50924 Federal Register / Vol. 62, No. 188 / Monday, September 29, 1997 / Notices

transmission rates on a nonexclusive

basis to the Administrator of Western;

(2) the authority to confirm, approve,

and place such rates into effect on an

interim basis to the Deputy Secretary;

and (3) the authority to confirm,

approve, and place into effect on a final

basis, to remand, or to disapprove such

rates to FERC. Existing DOE procedures

for public participation in power rate

adjustments (10 CFR Part 903) became

effective on September 18, 1985 (50 FR

37835).

These charges and rates are

established pursuant to section 302(a) of

the DOE Organization Act, 42 U.S.C.

§ 7152(a), through which the power

marketing functions of the Secretary of

the Interior and Reclamation under the

Reclamation Act of 1902, 43 U.S.C.

§ 371 et seq, as amended and

supplemented by subsequent

enactments, particularly section 9(c) of

the Reclamation Project Act of 1939, 43

U.S.C. § 485h(c), and other acts

specifically applicable to the project

system involved, were transferred to

and vested in the Secretary.

Dated: September 19, 1997.

Elizabeth A. Moler,

Deputy Secretary.

[FR Doc. 97–25749 Filed 9–26–97; 8:45 am]

BILLING CODE 6450–01–P

DEPARTMENT OF ENERGY

Western Area Power Administration

Central Valley Project and CaliforniaOregon Transmission Project—WAPA–

77

AGENCY: Western Area Power

Administration, DOE.

ACTION: Notice of rate order.

SUMMARY: Notice is given of the

confirmation and approval by the

Deputy Secretary of the Department of

Energy (DOE) of Rate Order No. WAPA–

77 and Rate Schedules CV–F9, CV–FT3,

CV–NFT3, CV–TPT4, CV–NWT1, CV–

PSS1, CV–RFS1, CV–EID1, CV–SPR1,

CV–SUR1, COTP–FT1, and COTP–NFT1

placing provisional rates for the Central

Valley Project (CVP) commercial firm

power and transmission services, power

scheduling service, and ancillary

services of the Western Area Power

Administration (Western), and placing

provisional rates for the CaliforniaOregon Transmission Project (COTP)

transmission services into effect on an

interim basis. The provisional rates, will

remain in effect on an interim basis

until the Federal Energy Regulatory

Commission (FERC) confirms, approves,

and places them into effect on a final

basis or until they are replaced by other

rates. The provisional rates will provide

sufficient revenue to pay all annual

costs, including interest expense, and

repayment of required investment

within the allowable period.

DATES: The provisional rates will be

placed into effect on an interim basis on

October 1, 1997, and will be in effect

until FERC confirms, approves, and

places the provisional rates in effect on

a final basis for a 5-year period ending

September 30, 2002, or until

superseded.

FOR FURTHER INFORMATION CONTACT: Ms.

Zola Jackson, Power Marketing

Manager, Western Area Power

Administration, Sierra Nevada

Customer Service Region, 114 Parkshore

Drive, Folsom, CA 95630–4710,

Telephone (916) 353–4421 or Mr. Joel K.

Bladow, Power Marketing Liaison

Office, Room 8G–027, 1000

Independence Avenue SW.,

Washington, DC 20585–0001,

Telephone (202) 586–5581.

SUPPLEMENTARY INFORMATION: The

Deputy Secretary of Energy, approved

the existing Rate Schedule CV–F8 for

CVP commercial firm power on

September 19, 1995 (Rate Order No.

WAPA–72, 60 FR 52671, October 10,

1995) and FERC confirmed and

approved the rate schedule on March

14, 1996, under FERC Docket No. EF95–

5012–000 (74 FERC ¶ 62,136). The

existing Rate Schedule CV–F8 became

effective on October 1, 1995, for the

period ending April 30, 1998, and is

being superseded by Rate Schedule CV–

F9. Under Rate Schedule CV–F8, the

composite rate on October 1, 1997, is

26.50 mills per kilowatt-hour (mills/

kWh), the base energy rate is 16.93

mills/kWh, the energy tier rate is 26.48

mills/kWh, and the capacity rate is

$4.58 per kilowatt-month (kW-month).

The provisional rates for CVP

commercial firm power in Rate

Schedule CV–F9 will result in an

overall composite rate of 20.95 mills/

kWh on October 1, 1997, and will result

in a decrease of approximately 21

percent when compared with the

existing CVP commercial firm power

rates under Rate Schedule CV–F8.

The Acting Assistant Secretary of

Energy, approved the existing Rate

Schedules CV–FT2, CV–NFT2, and CV–

TPT3 for CVP transmission services,

and the existing Rate Schedule CV–PC1

for peaking capacity service on April 12,

1993 (Rate Order No. WAPA–59, 58 FR

35933, July 2, 1993), and FERC

confirmed and approved the rate

schedules on September 22, 1993, under

FERC Docket No. EF93–5011–000 (64

FERC ¶ 61,332). The existing rate

schedules became effective on May 1,

1993, for the period ending April 30,

1998. Rate Schedule CV–PC1 is being

terminated effective October 1, 1997.

Rate Schedules CV–FT2, CV–NFT2, and

CV–TPT3 are being superseded by Rate

Schedules CV–FT3, CV–NFT3, and CV–

TPT4. Under Rate Schedules CV–FT2

and CV–NFT2, the CVP transmission

firm and non-firm services rates on

October 1, 1997, are $0.43 per kWmonth for firm service and 1.23 mills/

kWh for non-firm service. On October 1,

1997, the provisional rates in Rate

Schedules CV–FT3 and CV–NFT3 will

be $0.51 per kW-month for firm CVP

transmission service, an 18.6 percent

increase when compared with the

existing rate, and 1.00 mill/kWh for

non-firm CVP transmission service, an

18.7 percent decrease when compared

with the existing rate. The provisional

rate for transmission of CVP power by

others in Rate Schedule CV–TPT4 is a

direct pass through cost and will result

in no change on October 1, 1997, when

compared with the existing rate under

Rate Schedule CV–TPT3.

Since the COTP went into operation

in 1993, Western has sold COTP

transmission services on a short-term

basis using rates approved by the

Administrator of Western. Rate

schedules are being promulgated for

COTP firm and non-firm transmission

services to be consistent with FERC

Order No. 888. The provisional rates for

firm transmission service for Western’s

share of the COTP will result in 9.9

percent (FY 1998) and 34.0 percent (FY

1999 through FY 2002) reductions in the

existing rate of $2.03 per kW-month.

The provisional rates are $1.83 per kWmonth for FY 1998 and $1.34 per kWmonth for FY 1999 through FY 2002.

The provisional rates for non-firm COTP

transmission service will result in 21.2

percent (FY 1998) and 47.8 percent (FY

1999 through FY 2002) reductions in the

existing rate of 2.78 mills/kWh. The

provisional rates are 2.19 mills/kWh for

FY 1998 and 1.45 mills/kWh for FY

1999 through FY 2002.

Power scheduling service, network

transmission service, and ancillary

services are new services. The

provisional rates are designed to recover

only the cost incurred for providing the

services.

Provisional Rates for CVP Commercial

Firm Power

The provisional rates for CVP

commercial firm power are designed to

recover an annual revenue requirement

that includes the investment repayment,

interest, purchase power, and operation

and maintenance expense. A cost of

service study was used to allocate the
Federal Register / Vol. 62, No. 188 / Monday, September 29, 1997 / Notices 50925

projected annual revenue requirement

for commercial firm power between

capacity and energy. Based on this

study the capacity revenue requirement

includes 100 percent of capacity

purchase costs, 50 percent of the CVP

investment repayment, interest expense,

and power operation and maintenance

expense allocated to commercial power,

and 100 percent of purchased

transmission service expense. These

annual costs are reduced by the

projected revenue from sales of CVP

transmission to determine the capacity

revenue requirement. The energy

revenue requirement includes 100

percent of energy purchase costs and 50

percent of the CVP investment

repayment, interest expense, and power

operation and maintenance expense

allocated to commercial power. These

annual costs are reduced by the

projected revenue from sales of surplus

power to determine the energy revenue

requirement.

The provisional rates will also

include an Annual Energy Rate

Alignment (AERA). The AERA will be

applied to energy purchases from

Western under Rate Schedule CV–F9 at

or above an average annual load factor

of 80 percent, calculated at the end of

each fiscal year. The AERA will provide

revenues to cover the increased costs of

purchased energy. The AERA is the

difference between the estimated rate

for short-term energy purchases used in

the cost of service study for CVP

commercial firm power and the

provisional CVP energy rate. The AERA

is in addition to the provisional CVP

energy rate and replaces the existing

energy tier rate in Rate Schedule CV–F8.

Adjustment Clauses Associated With

the Provisional Rates for CVP

Commercial Firm Power

Adjustments for power factors, low

voltage losses, and revenue were

included in Rate Schedule CV–F8, and

will be continued in Rate Schedule CV–

F9.

Power Factor Adjustment

The power factor adjustment is

included in Rate Schedule CV–F9. The

low power factor charge or LPF Charge

is a charge that will be applied when the

customer does not maintain a calculated

95 percent or greater power factor.

Low Voltage Loss Adjustment

A 1.035 loss adjustment factor will be

applied to the billed amounts for low

voltage CVP commercial firm power

deliveries on the Pacific Gas and

Electric system.

Revenue Adjustment

The revenue adjustment clause or

RAC, is included in Rate Schedule CV–

F9. The RAC, tracks variances in future

revenues and expenses, and lessens the

probability of significant revenue

surplus or deficit to the CVP repayment.

The methodology for computing the

RAC is a comparison of estimated total

revenues less estimated total expenses

to actual total revenues less actual total

expenses.

Provisional Rates for CVP Transmission

Services

The provisional rates in Rate

Schedules CV–FT3 and CV–NFT3 for

CVP transmission services are based on

a revenue requirement that recovers: (1)

The CVP transmission system costs for

facilities associated with providing all

transmission services; and (2) the nonfacility costs allocated to transmission

services. These provisional firm and

non-firm CVP transmission service rates

include the costs for scheduling, system

control and dispatch service, and

reactive supply and voltage control

service needed to provide the

transmission service. The provisional

rates are applicable to existing firm and

non-firm CVP transmission services and

future point-to-point transmission

services. The rates charged for firm and

non-firm CVP transmission services for

a period of one year or less will be no

higher than the provisional rates.

Provisional Rate for Transmission of

CVP Power by Others

Transmission service costs incurred

by Western in the delivery of CVP

power over a third party’s transmission

system to a CVP customer, will be

directly passed through to that CVP

customer. The provisional rate in Rate

Schedule CV–TPT4 is proposed to be

automatically adjusted as third party

transmission costs are adjusted.

Provisional Rate Formula for Network

Transmission Service

Network transmission service, if

offered by Western, will be made

available consistent with FERC Order

No. 888. Due to existing contractual

arrangements and not being a control

area operator for the CVP, Western may

not be able to provide network

transmission service but has included a

rate formula in case Western offers the

service. The provisional rate formula

includes the costs for scheduling,

system control and dispatch service,

and reactive supply and voltage control

service needed to provide network

transmission service.

Provisional Rate for Power Scheduling

Service

Power scheduling is a new service

being offered by Western that provides

for the scheduling of resources to meet

loads and reserve requirements. The

provisional rate for power scheduling

service is designed to recover only the

cost incurred for providing the service.

Provisional Rates for Ancillary Services

Western will provide six ancillary

services consistent with FERC Order No.

888. Of the six ancillary services offered

by Western, two will be provided in

conjunction with the sale of CVP and/

or COTP transmission services. These

are scheduling, system control and

dispatch service, and reactive supply

and voltage control service. The

remaining four ancillary services,

regulation and frequency response

service, energy imbalance service,

spinning reserve service, and

supplemental reserve service will be

offered subject to availability. The

availability and type of ancillary service

will be determined based on excess

resources available at the time the

service is requested, except for the two

ancillary services provided in

conjunction with the sale of CVP and/

or COTP transmission services. The

costs associated with scheduling,

system control and dispatch service,

and for reactive supply and voltage

control service are included in the

appropriate transmission services rates.

Provisional Rates for COTP

Transmission Services

The provisional rates in Rate

Schedules COTP–FT1 and COTP–NFT1

for COTP transmission services include

a revenue requirement that recovers the

costs associated with: (1) Western’s

participation in the COTP; and (2)

scheduling, system control and dispatch

service, and reactive supply and voltage

control service needed to provide the

transmission service. The rates are

applicable to existing firm and non-firm

COTP transmission services and future

point-to-point transmission services.

The rates charged for firm and non-firm

COTP transmission services for a period

of one year or less will be no higher

than the provisional rates.

The provisional rates for CVP

commercial firm power and

transmission services, power scheduling

service, ancillary services, and for COTP

transmission services are developed

pursuant to the Department of Energy

Organization Act (42 U.S.C. 7101 et

seq.), through which the power

marketing functions of the Secretary of

the Interior and the Bureau of
50926 Federal Register / Vol. 62, No. 188 / Monday, September 29, 1997 / Notices

Reclamation under the Reclamation Act

of 1902 (43 U.S.C. 371 et seq.), as

amended and supplemented by

subsequent enactments, particularly

section 9(c) of the Reclamation Project

Act of 1939 (43 U.S.C. 485h(c)), and

other acts specifically applicable to the

project involved, were transferred to

and vested in the Secretary of Energy.

By Amendment No. 3 to Delegation

Order No. 0204–108, published

November 10, 1993, (58 FR 59716), the

Secretary of Energy delegated: (1) The

authority to develop long term power

and transmission rates on a

nonexclusive basis to the Administrator

of Western; (2) the authority to confirm,

approve, and place such rates into effect

on an interim basis to the Deputy

Secretary of Energy; and (3) the

authority to confirm, approve, and place

into effect on a final basis, to remand,

or to disapprove such rates to the FERC.

Existing DOE procedures for public

participation in power rate adjustments

are located at 10 CFR Part 903, effective

on September 18, 1985 (50 FR 37835).

The Procedures for Public

Participation in Power and

Transmission Rate Adjustments and

Extensions, 10 CFR part 903, have been

followed by Western in the

development of these provisional rates.

Rate Order No. WAPA–77,

confirming, approving, and placing the

proposed CVP commercial firm power

and transmission services rates, power

scheduling service, ancillary services,

and the COTP transmission services

rates into effect on an interim basis, is

issued, and the new Rate Schedules CV–

F9, CV–FT3, CV–NFT3, CV–TPT4, CV–

NWT1, CV–PSS1, CV–RFS1, CV–EID1,

CV–SPR1, CV–SUR1, COTP–FT1, and

COTP–NFT1 will be submitted

promptly to FERC for confirmation and

approval on a final basis.

Dated: September 19, 1997.

Elizabeth A. Moler,

Deputy Secretary.

Order Confirming, Approving, and

Placing the Central Valley Project;

Commercial Firm Power and

Transmission Services Rates, Power

Scheduling Service and Ancillary

Services Rates, and the CaliforniaOregon Transmission Project

Transmission Services Rates Into Effect

on an Interim Basis

October 1, 1997.

These rates are developed pursuant to

the Department of Energy Organization

Act (42 U.S.C. 7101 et seq.), through

which the power marketing functions of

the Secretary of the Interior and the

Bureau of Reclamation under the

Reclamation Act of 1902 (43 U.S.C. 371

et seq.), as amended and supplemented

by subsequent enactments, particularly

section 9(c) of the Reclamation Project

Act of 1939 (43 U.S.C. 485h(c)), and

other acts specifically applicable to the

project involved, were transferred to

and vested in the Secretary of the

Department of Energy (DOE).

By Amendment No. 3 to Delegation

Order No. 0204–108, published

November 10, 1993 (58 FR 59716), the

Secretary of Energy delegated: (1) The

authority to develop long term power

and transmission rates on a

nonexclusive basis to the Administrator

of the Western Area Power

Administration; (2) the authority to

confirm, approve, and place such rates

into effect on an interim basis to the

Deputy Secretary of Energy; and (3) the

authority to confirm, approve, and place

into effect on a final basis, to remand,

or to disapprove such rates to the

Federal Energy Regulatory Commission

(FERC). Existing DOE procedures for

public participation in power rate

adjustments are located at 10 CFR part

903.

Acronyms and Definitions

As used in this rate order, the

following acronyms and definitions

apply:

Administrator: The Administrator of

Western Area Power Administration.

AERA: Annual energy rate alignment.

An energy rate applied at the end of

each fiscal year to all energy

purchases under Rate Schedule CV–

F9 at or above an annual load factor

of 80 percent.

Ancillary Services: Those services

necessary to support the transfer of

electricity while maintaining reliable

operation of the transmission system

in accordance with good utility

practice. Ancillary services are

generally described in Federal Energy

Regulatory Commission Order No.

888, Docket Nos. RM95–8–000 and

RM94–7–001, issued April 24, 1996.

California-Oregon Transmission Project

(COTP): The 500-kilovolt

transmission project in which

Western has part ownership.

Capacity: The electric capability of a

generator, transformer, transmission

circuit or other equipment. It is

expressed in kW.

Capacity Rate: The rate which sets forth

the charges for capacity. It is

expressed in $ per kW-month and

applied to each kW delivered to each

customer.

Central Valley Project (CVP): A

multipurpose Federal water

development project extending from

the Cascade Range in northern

California to the plains along the Kern

River south of the City of Bakersfield.

Composite Rate: The rate for

commercial firm power and is the

total annual revenue requirement for

capacity and energy divided by the

total annual energy sales. It is

expressed in mills/kWh and used for

comparison purposes.

Contract 2947A: Western’s contract with

Pacific Gas and Electric, Southern

California Edison, and San Diego Gas

and Electric Companies for extra high

voltage transmission and exchange

service; Contract No. 14–06–200–

2947A, as amended.

Contract 2948A: Pacific Gas and Electric

Company’s contract with Western for

the sale, interchange and transmission

of power; Contract No. 14–06–200–

2948A, as amended.

Corps: United States Army Corps of

Engineers.

CRD: Contract rate of delivery. The

maximum amount of capacity made

available to a preference customer for

a period specified under a contract.

Customer: An entity with a contract and

receiving service from Western’s

Sierra Nevada Region.

DOE: United States Department of

Energy.

DOE Order RA6120.2: An order dealing

with power marketing administration

financial reporting and rate making

procedure.

EA2: Energy Bank Account No. 2

between Western and PG&E under

Contract 2948A.

Energy: Measured in terms of the work

it is capable of doing over a period of

time. It is expressed in kWh.

Energy Rate: The rate which sets forth

the charges for energy. It is expressed

in mills/kWh and applied to each

kWh delivered to each customer.

Energy Tier Rate: Existing energy rate in

Rate Schedule CV–F8 applied to

energy sales at a 70 percent and

higher monthly load factor.

FERC: Federal Energy Regulatory

Commission.

Firm: A type of product and/or service

that is available at the time requested

by the customer.

First Preference Customer: An entity

qualified to use preference power

within a county of origin (Trinity,

Calaveras and Tuolumne) as specified

under the Trinity River Division Act

of August 12, 1955 (69 Stat. 719), and

the Flood Control Act of 1962 (76

Stat. 1180).

FY: Fiscal year; October 1 to September

30.

Interior: United States Department of

the Interior.

Intertie: Pacific Northwest-Pacific

Southwest Intertie.
Federal Register / Vol. 62, No. 188 / Monday, September 29, 1997 / Notices 50927

kV: Kilovolt—the electrical unit of

measure of electric potential that

equal one thousand volts.

kvar: Kilovolt-ampere reactive—the

electrical unit of measurement for

reactive power in a circuit that equals

one thousand volt-amperes.

kW: Kilowatt—the electrical unit of

capacity that equal one thousand

watts.

kW-month: The electrical unit of the

monthly amount of capacity.

kWh: Kilowatt-hour—the electrical unit

of energy that equals one thousand

watts in one hour.

Load Factor: The ratio of average load in

kW supplied during a designated

period to the peak or maximum load

in kW occurring in that period.

LPF Charge: Low power factor charge.

Mill: A monetary denomination of the

United States that equal one tenth of

a cent or one thousandth of a dollar.

Mills/kWh: Mills per kilowatt-hour—the

unit of charge for energy.

MW: Megawatt—the electrical unit of

capacity that equal one million watts

or one thousand kilowatts.

NEPA: National Environmental Policy

Act of 1969 (42 U.S.C. 4321 et seq.).

Net Revenue: Revenue remaining after

paying all annual expenses.

Non-Firm: A type of product and/or

service that is not always available at

the time requested by the customer.

Northwest: Northwest United States.

O&M: Operation and maintenance.

PG&E: Pacific Gas and Electric

Company.

Power: Capacity and energy.

Power Factor: The ratio of real to

apparent power at any given point

and time in an electrical circuit.

Generally it is expressed as a

percentage ratio.

Power Scheduling Service: A service

that provides for the scheduling of

resources to meet loads and reserve

requirements.

Preference: The requirements of

Reclamation law which provide that

preference in the sale of Federal

power shall be given to municipalities

and other public corporations or

agencies and also to cooperatives and

other nonprofit organizations

financed in whole or in part by loans

made pursuant to the Rural

Electrification Act of 1936

(Reclamation Project Act of 1939,

section 9(c), 43 U.S.C. 485h(c)).

Project Use: Power as defined by

Reclamation law and/or used to

operate CVP facilities.

Provisional Rates: Rates which have

been confirmed, approved, and placed

in effect on an interim basis by the

Deputy Secretary of the Department of

Energy.

PRS: Power repayment study.

RAC: Revenue Adjustment Clause.

Rate Brochure: A document prepared

for public distribution explaining the

rationale and background of the rate

proposal contained in this rate order

dated March 25, 1996.

Reclamation: United States Department

of the Interior, Bureau of Reclamation.

Reclamation Law: A series of Federal

laws. Viewed as a whole, these laws

create the originating framework in

which the Western Area Power

Administration markets power.

Revenue Requirement: The revenue

required to recover O&M expenses,

purchase power and transmission

service expenses, interest, deferred

expenses, and repayment of Federal

investments, or other assigned costs.

Sierra Nevada Region: The Sierra

Nevada Customer Service Region of

Western Area Power Administration.

Secretary: Secretary of Energy.

Western: United States Department of

Energy, Western Area Power

Administration.

Withdrawable: Power that may be

withdrawn under certain conditions.

Effective Date

The new rates will become effective

on an interim basis on the first day of

the first full billing period beginning on

or after October 1, 1997, and will be in

effect pending FERC’s approval of them

or substitute rates on a final basis for a

5-year period ending September 30,

2002, or until superseded.

Public Notice and Comment

The Procedures for Public

Participation in Power and

Transmission Rate Adjustments and

Extensions, 10 CFR part 903, have been

followed by Western in the

development of these rates. The

following summarizes the steps Western

took to ensure involvement of interested

parties in the rate process:

1. The proposed rate adjustment was

initiated on May 1, 1996, when a letter

announcing the first of four informal

customer workshops was mailed to all

CVP customers. The first workshop was

held on May 13, 1996, in Folsom,

California. Sequential workshops were

held on August 21, October 25, and

December 17, 1996, in Folsom,

California. At these informal workshops,

Western explained the rationale for the

rate adjustment, presented rate designs

and methodologies, and answered

questions.

2. A Federal Register notice was

published on March 4, 1997 (62 FR

9763), officially announcing the

proposed rates for the CVP and COTP,

initiating the public consultation and

comment period, and announcing the

public information and public comment

forums.

3. On March 7, 1997, letters were

mailed from Western’s Sierra Nevada

Regional Office to all CVP preference

customers and interested parties

transmitting the Federal Register notice

of March 4, 1997, and announced the

times and locations for the two public

forums.

4. On March 25, 1997, beginning at 9

a.m. PST, the public information forum

was held at Western’s Sierra Nevada

Regional Office in Folsom, California.

At the public information forum

Western provided detailed explanations

of the proposed rates for the CVP and

COTP, provided a list of issues that

could change the proposed rates, and

answered questions. Notice was given

that additional information would be

provided at the public comment forum.

A rate brochure and an information

handout were provided at the forum.

5. On April 24, 1997, beginning at 9

a.m. PDT, the public comment forum

was held at Western’s Sierra Nevada

Regional Office in Folsom, California.

At the start of the forum, Western

presented the updated rates for the CVP

and COTP, provided a detailed

explanation of the changes to the

proposed rates, and answered questions.

A handout containing information

regarding the updated rates was

provided. After providing this

information, Western gave the public an

opportunity to comment for the record.

Three representatives made oral

comments.

6. Twelve comment letters were

received during the consultation and

comment period. The consultation and

comment period ended June 2, 1997. All

formally submitted comments have been

considered in the preparation of this

rate order.

Project History

The CVP is a large water and power

system, initially authorized by Congress

in 1935, which covers approximately

one-third of the State of California.

Legislatively defined purposes set the

priorities for the CVP as: (1) River

regulation; (2) improvement of

navigation; (3) flood control; (4)

irrigation; (5) domestic uses; and (6)

power. In addition, the CVP

Improvement Act of 1992 added fish

and wildlife habitat as a priority to the

list of CVP purposes.

The CVP is located within the Central

Valley and Trinity River basins of

California. The CVP includes 18 dams

and reservoirs with a total storage

capacity of 13 million acre-feet. The

system includes 615 miles of canals, 5
50928 Federal Register / Vol. 62, No. 188 / Monday, September 29, 1997 / Notices

pumping facilities, 11 powerplants with

a maximum operating capability of

about 2,044 MW, approximately 948

circuit-miles of high voltage

transmission lines, 15 substations, and

23 communication sites. Reclamation

operates the water control and delivery

system and all of the powerplants with

the exception of the San Luis Unit,

which is operated by the State of

California for Reclamation.

The Emergency Relief Appropriations

Act of 1935 initially authorized the CVP

to be constructed by Reclamation to

include Shasta Dam on the Sacramento

River in the north and Friant Dam on

the San Joaquin River in the south.

Located between these are the Tracy

Pumping Plant; the Delta-Mendota,

Contra Costa, Friant-Kern, and Madera

canals; and the Delta Cross Channel.

Powerplants at Shasta and Keswick

dams were also included in the initial

authorization, along with high voltage

transmission lines designed to transmit

power from Shasta and Keswick

powerplants to the Tracy pumps, and to

integrate the Federal hydropower into

other electric systems.

In 1944, Congress authorized the

American River Division, to be

constructed by the Corps. This Division

included Folsom Dam and Powerplant,

Nimbus Dam and Powerplant, and the

Sly Park Unit, all located on the

American River. In 1949, the Division

was reauthorized for integration into the

CVP.

The Trinity River Division was

authorized by Congress in 1955 to

include Trinity Dam and Powerplant,

Lewiston Dam and Powerplant, and the

Lewiston Fish Facilities, all located on

the Trinity River. The Trinity Division

also includes Judge Francis Carr

Powerplant, Whiskeytown Dam, and the

Spring Creek Powerplant.

The San Luis Unit, including the B.F.

Sisk San Luis Dam and San Luis

Reservoir, San Luis Canal, Coalinga

Canal, O’Neill and Dos Amigos

pumping plants, and William R.

Gianelli Pump-Generator, was

authorized by Congress in 1960.

In 1965, Congress authorized

construction of the Auburn-Folsom

South Unit as an addition to the CVP.

This unit included four subunits, three

of which have been constructed; the

Foresthill, Folsom-Malby, and Folsom

South Canal subunits. Funding to

complete the construction of the

Auburn Dam, Reservoir and Powerplant,

which is part of the fourth subunit, has

not been authorized by Congress.

Congress authorized the San Felipe

Division in 1967, and the Allen Camp

Unit in 1976.

Three Corps projects, Buchannan,

Hidden, and New Melones, were

authorized for integration into the CVP

in 1962. Black Butte, another Corps

project completed in the 1960’s, was

added to the CVP in 1970 by the Black

Butte Integration Act.

In 1964, Congress authorized the 500-

kV Intertie, of which Western has a 400

MW entitlement of transmission

capacity. On July 31, 1967, Western,

PG&E, Southern California Edison

Company, and San Diego Gas & Electric

Company entered into Contract 2947A,

as amended, to coordinate the operation

of the Intertie for the purpose of

transmitting electric power between the

Northwest and the Pacific Southwest.

Western, in marketing the Federal

hydroelectric power generated from the

CVP, currently has 80 CVP preference

and 34 CVP project use customers,

serving an estimated two million

people.

In 1967, PG&E and Western executed

Contract 2948A. This contract provides

for the sale, interchange, and

transmission of electric capacity and

energy between Western and PG&E.

Contract 2948A also includes provisions

for the integration of power generated

from the CVP with the 400 MW of

entitlement on the Intertie. The contract

also provides that PG&E will support a

maximum simultaneous demand of

1,152 MW for the preference customers

through 2004. If CVP power cannot meet

obligations to the preference customers,

Contract 2948A provides Western with

the right to purchase capacity and

energy from PG&E to meet those

requirements. Any energy in excess of

Western’s obligations to preference

customers can be sold to PG&E through

a banking provision in the contract. The

energy made available under this

banking arrangement allows Western to

supplement CVP generation to meet

preference customer load.

Power generated from the CVP is first

dedicated to project use. The remaining

power is allocated to various preference

customers in California. Preference

customers consist of: (1) Irrigation and

water districts; (2) public utility

districts; (3) municipalities; (4) Federal

agencies; (5) State agencies; (6) rural

electric cooperatives; (7) local and

suburban passenger transportation

entities; and (8) joint power authorities.

Each preference customer’s CRD is

composed of firm long-term power

allocations, and may include

withdrawable allocations that are

currently allocated, but unused by

another customer. For this rate

adjustment it is assumed that all

customer withdrawable CRDs can be

withdrawn in the event the load level of

1,152 MW set forth in Contract 2948A

is exceeded.

Western’s preference customer load

level is limited under Contract 2948A to

a maximum simultaneous demand,

excluding project loads, of 1,152 MW.

The maximum simultaneous demand is

the sum of each preference customer’s

demand for CVP power at a coincidental

moment, adjusted to the load center at

the Tracy Switchyard. Notwithstanding

the simultaneous demand limit,

Western has contractual obligations to

serve approximately 1,470 MW of firm

CRD to its preference customers. This

level of CRD can be served because of

the diversity in customers’ loads.

The COTP is a 342-miles long 500-kV

transmission project that electrically

interconnects the Northwest to

California with what is called the Third

AC Intertie. Operational since March

1993, the COTP interconnects with the

transmission systems of the Northwest

at the Captain Jack Substation, and with

the Pacific Southwest by its connection

near the Tesla Substation to the existing

Intertie. The project owners include

Western as well as several non-Federal

participants.

Power Repayment Study

Power repayment studies are prepared

each fiscal year to determine if power

revenues will be sufficient to pay,

within the prescribed time periods, all

costs assigned to the CVP power

function. Repayment criteria are based

on law, policies, and authorizing

legislation. DOE Order RA6120.2,

section 12b, requires that:

In addition to the recovery of the

above costs (operation and maintenance

and interest expenses) on a year-by-year

basis, the expected revenues are at least

sufficient to recover: (1) Each dollar of

power investment at Federal

hydroelectric generating plants within

50 years after they become revenue

producing, except as otherwise

provided by law; plus, (2) each annual

increment of Federal transmission

investment within the average service

life of such transmission facilities or

within a maximum of 50 years,

whichever is less; plus, (3) the cost of

each replacement of a unit of property

of a Federal power system within its

expected service life up to a maximum

of 50 years; plus, (4) each dollar of

assisted irrigation investment within the

period established for the irrigation

water users to repay their share of

construction costs.

CVP Transmission Service Rate Study

Transmission service rates are

charged to CVP customers receiving

transmission services over the CVP
Federal Register / Vol. 62, No. 188 / Monday, September 29, 1997 / Notices 50929

system for the transmission of non-CVP

power. A transmission service rate

study was prepared to ensure that

transmission service rates are based on

the cost of service of the CVP

transmission system.

A review of the CVP transmission

service rate study indicated that the

existing firm and non-firm CVP

transmission service rates under Rate

Schedules CV–FT2 and CV–NFT2,

needed to be adjusted. The provisional

rate for firm CVP transmission service is

$0.51 per kW-month, an 18.6 percent

increase from the existing rate of $0.43

per kW-month. The provisional rate for

non-firm CVP transmission service is

1.00 mill/kWh, an 18.7 percent

reduction in the existing 1.23 mills/kWh

rate. The change in the firm CVP

transmission service rate is due to

increases in transmission facilities costs

and in the basis for assigning

miscellaneous and non-facility

investment and O&M costs to

transmission to better reflect costs

associated with transmission for all

users. The change in the non-firm CVP

transmission service rate is primarily

due to a change in the load factor used

in determining the denominator in the

rate calculation. The same revenue

requirement is used in determining the

firm and non-firm CVP transmission

service rates.

Existing and Provisional Rates

CVP Commercial Firm Power

The provisional rates for CVP

commercial firm power are designed to

recover an annual revenue requirement

that includes the investment repayment,

interest, purchase power, and O&M

expenses. The provisional rates will also

include an AERA. The AERA will be

applied to energy purchases from

Western under Rate Schedule CV–F9 at

or above an average annual load factor

of 80 percent, calculated at the end of

each fiscal year. The AERA will provide

revenues to cover the increased costs of

purchased energy. The AERA is in

addition to the provisional CVP energy

rate and replaces the existing energy tier

rate.

A comparison of the existing and

provisional rates for CVP commercial

firm power follows:

COMPARISON OF EXISTING AND PROVISIONAL RATES

CVP Commercial firm power rate schedule

Effective period

Existing

(effective

10/01/97 to

04/30/98)

Provisional

Percent

change

from existing rate

Composite Rate (mills/kWh):

10/01/97 to 04/30/98 ......................................................................................................................... 26.50 20.95 (21)

05/1/98 to 09/30/98 ........................................................................................................................... .................... 20.95 (21)

10/01/98 to 09/30/99 ......................................................................................................................... .................... 19.31 (27)

10/01/99 to 09/30/00 ......................................................................................................................... .................... 19.31 (27)

10/01/00 to 09/30/01 ......................................................................................................................... .................... 18.56 (30)

10/01/01 to 09/30/02 ......................................................................................................................... .................... 20.08 (24)

Capacity Rate ($ per kW-month):

10/01/97 to 04/30/98 ......................................................................................................................... 4.58 5.03 10

5/1/98 to 09/30/98 ............................................................................................................................. .................... 5.03 10

10/01/98 to 09/30/99 ......................................................................................................................... .................... 4.37 (5)

10/01/99 to 09/30/00 ......................................................................................................................... .................... 4.31 (6)

10/01/00 to 09/30/01 ......................................................................................................................... .................... 3.81 (17)

10/01/01 to 09/30/02 ......................................................................................................................... .................... 4.02 (12)

Energy Rate (mills/kWh):

10/01/97 to 04/30/98 ......................................................................................................................... 16.93 10.31 (39)

05/1/98 to 09/30/98 ........................................................................................................................... .................... 10.31 (39)

10/01/98 to 09/30/99 ......................................................................................................................... .................... 10.06 (41)

10/01/99 to 09/30/00 ......................................................................................................................... .................... 10.19 (40)

10/01/00 to 09/30/01 ......................................................................................................................... .................... 10.51 (38)

10/01/01 to 09/30/02 ......................................................................................................................... .................... 11.58 (32)

AERA Rate (mills/kWh) supersedes existing energy tier rate in Rate Schedule CV–F8.1

10/01/97 to 04/30/98 ......................................................................................................................... (2) 2.86 ....................

05/1/98 to 09/30/98 ........................................................................................................................... (2) 2.86 ....................

10/01/98 to 09/30/99 ......................................................................................................................... (2) 3.57 ....................

10/01/99 to 09/30/00 ......................................................................................................................... (2) 3.92 ....................

10/01/00 to 09/30/01 ......................................................................................................................... (2) 4.09 ....................

10/01/01 to 09/30/02 ......................................................................................................................... (2) 3.53 ....................

1The existing energy tier rate under Rate Schedule CV–F8 is 26.48 mills/kWh and is effective for the period October 1, 1997, to April 30,

1998. 2 None.

CVP Transmission Services and Transmission of CVP Power by Others

A comparison of the existing and provisional rates for CVP transmission services and for transmission of CVP

power by others follows:
50930 Federal Register / Vol. 62, No. 188 / Monday, September 29, 1997 / Notices

COMPARISON OF EXISTING AND PROVISIONAL RATES

CVP Transmission rate schedules

Effective period

Existing

(effective

10/01/97 to

04/30/98)

Provisional

Percent

change

from existing rate

Firm Transmission Rate ($ per kW-month);

10/01/97 to 04/30/98 ......................................................................................................................... 0.43 0.51 18.6

05/1/98 to 09/30/02 ........................................................................................................................... .................... 0.51 18.6

Non-Firm Transmission Rate (mills/kWh):

10/01/97 to 04/30/98 ......................................................................................................................... 1.23 1.00 (18.7)

05/1/98 to 09/30/02 ........................................................................................................................... .................... 1.00 (18.7)

Transmission of CVP Power by Others Rate Schedule:

10/01/97 to 04/30/98 ......................................................................................................................... (1) (1) (2)

05/1/98 to 09/30/02 ........................................................................................................................... (1) (1) (2)

1Pass through cost.

2 Not applicable.

Network Transmission Service

The provisional rate formula for network transmission service, if offered by Western, is the product of the network

customer’s load ratio share times one twelfth (1⁄12) of the annual network transmission revenue requirement. The load

ratio share is based on the network customer’s hourly load, including its designated network load not physically interconnected with the CVP transmission system, coincident with Western’s monthly CVP transmission system peak minus

coincident peak usage of all firm CVP (including reserved capacity) point-to-point transmission service. The provisional

network transmission service rate formula includes the cost for scheduling, system control and dispatch service, and

reactive supply and voltage control services associated with the transmission service. The provisional rate is effective

for the period beginning October 1, 1997, through September 30, 2002.

Power Scheduling Service

Power scheduling service is a new service being offered by Western that provides for the scheduling of resources

to meet load and reserve requirements. The provisional rate for power scheduling service is $75.80 per hour and

will be applied based on an estimated time to provide the service to each customer receiving the service. The provisional

rate is effective for the period beginning October 1, 1997, through September 30, 2002.

Ancillary Services

Of the six ancillary services offered by Western, two will be provided in conjunction with the sale of CVP and/

or COTP transmission services. These are scheduling, system control and dispatch service, and reactive supply and

voltage control service. The remaining four ancillary services, regulation and frequency response service, energy imbalance

service, spinning reserve service, and supplemental reserve service will be offered subject to availability. The availability

and type of ancillary service will be determined based on excess resources available at the time the service is requested,

except for the two ancillary services provided in conjunction with the sale of CVP and/or COTP transmission services.

The provisional rates and descriptions for the six ancillary services are as follow:

PROVISIONAL RATES

Ancillary services rate schedules

Ancillary service type Rate

Scheduling, System Control and Dispatch Service—is required to

schedule the movement of power through, out of, within, or into a

control area.

Included in appropriate transmission rates.

Reactive Supply and Voltage Control Service—is reactive power support provided from generation facilities that is necessary to maintain

transmission voltages within acceptable limits of the system.

Included in appropriate transmission rates.

Regulation and Frequency Response Service—providing generation to

match resources and loads on a real-time continuous basis. Rate will

be applied to resources reserved for this service.

Monthly: $1.48 per kW-month; Weekly: $0.3360 per kW-week; Daily:

$0.0480 per kW-day.

Energy Imbalance Service—is provided when a difference occurs between the scheduled and actual delivery of energy to a load or from

a generation resource within a control area over a single month.

Hourly deviation (MW) is the net scheduled amount of energy for the

hour minus the hourly net metered (actual delivered) amount.

Within Limits of Deviation Band: Accumulated deviations are to be corrected or eliminated within 30 days. Any net deviations that are accumulated at the end of the month (positive or negative) are to be

exchanged with like hours of energy or charged at the composite

rate for CVP commercial firm power, then in effect.

Outside Limits of Deviation Band: (i) Positive Deviations—no charge,

lost to the system.

(ii) Negative Deviations—during on-peak hours, the greater of 3 times

the composite.

Rate for CVP commercial firm power, then in ......................................... Effect, or any additional cost incurred. During off-peak hours, the greater of the composite rate for CVP commercial firm power, then in effect, or any additional cost incurred.
Federal Register / Vol. 62, No. 188 / Monday, September 29, 1997 / Notices 50931

PROVISIONAL RATES—Continued

Ancillary services rate schedules

Ancillary service type Rate

Spinning Reserve Service—is providing capacity that is available the

first ten minutes to take load and is synchronized with the power system. Rate will be applied to resources reserved for this service.

Monthly: $1.35 per kW-month; Weekly: $0.3024 per kW-week; Daily:

$0.0432 per kW-day; Hourly: $0.0018 per kWh.

Supplemental Reserve Service—is providing capacity that is not synchronized, but can be available to serve loads within ten minutes.

Rate will be applied to resources reserved for this service.

Monthly: $1.27 per kW-month; Weekly: $0.2856 per kW-week; Daily:

$0.0408 per kW-day; Hourly: $0.0017 per kWh.

Provisional Rates for COTP Transmission Services

A comparison of the existing and provisional rates for transmission services for Western’s share of the COTP follows:

COMPARISON OF EXISTING AND PROVISIONAL RATES

COTP Transmission rate schedules

Effective Period Existing Provisional Percent

change

Firm Transmission Rate ($ per kW-month):

10/01/97 to 09/30/98 ......................................................................................................................... 2.03 1.83 (9.9)

10/01/98 to 09/30/02 ......................................................................................................................... 2.03 1.34 (34.0)

Non-Firm Transmission Rate (mills/kWh):

10/01/97 to 09/30/98 ......................................................................................................................... 2.78 2.19 (21.2)

10/01/98 to 09/30/02 ......................................................................................................................... 2.78 1.45 (47.8)

Certification of Rate

Western’s Administrator has certified

that the CVP commercial firm power,

CVP transmission services, transmission

of CVP power by others, network

transmission service, power scheduling

service, and ancillary services rates, and

COTP transmission services rates placed

into effect on an interim basis herein are

the lowest possible rates consistent with

sound business principles. The

provisional rates have been developed

in accordance with administrative

policies and applicable laws.

Discussion

CVP Commercial Firm Power

According to Reclamation law,

Western must establish power rates

sufficient to recover operation,

maintenance, and purchased power

expenses, and repay the Federal

government’s investment in generation

and transmission facilities. Rates must

also be set to cover interest expenses on

the unpaid balance of facilities’

investments, replacements and

additions, and certain non-power costs

in excess of the irrigation users’ ability

to repay.

The existing CVP commercial firm

power rates were confirmed and

approved by FERC for the period

October 1, 1995 through April 30, 1998,

in a FERC Order issued March 14, 1996.

Under Rate Schedule CV–F8 for the FY

1998, the composite rate on October 1,

1997, is 26.50 mills/kWh, the base

energy rate is 16.93 mills/kWh, the

energy tier rate is 26.48 mills/kWh, and

the capacity rate is $4.58 per kW-month.

The provisional rates for CVP

commercial firm power will result in an

overall composite rate decrease of

approximately 21 percent on October 1,

1997, when compared to the existing FY

1998 CVP commercial firm power rates

in Rate Schedule CV–F8. On a

composite rate basis, the proposed rates

continue to decrease in four years of the

5-year period ending September 30,

2002. The renegotiation and termination

of several long term firm purchase

power contracts are the major factors

contributing to this decrease.

The provisional rates consist of a

capacity rate, an energy rate, and an

annual energy rate alignment. The

AERA will be an additional cost for

energy purchases from Western under

Rate Schedule CV–F9 at or above an

average annual load factor of 80 percent,

calculated at the end of each fiscal year.

The AERA will provide revenues to

cover the increased costs of purchased

energy needed to meet the higher levels

of sales. The AERA is the difference

between the estimated rate for shortterm energy purchases used in the cost

of service study for CVP commercial

firm power and the provisional CVP

energy rate, as shown below.

Fiscal

year

Estimated

purchase

rate

(mills/

kWh)

CVP

commercial firm

energy

rate

(mills/

kWh)

AERA

(mills/

kWh)

1998 ...... 13.17 10.31 2.86

1999 ...... 13.63 10.06 3.57

2000 ...... 14.11 10.19 3.92

2001 ...... 14.60 10.51 4.09

2002 ...... 15.11 11.58 3.53

The AERA provides risk mitigation

for the assumptions used in the cost of

service study for CVP commercial firm

power. If the estimated purchase costs

are too low and customers increase their

energy purchases from Western, then

the AERA will provide additional

revenues to cover the increased costs of

energy. The AERA applies to only those

customers who purchase energy from

Western under Rate Schedule CV–F9 at

or above an average annual load factor

of 80 percent. The AERA is in addition

to the provisional CVP energy rate and

replaces the existing energy tier rate in

Rate Schedule CV–F8. The billing for

the AERA will be based on the

customer’s average annual load factor

and will occur at the end of each fiscal

year, based on the following formula:

AERA=(Total kWh¥(ALF * Hours in

fiscal year * 0.7999)) * AERA rate

Where:

AERA=Annual Energy Rate Alignment

kWh=Energy purchased from Western

during a fiscal year.
50932 Federal Register / Vol. 62, No. 188 / Monday, September 29, 1997 / Notices

ALF=Average of monthly billed

capacity purchased from Western

during a fiscal year.

An example of AERA billing follows:

Example of AERA Billing for FY 1998

Assumption: Average of monthly

billed capacity purchased from Western

during the FY 1998 is 50 MW and the

total annual energy purchased from

Western is 394,200,000 kWh.

Calculation of energy below 80

percent load factor:

50,000 kW × 8,760 hours ×

0.7999=350,356,200 kWh

Energy at or above 80 percent load

factor billed at AERA rate:

394,200,000 kWh¥350,356,200

kWh=43,843,800 kWh

43,843,800 kWh × 2.86 mills/

kWh0=$125,393.27

In order to utilize the CVP power

resources to their maximum benefit,

Western supports CVP generation with

capacity and energy purchases, mainly

from Northwest resources and PG&E.

The cost of the CVP power generation is

split equally between the capacity and

energy revenue requirements. The

amount of capacity and energy available

from the CVP hydroelectric system

varies widely because of hydrologic

conditions. These conditions can also

impact the value of the capacity and

energy. Due to this variability, an equal

split between the capacity and energy

revenue requirements for recovery of the

cost of the CVP power generation is

reflective of its actual costs associated

with providing power to all CVP

customers.

Currently, the existing rates under

Rate Schedule CV–F8 reflect a split of

35 percent capacity and 65 percent

energy. The provisional rates for CVP

commercial firm power are based on the

total annual CVP revenue requirement

being allocated between capacity and

energy in the following manner:

1. The capacity revenue requirement

includes 100 percent of capacity

purchase costs, 100 percent of

purchased transmission service

expense, and 50 percent of the annual

CVP investment repayment, interest

expense, and power O&M expense

allocated to commercial power. These

annual costs are reduced by the

projected revenue from CVP

transmission sales to determine the

capacity revenue requirement.

2. The energy revenue requirement

includes 100 percent of energy purchase

costs and 50 percent of the annual CVP

investment repayment, interest expense,

and power O&M expense allocated to

commercial power. These annual costs

are reduced by the projected revenue

from surplus power sales to determine

the energy revenue requirement.

The resulting percentage splits

between the capacity and energy

revenue requirements for the

provisional rates varies from 51 percent

allocated to capacity in FY 1998 to 42

percent allocated to capacity in FY 2002

due to changes in costs and revenues

each year. The average split for the 5-

year period is 46 percent to capacity and

54 percent to energy. The annual

percentage splits between the capacity

and energy revenue requirements are as

follow:

Effective period Capacity

(percent)

Energy

(percent)

10/1/97—9/30/98 ....... 51 49

10/1/98—9/30/99 ....... 48 52

10/1/99—9/30/00 ....... 47 53

10/1/00—9/30/01 ....... 43 57

10/1/01—9/30/02 ....... 42 58

5-year average .......... 46 54

Power Factor Adjustment

The power factor adjustment under

existing Rate Schedule CV–F8 will

continue and is included with the

provisional rates for CVP commercial

firm power. The low power factor

charge or LPF Charge, will continue to

encourage preference customers to

monitor their power factors and

maintain them at 95 percent or greater.

Western will continue the existing LPF

Charge under Rate Schedule CV–F9,

which includes a rate of $2.50 per kvar

for additional kvar required to raise the

customer’s power factor to 95 percent.

The $2.50 per kvar rate represents the

estimated cost of Western purchasing

and installing equipment to increase a

customer’s power factor plus an

additional charge to encourage

customers to monitor poor power

factors. The LPF Charge will be applied

when the customer does not maintain a

calculated 95 percent or greater power

factor.

The customer’s calculated power

factor used to determine if a charge will

be assessed is the arithmetic mean of the

customer’s measured monthly average

power factor and the measured monthly

on-peak power factor, rounded to the

nearest whole percent with 0.5 percent

or greater rounded to the next higher

percent. The measured on-peak power

factor is equal to the power factor

measured during a customer’s

maximum peak demand for each month,

as recorded at the customer’s point of

delivery. In the event of multiple

occurrences of the same peak demand,

the lowest associated power factor will

be used. The measured average power

factor will be the average power factor

for the billing month. Those customers

with multiple meter points will be

charged for the ‘‘totalizer’’ of the

multiple meter points. The monthly onpeak and average power factors are

those recorded for CVP power only.

Low Voltage Loss Adjustment

The low voltage adjustment under

existing Rate Schedule CV–F8 will

continue and is included in the

provisional rates for CVP commercial

firm power. A 1.035 loss adjustment

factor will be applied to the billed

amounts for low voltage CVP power

deliveries on PG&E’s system under

Contract 2948A.

Revenue Adjustment

The revenue adjustment clause or

RAC, tracks variances in future revenues

and expenses, and lessens the

probability of significant revenue

surplus or deficit to the CVP repayment.

The methodology for computing the

RAC is a comparison of estimated total

revenues less estimated total expenses

to actual total revenues less actual total

expenses. If the actual net revenue is

more than the estimated net revenue,

CVP preference customers receive a

credit. If actual net revenue is less than

the estimated net revenue, CVP

preference customers may have a

surcharge, if needed to make a

minimum investment payment. The

limit for surcharges is $20 million. The

limit for credits is $20 million plus the

amount of EA2 credit or other purchase

power contract adjustments used during

the fiscal year for which the RAC is

being calculated. The RAC is a carryover

from Rate Schedule CV–F8.

CVP Transmission Services and

Transmission of CVP Power by Others

The provisional rate for firm CVP

transmission service is $0.51 per kWmonth, an 18.6 percent increase from

the existing rate of $0.43 per kW-month

under Rate Schedule CV–FT2. The

provisional rate for non-firm CVP

transmission service is 1.00 mill/kWh,

an 18.7 percent reduction in the existing

1.23 mills/kWh rate under Rate

Schedule CV–NFT2. The change in the

firm CVP transmission service rate is

due to increases in transmission

facilities costs and in the basis for

assigning miscellaneous and nonfacility O&M costs to transmission to

better reflect costs associated with

transmission for all users. The change in

the non-firm CVP transmission service

rate is primarily due to a change in the

load factor used in determining the

denominator in the rate calculation. The

same revenue requirement is used in
Federal Register / Vol. 62, No. 188 / Monday, September 29, 1997 / Notices 50933

determining the firm and non-firm CVP

transmission service rates.

The provisional rates for CVP

transmission services are based on a

revenue requirement that recovers: (1)

The CVP transmission system costs for

facilities associated with providing all

transmission services; and (2) the nonfacility costs allocated to transmission

service. These provisional firm and nonfirm CVP transmission service rates

include the costs for scheduling, system

control and dispatch service, and

reactive supply and voltage control

service needed to provide the

transmission service. If scheduling,

system control and dispatch service,

and reactive supply and voltage control

service are not provided by Western, the

customers will be given credit for the

cost associated with these services, as

agreed by the parties. The provisional

rates are applicable to existing firm and

non-firm CVP transmission services and

future point-to-point transmission

services. The rates charged for firm and

non-firm CVP transmission services for

a period of one year or less will be no

higher than the provisional rates.

Transmission service costs incurred

by Western in the delivery of CVP

power over a third party’s transmission

system to a CVP customer, will be

directly passed through to that CVP

customer. Both annual revenues and

expenses are included in the PRS to

account for all charges, even though the

net effect is zero. Transmission pass

through revenues and expenses are

estimated using existing customer load

forecasts and project use requirements,

and applicable transmission service

rates. Transmission pass through

revenues and expenses primarily consist

of payments to PG&E for transmission

services to preference and project use

loads, and payments to the Sacramento

Municipal Utility District for

transmission services to preference

customers.

Network Transmission Service

Network transmission service is a new

service and, if offered by Western, will

be made available consistent with FERC

Order No. 888. Due to existing

contractual arrangements and not being

a control area operator for the CVP,

Western may not be able to provide

network transmission service but has

included a rate formula in case Western

offers the service. The provisional rate

formula for network transmission

service is based on a revenue

requirement that recovers the CVP

transmission system costs for facilities

associated with providing all

transmission services and the nonfacility costs allocated to transmission

service. The provisional rate formula

includes the costs for scheduling,

system control and dispatch service,

and reactive supply and voltage control

service needed to provide the network

transmission service.

Power Scheduling Service

Power scheduling is a new service

being offered by Western that provides

for the scheduling of resources to meet

loads and reserve requirements. The

provisional rate for power scheduling

service is designed to recover only the

cost incurred by Western for providing

the service. The provisional rate

includes two cost components. The first

cost component is the FY 1997 hourly

cost for dispatcher and/or scheduler

resources, escalated for the rate

adjustment period of FY 1998 through

FY 2002 to obtain an average hourly

cost. The second cost component is an

estimated hourly cost for equipment

necessary in providing the service.

Ancillary Services

Ancillary services are new services

and, if offered by Western, will be made

available consistent with FERC Order

No. 888. Of the six ancillary services

offered by Western, two will be

provided in conjunction with the sale of

CVP and/or COTP transmission

services. These are scheduling, system

control and dispatch service, and

reactive supply and voltage control

service. The remaining four ancillary

services, regulation and frequency

response service, energy imbalance

service, spinning reserve service, and

supplemental reserve service will be

offered subject to availability. Western’s

sales of ancillary services are subject to

the availability of its power resources

because Western allocates most of its

power resources to preference entities

under long-term commitments. The

availability and type of ancillary service

will be determined based on excess

resources available at the time the

service is requested.

The provisional rates for ancillary

services are designed to recover only the

costs associated with providing the

service(s). The costs for providing

scheduling, system control and dispatch

service, and reactive supply and voltage

control service are included in the

provisional transmission services rates.

The provisional rate for energy

imbalance service is based on standards

and practices used in the electric utility

industry. For the provisional rates for

regulation and frequency response,

spinning reserve, and supplemental

reserve services, Western used a

detailed cost of service study to

determine these rates, which are based

on CVP facilities that are used in

providing the service(s). Only those CVP

facilities costs are considered in the

determination of rates for regulation and

frequency response, spinning reserve,

and supplemental reserve services. The

CVP facilities that are used in providing

regulation and frequency response,

spinning reserve, and supplemental

reserve services are the Shasta, Folsom,

Trinity, New Melones, Spring Creek,

and Judge F. Carr powerplants. The

Nimbus and Keswick powerplants are

not available because of river run

conditions. There are no governors at

the O’Neill and San Luis powerplants,

which makes them unavailable for

providing the services.

COTP Transmission Services

Since the COTP went into operation

in 1993, Western has sold COTP

transmission services on a short-term

basis using rates approved by the

Administrator. Rate schedules are being

promulgated for COTP firm and nonfirm transmission services to be

consistent with FERC Order No. 888.

The provisional rates for firm

transmission service for Western’s share

of the COTP are $1.83 per kW-month for

FY 1998 and $1.34 per kW-month for

FY 1999 through FY 2002. These rates

for firm COTP transmission service

result in 9.9 percent (FY 1998) and 34.0

percent (FY 1999 through FY 2002)

reductions in the existing rate of $2.03

per kW-month. The provisional rates for

non-firm COTP transmission service are

2.19 mills/kWh for FY 1998 and 1.45

mills/kWh for FY 1999 through FY

2002. These rates for non-firm COTP

transmission service result in 21.2

percent (FY 1998) and 47.8 percent (FY

1999 through FY 2002) reductions in the

existing rate of 2.78 mills/kWh. These

rates are lower than the existing rates for

COTP firm and non-firm transmission

services due to reduced costs for and the

terminations of some contracts for COTP

transmission capacity.

The provisional rates for COTP

transmission services includes a

revenue requirement that recovers the

costs associated with: (1) Western’s

participation in the COTP; and (2)

scheduling, system control and dispatch

service, and reactive supply and voltage

control service needed to provide the

transmission service. If scheduling,

system control and dispatch service,

and reactive supply and voltage control

service are not provided by Western, the

customers will be given credit for the

cost associated with these services, as

agreed by the parties. The provisional

rates are applicable to existing firm and

non-firm COTP transmission services

and future point-to-point transmission
50934 Federal Register / Vol. 62, No. 188 / Monday, September 29, 1997 / Notices

services. The rates charged for firm and

non-firm COTP transmission services

for a period of one year or less will be

no higher than the provisional rates.

Statement of Revenue and Related

Expenses

The following table provides a

summary of revenues and expenses for

the 5-year provisional rate period and

the 3-year existing rate period.

CVP COST EVALUATION RATE PERIOD REVENUES AND EXPENSES ($1,000)

Provisional

rate PRS

FY 1998–02

Existing rate

PRS FY

1996–98

Difference

Total Revenues ................................................................. 824,651 609,954 Not Applicable See Note below.

Revenue Distribution:

O&M ........................................................................... 216,776 105,521 Note: The revenues and expenses for the provisional

rates are for 5 years. Those for the existing rates are

for 3 years. Therefore, the difference is not applicable.

Purchase Power ......................................................... 390,689 407,804

Transmission .............................................................. 80,335 45,098

Interest ........................................................................ 54,536 29,933

Other ........................................................................... 9,073 0

Investment Repayment .............................................. 73,242 21,598

Capitalized Expenses ................................................. 0 0

Prior-Year Adjustment ................................................ 0 0

The following table provides a summary of the average annual revenues and expenses for the provisional and

existing rate periods.

CVP COMPARISON OF COST EVALUATION RATE PERIOD AVERAGE ANNUAL REVENUES AND EXPENSES ($1,000)

Provisional

rate average annual

Existing rate

average annualDifference

Total Revenues ............................................................................................................................. 164,930 203,318 (38,388)

Revenue Distribution:

O&M .................................................................................................................................................. 43,355 35,174 8,181

Purchase Power ................................................................................................................................ 78,138 135,935 (57,797)

Transmission ..................................................................................................................................... 16,067 15,033 (1,034)

Interest .............................................................................................................................................. 10,907 9,978 (929)

Other ................................................................................................................................................. 1,815 0 1,815

Investment Repayment ..................................................................................................................... 14,648 7,199 7,449

Capitalized Expenses ........................................................................................................................ 0 0 ....................

Prior-Year Adjustment ....................................................................................................................... 0 0 ....................

Basis for Rate Development

The existing rates for CVP commercial

firm power, CVP transmission services

and transmission of CVP power by

others in Rate Schedules CV–F8, CV–

FT2, CV–NFT2, and CV–TPT3 expire

April 30, 1998. Reduced costs for and

the terminations of some of Western’s

power purchase and COTP transmission

contracts have occurred. Power

scheduling, network transmission, and

ancillary services are new services being

offered by Western. The proposed rate

adjustment is needed to put into place

rates, which will replace the existing

rates, that reflect reduced purchase

power expenses due to a decrease in

customers’ CVP power purchases,

reduced costs of transmission contracts,

current methodology in rate design, and

to provide rates for new services. The

provisional rates will provide sufficient

revenue to pay all annual costs,

including interest expense, and

repayment of required investment

within the allowable period. The

provisional rates are scheduled to go in

effect on October 1, 1997, to correspond

with the start of the Federal fiscal year,

and will remain in effect through

September 30, 2002.

The provisions for power factor

adjustment, low voltage loss adjustment,

and revenue adjustment are part of the

provisional rates for CVP commercial

firm power. The provisions and

methodologies for these adjustments are

not being modified and will remain as

specified in Rate Schedule CV–F8.

Comments

During the public consultation and

comment period, Western received 12

written comments on the rate

adjustment. In addition, three customer

representatives commented during the

April 24, 1997 public comment forum.

All comments received by the end of the

public consultation and comment

period, June 2, 1997, were reviewed and

considered in the preparation of this

rate order.

Written comments were received from

the following sources:

Bookman-Edmonston Engineering, Inc.

(California)

Calaveras Public Power Agency

(California)

National Aeronautics and Space

Administration, Ames Research

Center (California)

Northern California Power Agency

(California)

City of Palo Alto (California)

City of Redding (California)

City of Roseville (California)

Sacramento Municipal Utility District

(California)

City of Santa Clara (California)

Trinity County Board of Supervisors

(California)

Trinity County Public Utilities District

(California)
Federal Register / Vol. 62, No. 188 / Monday, September 29, 1997 / Notices 50935

Tuolumne Public Power Agency

(California)

The comments received in

correspondence dealt with the CVP

commercial firm power rate design,

specifically, the capacity and energy

split for revenue recovery and the

AERA, the CVP transmission service

rate design, separate county-of-origin

rate, and the RAC. All comments

supported Western’s efforts to reduce

the rates. The following is a summary of

the comments received by the end of the

consultation and comment period and

Western’s responses to those comments.

The comments and responses,

paraphrased for brevity are presented

below. Specific comments are used for

clarification where necessary.

CVP Commercial Firm Power (Capacity

and Energy Revenue Requirement Split)

The following comments relate to the

change in CVP rate design from

recovering 35 percent of the revenue

requirement from capacity and 65

percent from energy, to capacity and

energy revenue requirement percentage

splits that varies from 51 percent

allocated to capacity in FY 1998 to 42

percent allocated to capacity in FY

2002.

Comments: Five customers

commented that they want the

provisional rates for CVP commercial

firm power to reflect a true cost of

service allocation by including

investment payment, interest expense,

and O&M expense in the capacity

revenue requirement. This would result

in a capacity and energy revenue

requirement split of 70 percent allocated

to capacity and 30 percent allocated to

energy. Three of the customers

commented that they support a

‘‘phasing-in’’ approach in achieving a

rate design toward the ‘‘true cost of

service’’ allocation of 70 percent

capacity and 30 percent energy. Two

other customers commented that they

also support the phasing-in approach,

but want a split closer the existing rate

design in the first year and eventually

moving toward a split of 50 percent

capacity and 50 percent energy. A

representative that represents a coalition

of fourteen agricultural CVP power

customers, commented that it prefers

the existing allocation split, but

supports the proposed splits in the

provisional rates as an effective balance

among Western’s customers.

Responses: Western believes its

proposed revenue requirement

percentage splits between capacity and

energy reflects a ‘‘true cost of service’’

allocation. The cost of the CVP power

generation is split equally between the

capacity and energy revenue

requirements. The amount of capacity

and energy available from the CVP

hydroelectric system varies widely

because of hydrologic conditions. These

conditions can also impact the value of

the capacity and energy. Due to this

variability, Western believes that an

equal split between the capacity and

energy revenue requirements for

recovery of the cost of the CVP power

generation is reflective of its actual costs

associated with providing power to all

CVP customers. However, in order to

utilize the CVP power resources to their

maximum benefit, Western supports the

CVP generation with capacity and

energy purchases, mainly from

Northwest resources and from PG&E.

Therefore, capacity purchase costs are

allocated to capacity and energy

purchase costs are allocated to energy.

Western believes that all CVP customers

benefit from this marketing approach

and should pay for these benefits.

Because the CVP costs vary annually,

the percentage splits also vary annually.

In response to comments relating to

‘‘phasing-in’’ the change in the capacity

and energy revenue requirement split,

Western believes that it is inappropriate

for this rate adjustment period. The

annual changes in the revenue

requirement splits reflect the change in

annual costs for providing firm power

service.

Comment: One customer commented

that the rates being generated are for the

benefit of the high load factor

customers, and put the low load factor

customers at a significant disadvantage.

Also, this customer commented that it

does not like the financial burden of

supplemental thermal energy spread to

all customers, since high load factor

customers benefit from this

arrangement. This customer wants to

‘‘unbundle’’ the cost of thermally

generated supplemental energy from the

cost of CVP hydroelectric power.

Response: Western markets power

based on a pool of resources, all of

which can be used to serve firm power

contractual loads. It is Western’s

position that Western has an obligation

to meet all its contractual commitments.

The provisional rates reflect Western’s

actual costs associated with providing

power to all CVP customers, not an

individual customer’s consumption of

capacity or energy. All resources

necessary to supply the total CVP

commercial power obligation are

considered in each kWh and kW of

power sales. This results in a

homogenous and nondiscriminatory rate

design. The generalization that high

load factor customers cause the

purchase of energy in excess of CVP

generation, while low load factor

customer do not, is inaccurate. The

annual CVP generation follows a pattern

of high generation in the spring and

summer months, and low generation in

the fall and winter months. If low load

factor customers were to peak

significantly and have high loads in a

fall or winter month, a substantial

portion of the energy served by Western

for such loads is likely from purchased

power.

CVP Commercial Firm Power (AERA)

The following comments relate to the

CVP annual energy rate alignment,

which is an additional cost for firm

energy purchases at or above an average

load factor of 80 percent.

Comments: Two customers want to

eliminate the AERA. They argued that

given the conservatism of the forecasts

used to develop the rates, the AERA is

equivalent to ‘‘wearing both a belt and

suspenders’’. One other customer wants

a redefinition of the AERA to, ‘‘* * * is

equal to the pass-through energy costs

above the CVP commercial firm energy

rate.’’

Responses: Western is adopting the

change in the definition of the AERA to,

‘‘* * * the difference between the

estimated rate for short term energy

purchases used in the cost of service

study for CVP commercial firm power

and the provisional CVP energy rate.’’

The AERA provides risk mitigation for

the purchase rate assumptions used in

this rate adjustment. If the estimated

purchase costs are too low and

customers increase their energy

purchases from Western, then the AERA

will provide additional revenues to

cover the increased costs of energy. The

AERA will be an additional cost for

energy purchases from Western at or

above an average annual load factor of

80 percent. The AERA replaces the

existing energy tier rate and is designed

to reduce the impact of purchasing

additional CVP support energy on all

customers. The AERA applies to only

those customers who purchase energy

from Western at or above an average

annual load factor of 80 percent.

CVP Transmission Services Rates

The following comments relate to the

provisional rates for CVP transmission

services.

Comment: Three customers

commented that the costs of nontransmission items and certain customer

specific items in Western’s plant-inservice study should not be included as

part of the rates development. These

customers believe that these items have

been either paid for through other

sources of funds or paid entirely by a

particular customer, and therefore
50936 Federal Register / Vol. 62, No. 188 / Monday, September 29, 1997 / Notices

should not be charged to all CVP

customers. Examples of items, which

the customers gave to be excluded from

the calculations are Roseville Substation

and COTP lands.

Response: Western reviewed the costs

allocated under the non-facility specific

O&M and concluded that the some costs

allocated for COTP lands was incorrect.

This amount totaling $4,060 was

omitted from the final rate calculation.

In response to the Roseville Substation,

there were no plant-in-service costs

allocated in the rate calculation,

however, there were costs associated

with interest expense at an 8.875

percent rate. The interest expense was

revised, as explained below.

Comments: Three customers

commented that certain interest

expenses for various transmission

facilities, those with higher interest

rates, have been either retired or paid off

by Western. It is their understanding

that as a result of the 1992–93

settlement between Western and PG&E,

Western was not able to refund the large

cash settlement from PG&E through the

RAC process, and therefore Western

used some of the refund to purchase

down some of the higher interest loans.

These customers believe that it is

inappropriate to be charged for interest

obligations which do not exist. The

three customers want the rate

calculations to be based on only the

actual interest rates for costs remaining,

or be based on average system-wide

interest costs.

Responses: Western reviewed the

costs included in the plant-in-service

study and determined that there was an

error in the interest rate calculation for

the facilities listed as plant in service

(P–I–S). This error has been corrected,

and as a result, all interest expenses for

repaid investment was excluded from

the transmission rate study. The interest

associated with the Roseville Substation

mentioned above was also excluded.

Western applied interest to P–I–S

facilities at the interest rates applicable

to each project. When a specific interest

rate was not identified, a 3.0 percent

rate was applied. The average interest

rate applied to P–I–S facilities in the

CVP transmission rate study calculates

to be 3.08 percent.

In order to recognize the P–I–S paid

through transmission revenue, Western

made an adjustment to account for

repayment of transmission investment

that have been made during FY 1993 to

FY 1997 as follows:

1. The total investment amount for

this rate adjustment was reduced by the

total payment on investment for five

years of the 50-year repayment period of

the 1993 rate adjustment.

2. The remaining investment payment

amount from the 1993 rate adjustment

was amortized over 45 years.

3. The remainder of the total

investment for this rate adjustment that

was not included in the 1993 rate

adjustment was amortized for 50 years,

to calculate an annual payment for these

investments. The result was deducted

from the annual payment.

Comment: Two customers

recommended that since the provisional

rates represent a net 20 percent increase

in the existing CVP transmission

services rates, which is a significant

change, a ‘‘phasing-in’’ approach would

be better for them to have time to adjust.

Also, this phasing-in approach would

allow time to evaluate the possible

impacts from the future California’s

Independent System Operator on

transmission usage and costs.

Response: Western believes that the

CVP transmission rates accurately

reflect the cost of providing CVP

transmission service. Therefore,

Western will not be implementing a

‘‘phasing-in’’ period for the provisional

CVP transmission services rates.

Comment: Three customers

recommended a formation of a customer

group to work with Western on the

tracking, monitoring and allocating of

Western’s transmission expenses.

Response: At several meetings during

the informal public process, Western

discussed with the preference customers

the transmission rate costs and rate

design methodology. The comment

recommending a formation of a

customer group to work with Western

on the tracking, monitoring, and

allocating of Western’s transmission

expenses is outside the scope of this rate

adjustment and public process.

County of Origin Rate for First

Preference Customers

The following comments relate to

inquiries for a separate county of origin

rate for first preference customers.

Comments: Four customers

commented that they believe there must

be a county of origin rate for first

preference customers and encourage

Western to recognize the need to ‘‘treat

first preference customers in a unique

manner, since they are legislated

recipients of CVP power’’. These

customers want Western to establish a

first preference county of origin rate

which is reflective of the actual cost of

power generation from CVP facilities in

those counties. One customer

commented that in the past, they have

‘‘been penalized by having to pay for

purchased power to meet other

customers’ load requirements’ and that

they have been ‘‘deprived of most of the

first preference benefits.’’ Another

customer argued that ‘‘the rights granted

by Congress to them should be met first

before other Western customers receive

extra services’’ and that the provisional

rates are ‘‘many times higher than the

rates contemplated by Congress as

partial mitigation’’.

Responses: The Flood Control Act of

1962 authorized construction of the

New Melones Project and specifically

granted first preference to preference

customers in Calaveras and Tuolumne

counties, in a quantity to the extent

needed but not to exceed 25 percent of

such additional CVP energy resulting

from the construction of the New

Melones Project power facility and its

integration into the CVP system. The

Act of August 12, 1955 authorized

construction of the Trinity River

Division and granted a similar first

preference to preference customers in

Trinity County, to the extent of 25

percent of such additional energy

available from the CVP power system as

a result of the construction of the

Trinity River Project, as integrated into

the CVP system, and who are ready, able

and willing to enter into contracts for

the energy.

The Acts entitled the preference

customers in those counties who are

ready, able and willing to enter

contracts with Western to a first

preference in the purchase of CVP

energy to the extent needed, but not to

exceed 25 percent and under certain

conditions. The authorizing legislation

also provides that the Trinity and New

Melones projects be integrated and

coordinated, from both a financial and

an operational standpoint, with the

operation of other features of the CVP.

In Trinity County v. Harrington the

court determined first preference

customers are not entitled to

preferential rates based on the operating

costs of Trinity and New Melones

projects alone, as opposed to operating

costs of the CVP system as a whole. The

provisional rates for CVP commercial

firm power are based on the operation

costs of the CVP system as whole, and

will be applied to all CVP customers

who purchase CVP power from Western.

In addition, since the CVP power

service provided to first preference

customers is the same as that provided

to other customers who receive CVP

power, the provisional rates for CVP

commercial firm power charged to other

CVP customers will be the same for the

first preference customers.

Other Comments

The following comments relate to the

RAC, project use power, allocation of
Federal Register / Vol. 62, No. 188 / Monday, September 29, 1997 / Notices 50937

multipurpose joint costs, EA2, energy

tier rate, and general rate design.

Comment: The RAC distribution

should be reset for each 6-month period

rather than the 9-month period. This

would enable Western to adjust

revenues for wholesale customers more

promptly.

Response: The annual maximum RAC

credit is $20 million plus the use of EA2

credit from PG&E and/or other

adjustments from purchase power

contracts. Limiting the distribution of

the RAC to 6 months would make it

difficult to refund the maximum RAC

credit allowed. Using a 9 month

distribution ensures most, if not all

customers, will receive maximum

benefit from the RAC calculation.

Comment: Allocating larger portions

of multipurpose joint costs to the CVP

power customers must be stopped

because it impairs Western’s efforts to

remain competitive in the new

restructured California’s electric market.

Response: The Bureau of Reclamation

is responsible for the allocation of CVP

multipurpose costs. Comments

pertaining to the allocation of these

costs should be directed to Reclamation

during their public participation process

on the CVP cost allocation.

Comment: Western needs to rethink

its use of the EA2 energy based on its

recent discussions with PG&E and work

closely with the customers on this

matter.

Response: Future use of EA2 can be

impacted by many variables, some of

which can not be evaluated at this time

because information is not available. An

example would be the possible impact

on EA2 from the divesture of PG&E’s

generation. Western has based its

projections for EA2 usage on the

information currently available. The

RAC is available to cover possible

changes in the costs associated with

EA2.

Comment: Project use customers have

underpaid Western for project use

power during past years in an amount

between $15–20 million. Request that

Western increase project use revenue

collection to bring such balance to zero

by the end of this 5-year rate adjustment

period. Also request that the project use

additional revenue be included in the

initial setting of Western’s rates, instead

of allowing the additional revenue to

roll through the RAC.

Response: The amount owed by the

project use customers is still being

determined. Western is anticipating full

payment by December 2004, however

the exact timing and magnitude of

payments from the project use

customers is not known. Given this

uncertainty, Western believes it is

prudent to exclude any estimated

amount in the provisional rates. Any

payments made will flow through the

annual RAC calculation.

Comments: The proposed CVP energy

component of the rates appears

marginally competitive. Western should

set the rates based on a ‘‘high use’’

scenario instead of the ‘‘average use’’

scenario. This will give lower rates and

the scheduling customers will more

likely utilize CVP power. In the event

that CVP energy delivery is less than

planned, the RAC would be used to

meet revenue requirement. It would

highly be unlikely that the $20 million

RAC limit for revenue recovery would

cause a revenue shortfall if rates are

based on very high usage and lower

than average usage occurred. Western

should adopt a higher energy use basis

in the derivation of rates.

Responses: In developing the

provisional rates, Western performed

studies that considered maximum,

minimum and average use (power sales)

scenarios based on historical sales. The

results of these studies indicated that

the maximum sales or high sales

scenario was not justifiable because of

the magnitude of increase from the FY

1996 recorded amounts for firm

commercial power sales. The average

sales scenario was an appropriate

transition given the historical sales

levels and the change to the power rates

contained in this rate adjustment. Due

to the volatility of the electric industry,

the $20 million RAC limit may not be

sufficient to cover the assumptions of

average versus maximum power sales if

the actual costs are substantially higher

that those projected in this rate

adjustment.

Comment: Western’s energy forecast

for FY 1999 is wrong and the proposed

rates undercuts the 1999 market energy

rates by over 50 percent. Believes this

will have customers purchasing energy

as much as possible from Western, thus

depleting the EA2 energy and cause a

clamor by the high load factor

customers for Western to get back into

procuring supplemental thermal energy.

Response: The studies Western

performed in developing the provisional

rates indicate that the EA2 energy will

be available throughout the 5-year rate

adjustment period. In fact, there is a

balance remaining in EA2 after the 5-

year period.

Comment: A customer commented it

liked the tiered energy rate arrangement

since it represented Western’s effort

toward ‘‘marginal cost’’ pricing and

caused a reduction in consumption of

Western’s supplemental thermal energy.

This customer recommends that

Western adopts a rate form like the

existing tier rate and establish a tier rate

at the 2.2 to 2.4 cents per kWh range for

energy sales over 70 percent load factor.

Response: Western performed an

analysis that considered the

implementation of an energy tier rate.

The methodology and the assumptions

used were the same as those used in

developing the existing energy tier rate.

The result of this analysis indicated that

the difference between the base and

energy tier rates was minimal.

Therefore, Western decided an energy

tier rate will not be implemented for

this rate adjustment.

Environmental Compliance

In compliance with the National

Environmental Policy Act of 1969, 42

U.S.C. 4321 et seq.; the Council on

Environmental Quality Regulations for

implementing NEPA (40 CFR parts 1500

through 1508); and the DOE NEPA

Implementing Procedures and

Guidelines (10 CFR part 1021), Western

has determined that this action is

categorically excluded from the

preparation of an environmental

assessment or an environmental impact

statement.

Determination Under Executive Order

12866

DOE has determined that this is not

a significant regulatory action because it

does not meet the criteria of Executive

Order 12866, 58 FR 51735. Western has

an exemption from centralized

regulatory review under Executive

Order 12866; accordingly, no clearance

of this notice by the Office of

Management and Budget is required.

Availability of Information

Information regarding this rate

adjustment, including power repayment

studies, comments, letters,

memorandums, and other supporting

material made or kept by Western for

the purpose of developing the

provisional rates, is available for public

review in the Sierra Nevada Regional

Office, Western Area Power

Administration, Office of the Power

Marketing Manager, 114 Parkshore

Drive, Folsom, California 95630, and the

Power Marketing Liaison Office, Room

8G–027, 1000 Independence Avenue

SW., Washington, DC 20585.

Submission to the Federal Energy

Regulatory Commission

The rates herein confirmed, approved,

and placed into effect on an interim

basis, together with supporting

documents, will be submitted to FERC

for confirmation and approval on a final

basis.
50938 Federal Register / Vol. 62, No. 188 / Monday, September 29, 1997 / Notices

Order

In view of the foregoing and pursuant

to the authority delegated to me by the

Secretary of Energy, I confirm and

approve on an interim basis, effective

October 1, 1997, Rate Schedules CV–F9,

CV–FT3, CV–NFT3, CV–TPT4, CV–

NWT1, CV–PSS1, CV–RFS1, CV–EID1,

CV–SPR1, CV–SUR1, COTP–FT1, and

COTP–NFT1 for the Central Valley

Project and for the California-Oregon

Transmission Project of the Western

Area Power Administration. The rate

schedules will remain in effect on an

interim basis, pending confirmation and

approval on a final basis by the Federal

Energy Regulatory Commission, through

September 30, 2002, or until

superseded.

Dated: September 19, 1997.

Elizabeth A. Moler,

Deputy Secretary.

Rate Schedule CV–F9

(Supersedes Schedule CV–F8)

Central Valley Project

Schedule of Rates for Commercial Firm

Power

Effective: October 1, 1997.

Available: Within the marketing area

served by the Sierra Nevada Customer

Service Region.

Applicable: To the commercial firm

power customers for general power

service supplied through one meter, at

one point of delivery, unless otherwise

provided by in the service agreement.

Character and Conditions of Service:

Alternating current, 60 hertz, threephase, delivered and metered at the

voltages and points established by

contract.

Monthly rates: Period Capacity

(kW=Month)

Energy

(mills/kWh)

AERA

(mills/kWh)

10/01/97–09/30/98 .................................................................................................................................... $5.03 10.31 2.86

10/01/98–09/30/99 .................................................................................................................................... 4.37 10.06 3.57

10/01/99–09/30/00 .................................................................................................................................... 4.31 10.19 3.92

10/01/00–09/30/01 .................................................................................................................................... 3.81 10.51 4.09

10/01/01–09/30/02 .................................................................................................................................... 4.02 11.58 3.53

Billing: Demand: The rates listed

above for capacity will be the charge per

kW of billing demand. The billing

demand is the highest 30-minute

integrated demand measured or

scheduled during the month up to, but

not in excess of, the delivery obligation

under the power sales contract.

Energy: The rates listed above for

energy will be a charge per kWh for all

energy use up to, but not in excess of,

the maximum kWh obligation of the

United States during the month as

established under the power sales

contract.

Annual Energy Rate Alignment

(AERA): The rates listed above for

AERA will be an additional charge per

kWh for energy purchases at or above an

average annual load factor of 80 percent,

calculated at the end of each Federal

fiscal year (September 30). The AERA is

in addition to the CVP energy rate. The

billing for the AERA will be based on

the following formula:

AERA=(Total kWh¥(ALF * Hours in

fiscal year * 0.7999)) * AERA rate

Where:

AERA=Annual Energy Rate Alignment

kWh = Energy purchased from Western

during a fiscal year.

ALF=Average of monthly billed

capacity purchased from Western

during a fiscal year.

Adjustments

Billing for Unauthorized Overruns.

For each billing period in which there

is a contract violation involving an

unauthorized overrun of the contractual

obligation for capacity and/or energy,

such overrun will be billed at 10 times

the applicable rates above.

For Revenue Adjustment. The

following methodology will be used for

the revenue adjustment clause (RAC)

calculation:

1. If the actual net revenue is greater

than the projected net revenue for the

RAC calculation period, a revenue

credit will be allocated during the RAC

adjustment period. The credit will equal

the difference between the actual net

revenue and projected net revenue,

represented by the following formula:

ANR>PNR; C=ANR¥PNR

Where:

ANR=Actual Net Revenue

PNR=Projected Net Revenue

C=Credit

2. If actual net revenue is less than the

projected net revenue for the RAC

calculation period, a revenue surcharge

will be allocated during the RAC

adjustment period.

2.1 If the actual net revenue is

negative, the surcharge will be equal to

the minimum investment payment plus

the annual deficit, represented by the

following formula:

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

Where:

ANR=Actual Net Revenue

PNR=Projected Net Revenue

MIP=Minimum Investment Payment

AD=Annual Deficit

S=Surcharge

2.2 If the actual net revenue is

positive, the surcharge will equal the

minimum investment payment less the

actual net revenue, represented by the

following formula:

ANR<PNR and>0; S=MIP¥ANR (if

ANR>MIP, S=0)

Where:

ANR=Actual Net Revenue

PNR=Projected Net Revenue

MIP=Minimum Investment Payment

S=Surcharge

Provided, that if the actual net

revenue is greater than the minimum

investment payment, the surcharge will

be equal to zero.

3. The maximum RAC credit

allocation will equal $20 million plus

the amount of the Pacific Gas and

Electric Company refund credit applied

to Western power bills for the fiscal

year, or other purchase power contract

adjustments used in recording

associated expense.

4. The maximum allocation for a RAC

surcharge will not exceed $20 million.

5. The RAC credit or surcharge will be

allocated to each CVP commercial firm

power customer based on the proportion

of the customer’s billed obligation to

Western for CVP commercial firm

capacity and energy to the total billed

obligation for all CVP commercial firm

power customers for CVP commercial

firm capacity and energy for the RAC

calculation period.

6. For purposes of the RAC

calculation, the following terms are

defined:

6.1 Actual Net Revenue—The recorded

net revenue.

6.2 Annual Deficit—The amount the

recorded annual expenses, including

interest, exceeding recorded annual

revenues.

6.3 Minimum Investment Payment—

The lesser of 1 percent of the recorded
Federal Register / Vol. 62, No. 188 / Monday, September 29, 1997 / Notices 50939

unpaid investment balance at the end

of the prior fiscal year that the RAC

is being calculated, or the projected

net revenue.

6.4 Projected Net Revenue—The

annual net revenue available for

investment repayment projected in

the PRS for the rate case during the

fiscal year that the RAC is being

calculated (see Table 1).

6.5 RAC Adjustment Period—The

period January 1 through September

30, following the RAC calculation

period when credits or surcharges

will be applied to the power bills.

6.6 RAC Calculation Period—The last

recorded fiscal year (October 1

through September 30).

6.7 Recorded Net Revenue—The

annual net revenue available for

repayment recorded in the PRS for the

fiscal year that the RAC is being

calculated.

7. Subject to modification by a

superseding rate schedule, the final

RAC will be allocated to the customers

during the period January 1, 2003, to

September 30, 2003.

TABLE 1.—PROJECTED NET REVENUE

AVAILABLE FOR INVESTMENT REPAYMENT FOR REVENUE ADJUSTMENT

CLAUSE

Period Projected net

revenue

October 1, 1997–September

30, 1998.

$5,522,851

October 1, 1998–September

30, 1999.

9,534,973

October 1, 1999–September

30, 2000.

12,196,514

October 1, 2000–September

30, 2001.

17,039,731

October 1, 2001–September

30, 2002.

28,948,352

For Transformer Losses

If delivery is made at transmission

voltage but metered on the low voltage

side of the substation, the meter

readings will be increased to

compensate for transformer losses as

provided for in the contract.

For Power Factor Adjustment

The customer will be required to

maintain a power factor at all points of

measurement between 95 percent

lagging and 95 percent leading. The low

power factor charge (LPF Charge) will

be applied when the customer does not

maintain a 95 percent or greater power

factor. The charge for additional

kilovolt-ampere reactive (kvar) required

to raise the customer’s power factor to

95 percent will be calculated by

multiplying the customer’s monthly

maximum peak demand by the LPF

Charge for the customer’s calculated

power factor as provided in the Table 2.

The kvar rate in the LPF Charge is $2.50

per kvar.

TABLE 2.—LOW POWER FACTOR

CHARGE

Calculated power factor

LPF

charge

($ per

kW)

0.95 ................................................. $0.00

0.94 ................................................. 0.09

0.93 ................................................. 0.17

0.92 ................................................. 0.24

0.91 ................................................. 0.32

0.90 ................................................. 0.39

0.89 ................................................. 0.46

0.88 ................................................. 0.53

0.87 ................................................. 0.60

0.86 ................................................. 0.66

0.85 ................................................. 0.73

0.84 ................................................. 0.79

0.83 ................................................. 0.86

0.82 ................................................. 0.92

0.81 ................................................. 0.99

0.80 ................................................. 1.05

0.79 ................................................. 1.12

0.78 ................................................. 1.18

0.77 ................................................. 1.25

0.76 ................................................. 1.32

0.75 & below ................................... 1.38

The rules and limitations of the LPF

Charge are as follow:

(a) The calculated power factor used

to determine if a charge will be assessed

is the arithmetic mean of the customer’s

measured monthly average power factor

and their measured monthly on-peak

power factor, rounded to the nearest

whole percent with 0.5 percent or

greater rounded to the next higher

percent.

(b) The measured on-peak power

factor is equal to the power factor

measured during the customer’s

maximum peak demand for each month,

as recorded at the customer’s point of

delivery. In the event of multiple

occurrences of the same peak demand,

the lowest associated power factor will

be used. The measured average power

factor will be the average power factor

for the billing month. If the customer

has multiple points of delivery, the

power factor will be determined from

totalized information from the points of

delivery. The monthly average and onpeak power factors are those recorded

for CVP power only.

(c) The upper limit for both the

monthly average and measured on-peak

power factors is 95 percent. No credit

will be given for customers operating

between 100 percent and 95 percent

power factors.

(d) The LPF Charge will be applicable

to calculated power factors less than 95

percent, lagging or leading.

(e) Customers that have a monthly

maximum peak demand less than or

equal to 50 kW will not be subject to the

LPF Charge.

(f) Western may waive the LPF Charge

for good cause in whole or in part.

Rate Schedule CV–FT3

(Supersedes Schedule CV–FT2)

Central Valley Project

Schedule of Rate for Firm Transmission

Service

Effective: October 1, 1997.

Available: Within the marketing area

served by the Sierra Nevada Customer

Service Region.

Applicable: To firm transmission

service where power is received into the

CVP system at points of interconnection

with other systems and transmitted and

delivered to points of delivery on the

CVP system as agreed to by the parties.

Character and Conditions of Service:

Transmission service for three-phase

alternating current at 60 hertz, delivered

and metered at the voltages and points

of delivery. Transmission service

includes scheduling, system control and

dispatch service, and reactive supply

and voltage control service needed to

support the transmission service

provided.

Rate: Firm Transmission Service

Charge: $0.51 per kW-month.

Billing: The rate listed above will be

applied monthly to the maximum

amount of capacity reserved, payable

whether utilized or not.

Adjustments

For Losses

Losses incurred in connection with

the transmission and delivery of power

under this rate schedule will be

accounted for as agreed to by the

parties.

Rate Schedule CV–NFT3

(Supersedes Schedule CV–NFT2)

Central Valley Project

Schedule of Rate for Non-Firm

Transmission Service

Effective: October 1, 1997.

Available: Within the marketing area

served by the Sierra Nevada Customer

Service Region.

Applicable: To non-firm transmission

service where power is received into the

CVP system at points of receipt with

other systems and transmitted and

delivered, subject to the availability of

transmission capacity, to points of
50940 Federal Register / Vol. 62, No. 188 / Monday, September 29, 1997 / Notices

delivery on the CVP system as agreed to

by the parties.

Character and Conditions of Service:

Transmission service on an intermittent

basis for capacity, three-phase

alternating current at 60 hertz, delivered

and metered at the voltages and points

of delivery. Transmission service

includes scheduling, system control and

dispatch service, and reactive supply

and voltage control service needed to

support the transmission service

provided.

Rate: Non-firm Transmission Service

Charge: 1.00 mill per kWh.

Billing: The rate listed above will be

applied monthly to the maximum

amount of capacity reserved, payable

whether utilized or not.

Adjustments

For Losses

Losses incurred in connection with

the transmission and delivery of power

under this rate schedule will be

accounted for as agreed to by the

parties.

Rate Schedule CV–TPT4

(Supersedes Schedule CV–TPT3)

Central Valley Project

Schedule of Rate for Transmission of

CVP Power by Others

Effective: October 1, 1997.

Available: Within the marketing area

served by the Sierra Nevada Customer

Service Region.

Applicable: To power service

customers of the CVP who require

transmission service by a third party to

receive power sold by Western.

Character and Conditions of Service:

Transmission service for three-phase

alternating current at 60 hertz, delivered

and metered at the voltages and points

of delivery as agreed to by the parties.

Rate Formula: When Western utilizes

transmission facilities, other than its

own, in providing service under a

customer’s power sales contract, and

costs are incurred by Western for the

use of such facilities, the customer will

pay all costs, including transmission

losses, incurred in the delivery of such

power. The transmission losses

chargeable to the customer will be those

losses which are in excess of the ‘‘at or

above 44-kV’’ transmission losses

specified by Contract No. 14–06–200–

2948A. For billing purposes,

transmission losses will be added to the

meter readings of the power and energy

delivered to the customer under the

customer’s power sales agreement with

Western.

Rate Schedule CV–NWT1

Central Valley Project

Schedule of Rate for Network

Transmission Service

Effective: October 1, 1997.

Available: Within the marketing area

served by the Sierra Nevada Customer

Service Region.

Applicable: To customers of the CVP

who receive network transmission

service, subject to the availability of

transmission capacity, to points of

delivery specified in the service

agreement.

Character and Conditions of Service:

Transmission service for three-phase

alternating current at 60 hertz, delivered

and metered at the voltages and points

of delivery. Transmission service

includes scheduling, system control and

dispatch service, and reactive supply

and voltage control service needed to

support the transmission service

provided.

Rate Formula: The rate formula for

network transmission service is the

product of the network customer’s load

ratio share times one twelfth (1⁄12) of the

annual network transmission revenue

requirement. The load ratio share is

based on the network customer’s hourly

load, including its designated network

load not physically interconnected with

the CVP transmission system,

coincident with the monthly CVP

transmission system peak minus the

coincident peak for all firm CVP

(including reserved capacity) point-topoint transmission service.

Billing: Billing determinants for the

rate formula above will be as specified

in the service agreement.

Adjustments

For Losses

Losses incurred in connection with

the transmission and delivery of power

under this rate schedule will be

accounted for in accordance with the

service agreement.

Rate Schedule CV–PSS1

Schedule of Rate for Power Scheduling

Service

Effective: October 1, 1997.

Available: Within the marketing area

served by the Sierra Nevada Customer

Service Region.

Applicable: To customers receiving

power scheduling service from Western.

Character and Conditions of Service:

Power scheduling service provides for

the scheduling of resources to meet

loads and reserve requirements.

Rate: $75.80 per hour.

Billing: The rate listed above will be

applied to the number of hours required

by Western staff to perform the power

scheduling service. A power scheduling

service charge will be specified in the

service agreement.

Rate Schedule CV–RFS1

Central Valley Project

Schedule of Rates for Regulation and

Frequency Response Service

Effective: October 1, 1997.

Available: Within the marketing area

served by the Sierra Nevada Customer

Service Region.

Applicable: To customers receiving

regulation and frequency response

service from Western.

Character and Conditions of Service:

Regulation and frequency response

service provides generation to match

resources and loads on a real-time

continuous basis.

Rates: Regulation and Frequency

Service Charge: Monthly: $1.48 per kWmonth; Weekly: $0.3360 per kW-week;

Daily: $0.0480 per kW-day.

Billing: The rates listed above will be

applied to the maximum service amount

in kilowatts agreed to in the service

agreement, payable whether utilized or

not.

Rate Schedule CV–EID1

Central Valley Project

Schedule of Rate for Energy Imbalance

Service

Effective: October 1, 1997.

Available: Within the marketing area

served by the Sierra Nevada Customer

Service Region.

Applicable: To customers receiving

energy imbalance service from Western.

Character and Conditions of Service:

Energy imbalance service provides

energy when a difference occurs

between the scheduled and actual

delivery of energy to a load or from a

generation resource within a control

area over a single month. The hourly

deviation, in megawatt units, is the net

scheduled amount of energy for the

hour minus the hourly net metered

(actual delivered) amount.

Rates Formula

Within Limits of Deviation Band

Accumulated deviations are to be

corrected or eliminated within 30 days.

Any net deviations that are accumulated

at the end of the month (positive or

negative) are to be exchanged with like

hours of energy or charged at the

composite rate for CVP commercial firm

power, then in effect.

Outside Limits of Deviation Band

(i) Positive Deviations—no charge,

lost to the system.
Federal Register / Vol. 62, No. 188 / Monday, September 29, 1997 / Notices 50941

(ii) Negative Deviations—during onpeak hours, the greater of (1) 3 times the

composite rate for CVP commercial firm

power, then in effect; or (2) any

additional cost incurred. During offpeak hours, the greater of (1) the

composite rate for CVP commercial firm

power, then in effect; or (2) any

additional cost incurred.

Billing: The billing determinants for

the above rates formula will be specified

in the service agreement.

Rate Schedule CV–SPR1

Central Valley Project

Schedule of Rates for Spinning Reserve

Service

Effective: October 1, 1997.

Available: Within the marketing area

served by the Sierra Nevada Customer

Service Region.

Applicable: To customers receiving

spinning reserve service from Western.

Character and Conditions of Service:

Spinning reserve service provides

capacity that is available the first ten

minutes to take load and is

synchronized with the power system.

Rates: Spinning Reserve Service

Charge: Monthly: $1.35 per kW-month;

Weekly: $0.3024 per kW-week; Daily:

$0.0432 per kW-day; Hourly: $0.0018

per kWh.

Billing: The rates listed above will be

applied to the maximum service amount

in kilowatts agreed to in the service

agreement, payable whether utilized or

not.

Rate Schedule CV–SUR1

Central Valley Project

Schedule of Rates for Supplemental

Reserve Service

Effective: October 1, 1997.

Available: Within the marketing area

served by the Sierra Nevada Customer

Service Region.

Applicable: To customers receiving

supplemental reserve service from

Western.

Character and Conditions of Service:

Supplemental reserve service provides

capacity that is not synchronized with

the power system, but can be available

to serve load within ten minutes.

Rates: Supplemental Reserve Service

Charge: Monthly: $1.27 per kW-month;

Weekly: $0.2856 per kW-week; Daily:

$0.0408 per kW-day; Hourly: $0.0017

per kWh.

Billing: The rates listed above will be

applied to the maximum service amount

in kilowatts agreed to in the service

agreement, payable whether utilized or

not.

Rate Schedule COTP–FT1

California-Oregon Transmission Project

Schedule of Rates for Firm

Transmission Service

Effective: October 1, 1997.

Available: Within the marketing area

served by the Sierra Nevada Customer

Service Region.

Applicable: To firm transmission

service customers where power is

received into the COTP system at points

of interconnection with other systems

and transmitted and delivered to points

of delivery on the COTP system as

agreed to by the parties.

Character and Conditions of Service:

Transmission service for three-phase

alternating current at 60 hertz, delivered

and metered at the voltages and points

of delivery. Transmission service

includes scheduling, system control and

dispatch service, and reactive supply

and voltage control service needed to

support the transmission service

provided.

Rates: October 1, 1997—September

30, 1998: $1.83 per kW-month. October

1, 1998—September 30, 2002: $1.34 per

kW-month.

Billing: The rates listed above will be

applied monthly to the maximum

amount of capacity reserved, payable

whether utilized or not.

Adjustments

For Losses

Losses incurred in connection with

the transmission and delivery of power

under this rate schedule will be

accounted for as agreed to by the

parties.

Rate Schedule COTP–NFT1

California-Oregon Transmission Project

Schedule of Rates for Non-Firm

Transmission Service

Effective: October 1, 1997.

Available: Within the marketing area

served by the Sierra Nevada Customer

Service Region.

Applicable: To non-firm transmission

service customers where power is

received into the COTP system at points

of receipt with other systems and

transmitted and delivered, subject to the

availability of transmission capacity, to

points of delivery on the COTP system

as agreed to by the parties.

Character and Conditions of Service:

Transmission service on an intermittent

basis for capacity, three-phase

alternating current at 60 hertz, delivered

and metered at the voltages and points

of delivery. Transmission service

includes scheduling, system control and

dispatch service, and reactive supply

and voltage control service needed to

support the transmission service

provided.

Rates: October 1, 1997–September 30,

1998: 2.19 mills per kWh; October 1,

1998–September 30, 2002: 1.45 mills

per kWh.

Billing: The rates listed above will be

applied monthly to the maximum

amount of capacity reserved, payable

whether utilized or not.

Adjustments

For Losses

Losses incurred in connection with

the transmission and delivery of power

and energy under this rate schedule will

be accounted for as agreed to by the

parties.

[FR Doc. 97–25746 Filed 9–26–97; 8:45 am]

BILLING CODE 6450–01–P

DEPARTMENT OF ENERGY

Western Area Power Administration

Colorado River Storage Project—

Notice of Order Confirming and

Approving an Extension of the Firm

Transmission Service Rate—WAPA–74

AGENCY: Western Area Power

Administration, DOE.

ACTION: Notice of rate order

SUMMARY: This action is to extend the

existing Colorado River Storage Project

firm transmission rate until March 31,

1998. Without this action, the existing

firm transmission rate will expire

September 30, 1997 and no rate will be

in effect for this service.

FOR FURTHER INFORMATION CONTACT: Mr.

Dave Sabo, CRSP Manager, CRSP

Customer Service Center, Western Area

Power Administration, P.O. Box 11606,

Salt Lake City, UT 84147–0606, (801)

524–5493.

SUPPLEMENTARY INFORMATION: By

Amendment No. 3 to Delegation Order

No. 0204–108, published November 10,

1993 (58 FR 59716), the Secretary of

Energy delegated (1) the authority to

develop long-term power and

transmission rates on a nonexclusive

basis to the Administrator of Western

Area Power Administration (Western);

(2) the authority to confirm, approve,

and place such rates into effect on an

interim basis to the Deputy Secretary;

and (3) the authority to confirm,

approve, and place into effect on a final

basis, to remand, or to disapprove such

rates to the Federal Energy Regulatory

Commission (FERC).

Pursuant to Delegation Order No.

0204–108 and existing Department of

Energy procedures for public