70510 Federal Register / Vol. 69, No. 233 / Monday, December 6, 2004 / Notices 

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.

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rate schedules are superseded.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 

ddietz@wapa.gov.

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 passthrough 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 nonfirm transmission rates are the same. A 

change from the existing to the 

provisional formula rate is the passthrough 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.

Federal Register / Vol. 69, No. 233 / Monday, December 6, 2004 / Notices 70511

COMPARISON OF EXISTING AND ESTIMATED RATES FROM THE PROVISIONAL FORMULA RATE CVP TRANSMISSION SERVICE

Existing 

rates 

Estimated 

rates from the 

provisional formula rate (effective 1/1/05) 

Percent 

change 

CVP Firm Transmission Rate ($/kWmonth) ................................................................................................ $0.57 $1.03 81 

CVP Non-Firm Transmission Rate (mills/kWh) ........................................................................................... 1.00 1.40 40 

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

Existing 

rates 

Estimated 

rates from the 

provisional formula rates (effective 1/1/05) 

Percent 

change 

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 passthrough 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

Ancillary service type Existing rates Rate from the provisional formula rates Change 

Scheduling and System Control 

and Dispatch Service.

Included in the appropriate transmission rates Included in the appropriate transmission rates N/A. 

Reactive Supply and Voltage Control Service.Included in the appropriate transmission rates Included in the appropriate transmission rates N/A. 

Spinning Reserve Service .............. $2.946 per kWmonth ...................................... Prices consistent with CAISO market ............. Varies. 

Non-Spinning Reserve Service ...... $2.491 per kWmonth ...................................... Prices consistent with CAISO market ............. Varies. 

Regulation and Frequency Response Service.$2.496 per kWmonth ...................................... $2.57 per kWmonth ........................................ 3%. 

70512 Federal Register / Vol. 69, No. 233 / Monday, December 6, 2004 / Notices 

COMPARISON OF EXISTING AND ESTIMATED RATES FROM THE PROVISIONAL FORMULA RATES CVP ANCILLARY

SERVICES—Continued

Ancillary service type Existing rates Rate from the provisional formula rates Change 

Energy Imbalance Service ............. Within Limits of Deviation Band: Accumulated 

deviations are to be corrected or eliminated 

within 30 days. Any net deviations that are 

accumulated at the end of the month (positive or negative) are to be exchanged in 

like hours of energy or charged at the composite rate then in effect for CVP firm 

power.

Within Limits of Deviation Band: There is no 

financial charge for deviations (energy) 

within the bandwidth.

Outside Limits of Deviation Band: Positive 

Deviations (overdelivery)—the greater of no 

charge, or any additional cost incurred. 

Negative Deviations (underdelivery)—during on-peak hours the greater of three 

times the composite rate then in effect for 

CVP firm power or any additional cost incurred. During off-peak hours the greater of 

the composite rate then in effect for CVP 

firm power or any additional cost incurred.

Outside the Limits of the Deviation Band: 

Positive Deviations (overdelivery)—for any 

hourly average positive deviation, the 

amount of deviation outside the bandwidth 

is lost to the system. Negative Deviations 

(underdelivery)—for any hourly average 

negative deviation, the amount of deviation 

outside the bandwidth is charged at the 

greater of 150 percent of market price or 

actual cost.

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 Commissionregulated, 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 

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

70514 Federal Register / Vol. 69, No. 233 / Monday, December 6, 2004 / Notices 

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 westcentral 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 

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

70516 Federal Register / Vol. 69, No. 233 / Monday, December 6, 2004 / Notices 

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

Power service Existing rate Provisional formula 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 Power Revenue Requirement.N/A. 

Custom Product Power ........................... N/A ......................................................... Pass Through ........................................ N/A. 

Cost-of-Service Study 

Western prepared a detailed cost-ofservice 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:

CVP TRR

TTc NITSc +

Where: 

TRR = Transmission revenue 

requirement. 

TTc = Total transmission capacity 

under ETCs. 


EN06DE04.000</GPH>
Federal Register / Vol. 69, No. 233 / Monday, December 6, 2004 / Notices 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:

COTP Seaso

Western s Share of

nal Transmission Revenue Requirement

’ COTP Seasonal Capacity

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-ofservice 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:

PACI Seaso

Western s PACI Sea

nal Transmission Revenue Requirement

’ sonal Capacity

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-ofservice 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 thirdparty 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 


EN06DE04.001</GPH> EN06DE04.002</GPH>
70518 Federal Register / Vol. 69, No. 233 / Monday, December 6, 2004 / Notices 

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

Existing rates 

(Note 1) 

Estimated rates 

from the provisional 

formula rates

(effective 1/1/05) 

Percent 

change 

CVP Firm Transmission Rate ($/kWmonth) ........................................................................... $0.57 $1.03 81

CVP Non-Firm Transmission Rate (mills/kWh) ...................................................................... 1.00 1.40 40 

CVP NITS Monthly Revenue Requirement ............................................................................ N/A $1,021,712 N/A 

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) nonspinning 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 nonfacility 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

Ancillary service type Existing rates Estimated rate under the provisional formula 

rates Change 

Scheduling and System Control 

and Dispatch Service.

Included in the appropriate transmission rates Included in the appropriate transmission rates N/A 

Reactive Supply Voltage Control 

Service.

Included in the appropriate transmission rates Included in the appropriate transmission rates N/A 

Spinning Reserve Service .............. $2.946 per kWmonth ...................................... Prices consistent with CAISO market ............. Varies 

Non-Spinning Reserve Service ...... $2.491 per kWmonth ...................................... Prices consistent with CAISO market ............. Varies 

Regulation and Frequency Response Service.$2.496 per kWmonth ...................................... $2.57 per kWmonth ........................................ 3% 

Federal Register / Vol. 69, No. 233 / Monday, December 6, 2004 / Notices 70519

COMPARISON OF EXISTING AND ESTIMATED RATES FROM THE PROVISIONAL FORMULA RATES CVP ANCILLARY

SERVICES—Continued

Ancillary service type Existing rates Estimated rate under the provisional formula 

rates Change 

Energy Imbalance Service ............. Within Limits of Deviation Band: Accumulated 

deviations are to be corrected or eliminated 

within 30 days. Any net deviations that are 

accumulated at the end of the month (positive or negative) are to be exchanged in 

like hours of energy or charged at the composite rate then in effect for CVP firm 

power.

Within Limits of Deviation Band: There is no 

financial charge for deviations (energy) 

within the bandwidth.

Outside Limits of Deviation Band: Positive 

Deviations (overdelivery)—the greater of no 

charge, or any additional cost incurred. 

Negative Deviations (underdelivery)—during on-peak hours the greater of three 

times the composite rate then in effect for 

CVP firm power or any additional cost incurred. During off-peak hours the greater of 

the composite rate then in effect for CVP 

firm power or any additional cost incurred.

Outside the Limits of the Deviation Band: 

Positive Deviations (overdelivery)—for any 

hourly average positive deviation, the 

amount of deviation outside the bandwidth 

(MWh) is lost to the system. Negative Deviations (underdelivery)—for any hourly average negative deviation, the amount of deviation outside the bandwidth (MWh) is 

charged at the greater of 150 percent of 

market price or actual cost.

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 

43⁄4-year provisional rate approval 

period. The table includes a comparison 

of existing rate data to provisional rate 

data and the difference.

PRS COMPARISON OF 43⁄4 YEAR RATE PERIOD (JAN 1, 2005–SEP 30, 2009), TOTAL REVENUES AND EXPENSES

Existing rate

(Note 1)

($000) 

Provisional

revenue requirement

($000) 

Difference

($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 

70520 Federal Register / Vol. 69, No. 233 / Monday, December 6, 2004 / Notices 

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:

First Pref

Gen Power Purc oject Use

erence Customer’s % = FP Customer Load

+ − hases Pr

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. 


EN06DE04.003</MATH>
Federal Register / Vol. 69, No. 233 / Monday, December 6, 2004 / Notices 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 lumpsum 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 

70522 Federal Register / Vol. 69, No. 233 / Monday, December 6, 2004 / Notices 

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

CVP transm

TTc NITSc

ission revenue requirement

+

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 


EN06DE04.004</MATH>
Federal Register / Vol. 69, No. 233 / Monday, December 6, 2004 / Notices 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 ThirdParty Transmission 

The provisional formula rate for thirdparty 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:

COTP Seaso

Western s Share of

nal Transmission Revenue Requirement

’ COTP Seasonal Capacity

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

Season Existing rate Estimated rates from the provisional

formula rate 

Percent

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

Season Existing rate Estimated rate from the provisional

formula rate 

Percent

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 


EN06DE04.005</MATH>
70524 Federal Register / Vol. 69, No. 233 / Monday, December 6, 2004 / Notices 

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

PACI Seaso

Western s PACI Sea

nal Transmission Revenue Requirement

’ sonal Capacity

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 nonfirm 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

Season Estimated monthly 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 thirdparty transmission, by the Customer 

receiving the Base Resource is 

consistent with the 2004 Power 

Marketing Plan and the appropriate 

method to recover such costs. 


EN06DE04.006</MATH>
Federal Register / Vol. 69, No. 233 / Monday, December 6, 2004 / Notices 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 thirdparty 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 Commissionapproved 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-topoint. 

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 NonSpinning Reserve 

The provisional formula rate for nonspinning reserve is the price consistent 

with the CAISO market plus all costs 

incurred as a result of the sale of nonspinning 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 

70526 Federal Register / Vol. 69, No. 233 / Monday, December 6, 2004 / Notices 

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

Annual Revenue Requirement

Annual Regulating Capacity kW

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, nonspinning 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 nonspinning 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 


EN06DE04.007</MATH>
Federal Register / Vol. 69, No. 233 / Monday, December 6, 2004 / Notices 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. Selfprovision 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

Service May 2003 per unit cost May 2004 per unit cost Percent

increase 

Scheduling and System Control and Dispatch ........................... $60.00/E-tag ............................ By contract ............................... N/A 

Reactive Power and Voltage Control .......................................... $0.07/kWmonth ........................ Assigned by transmission system.N/A 

Operating Reserve—Spinning .................................................... $0.31/kWmonth ........................ $3.30/kWmonth ........................ 965 

Operating Reserve—Supplemental Reserve Service (non-spin) $0.19/kWmonth ........................ $2.52/kWmonth ........................ 1226 

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

Service 

Revenue requirement with 

purchase 

costs 

Revised revenue requirement without 

purchase 

costs 

Regulation with Frequency Response Service ....................................................................................................... $2,277,692 $905,613 

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 

70528 Federal Register / Vol. 69, No. 233 / Monday, December 6, 2004 / Notices 

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 CaliforniaOregon 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, threephase, delivered and metered at the 

voltages and points established by 

contract. This service includes the 

Central Valley Project (CVP) 

transmission, spinning, and nonspinning 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:

Federal Register / Vol. 69, No. 233 / Monday, December 6, 2004 / Notices 70529

FP Customer Percentage = FP Customer Load

Gen Power Purc oject Use + − hases Pr

FP Customer Charge = FP Customer 

Percentage × 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

FP customers 

Maximum FP 

customer’s 

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 × 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

BR customer BR percentage 

from contract 

Hourly BR = 

30 MWh 

Customer’s 

BR in excess 

of load 

Customers receiving EE 

BR delivered 

(adjusting for 

EE) 

Revised BR 

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 


EN06DE04.008</MATH>
70530 Federal Register / Vol. 69, No. 233 / Monday, December 6, 2004 / Notices 

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, threephase, 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] 

CPP forecasted (MWh) 

Customer 

charged for 

CPP 

CPP RR Surplus CPP 

sales 

Proceeds from 

excess CPP 

sales 

Proceeds deposited into 

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.

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

CPP forecasted (MWh) CPP cost Surplus CPP 

Proceeds from 

excess CPP 

sales 

Charge per 

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] 

CPP purchased

(MWh) 

CPP used

(MWh) CPP costs Surplus CPP sold 

Proceeds from 

excess CPP 

sales 

CPP customer 

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

70532 Federal Register / Vol. 69, No. 233 / Monday, December 6, 2004 / Notices 

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

CVP TRR

TTc NITSc +

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 


En06de04.009</MATH>
Federal Register / Vol. 69, No. 233 / Monday, December 6, 2004 / Notices 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

COTP TRR

Western’s COTP Seasonal Capacity

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 CaliforniaOregon 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

PACI TRR

Western’s PACI Seasonal Capacity

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 


EN06DE04.010</MATH> EN06DE04.011</GPH>
70534 Federal Register / Vol. 69, No. 233 / Monday, December 6, 2004 / Notices 

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 thirdparty 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. 

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

Annual Revenue Requirement

Annual Regulating Capacity kW

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. 


EN06DE04.012</GPH>
70536 Federal Register / Vol. 69, No. 233 / Monday, December 6, 2004 / Notices 

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-bycase 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