Customer(s). Unless otherwise agreed to by 
Western, Custom Product Power funded in advance that is surplus to the 
load requirements of the Customer(s) will be sold. If the Customer(s) 
fail to have an account available to receive the proceeds from the sale 
of surplus Custom Product Power, the proceeds are forfeited to Western 
and will be applied to the Custom Product Power cost for the 
Customer(s), to the extent possible.
    The table below illustrates the pass through of the Custom Product 
Power costs for three Customers and the treatment of proceeds from the 
sale of surplus Custom Product Power. As depicted in the table below, 
Customers A, B, and C have payment responsibility for a Custom Product 
Power purchase that was made for them as a group and forecasted for 
them individually. Customer C must pay for the 3 megawatthours (MWh) 
even though the Custom Product Power could not be used. The proceeds 
from the sale of the surplus 3 MWh are deposited into Customer C's 
account.

                            CPP Cost Recovery with Proceeds from Sales of Surplus CPP Advanced Customer Funding with Account
                                     [Western made a CPP purchase of 13 megawatts (MW) for the hour @ $10/MWh=$130]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                             Customer                                      Proceeds from     Proceeds
                                                          CPP forecasted    charged for       CPP RR        Surplus CPP     excess CPP    deposited into
                                                               (MWh)            CPP                            sales           sales           acct
--------------------------------------------------------------------------------------------------------------------------------------------------------
Customer A..............................................               6             $60  ..............               0              $0              $0
Customer B..............................................               4              40  ..............               0               0               0
Customer C..............................................               3              30  ..............               3              12              12
                                                         -----------------
    Total...............................................              13             130            $130               3              12             12
--------------------------------------------------------------------------------------------------------------------------------------------------------
Notes:
1. Western sold 3 MWh of CPP at $4/MWh=$12.
2. Proceeds are deposited into Customer C's escrow account because Customer C's CPP amount was surplus.

    The table below illustrates the pass through of the Custom Product 
Power costs for three Customers and the treatment of proceeds from the 
sale of surplus Custom Product Power for the Customer(s) that have not 
established an account. As depicted in the table below, all Customers 
must pay for the Custom Product Power forecasted for them individually. 
Customer C must pay for the 3 MWh even though the Custom Product Power 
could not be used by Customer C. The proceeds from the sale of the 
surplus 3 MWh are used to reduce the Custom Product Power costs for the 
group to the extent possible, since Customer C does not have an account 
available for the proceeds. If the costs of the Custom Product Power 
are fully recovered and proceeds remain from the sale of surplus Custom 
Product Power, the remaining proceeds will be used to reduce the power 
revenue requirement.

[[Page 70531]]



       CPP Cost Recovery with Proceeds from Sales of Surplus CPP Advanced Customer Funding Without Account
                       [Western made a CPP purchase of 13 MW for the hour @ $10/MWh=$130]
----------------------------------------------------------------------------------------------------------------
                                                                                   Proceeds from
                                  CPP forecasted     CPP cost       Surplus CPP     excess CPP      Charge per
                                       (MWh)                                           sales         customer
----------------------------------------------------------------------------------------------------------------
Customer A......................               6             $60               0  ..............          $54.46
Customer B......................               4              40               0  ..............           36.31
Customer C......................               3              30               3  ..............          $27.23
                                 -----------------
    Total.......................              13             130               3             $12        $118.00
----------------------------------------------------------------------------------------------------------------
Notes:
1. Western sold 3 MWh of surplus CPP at $4/MWh = $12.
2. Proceeds reduce the CPP cost because no account is available for the proceeds of the sale of surplus CPP.
3. Proceeds from surplus sales reduce CPP costs and are allocated to each Customer based on the amount of CPP
  forecasted.

    Use of Receipts, Federal Reimbursable, or Appropriations Authority:
    If the Custom Product Power is funded through appropriations, 
Federal reimbursable, or use of receipts authority, the cost of the 
Custom Product Power is passed through to the Customer(s) that have 
this power in their final schedule. Custom Product Power funded through 
appropriations, Federal reimbursable, or use of receipts authority that 
is surplus to the load requirements of the Customer(s) will be sold. 
Proceeds from the sale of surplus Custom Product Power funded through 
use of receipts, Federal reimbursable, or appropriations authority will 
be applied to the Custom Product Power purchase cost for the 
Customer(s) to the extent possible. If the cost of the Custom Product 
Power is fully recovered and proceeds remain from the sale of surplus 
Custom Product Power, the remaining proceeds will be used to reduce the 
power revenue requirement. The table below illustrates the pass through 
of the Custom Product Power costs to each Customer and the treatment of 
proceeds from the sale of surplus Custom Product Power funded through 
appropriations, Federal reimbursable, or use of receipts authority. As 
shown, Customers A and B are responsible for paying the full costs of 
the Custom Product Power purchase made by Western (Total Custom Product 
Power revenue requirement is $130) because they are the only Customers 
that had the Custom Product Power in their final schedules. The Custom 
Product Power revenue requirement of $130 is reduced by the sales of 
$12, which reduces the Custom Product Power revenue requirement to 
$118. Therefore, the reduced Custom Product Power revenue requirement 
of $118 is prorated to each Customer based on the amount of Custom 
Product Power in their final schedules.

              CPP Cost Recovery With Proceeds From Sales of Surplus CPP Use of Receipts, Federal Reimbursable, or Appropriations Authority
                                          [Western made a CPP purchase of 13 MW for the hour @ $10/MWh = $130]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                           Proceeds from
                                                           CPP purchased     CPP used        CPP costs      Surplus CPP     excess CPP     CPP customer
                                                               (MWh)           (MWh)                           sold            sales          charges
--------------------------------------------------------------------------------------------------------------------------------------------------------
Customer A..............................................               6               6  ..............               0  ..............          $70.80
Customer B..............................................               4               4  ..............               0  ..............           47.20
Customer C..............................................               3               0  ..............               3  ..............            0.00
                                                         -----------------
    Total...............................................              13              10            $130               3             $12          118.00
--------------------------------------------------------------------------------------------------------------------------------------------------------
Notes:
1. Western sold 3 MWh of CPP at $4/MWh = $12.
2. Proceeds from the sale of surplus CPP reduce the CPP Costs prorated based on the amount of CPP used.

    Western will charge $31.07 per schedule per day to cover its 
administrative costs for procuring and scheduling Custom Product Power 
if the Customer has not contracted with Western for this type of 
service through other agreements. If the actual number of schedules for 
the month is not available, Western will estimate the number of 
schedules for the month and apply the $31.07 per schedule charge to the 
estimated number of schedules.
    Billing: Billing for Custom Product Power will occur monthly using 
the formula rate.
    Adjustments for Losses: All losses incurred for delivery of Custom 
Product Power under this rate schedule shall be the responsibility of 
the Customer that has contracted for this service.
    Adjustment for Audit Adjustments: Financial audit adjustments that 
apply to the revenue requirement under this rate schedule will be 
evaluated on a case-by-case basis to determine the appropriate 
treatment for repayment and cash flow management.

Rate Schedule CV-T1 (Supersedes Schedules CV-FT4 and CV-NFT4)

Central Valley Project; Schedule of Rate for Transmission Service

    Effective: January 1, 2005, through September 30, 2009.
    Available: Within the marketing area served by the Sierra Nevada 
Customer Service Region.
    Applicable: To Customers receiving Central Valley Project (CVP) 
firm and/or non-firm transmission service.
    Character and Conditions of Service: Transmission service for 
three-phase, alternating current at 60 hertz, delivered

[[Page 70532]]

and metered at the voltages and points of delivery or receipt, adjusted 
for losses, and delivered to points of delivery. This service includes 
scheduling, system control and dispatch service, and reactive supply 
and voltage control from generation sources service needed to support 
the transmission service.
    Formula Rate: The formula rate for CVP firm and non-firm 
transmission service includes three components:
Component 1
[GRAPHIC] [TIFF OMITTED] TN06DE04.009

Where:
    CVP TRR = Transmission Revenue Requirement is the costs associated 
with facilities that support the transfer capability of the CVP 
transmission system, excluding generation facilities and radial lines.
    TTc = Total Transmission Capacity is the total transmission 
capacity under long-term contract between the Western Area Power 
Administration (Western) and other parties.
    NITSc = Average 12-month coincident peaks of network integrated 
transmission service (NITS) Customers at the time of the monthly CVP 
transmission system peak. For rate design purposes, Western's use of 
the transmission system to meet its statutory obligations is treated as 
NITS.

    Western will revise the rate from Component 1 based on either of 
the following two conditions: (a) Updated financial data available in 
March of each year, and (b) a change in the numerator or denominator 
that results in a rate change of at least $0.05 per kilowattmonth. Rate 
change notifications will be posted on the Open Access Same-Time 
Information System.
Component 2
    Any charges or credits associated with the creation, termination, 
or modification to any tariff, contract, or rate schedule accepted or 
approved by the Federal Energy Regulatory Commission (Commission) or 
other regulatory body will be passed on to each appropriate Customer. 
The Commission or other regulatory body accepted or approved charges or 
credits apply to the service to which this rate methodology applies. 
When possible, Western will pass through directly to the appropriate 
Customer, the Commission or other regulatory body accepted or approved 
charges or credits in the same manner Western is charged or credited. 
If the Commission or other regulatory body accepted or approved charges 
or credits cannot be passed through directly to the appropriate 
Customer in the same manner Western is charged or credited, the charges 
or credits will be passed through using Component 1 of the CVP 
transmission service formula rate.
Component 3
    Any charges or credits from the Host Control Area (HCA) applied to 
Western for providing this service will be passed through directly to 
the appropriate Customer in the same manner Western is charged or 
credited, to the extent possible. If the HCA costs or credits cannot be 
passed through to the appropriate Customer in the same manner Western 
is charged or credited, the charges or credits will be passed through 
using Component 1 of the CVP transmission service formula rate.
    Billing: The formula rate above applies to the maximum amount of 
capacity reserved for periods ranging from 1 hour to 1 month, payable 
whether used or not. Billing will occur monthly.
    Adjustment for Losses: Losses incurred for service under this rate 
schedule will be accounted for as agreed to by the parties in 
accordance with the service agreement.
    Adjustment for Audit Adjustments: Financial audit adjustments that 
apply to the revenue requirement under this rate schedule will be 
evaluated on a case-by-case basis to determine the appropriate 
treatment for repayment and cash flow management.

Rate Schedule CV-NWT3 (Supersedes Schedule CV-NWT2)

Central Valley Project; Schedule of Rate for Network Integration 
Transmission Service

    Effective: January 1, 2005, through September 30, 2009.
    Available: Within the marketing area served by the Sierra Nevada 
Customer Service Region.
    Applicable: To Customers who receive Central Valley Project (CVP) 
Network Integration Transmission Service (NITS), to points of delivery 
and receipt as 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 or receipt, adjusted for losses, 
and delivered to points of delivery. This service includes scheduling, 
system control and dispatch service, and reactive supply and voltage 
control from generation sources service needed to support the 
transmission service.
    Formula Rate: The formula rate for CVP NITS includes three 
components:
Component 1
NITS Customer's monthly demand charge = NITS Customer's load ratio 
share times one-twelfth (1/12) of the Annual Network TRR.

Where:
    NITS Customer's load ratio share = The NITS Customer's hourly load 
(including behind the meter generation minus the NITS Customer's hourly 
Base Resource) coincident with the monthly CVP transmission system peak 
minus the coincident peak for all firm CVP (including reserved 
transmission capacity) transmission service, expressed as a ratio.
    Annual Network TRR = Total CVP transmission revenue requirement, 
less revenues from long-term contracts for CVP transmission between the 
Western Area Power Administration (Western) and other parties.

    The Annual Network TRR will be revised when the rate from Component 
1 of the CVP transmission rate under Rate Schedule CV-T1 is revised.
Component 2
    Any charges or credits associated with the creation, termination, 
or modification to any tariff, contract, or rate schedule accepted or 
approved by the Commission or other regulatory body will be passed on 
to each appropriate Customer. The Commission accepted or approved 
charges or credits apply to the service to which this rate methodology 
applies.
    When possible, Western will pass through directly to the 
appropriate Customer, the Commission or other regulatory body accepted 
or approved charges or credits in the same manner Western is charged or 
credited. If the Commission or other regulatory body accepted or 
approved charges or credits cannot be passed through directly to the 
appropriate Customer in the same manner Western is charged or credited, 
the charges or credits will be passed through using Component 1 of the 
CVP NITS formula rate.
Component 3
    Any charges or credits from the Host Control Area (HCA) applied to 
Western for providing this service will be passed through directly to 
the appropriate Customer in the same manner Western is charged or 
credited, to the extent

[[Page 70533]]

possible. If the HCA charges or credits cannot be passed through to the 
appropriate Customer in the same manner Western is charged or credited, 
the charges or credits will be passed through using Component 1 of the 
CVP NITS formula rate.
    Billing: NITS will be billed monthly under the formula rate.
    Adjustment for Losses: Losses incurred for service under this rate 
schedule will be accounted for as agreed to by the parties in 
accordance with the service agreement.
    Adjustment for Audit Adjustments: Financial audit adjustments that 
apply to the revenue requirement under this rate schedule will be 
evaluated on a case-by-case basis to determine the appropriate 
treatment for repayment and cash flow management.

Rate Schedule COTP-T1 (Supersedes Schedules COTP-FT2 and COTP NFT-2)

California-Oregon Transmission Project; Schedule of Rate for 
Transmission Service

    Effective: January 1, 2005, through September 30, 2009.
    Available: Within the marketing area served by the Sierra Nevada 
Customer Service Region.
    Applicable: To Customers receiving California-Oregon Transmission 
Project (COTP) firm and/or non-firm transmission service.
    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 or receipt, adjusted for losses, 
and delivered to points of delivery. This service includes scheduling, 
system control and dispatch service, and reactive supply and voltage 
control from generation sources service needed to support the 
transmission service.
    Formula Rate: The formula rate for COTP firm and non-firm 
transmission service includes three components:
Component 1
[GRAPHIC] [TIFF OMITTED] TN06DE04.010

Where:
    COTP TRR = COTP Seasonal Transmission Revenue Requirement (the 
Western Area Power Administration's (Western) costs associated with 
facilities that support the transfer capability of the COTP).
    Western's share of COTP Seasonal Capacity = Western's share of COTP 
capacity (subject to curtailment) 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 the rate from Component 1 of the formula rate 
for COTP firm transmission service at least 15 days before the start of 
each COI rating season. Rate change notifications will be posted on the 
Open Access Same-Time Information System.
Component 2
    Any charges or credits associated with the creation, termination, 
or modification to any tariff, contract, or rate schedule accepted or 
approved by the Federal Energy Regulatory Commission (Commission) or 
other regulatory body will be passed on to each appropriate Customer. 
The Commission accepted or approved charges or credits apply to the 
service to which this rate methodology applies.
    When possible, Western will pass through directly to the 
appropriate Customer, the Commission or other regulatory body accepted 
or approved charges or credits in the same manner Western is charged or 
credited. If the Commission or other regulatory body accepted or 
approved charges or credits cannot be passed through directly to the 
appropriate Customer in the same manner Western is charged or credited, 
the charges or credits will be passed through using Component 1 of the 
COTP transmission service formula rate.
Component 3
    Any charges or credits from the Host Control Area (HCA) applied to 
Western for providing this service will be passed through directly to 
the appropriate Customer in the same manner Western is charged or 
credited, to the extent possible. If the HCA charges or credits cannot 
be passed through to the appropriate Customer in the same manner 
Western is charged or credited, the charges or credits will be passed 
through using Component 1 of the COTP transmission service formula 
rate.
    Billing: The formula rate above applies to the maximum amount of 
capacity reserved for periods ranging from 1 hour to 1 month, payable 
whether used or not. Billing will occur monthly.
    Adjustment for Losses: Losses incurred for service under this rate 
schedule will be accounted for as agreed to by the parties in 
accordance with the service agreement.
    Adjustment for Audit Adjustments: Financial audit adjustments that 
apply to the revenue requirement under this rate schedule will be 
evaluated on a case-by-case basis to determine the appropriate 
treatment for repayment and cash flow management.

Rate Schedule PACI-T1

Pacific Alternating Current Intertie Project; Schedule of Rate for 
Transmission Service

    Effective: January 1, 2005, through September 30, 2009.
    Available: Within the marketing area served by the Sierra Nevada 
Customer Service Region.
    Applicable: To Customers receiving the Pacific Alternating Current 
Intertie (PACI) firm and/or non-firm transmission service.
    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 or receipt, adjusted for losses, 
and delivered to points of delivery. This service includes scheduling, 
system control and dispatch service, and reactive supply and voltage 
control from generation sources service needed to support the 
transmission service.
    Formula Rate: The formula rate for PACI firm and non-firm 
transmission service includes three components:
Component 1
[GRAPHIC] [TIFF OMITTED] TN06DE04.011

Where:
    PACI TRR = PACI Seasonal Transmission Revenue Requirement, the 
Western Area Power Administration's (Western) costs associated with 
facilities that support the transfer capability of the PACI.
    Western's PACI Seasonal Capacity = Western's share of PACI capacity 
(subject to curtailment) 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 the rate from Component 1 of the formula rate 
for PACI firm transmission service at least 15 days before the start of 
each COI rating season. Rate change notifications will be posted on the 
Open Access Same-Time Information System.
Component 2
    Any charges or credits associated with the creation, termination, 
or

[[Page 70534]]

modification to any tariff, contract, or rate schedule accepted or 
approved by the Federal Energy Regulatory Commission (Commission) or 
other regulatory body will be passed on to each appropriate Customer. 
The Commission accepted or approved charges or credits apply to the 
service to which this rate methodology applies.
    When possible, Western will pass through directly to the 
appropriate Customer, the Commission or other regulatory body accepted 
or approved charges or credits in the same manner Western is charged or 
credited. If the Commission or other regulatory body accepted or 
approved charges or credits cannot be passed through directly to the 
appropriate Customer in the same manner Western is charged or credited, 
the charges or credits will be passed through using Component 1 of the 
PACI transmission service formula rate.
Component 3
    Any charges or credits from the Host Control Area (HCA) applied to 
Western for providing this service will be passed through directly to 
the appropriate Customer in the same manner Western is charged or 
credited, to the extent possible. If the HCA costs or credits cannot be 
passed through to the appropriate Customer, the charges or credits will 
be passed through using Component 1 of the PACI transmission service 
formula rate.
    Billing: The formula rate above applies to the maximum amount of 
capacity reserved for periods ranging from 1 hour to 1 month, payable 
whether used or not. Billing will occur monthly.
    Adjustment for Losses: Losses incurred for service under this rate 
schedule will be accounted for as agreed to by the parties in 
accordance with the service agreement.
    Adjustment for Audit Adjustments: Financial audit adjustments that 
apply to the revenue requirement under this rate schedule will be 
evaluated on a case-by-case basis to determine the appropriate 
treatment for repayment and cash flow management.

Rate Schedule CV-TPT6 (Supersedes CV-TPT5)

Central Valley Project; Schedule of Rate for Transmission of Western 
Power by Others

    Effective: January 1, 2005, through September 30, 2009.
    Available: Within the marketing area served by the Sierra Nevada 
Customer Service Region.
    Applicable: To the Western Area Power Administration's (Western) 
power service Customers 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 or receipt, adjusted for losses, 
and delivered to points as agreed to by the parties.

Formula Rate

Component 1
    When Western uses transmission facilities other than its own in 
supplying Western power, and costs are incurred by Western for the use 
of such facilities, the Customer will pay all costs, including 
transmission losses, incurred in the delivery of such power.
Component 2
    Any charges or credits associated with the creation, termination, 
or modification to any tariff, contract, or rate schedule accepted or 
approved by the Federal Energy Regulatory Commission (Commission) or 
other regulatory body will be passed on to each appropriate Customer. 
The Commission accepted or approved charges or credits apply to the 
service to which this rate methodology applies.
    When possible, Western will pass through directly to the 
appropriate Customer, the Commission or other regulatory body accepted 
or approved charges or credits in the same manner Western is charged or 
credited. If the Commission or other regulatory body accepted or 
approved charges or credits cannot be passed through directly to the 
appropriate Customer in the same manner Western is charged or credited, 
the charges or credits will be passed through using Component 1 of the 
third-party transmission service formula rate.
Component 3
    Any charges or credits from the Host Control Area (HCA) applied to 
Western for providing this service will be passed through directly to 
the appropriate Customer in the same manner Western is charged or 
credited, to the extent possible. If the HCA charges or credits cannot 
be passed through to the appropriate Customer, the charges or credits 
will be passed through using Component 1 of the third-party 
transmission service formula rate.
    Billing: Third-party transmission will be billed monthly under the 
formula rate.
    Adjustments for Losses: All losses incurred for delivery of power 
under this rate schedule shall be the responsibility of the Customer 
that received the power.
    Adjustment for Audit Adjustments: Financial audit adjustments that 
apply to the revenue requirement under this rate schedule will be 
evaluated on a case-by-case basis to determine the appropriate 
treatment for repayment and cash flow management.

Rate Schedule CV-SPR3 (Supersedes Schedule CV-SPR2)

Central Valley Project; Schedule of Rate for Spinning Reserve Service

    Effective: January 1, 2005, through September 30, 2009.
    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 immediately to take load and is 
synchronized with the power system.
    Formula Rate: The provisional formula rate for spinning reserve 
service is the price consistent with the California Independent System 
Operator's market plus all costs incurred as a result of the sale of 
spinning reserves, such as: (1) The Western Area Power Administration's 
(Western) scheduling costs, (2) any charges or credits associated with 
the creation, termination, or modification to any tariff, contract, or 
rate schedule accepted or approved by the Federal Energy Regulatory 
Commission (Commission) or other regulatory body to which this rate 
methodology applies, and (3) any charges or credits from the Host 
Control Area applied to Western for providing this service.
    For Customers that have a contractual obligation to provide 
spinning reserve service to Western and do not fulfill that obligation, 
the penalty for nonperformance will be the greater of actual costs or 
150 percent of the market price.
    Billing: The formula rate above will be applied to the amount of 
spinning reserve sold. Billing will occur monthly.
    Adjustment for Audit Adjustments: Financial audit adjustments that 
apply to formula rate in this rate schedule will be evaluated on a 
case-by-case basis to determine the appropriate treatment for repayment 
and cash flow management.

Rate Schedule CV-SUR3 (Supersedes Schedule CV-SUR2)

Central Valley Project; Schedule of Rate for Non-Spinning Reserve 
Service

    Effective: January 1, 2005, through September 30, 2009.
    Available: Within the marketing area served by the Sierra Nevada 
Customer Service Region.

[[Page 70535]]

    Applicable: To Customers receiving non-spinning reserve service.
    Character and Conditions of Service: Non-spinning reserve service 
supplies capacity that is available within the first 10 minutes to take 
load and is synchronized with the power system.
    Formula Rate: The provisional formula rate for non-spinning reserve 
service is the price consistent with the California Independent System 
Operator's market plus all costs incurred as a result of the sale of 
spinning reserves, such as: (1) The Western Area Power Administration's 
(Western) scheduling costs, (2) any charges or credits associated with 
the creation, termination, or modification to any tariff, contract, or 
rate schedule accepted or approved by the Federal Energy Regulatory 
Commission or other regulatory body to which this rate methodology 
applies, and (3) any charges or credits from the Host Control Area 
applied to Western for providing this service.
    For Customers with a contractual obligation to provide non-spinning 
reserve service to Western and who do not fulfill that obligation, the 
penalty for nonperformance will be the greater of actual costs or 150 
percent of the market price.
    Billing: The formula rate above will be applied to the amount of 
non-spinning reserve sold. Billing will occur monthly.
    Adjustment for Audit Adjustments: Financial audit adjustments that 
apply to formula rate under this rate schedule will be evaluated on a 
case-by-case basis to determine the appropriate treatment for repayment 
and cash flow management.

Rate Schedule CV-RFS3 (Supersedes Schedule CV-RFS2)

Central Valley Project; Schedule of Rate for Regulation and Frequency 
Response Service

    Effective: January 1, 2005, through September 30, 2009.
    Available: Within the marketing area served by the Sierra Nevada 
Customer Service Region.
    Applicable: To Customers receiving Regulation and Frequency 
Response Service (Regulation).
    Character and Conditions of Service: Regulation is necessary to 
provide for the continuous balancing of resources and interchange with 
load and for maintaining scheduled interconnection frequency at 60 
cycles per second.
    Formula Rate: The provisional formula rate for Regulation includes 
three components:
Component 1
[GRAPHIC] [TIFF OMITTED] TN06DE04.012

    The annual regulating capacity is the total regulating capacity 
bandwidths provided by the Western Area Power Administration (Western) 
under the interconnected operations agreements with sub-control area 
(SCA) members. The penalty for nonperformance by an SCA Customer that 
has committed to self-provision for its regulating capacity requirement 
will be the greater of actual costs or 150 percent of the market price.
    Western will revise the rate resulting from Component 1 based on 
either of the following two conditions: (a) updated financial data 
available in March of each year, and (b) a change in the numerator or 
denominator that results in a rate change of at least $0.25 per 
kilowattmonth.
Component 2
    Any charges or credits associated with the creation, termination, 
or modification to any tariff, contract, or rate schedule accepted or 
approved by the Federal Energy Regulatory Commission (Commission) or 
other regulatory body will be passed on to each appropriate Customer. 
The Commission accepted or approved charges or credits apply to the 
service to which this rate methodology applies.
    When possible, Western will pass through directly to the 
appropriate Customer, the Commission or other regulatory body accepted 
or approved charges or credits in the same manner Western is charged or 
credited. If the Commission or other regulatory body accepted or 
approved charges or credits cannot be passed through directly to the 
appropriate Customer in the same manner Western is charged or credited, 
the charges or credits will be passed through using Component 1 of the 
regulation and frequency response service formula rate.
Component 3
    Any charges or credits from the Host Control Area (HCA) applied to 
Western for providing this service will be passed through directly to 
the appropriate Customer in the same manner Western is charged or 
credited, to the extent possible. If the HCA charges or credits cannot 
be passed through to the appropriate Customer in the same manner 
Western is charged or credited, the charges or credits will be passed 
through using Component 1 of the Regulation formula rate.
    Billing: The formula rate above will be applied to the regulating 
capacity bandwidth contained in the service agreement. Billing will 
occur monthly.
    Adjustment for Audit Adjustments: Financial audit adjustments that 
apply to the revenue requirement under this rate schedule will be 
evaluated on a case-by-case basis to determine the appropriate 
treatment for repayment and cash flow management.

Rate Schedule CV-EID3 (Supersedes Schedule CV-EID2)

Central Valley Project Schedule of Rate for Energy Imbalance Service

    Effective: January 1, 2005, through September 30, 2009.
    Available: Within the marketing area served by the Sierra Nevada 
Customer Service Region.
    Applicable: To Customers receiving energy imbalance service.
    Character and Conditions of Service: Energy imbalance service is 
provided when a difference occurs between the scheduled and the actual 
delivery of energy to a load or from a generation resource over an 
hour. The hourly deviation, in megawatts, is the net scheduled amount 
of energy for the hour minus the hourly net metered (actual delivered) 
amount.
    Energy imbalance service uses the regulating capacity bandwidth 
that is established in the service agreement.
    Formula Rate: The formula rate for Energy Imbalance Service has 
three components:
Component 1
    An hourly average negative deviation (underdelivery) outside the 
regulating capacity bandwidth will be charged the greater of 150 
percent of market price or actual cost. An hourly average positive 
deviation (overdelivery) outside the bandwidth is lost to the system.
Component 2
    Any charges or credits associated with the creation, termination, 
or modification to any tariff, contract, or rate schedule accepted or 
approved by the Federal Energy Regulatory Commission (Commission) or 
other regulatory body will be passed on to each appropriate Customer. 
The Commission accepted or approved charges or credits apply to the 
service to which this rate methodology applies.
    To the extent possible, the Western Area Power Administration 
(Western) will pass through directly to the appropriate Customer, the 
Commission or other regulatory body accepted or approved charges or 
credits in the same manner Western is charged or credited.

[[Page 70536]]

Component 3
    Any charges or credits from the Host Control Area applied to 
Western for providing this service will be passed through directly to 
the appropriate Customer in the same manner Western is charged or 
credited, to the extent possible.
    Billing: Billing for average hourly negative deviations outside the 
bandwidth will occur monthly.
    Adjustment for Audit Adjustments: Financial audit adjustments that 
apply to the formula rate under this rate schedule will be evaluated on 
a case-by-case basis to determine the appropriate treatment for 
repayment and cash flow management.

[FR Doc. 04-26628 Filed 12-3-04; 8:45 am]
BILLING CODE 6450-01-P