21202 Federal Register / Vol. 66, No. 82 / Friday, April 27, 2001 / Notices

DEPARTMENT OF ENERGY

Western Area Power Administration

Central Valley Project and CaliforniaOregon Transmission Project—Rate

Order No. WAPA–95

AGENCY: Western Area Power

Administration, DOE.

ACTION: Notice of rate order.

SUMMARY: Western Area Power

Administration’s Administrator has

confirmed and approved Rate Order No.

WAPA–95 and Rate Schedules CV–F10,

CV–FT4, CV–NFT4, CV–TPT5, CV–

NWT2, CV–RFS2, CV–EID2, CV–SPR2,

CV–SUR2, CV–PSS2, CV–SCS1, COTP–

FT2, and COTP–NFT2. These rate

schedules place into effect provisional

rates for the Central Valley Project (CVP)

firm power and transmission services,

ancillary services, power scheduling

service, and scheduling coordinator

service, and the California-Oregon

Transmission Project (COTP)

transmission services of the Western

Area Power Administration (Western).

The provisional rates will be in effect

for an interim period until the Federal

Energy Regulatory Commission (FERC)

confirms, approves, and places them

into effect on a final basis or until they

are replaced by other rates. The

provisional rates will provide sufficient

revenue to pay all annual costs,

including interest expense, and repay

required investment in the allowable

period.

DATES: The provisional rates will be

effective the first day of the first full

billing period beginning on or after

April 1, 2001, until FERC confirms,

approves, and places them into effect on

a final basis. These rates will stay in

effect through December 31, 2004, or

until other rates replace them.

FOR FURTHER INFORMATION CONTACT: Ms.

Debbie Dietz, Rates Manager, Western

Area Power Administration, Sierra

Nevada Customer Service Region, 114

Parkshore Drive, Folsom, CA 95630–

4710, (916) 353–4453, e-mail

ddietz@wapa.gov.

SUPPLEMENTARY INFORMATION: The

Deputy Secretary of Energy approved

the existing Rate Schedules CV–F9 for

CVP commercial firm power, CV–FT3,

CV–NFT3, CV–TPT4, and CV–NWT1 for

CVP transmission services, CV–RFS1,

CV–EID1, CV–SPR1, CV–SUR1 for CVP

ancillary services, CV–PSS1 for power

scheduling service, and COTP–FT1 and

COTP–NFT1 for COTP transmission

services on September 19, 1997 (Rate

Order No. WAPA–77, 62 FR 50924,

September 29, 1997). FERC confirmed

and approved the rate schedules on

January 8, 1998, under FERC Docket No.

EF97–5011–000 (82 FERC ¶62,006). The

existing rate schedules became effective

October 1, 1997, for the period ending

September 30, 2002.

Rate Schedule CV–F10 supersedes

Rate Schedule CV–F9. Under Rate

Schedule CV–F9, the composite rate on

April 1, 2001, is 18.56 mills per

kilowatthour (mills/kWh). The

provisional rates for CVP firm power in

Rate Schedule CV–F10 will result in an

overall composite rate of 20.08 mills/

kWh on April 1, 2001. This results in an

increase of about 8 percent when

compared with the existing CVP

commercial firm power rates under Rate

Schedule CV–F9.

Western also developed provisional

rates for CVP firm power with the

transmission revenue requirement

removed from the CVP firm power

revenue requirement. These rates are

also in Rate Schedule CV–F10. These

rates will apply if Western joins the

California Independent System Operator

(CAISO) or a Regional Transmission

Organization (RTO) and if the CAISO or

RTO uses Western’s transmission

revenue requirement to develop a

regional transmission rate. The

provisional rates for CVP firm power

with the transmission revenue

requirement removed in Rate Schedule

CV–F10 will result in an overall

composite rate of 18.51 mills/kWh on

April 1, 2001. This results in a decrease

of less than 1 percent when compared

with the existing CVP commercial firm

power rates under Rate Schedule CV–

F9. In addition, both sets of CVP firm

power provisional rates include any

charges or credits associated with the

creation, termination, or modification to

any tariff, contract, or schedule

approved or accepted by FERC, under

which Western take service will be

passed through to the appropriate

customers.

Rate Schedules CV–FT4, CV–NFT4,

CV–TPT5, and CV–NWT2 replace Rate

Schedules CV–FT3, CV–NFT3, CV–

TPT4, and CV–NWT1, respectively.

Provisional formula rates developed for

CVP transmission services are

consistent with FERC Order No. 888.

Under Rate Schedules CV–FT3 and CV–

NFT3, the CVP transmission services

rates on April 1, 2001, are $0.51/

kWmonth for firm service and 1.00 mill/

kWh for nonfirm service. On April 1,

2001, the provisional formula rate in

Rate Schedule CV–FT4 results in an

estimated rate of $.70/kWmonth for firm

CVP transmission service, a 37-percent

increase when compared with the

existing rate. Based on an Open Access

Transmission Tariff Service Agreement

to provide transmission service in the

future, on October 1, 2001, the

provisional formula rate in Rate

Schedule CV–FT4 results in an

estimated rate of $.56/kWmonth for CVP

firm transmission service. On April 1,

2001, the provisional formula rate in

Rate Schedule CV–NFT4 results in a

rate of 1.00 mill/kWh for CVP nonfirm

transmission service, which is the same

rate as the existing rate. If the rates

resulting from the proposed formula rate

are higher than other transmission rates

in California, firm or nonfirm

transmission service for 1 year or less

may be sold at lower rates. The

provisional rate for transmission of CVP

power by others in Rate Schedule CV–

TPT5 is a pass through cost and results

in no change from the existing Rate

Schedule CV–TPT4 on April 1, 2001.

The provisional formula rate for

network integration transmission

service in Rate Schedule CV–NWT2 will

be the same as the existing formula rate

for network integration transmission

service under Rate Schedule CV–NWT1.

The existing transmission rates

include costs for scheduling, system

control and dispatch service and

reactive supply and voltage control

service. The transmission provisional

formula rates include the costs of these

services.

The provisional rates in Rate

Schedule CV–RFS2, effective April 1,

2001, for monthly regulation and

frequency response service will result in

a 69-percent increase for the same

service when compared to the existing

monthly rate under Rate Schedule CV–

RFS1. The provisional rates for

regulation and frequency response

service are: monthly—$2.496/kWmonth,

weekly—$.574/kWweek, and daily—

$.082/kWday. The weekly and daily

rates are derived from the monthly rate.

The provisional formula rate for

energy imbalance service under Rate

Schedule CV–EID2 will be the same as

the existing formula rate for energy

imbalance service under Rate Schedule

CV–EID1.

The provisional rates in Rate

Schedule CV–SPR2, effective April 1,

2001, for monthly spinning reserve

service will result in a 118-percent

increase for the same service when

compared to the existing monthly rate

under Rate Schedule CV–SPR1. The

provisional rates for spinning reserve

service are: monthly—$2.946/kWmonth,

weekly—$.672/kWweek, daily—$.096/

kWday, and hourly—$.0040/kWh. The

weekly, daily, and hourly rates are

derived from the monthly rate.

The provisional rates in Rate

Schedule CV–SUR2, effective April 1,

2001, for monthly supplemental reserve

Federal Register / Vol. 66, No. 82 / Friday, April 27, 2001 / Notices 21203

service will result in a 96-percent

increase for the same service when

compared to the existing monthly rate

under Rate Schedule CV–SUR1. The

provisional rates for supplemental

reserve service are: monthly—$2.491/

kWmonth, weekly—$.574/kWweek,

daily—$.082/kWday, and hourly—

$.0034/kWh. The weekly, daily, and

hourly rates are derived from the

monthly rates.

The provisional rate for power

scheduling service in Rate Schedule

CV–PSS2 is $76.65 per hour. This

results in a 1-percent increase compared

to the existing rate in Rate Schedule

CV–PSS1 of $75.80 per hour on April 1,

2001.

Scheduling coordinator service is a

new service. The provisional rate for

scheduling coordinator service is $76.65

per hour and is designed to recover only

the cost incurred for providing the

service.

Rate Schedules COTP–FT2 and

COTP–NFT2 replace Rate Schedules

COTP–FT1 and COTP–NFT1.

Provisional formula rates developed for

COTP firm and nonfirm transmission

services are consistent with FERC Order

No. 888. The estimated rates from the

provisional formula rate in Rate

Schedule COTP–FT2 for firm

transmission service for Western’s share

of the COTP will result in a 30-percent

decrease in the summer, a 16-percent

decrease in the winter, and a 25-percent

decrease in the spring compared to the

existing rate of $1.34/kWmonth in Rate

Schedule COTP–FT1 on April 1, 2001.

The estimated rates from the provisional

formula rate for COTP firm transmission

service beginning in April 2001 are:

summer—$.94/kWmonth, winter—

$1.12/kWmonth, and spring—$1.00/

kWmonth. The estimated rates from the

provisional formula rate in Rate

Schedule COTP–NFT2 for COTP

nonfirm transmission service will result

in a 11-percent decrease in the summer,

a 6-percent increase in the winter, and

a 6-percent decrease in the spring

compared to the existing rate in Rate

Schedule COTP–NFT1 of 1.45 mills/

kWh on April 1, 2001. The estimated

rates from the provisional formula rate

for COTP nonfirm transmission service

beginning April 2001 are: summer—1.29

mills/kWh, winter—1.54 mills/kWh,

and spring—1.37 mills/kWh.

Provisional Rates for CVP Firm Power

On December 13, 2000, Western

provided updates to the proposed CVP

firm power rates. There were no updates

to any of the other rates proposed by

Western.

The CVP firm power rates include

Project Dependable Capacity support

purchase costs and pass through of

FERC-accepted or -approved costs or

credits. Western also updated the

Revenue Adjustment Clause (RAC). The

limit for the RAC credit and surcharge

is $20 million, $10 million for the

October to December 2004 period, plus

any purchase or exchange power

contract adjustments.

Western developed two sets of

provisional firm power rates. One set of

rates includes the transmission revenue

requirement, and the other set of rates

removes the transmission revenue

requirement. Both sets are designed to

recover an annual revenue requirement

that includes investment repayment,

interest, purchase power costs,

operation and maintenance (O&M)

expense, and FERC-accepted or

-approved charges or credits. Western

used a cost-of-service study to divide

the projected annual revenue

requirement for firm power between

capacity and energy. Based on this

study, the capacity revenue requirement

includes: (1) 100 percent of capacity

purchase costs; (2) 50 percent of the

investment repayment; (3) 50 percent of

the interest expense; (4) 50 percent of

the O&M expense allocated to power;

and (5) 100 percent of CVP and COTP

transmission expense. Projected CVP

and COTP transmission revenue and 50

percent of projected CVP project use

revenue reduce the annual costs that

make up the capacity revenue

requirement. The energy revenue

requirement includes: (1) 100 percent of

energy purchase costs; (2) 50 percent of

the investment repayment; (3) 50

percent of the interest expense; and (4)

50 percent of the O&M expense

allocated to power. Projected surplus

power revenue and 50 percent of

projected CVP project use revenue

reduce the annual costs that make up

the energy revenue requirement.

For the provisional power rates with

the transmission revenue requirement

removed, Western used a cost-of-service

study to divide the projected annual

revenue requirement for firm power

between capacity and energy. Based on

this study, the capacity revenue

requirement includes: (1) 100 percent of

capacity purchase costs; (2) 50 percent

of the investment repayment; (3) 50

percent of the interest expense; and (4)

50 percent of the O&M expense

allocated to power. Fifty percent of the

projected CVP project use revenue

reduces the annual costs that make up

the capacity revenue requirement. The

energy revenue requirement includes:

(1) 100 percent of energy purchase costs;

(2) 50 percent of the investment

repayment; (3) 50 percent of the interest

expense; and (4) 50 percent of the O&M

expense allocated to power. Projected

surplus power revenue and 50 percent

of the projected CVP project use revenue

reduce the annual costs that make up

the energy revenue requirement.

Additionally, under both sets of CVP

firm power rates, Western will also pass

through to each appropriate customer

any charges or credits associated with

the creation, termination, or

modification to any tariff, contract, or

schedule accepted or approved by FERC

under which Western takes service.

Rate Schedule CV–F9 and Rate

Schedule CV–F10 include adjustment

clauses for power factors, low voltage

losses, and revenue.

Power Factor Adjustment

The power factor adjustment is a low

power factor (LPF) charge that applies

when the customer does not maintain a

calculated 95 percent or greater power

factor.

Low Voltage Loss Adjustment

The low voltage loss adjustment

applies to the billed amounts for low

voltage CVP firm power deliveries on

the Pacific Gas and Electric Company

(PG&E) system.

Revenue Adjustment

The RAC provides for a comparison

between the projected net revenues in

the rate adjustment power repayment

study (PRS) to the actual net revenues.

If the actual net revenue is more than

the projected net revenue, CVP firm

power customers receive a credit. If

actual net revenue is less than the

projected net revenue, CVP firm power

customers may pay a surcharge, if

needed, to make a minimum investment

payment. The limit for the RAC credit

or surcharge is $20 million, $10 million

for the October to December 2004

period, plus any purchase or exchange

power contract adjustments during the

fiscal year (FY) for which the RAC is

being calculated. The RAC is calculated

annually and the associated distribution

of the RAC credit or surcharge occurs

during a 9-month period on power bills

issued January through September. For

customers whose RAC credits cannot be

fully credited through nine equal

monthly amounts, Western has the

option to increase the RAC credit during

August and September. The first RAC

calculation under the provisional rates

will be based on the net revenue for FY

2001, including revenues and expenses

for October 2000 to March 2001, which

is outside of the rate adjustment period.

A RAC will be calculated for October

through December 2004. The RAC credit

or surcharge for October through

21204 Federal Register / Vol. 66, No. 82 / Friday, April 27, 2001 / Notices

December 2004 is applied to the April

to September 2005 bills.

Provisional Formula Rates for CVP

Transmission Services

A revenue requirement that recovers:

(1) the costs for facilities that support

the transfer capability of the CVP

transmission system (excluding

generation facilities and radial lines); (2)

the nonfacilities costs allocated to

transmission; and (3) any transmissionrelated costs incurred by Western due to

electric industry restructuring or other

changes in the industry is the basis for

the provisional formula rates in Rate

Schedules CV–FT4 and CV–NFT4 for

CVP firm and nonfirm transmission

services. Western will revise as of April

30 of each year the rates from the

provisional formula rates based on

updated data. In addition to the annual

update on April 30 of each year,

Western will also revise the rates if

there is a change in the numerator or

denominator that results in a firm

transmission rate change of at least $.05/

kWmonth. The provisional formula

rates include Western’s cost for

scheduling, system control and dispatch

service and reactive supply and voltage

control service needed to support the

transmission service. The provisional

formula rates apply to existing CVP firm

transmission service and future pointto-point transmission service. If the

rates from the provisional formula rates

are higher than other transmission rates

in California, firm or nonfirm

transmission service for 1 year or less

may be sold at lower rates.

Provisional Rate for Transmission of

CVP Power by Others

Western will pass on to the

appropriate customer any transmission

service costs it incurs for delivering CVP

power over a third party’s transmission

system. The provisional rate in Rate

Schedule CV–TPT5 will be adjusted

automatically as third party

transmission costs are adjusted.

Provisional Formula Rate for Network

Integration Transmission Service

If Western offers network integration

transmission service, it will be

consistent with FERC Order No. 888.

The provisional formula rate for

network integration transmission

service is the product of the network

customer’s load ratio share times 1⁄12 of

the annual network transmission

revenue requirement. The load ratio

share is the network customer’s hourly

load coincident with Western’s monthly

CVP transmission system peak, minus

the coincident peak for all firm CVP

point-to-point transmission service, plus

the reserved capacity of all firm pointto-point transmission service customers.

A revenue requirement that recovers: (1)

the costs for facilities that support the

transfer capability of the CVP

transmission system (excluding

generation facilities and radial lines); (2)

the nonfacilities costs allocated to

transmission; and (3) any transmissionrelated costs incurred by Western due to

electric industry restructuring or other

changes in the industry is the basis for

the provisional formula rate for network

integration transmission service. The

provisional formula rate includes

Western’s cost for scheduling, system

control and dispatch service and

reactive supply and voltage control

service needed to support the

transmission service.

Provisional Rates for Ancillary Services

Western will offer six ancillary

services consistent with FERC Order No.

888. Two of the ancillary services—

scheduling, system control and dispatch

service and reactive supply and voltage

control service—are included with the

sale of CVP and/or COTP transmission

services. The appropriate transmission

services rates include the costs for these

two ancillary services. Subject to

availability, Western will offer

regulation and frequency response,

energy imbalance, spinning reserve, and

supplemental reserve services. Except

for the two ancillary services provided

with the sale of CVP and/or COTP

transmission services, the basis for

availability and type of ancillary

services is excess resources at the time

the service is requested.

Provisional Rate for Power Scheduling

Service

The power scheduling service

schedules resources to meet load and

reserve requirements. The provisional

rate for power scheduling service is

designed to recover only the cost to

supply the service.

Provisional Rate for Scheduling

Coordinator Service

Scheduling coordinator service is a

new service. It includes scheduling,

real-time dispatching, and financial

settlements with the CAISO and/or

power exchanges. The provisional rate

for scheduling coordinator service is

designed to recover only the cost to

supply the service.

Provisional Formula Rates for COTP

Transmission Services

A revenue requirement that recovers:

(1) Western’s share of costs for facilities

that support the transfer capability of

the COTP; (2) Western’s share of the

nonfacilities costs allocated to

transmission; and (3) any transmissionrelated costs that Western incurs due to

electric industry restructuring or other

changes in the industry is the basis for

the provisional formula rates in Rate

Schedules COTP–FT2 and COTP–NFT2

for COTP firm and nonfirm transmission

services. The rates from the provisional

formula rate will be updated each

season to coincide with the changes in

the California-Oregon Intertie transfer

capability. The provisional formula

rates include Western’s cost for

scheduling, system control and dispatch

service and reactive supply and voltage

control needed to support the

transmission service. The provisional

formula rates apply to existing COTP

firm and nonfirm transmission service

and future point-to-point transmission

service. If the rates from the provisional

formula rate are higher than other

transmission rates in California, firm or

nonfirm transmission service for 1 year

or less may be sold at lower rates.

Procedural Requirements

The provisional rates for CVP firm

power and transmission services,

ancillary services, power scheduling

service, scheduling coordinator service,

and COTP transmission services are

developed under the Department of

Energy Organization Act (42 U.S.C.

7101–7352.), through which the power

marketing functions of the Secretary of

the Interior and the Bureau of

Reclamation under the Reclamation Act

of 1902 (ch. 1093, 32 Stat. 388), as

amended and supplemented by

subsequent enactments, particularly

section 9(c) of the Reclamation Project

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

other acts that specifically apply to the

project involved, were transferred to

and vested in the Secretary of Energy.

By Amendment No. 3 to Delegation

Order No. 0204–108, published

November 10, 1993 (58 FR 59716), the

Secretary of Energy delegated (1) the

authority to develop long-term power

and transmission rates on a

nonexclusive basis to Western’s

Administrator; and (2) the authority to

confirm, approve, and place into effect

on a final basis, to remand, or to

disapprove such rates to FERC. In

Delegation Order No. 0204–172,

effective November 24, 1999, the

Secretary of Energy delegated the

authority to confirm, approve, and place

such rates into effect on an interim basis

to the Deputy Secretary. On April 10,

2001, by Amendment No. 4 to

Delegation Order No. 0204–108, the

Secretary of Energy delegated to

Western’s Administrator the authority to

confirm, approve, and place into effect

Federal Register / Vol. 66, No. 82 / Friday, April 27, 2001 / Notices 21205

on an interim basis the rates in the

Central Valley Project and CaliforniaOregon Transmission Project-Rate Order

No. WAPA–95.

Western followed the DOE procedures

for Public Participation in Power and

Transmission Rate Adjustments and

Extensions (10 CFR part 903) to develop

these provisional rates.

Rate Order No. WAPA–95,

confirming, approving, and placing the

proposed CVP firm power and

transmission services, ancillary services,

power scheduling service, and

scheduling coordinator service rates,

and the COTP transmission services

rates into effect on an interim basis, is

issued. New Rate Schedules CV–F10,

CV–FT4, CV–NFT4, CV–TPT5, CV–

NWT2, CV–RFS2, CV–EID2, CV–SPR2,

CV–SUR2, CV–PSS2, CV–SCS1, COTP–

FT2, and COTP–NFT2 will be submitted

promptly to FERC for confirmation and

approval on a final basis.

Dated: April 13, 2001.

Michael S. Hacskaylo,

Administrator.

Order Confirming, Approving, and

Placing the Central Valley Project Firm

Power, Transmission Services,

Ancillary Services, Power Scheduling

Service, and Scheduling Coordiantor

Service Rates, and the CaliforniaOregon Transmission Project

Transmission Services Rates Into Effect

on an Interim Basis

These rates are developed under the

Department of Energy Organization Act

(42 U.S.C. 7101–7352), through which

the power marketing functions of the

Secretary of the Interior and the Bureau

of Reclamation under the Reclamation

Act of 1902 (ch. 1093, 32 Stat. 388), as

amended and supplemented by

subsequent enactments, particularly

section 9(c) of the Reclamation Project

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

other acts that specifically apply to the

project involved, were transferred to

and vested in the Secretary of Energy

(Secretary).

By Amendment No. 3 to Delegation

Order No. 0204–108, published

November 10, 1993 (58 FR 59716), the

Secretary delegated (1) the authority to

develop long-term power and

transmission rates on a nonexclusive

basis to Western’s Administrator; and

(2) the authority to confirm, approve,

and place into effect on a final basis, to

remand, or to disapprove such rates to

the FERC. In Delegation Order No.

0204–172, effective November 24, 1999,

the Secretary delegated the authority to

confirm, approve, and place such rates

into effect on an interim basis to the

Deputy Secretary. On April 10, 2001, by

Amendment No. 4 to Delegation Order

No. 0204–108, the Secretary of Energy

delegated to Western’s Administrator

the authority to confirm, approve, and

place into effect on an interim basis the

rates in the Central Valley Project and

California-Oregon Transmission ProjectRate Order No. WAPA–95. Existing DOE

procedures for public participation in

power and transmission rate

adjustments are found in 10 CFR part

903. Procedures for approval of Power

Marketing Administration rates are

found in 18 CFR part 300.

Acronyms and Definitions

As used in this rate order, the

following acronyms and definitions

apply:

Administrator ............................. The Administrator of the Western Area Power Administration.

Ancillary Services ...................... Those services necessary to support the transfer of electricity while maintaining reliable operation of the

transmission system following good utility practice. Federal Energy Regulatory Commission Order No.

888, Docket Nos. RM95–8–000 and RM94–7–001, issued April 24, 1996, generally describe ancillary

services.

CAISO ......................................... The California Independent System Operator Corporation. A state chartered, nonprofit corporation that

controls the transmission facilities of all participating transmission owners and dispatches certain generating units and loads.

COI .............................................. The California-Oregon Intertie. It is three 500-kilovolt lines linking California and Oregon making up the

California-Oregon Transmission Project and Pacific Alternating Current Intertie transmission lines. The

Western Systems Coordinating Council establishes the seasonal transfer capability for the CaliforniaOregon Intertie.

COTP ........................................... The California-Oregon Transmission Project. A 500-kilovolt transmission project in which Western has

part ownership.

CRD ............................................. Contract rate of delivery. The maximum amount of capacity made available to a preference customer for

a period specified under a contract.

CVP .............................................. The Central Valley Project. A multipurpose Federal water development project extending from the Cascade Range in northern California to the plains along the Kern River south of the city of Bakersfield.

Capacity ...................................... The electric capability of a generator, transformer, transmission circuit or other equipment. It is expressed in kilowatts.

Capacity Rate .............................. The rate that states the charge for capacity. It is expressed in dollars per kilowatt and applied to each

kilowatt delivered to each customer.

Composite Rate ........................... The rate for firm power. The annual revenue requirement for firm power divided by the total annual energy sales. It is expressed in mills per kilowatthour and used for comparison purposes.

Contract 2947A ........................... Contract No. 14–06–200–2947A, as amended. The Western Area Power Administration’s contract with

the Pacific Gas and Electric, Southern California Edison, and San Diego Gas and Electric companies

for extra high voltage transmission and exchange service.

Contract 2948A ........................... Contract No. 14–06–200–2948A, as amended. The Pacific Gas and Electric Company’s contract with the

Western Area Power Administration for the sale, interchange, and transmission of power.

Corps ........................................... United States Army Corp of Engineers.

Customer ..................................... An entity with a contract and receiving service from the Western Area Power Administration’s Sierra

Nevada Customer Service Region.

DLL .............................................. Designated load level. The simultaneous load level at which the Western Area Power Administration

buys capacity from the Pacific Gas and Electric Company at the lower of two capacity rates under Contract No. 14–06–200–2948A.

DOE Order RA6120.2 ................. An order dealing with power marketing administration financial reporting and repayment criteria.

EA2 .............................................. Energy Bank Account No. 2 between the Western Area Power Administration and the Pacific Gas and

Electric Company under Contract No. 14–06–200–2948A.

21206 Federal Register / Vol. 66, No. 82 / Friday, April 27, 2001 / Notices

Energy ......................................... Measured in terms of the work it is capable of doing over a period of time. It is expressed in

kilowatthours.

Energy Rate ................................. The rate that states the charge for energy. It is expressed in mills per kilowatthour and applied to each

kilowatthour delivered to each customer.

FY ................................................ Fiscal year. October 1 to September 30.

Firm ............................................. A type of product and/or service available at the time requested by the customer.

First Preference Customer .......... An entity qualified to use preference power within a county of origin (Trinity, Calaveras, and Tuolumne)

as specified under the Trinity River Division Act of August 12, 1955 (69 Stat. 719), and the Flood Control Act of 1962 (76 Stat. 1180).

kV ................................................ Kilovolt. The electrical unit of measure of electric potential that equals one thousand volts.

kvar .............................................. Kilovolt-ampere reactive. The electrical unit of measurement for reactive power in a circuit that equals

one thousand volt-amperes.

kW ............................................... Kilowatt. The electrical unit of capacity that equals one thousand watts.

kWh ............................................. Kilowatthour. The electrical unit of energy that equals one thousand watts in one hour.

kWmonth .................................... Kilowattmonth. The electrical unit of the monthly amount of capacity.

Load Factor ................................. The ratio of average load in kilowatts supplied during a specified period to the peak or maximum load

in kilowatts occurring in that period.

MW .............................................. Megawatt. The electrical unit of capacity that equals one million watts or one thousand kilowatts.

Mill .............................................. A monetary denomination of the United States that equals one tenth of a cent or one thousandth of a

dollar.

Mills/kWh ................................... Mills per kilowatthour. The unit of charge for energy.

NEPA ........................................... National Environmental Policy Act of 1969 (42 U.S.C. 4321 et seq.).

Net Revenue ................................ Revenue remaining after paying all annual expenses.

Nonfirm ....................................... A type of product and/or service that may not be available at the time requested by the customer.

Northwest .................................... Northwest United States, including Oregon and Washington.

PDC .............................................. Project Dependable Capacity. A negotiated amount of capacity and associated energy available from the

CVP under contract 2948A.

Power .......................................... Capacity and energy.

Power Factor ............................... The ratio of real to apparent power at any given point and time in an electrical circuit. Generally it is expressed as a percentage ratio.

Preference ................................... The requirements of Reclamation law which state that preference in the sale of Federal power shall be

given to municipalities and other public corporations or agencies and also to cooperatives and other

nonprofit organizations financed in whole or in part by loans made under the Rural Electrification Act

of 1936 (Reclamation Project Act of 1939, section 9(c), 43 U.S.C. 485h(c)).

Project Use .................................. Power used to operate Central Valley Project facilities, pursuant to Reclamation law.

Provisional Rates ........................ Rates the Deputy Secretary of Energy has confirmed, approved, and placed in effect on an interim basis.

Rate Brochure ............................. A November 17, 2000, document prepared for public distribution that explains the rationale and development of the rates in this rate order.

Reclamation ................................ United States Department of the Interior, Bureau of Reclamation.

Reclamation Law ........................ A series of Federal laws. Viewed as a whole, these laws create the originating framework in which the

Western Area Power Administration markets power.

Secretary ..................................... Secretary of the United States Department of Energy.

Sierra Nevada Region ................. The Sierra Nevada Customer Service Region of the Western Area Power Administration.

Western ....................................... United States Department of Energy, Western Area Power Administration.

Withdrawable ............................. Power that may be withdrawn under certain conditions.

Effective Date

The provisional rates will take effect

on the first day of the first full billing

period beginning on or after April 1,

2001, and will be in effect pending

FERC’s approval of them or substitute

final rates. The approved rates will stay

in effect through December 31, 2004, or

until superseded.

Public Notice and Comment

Western followed 10 CFR part 903,

Procedures for Public Participation in

Power and Transmission Rate

Adjustments and Extensions, in

developing these rates. The steps

Western took to involve interested

parties in the rate development process

are:

1. The proposed rate adjustment

started on August 25, 2000, with a letter

to all CVP preference customers and

interested parties announcing an

informal rate workshop on August 31,

2000. Two additional informal rate

meetings were held on September 20,

2000, and October 5, 2000, in Folsom,

California, to discuss Western’s

proposed rates. Western explained the

rationale for the rate adjustment,

presented rate designs and

methodologies, and answered questions.

2. A Federal Register notice

published on November 8, 2000 (65 FR

66989), officially announced the

proposed rates for the CVP and COTP,

started the public consultation and

comment period, and announced the

public information and public comment

forums.

3. On November 13, 2000, Western’s

Sierra Nevada Customer Service Region

sent a letter to all CVP preference

customers and interested parties

announcing the times and locations for

two public forums.

4. On November 17, 2000, 1 p.m.,

Western held a public information

forum in Folsom, California. Western

gave detailed explanations of the

proposed rates for the CVP and COTP,

supplied a list of issues that could

change the proposed rates, answered

questions, and gave notice that it would

supply additional information at the

public comment forum. A rate brochure

and handout were made available.

5. On December 13, 2000, 1 p.m.,

Western held a public comment forum

in Folsom, California. Western

presented updated proposed rates for

CVP firm power, gave a detailed

explanation of the updates to the

proposed rates, answered questions, and

distributed information about the

updated rates. Western then gave the

public an opportunity to comment for

the record. Two representatives made

oral comments.

6. Western received four comment

letters during the consultation and

comment period, which ended

December 29, 2000. Western considered

all comments received during the

comment period.

Federal Register / Vol. 66, No. 82 / Friday, April 27, 2001 / Notices 21207

Project Description

Initially authorized by Congress in

1935, CVP is a large water and power

system that covers about one-third of

the state of California. Legislation set

the purposes of CVP in priority as: (1)

Improvement of navigation; (2) river

regulation; (3) flood control; (4)

irrigation; and (5) power. The CVP

Improvement Act of 1992 added fish

and wildlife as a priority between

irrigation and power.

The CVP is within the Central Valley

and Trinity River basins of California. It

includes 18 dams and reservoirs with a

total storage capacity of 13 million acrefeet. The system includes 615 miles of

canals, 5 pumping facilities, 10

powerplants with a maximum operating

capability of about 2,021 MW, about 946

circuit-miles of high voltage

transmission lines, 15 substations, and

16 communication sites. Reclamation

operates the water control and delivery

system and all of the powerplants

except the San Luis Unit, which the

State of California operates for

Reclamation.

The Emergency Relief Appropriations

Act of 1935 authorized Reclamation to

build the CVP, including Shasta and

Keswick Dams on the Sacramento River.

The initial authorization included

powerplants at Shasta and Keswick

Dams along with high voltage

transmission lines to transmit power

from Shasta and Keswick Powerplants

to the Tracy Pumping Plant and to

integrate Federal hydropower into other

electric systems.

Additional CVP facilities were

authorized by Congress through a series

of laws. The American River Division

was authorized in 1944 and includes the

Folsom Dam and Powerplant and the

Nimbus Dam and Powerplant on the

American River. The Trinity Dam and

Powerplant, Judge Francis Carr

Powerplant, and Spring Creek

Powerplant were authorized as part of

the Trinity River Divison in 1955. The

San Luis Unit was authorized in 1960

and includes the B. F. Sisk San Luis

Dam and San Luis Reservoir, O’Neill

and Dos Amigos Pumping Plants, and

William R. Gianelli Pump-Generator. In

1962, Congress authorized for

integration into CVP New Melones,

which is a Corps project.

In 1964, Congress authorized the 500-

kV Intertie. Western has a 400 MW

entitlement of transmission capacity on

the Intertie. On July 31, 1967,

Reclamation (Western’s predecessor),

PG&E, the Southern California Edison

Company, and the San Diego Gas &

Electric Company entered into Contract

2947A to coordinate the operation of the

Intertie to transmit electric power

between the Northwest and the Pacific

Southwest.

In marketing Federal hydroelectric

power generated from the CVP, Western

currently has 80 preference and 34

project use customers serving an

estimated 2 million people.

In 1967, PG&E and Reclamation

(Western’s predecessor) executed

Contract 2948A, allowing for the sale,

interchange, and transmission of electric

capacity and energy between Western

and PG&E. Contract 2948A also includes

provisions for integrating power

generated from the CVP with Western’s

400 MW of entitlement on the Intertie.

The contract also states PG&E will

support a maximum simultaneous

demand of 1,152 MW for preference

customers through 2004. If CVP power

cannot meet obligations to preference

customers, Contract 2948A gives

Western the right to purchase capacity

and energy from PG&E to meet those

requirements. Any energy in excess of

project use loads and Western’s

obligations to preference customers can

be sold to PG&E through an energy

banking provision in the contract. The

energy made available under this

banking arrangement allows Western to

supplement CVP generation to meet

preference customer load.

Power generated from the CVP is first

dedicated to project use. The remaining

power is allocated to various preference

customers in California. Types of

preference customers include: (1)

Irrigation and water districts; (2) public

utility districts; (3) municipalities; (4)

Federal agencies; (5) State agencies; and

(6) rural electric cooperatives.

Each preference customer’s CRD

includes firm long-term power

allocations, and may include

withdrawable allocations that are

currently allocated to, but unused by,

another customer. For this rate

adjustment, it is assumed that all

customer withdrawable CRDs can be

withdrawn in the event the maximum

simultaneous demand of 1,152 MW in

Contract 2948A is exceeded.

Western’s preference customer

maximum simultaneous demand of

1,152 MW excludes project use loads.

The maximum simultaneous demand is

the sum of each preference customer’s

demand for CVP power at a coincidental

moment, adjusted to the load center at

the Tracy Switchyard. Despite the

simultaneous demand limit, Western

has contractual obligations to serve

about 1,502 MW of firm CRD to its

preference customers. This level of CRD

can be served because of the diversity in

customers’ loads.

The COTP is a 342-mile, 500-kV

transmission project that electrically

interconnects the Northwest to

California with the third alternating

current intertie. Operational since

March 1993, COTP interconnects with

the transmission systems of the

Northwest at Captain Jack Substation

and with the Pacific Southwest by its

connection near the Tesla Substation to

the existing Intertie. Project owners

include Western and several nonFederal participants.

Power Repayment Study

Western prepares a power repayment

study (PRS) each FY to decide if

revenues will be sufficient to pay,

within the prescribed time periods, all

costs assigned to the CVP power

function. Repayment criteria are based

on law, policies including DOE Order

RA6120.2, and authorizing legislation.

The CVP rate adjustment PRS reflects an

increase in customer load, purchase

power costs, Reclamation O&M costs,

and CVP and COTP transmission and

CVP project use revenues. It also reflects

the suspension in Western’s Northwest

purchase power contracts. The PRS

shows enough revenue to pay all annual

costs, including interest expense, and

repays investment in the allowable

period.

Transmission Cost-of-Service Study

The CVP and COTP firm and nonfirm

transmission provisional formula rates

consist of two components. Component

1 recovers the cost of the CVP

transmission system and COTP.

Component 2 is any transmissionrelated costs incurred by Western due to

electric industry restructuring or other

industry changes. A cost-of-service

study determines component 1. The

CVP transmission system and COTP

have separate cost-of-service studies

that are used for the firm and nonfirm

provisional formula rates. The studies

identify the costs associated with

facilities that support the transfer

capability of the CVP transmission

system and COTP, excluding generation

facilities and radial lines.

There are two primary reasons for the

increase in transmission costs in the

CVP cost-of-service study. One reason is

facilities that support the transfer

capability of the CVP transmission

system (excluding generation facilities

and radial lines) are included as

transmission. The second reason is the

increase in transmission O&M expenses.

O&M not directly charged to a facility is

charged to transmission based on a ratio

of transmission plant to total plant.

The transmission costs from the COTP

cost-of-service study have not changed

21208 Federal Register / Vol. 66, No. 82 / Friday, April 27, 2001 / Notices

significantly. However, the termination

of a contractual obligation to provide

standby transmission service increased

the amount of capacity available for

sale. The amount of COTP capacity used

in component 1 of the formula rate will

change with the seasonal transfer

capability of the COI.

Existing and Provisional Rates

CVP Firm Power

The provisional rates for CVP firm

power are designed to recover an annual

revenue requirement that includes the

investment repayment, interest,

purchase power costs, O&M expenses,

and any charges or credits associated

with the creation, termination, or

modification to any tariff, contract, or

schedule approved or accepted by FERC

under which Western takes service.

Western also developed provisional

rates for CVP firm power with the

transmission revenue requirement

removed. These rates would apply if

Western joins the CAISO or an RTO and

if the CAISO or RTO uses the

transmission revenue requirement to

develop a regional transmission rate.

Western has not made a decision on

joining the CAISO or RTO. The decision

to join the CAISO or an RTO is not part

of this rate adjustment process. These

rates are also designed to recover an

annual revenue requirement that

includes investment repayment,

interest, purchase power, O&M expense,

and any charges or credits associated

with the creation, termination, or

modification to any tariff, contract, or

schedule accepted or approved by

FERC.

A comparison of the existing rates and

both sets of provisional rates for CVP

firm power are in the next two tables.

COMPARISON OF EXISTING AND PROVISIONAL RATES, CVP FIRN POWER WITH THE TRANSMISSION REVENUE

REQUIREMENT INCLUDED

Rate Period

Existing Rates

(Effective 04/01/

01 to 09/30/01)

Provisional Rates Percent Change

Composite Rate (mills/kWh):

04/01/01 to 09/30/01 ................................................................................................ 18.56 20.08 8

10/01/01 to 09/30/02 ................................................................................................ ............................ 23.83 28

10/01/02 to 09/30/03 ................................................................................................ ............................ 24.63 33

10/01/03 to 09/30/04 ................................................................................................ ............................ 24.73 33

10/01/04 to 12/31/04 ................................................................................................ ............................ 30.83 66

Capacity Rate ($/kWmonth):

04/01/01 to 09/30/01 ................................................................................................ 3.81 3.44 (10)

10/01/01 to 09/30/02 ................................................................................................ ............................ 3.73 (2)

10/01/02 to 09/30/03 ................................................................................................ ............................ 3.89 2

10/01/03 to 09/30/04 ................................................................................................ ............................ 3.86 1

10/01/04 to 12/31/04 ................................................................................................ ............................ 3.80 ............................

Energy Rate (mills/kWh):

04/01/01 to 09/30/01 ................................................................................................ 10.51 14.01 33

10/01/01 to 09/30/02 ................................................................................................ ............................ 17.68 68

10/01/02 to 09/30/03 ................................................................................................ ............................ 18.22 73

10/01/03 to 09/30/04 ................................................................................................ ............................ 18.38 75

10/01/04 to 12/31/04 ................................................................................................ ............................ 24.97 138

Note: In addition to the provisional firm power rates above, any charges or credits associated with the creation, termination, or modification to

any tariff, contract, or schedule accepted by FERC will be passed through to the appropriate customer(s).

COMPARISON OF EXISTING AND PROVISIONAL RATES, CVP FIRM POWER WITH THE TRANSMISSION REVENUE

REQUIREMENT REMOVED

Rate Period

Existing Rates

(Effective 04/01/

01 to 09/30/01)

Provisional Rates Percent Change

Composite Rate (mills/kWh):

04/01/01 to 09/30/01 ................................................................................................ 18.56 18.51 ............................

10/01/01 to 09/30/02 ................................................................................................ ............................ 22.48 21

10/01/02 to 09/30/03 ................................................................................................ ............................ 23.26 25

10/01/03 to 09/30/04 ................................................................................................ ............................ 23.41 26

10/01/04 to 12/31/04 ................................................................................................ ............................ 29.47 59

Capacity Rate ($/kWmonth):

04/01/01 to 09/30/01 ................................................................................................ 3.81 2.55 (33)

10/01/01 to 09/30/02 ................................................................................................ ............................ 2.91 (24)

10/01/02 to 09/30/03 ................................................................................................ ............................ 3.08 (19)

10/01/03 to 09/30/04 ................................................................................................ ............................ 3.05 (20)

10/01/04 to 12/31/04 ................................................................................................ ............................ 2.92 (23)

Energy Rate (mills/kWh):

04/01/01 to 09/30/01 ................................................................................................ 10.51 14.01 33

10/01/01 to 09/30/02 ................................................................................................ ............................ 17.68 68

10/01/02 to 09/30/03 ................................................................................................ ............................ 18.18 73

10/01/03 to 09/30/04 ................................................................................................ ............................ 18.38 75

10/01/04 to 12/31/04 ................................................................................................ ............................ 24.97 138

Note: Customers are required to buy transmission at an additional cost under these rates. In addition to the provisional firm power rates above,

any charges or credits associated with the creation, termination, or modification to any tariff, contract, or schedule accepted by FERC will be

passed through to the appropriate customer(s).

Federal Register / Vol. 66, No. 82 / Friday, April 27, 2001 / Notices 21209

CVP Transmission Services and

Transmission of CVP Power by Others

The provisional formula rate for CVP

firm transmission includes two

components.

Component 1 = transmission revenue requirement

CVP capacity + total transmission capacity under long-term contracts

Component 1 =transmission revenue

requirement CVP capacity + total

transmission capacity under long-term

contracts

Component 1 is the ratio of Western’s

transmission revenue requirement (less

revenue credits) to the sum of the

maximum operating capacity under

normal operating conditions of the

northern CVP powerplants (CVP

capacity) and the total transmission

capacity under long-term contract

between Western and other parties. The

Northern CVP powerplants are Judge

Francis Carr, Folsom, Keswick, Nimbus,

Shasta, Spring Creek, and Trinity.

Western will revise the rate from

component 1 of the provisional formula

rate based on updated data as of April

30 of each year. Western will also revise

the rate from component 1 if there is a

change in the numerator or denominator

that results in a rate change of at least

$.05/kWmonth.

Component 2 is for any transmissionrelated costs incurred by Western due to

electric industry restructuring or other

industry changes. The costs in

component 2, as well as any changes to

these costs, will be passed on to each

appropriate transmission customer.

The provisional formula rates for CVP

transmission services are based on a

revenue requirement that recovers: (1)

The costs of facilities that support the

transfer capability of the CVP

transmission system (excluding

generation facilities and radial lines); (2)

the nonfacilities costs allocated to

transmission; and (3) any transmissionrelated costs incurred by Western due to

electric industry restructuring or other

changes in the industry. The provisional

formula rate includes Western’s cost for

scheduling, system control and dispatch

service and reactive supply and voltage

control service needed to support the

transmission service. The provisional

formula rates apply to existing CVP firm

and nonfirm transmission services and

future point-to-point transmission

services. If the rates from the

provisional formula rates are higher

than other transmission rates in

California, then firm or nonfirm

transmission service for 1 year or less

may be sold at lower rates. The

provisional rate for transmission of CVP

power by others is a pass through cost,

which is the same as the existing rate.

This table compares the existing and the

estimated rates from the provisional

formula rates for CVP transmission

services and for transmission of CVP

power by others.

COMPARISON OF EXISTING AND PROVISIONAL FORMULA RATES CVP FIRM AND NONFIRM TRANSMISSION RATE

SCHEDULES

Rate period

Existing rates

(effective 04/01/

01 to 09/30/01)

Estimated rates

from the provisional formula

rates

Percent rates

change

Firm ($/kWmonth):

04/01/01 to 09/30/01 .................................................................................................. 0.51 0.70 37

10/01/01 to 04/30/02 .................................................................................................. ............................ 0.56 10

Nonfirm (mills/kWh):

04/01/01 to 04/30/02 .................................................................................................. 1.00 1.00 ..........................

COMPARISON OF EXISTING AND PROVISIONAL FORMULA RATES TRANSMISSION OF CVP POWER BY OTHERS RATE

SCHEDULE

Rate period Existing rate (effective 04/01/01

to 09/30/01) Provisional rate Percent change

04/01/01 to 12/31/04 ................................................. Pass through Cost ....................... Pass through Cost ....................... Not Applicable.

Network Integration Transmission

Service

If Western offers network integration

transmission service, it will be made

available consistent with FERC Order

No. 888. The provisional formula rate

for network integration transmission

service includes two components.

Component 1 is the product of the

network customer’s load ratio share,

times 1⁄12 of the annual network

transmission revenue requirement. The

load ratio share is the network

customer’s hourly load coincident with

Western’s monthly CVP transmission

system peak, minus the coincident peak

for all firm CVP point-to-point

transmission service, plus the reserved

capacity of all firm point-to-point

transmission service customers.

Component 2 is any transmissionrelated costs incurred by Western due to

electric industry restructuring or other

industry changes. The costs in

component 2, as well as any changes to

these costs, will be passed through to

each appropriate transmission customer

as part of the network integration

transmission revenue requirement. The

provisional formula rate for network

integration transmission service is based

on a revenue requirement that recovers:

(1) the cost for facilities that support the

21210 Federal Register / Vol. 66, No. 82 / Friday, April 27, 2001 / Notices

transfer capability of the CVP

transmission system (excluding

generation facilities and radial lines); (2)

the nonfacilities costs allocated to

transmission; and (3) any transmissionrelated costs incurred by Western due to

electric industry restructuring or other

industry changes. The provisional

formula rate includes Western’s cost for

scheduling, system control and dispatch

service and reactive supply and voltage

control service needed to support the

transmission service.

Ancillary Services

Western will offer six ancillary

services consistent with FERC Order No.

888. Two of the ancillary services will

be supplied with the sale of CVP and/

or COTP transmission services. These

are scheduling, system control and

dispatch, and reactive supply and

voltage control services. The remaining

four ancillary services are regulation

and frequency response, energy

imbalance, spinning reserve, and

supplemental reserve. Availability and

type of ancillary service will be based

on excess resources at the time the

service is requested, except for the two

ancillary services supplied in

conjunction with the sale of CVP and/

or COTP transmission services. The

appropriate transmission services rates

include costs for scheduling, system

control and dispatch service and

reactive supply and voltage control

service. The major factor for the increase

in the spinning reserve, supplemental

reserve, and regulation and frequency

response services rates is the increase in

Reclamation power O&M expenses. This

table compares the existing and the

provisional rates.

COMPARISON OF EXISTING AND PROVISIONAL ANCILLARY SERVICES RATES CVP ANCILLARY SERVICE RATE SCHEDULES

Ancillary service type Existing rates Provisional rates Percent

change

Scheduling, System Control

and Dispatch Service.

Appropriate transmission rates include Western’s cost.Appropriate transmission rates include Western’s cost.NA

Reactive Supply and Voltage

Control Service.

Appropriate transmission rates include Western’s cost.Appropriate transmission rates include Western’s cost.NA

Regulation and Frequency Response Service.Monthly: $1.48/kWmonth .....................................

Weekly: $.336/kWweek .......................................

Daily: $.048/kWday ..............................................

Monthly: $2.496/kWmonth ...................................

Weekly: $0.574/kWweek .....................................

Daily: $0.082/kWday ............................................

69

71

71

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

deviations are to be corrected or eliminated

within 30 days. Any net deviations that are

are to 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 then in effect for CVP firm

power.

Within Limits of Deviation Band: Accumulated

deviations are to be corrected or eliminated

within 30 days. Any net deviations that are

are to 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 then in effect for CVP firm

power.

NA

Outside Limits of Deviation Band: Positive Deviations—The greater of no charge, or any additional cost incurred. Negative Deviations—

during on-peak hours is the greater of 3 times

the composite rate then in effect for CVP firm

power or any additional cost incurred. During

off-peak hours is the greater of the composite

rate then in effect for CVP firm power or any

additional cost incurred.

Outside Limits of Deviation Band: Positive Deviations—The greater of no charge, or any additional cost incurred. Negative Deviations—

during on-peak hours is the greater of 3 times

the composite rate then in effect for CVP firm

power or any additional cost incurred. During

off-peak hours is the greater of the composite

rate then in effect for CVP firm power or any

additional cost incurred.

Spinning Reserve Service ....... Monthly: $1.35/kWmonth .....................................

Weekly: $.3024/kWweek .....................................

Daily: $.0432/kWdayHourly: $.0018/kWh ............

Monthly: $2.946/kWmonth ...................................

Weekly: $0.672/kWweek .....................................

Daily: $0.096/kWday ............................................

Hourly: $0.0040/kWh ...........................................

118

121

122

122

Supplemental Reserve Service Monthly: $1.27/kWmonth .....................................

Weekly: $.2856/kWweek .....................................

Daily: $.0408/kWday ............................................

Hourly: $.0017/kWh .............................................

Monthly: $2.491/kWmonth ...................................

Weekly: $0.574/kWweek .....................................

Daily: $0.082/kWday ............................................

Hourly: $0.0034/kWh ...........................................

96

100

100

100

Power Scheduling Service

Western supplies power scheduling

service for the scheduling of resources

to meet load and reserve requirements.

The provisional rate of $76.65 per hour

will apply to the estimated time for each

customer’s service. The rate is designed

to recover only the cost incurred for

supplying the service.

Scheduling Coordinator Service

Scheduling coordinator service is a

new service for scheduling, real-time

dispatching, and financial settlements

with the CAISO and/or power

exchanges. The provisional rate of

$76.65 per hour will apply to the

estimated time for each customer’s

service. The rate is designed to recover

only the cost incurred for supplying the

service.

Provisional Formula Rates for COTP

Transmission Services

The provisional formula rate for

COTP transmission includes two

components.

Component 1 = transmission revenue requirement

Western' s share of COTP seasonal capacity

Federal Register / Vol. 66, No. 82 / Friday, April 27, 2001 / Notices 21211

Component 1 is the ratio of the

transmission revenue requirement (less

revenue credits) to Western’s share of

COTP seasonal capacity. Western will

update the rate from component 1 at

least 15 days before the start of each

season. Seasonal definitions for

summer, winter, and spring are June

through October, November through

March, and April through May,

respectively.

Component 2 is any transmissionrelated costs incurred by Western due to

electric industry restructuring or other

industry changes. The costs in

component 2, as well as any changes to

these costs, will be passed on to each

appropriate transmission customer.

The provisional rates for COTP

transmission service are based on a

revenue requirement that recovers: (1)

Western’s share of costs for facilities

that support the transfer capability of

the COTP; (2) Western’s share of the

nonfacilities costs allocated to

transmission; and (3) any transmissionrelated costs incurred by Western due to

electric industry restructuring or other

changes in the industry. The provisional

formula rates include Western’s cost for

scheduling, system control and dispatch

service and reactive supply and voltage

control service needed to support the

transmission service. The provisional

formula rates apply to existing COTP

firm and nonfirm transmission services

and future point-to-point transmission

services. If the estimated rates from the

provisional formula rates are higher

than other transmission rates in

California, firm or nonfirm transmission

service for 1 year or less may be sold at

lower rates. No generation resources or

loads are directly connected to the

COTP, so network integration

transmission service is not offered for

the COTP.

This table compares the existing and

estimated rates from the provisional

formula rates for transmission services

for Western’s share of the COTP.

COMPARISON OF EXISTING AND PROVISIONAL FORMULA RATES, COTP TRANSMISSION RATE SCHEDULES

Rate Period Existing

Rates

Estimated Rates from Provisional Formula

Rates

Percent

change

Firm Transmission Rate ($/kWmonth):

04/01/01 to 03/31/02 ......................................................................... 1.34 Summer—.94 ....................................................

Winter—1.12 .....................................................

Spring—1.00 .....................................................

(30)

(16)

(25)

Nonfirm Transmission Rate (mills/kWh):

04/01/01 to 03/31/02 ......................................................................... 1.45 Summer—1.29 ..................................................

Winter—1.54 .....................................................

Spring—1.37 .....................................................

(11)

6

(6)

Certification of Rates

Western’s Administrator certified that

the provisional rates for CVP firm

power, CVP transmission services,

transmission of CVP power by others,

network integration transmission

service, ancillary services, power

scheduling service, scheduling

coordinator service, and COTP

transmission services are the lowest

possible rates consistent with sound

business principles. The provisional

rates were developed under

administrative policies and applicable

laws.

Discussion

CVP Firm Power

According to Reclamation law,

Western must establish power rates

sufficient to recover operation,

maintenance, and purchase power

expenses, and repay the Federal

Government’s investment. Rates must

also recover interest expenses on the

unpaid balance of facilities’

investments, replacements and

additions, and certain nonpower costs

in excess of the irrigation users’ ability

to repay.

A FERC order issued January 8, 1998,

confirmed and approved the existing

CVP commercial firm power rates for

October 1, 1997, through September 30,

2002. Under Rate Schedule CV–F9 for

FY 2001, the composite rate is 18.56

mills/kWh, the base energy rate is 10.51

mills/kWh, and the capacity rate is

$3.81/kWmonth. The provisional rates

for CVP firm power result in an overall

composite rate increase of about 8

percent on April 1, 2001. On a

composite rate basis, the provisional

rates increase during the rate case

period compared to the existing rates

due primarily to increased purchased

power costs. To use CVP power

resources to their maximum benefit,

Western supports CVP generation with

capacity and energy purchases mainly

from PG&E. The provisional rates

increase after April to September 2001

due to the depletion of EA2 in

September 2001. The increases in FY

2002 and FY 2003 are due to increases

in prices for short-term purchases and

power from PG&E. In FY 2004, these

increases are offset by decreases in O&M

and other expenses. The significant

increase in rates during October through

December 2004 recovers short-term

power purchase costs for PDC support

due to lower CVP generation during

those months. Western will also pass

through to each appropriate customer

any charges or credits associated with

the creation, termination, or

modification to any tariff, contract, or

schedule accepted or approved by

FERC.

The provisional rates for CVP firm

power with the transmission revenue

requirement removed in Rate Schedule

CV–F10 will result in an overall

composite rate of 18.51 mills/kWh on

April 1, 2001. This results in a change

of less than 1 percent when compared

with the existing rates under Rate

Schedule CV–F9.

The cost of the CVP power generation

is split equally between the capacity

and energy revenue requirements. The

amount of capacity and energy available

from the CVP hydroelectric system

varies widely because of hydrologic

conditions. These conditions can also

impact the value of the capacity and

energy. Due to this variability, an equal

split between the capacity and energy

revenue requirements is used to recover

the CVP power generation cost, which

reflects its actual costs associated with

providing power to all CVP customers.

The existing rates under Rate

Schedule CV–F9 reflect a 5-year average

split of 46 percent to capacity and 54

percent to energy. Both sets of

provisional rates are based on allocating

the total annual CVP revenue

requirement split between capacity and

energy in this way:

1. For the rates that include the

transmission revenue requirement, the

capacity revenue requirement includes

100 percent of capacity purchase costs,

100 percent of CVP and COTP

21212 Federal Register / Vol. 66, No. 82 / Friday, April 27, 2001 / Notices

transmission expense, and 50 percent of

the annual CVP investment repayment,

interest expense, and power O&M

expense allocated to power. Projected

CVP and COTP transmission revenue

and 50 percent of projected CVP project

use revenue reduce the annual costs that

make up the capacity revenue

requirement. The capacity revenue

requirement for the rates that have the

transmission revenue requirement

removed is the same, except the CVP

and COTP transmission expense and

revenue are excluded from the

calculation.

2. The energy revenue requirement

includes 100 percent of energy purchase

costs and 50 percent of the annual CVP

investment repayment, interest expense,

and power O&M expense allocated to

power. Projected surplus power revenue

and 50 percent of projected CVP project

use revenue reduce annual costs that

make up the energy revenue

requirement.

3. Western will pass through to each

appropriate customer any charges or

credits associated with the creation,

termination, or modification to any

tariff, contract, or schedule accepted or

approved by FERC under which

Western takes service.

The resulting percentage splits for the

provisional rates with the transmission

revenue requirement included vary from

19 percent allocated to capacity during

October 1, 2004, through December 31,

2004, to 30 percent allocated to capacity

in FY 2001, primarily due to changes in

purchase power costs each year. The

average split for the rate period is 25

percent to capacity and 75 percent to

energy. This table is the annual

percentage splits between the capacity

and energy revenue requirements.

ENERGY/CAPACITY SPLITS WITH THE TRANSMISSION REVENUE REQUIREMENT INCLUDED

Effective period Capacity

(percent)

Energy

(percent)

04/01/01–9/30/01 ............................................................................................................................................................. 30 70

10/01/01–9/30/02 ............................................................................................................................................................. 26 74

10/01/02–9/30/03 ............................................................................................................................................................. 26 74

10/01/03–9/30/04 ............................................................................................................................................................. 26 74

10/01/04–12/31/04 ........................................................................................................................................................... 19 81

Average for the 5 periods ................................................................................................................................................ 25 75

The resulting percentage splits for the

provisional rates with the transmission

revenue requirement removed vary from

15 percent allocated to capacity during

October 1, 2004, through December 31,

2004, to 24 percent allocated to capacity

in FY 2001, primarily due to changes in

purchase power costs each year. The

average split for the rate period is 21

percent to capacity and 79 percent to

energy. This table is the annual

percentage splits between the capacity

and energy revenue requirements.

ENERGY/CAPACITY SPLITS WITH THE TRANSMISSION REVENUE REQUIREMENT REMOVED

Effective period Capacity

(percent)

Energy

(percent)

04/01/01–9/30/01 ............................................................................................................................................................. 24 76

10/01/01–9/30/02 ............................................................................................................................................................. 21 79

10/01/02–9/30/03 ............................................................................................................................................................. 22 78

10/01/03–9/30/04 ............................................................................................................................................................. 21 79

10/1/04–12/31/04 ............................................................................................................................................................. 15 85

Average for the 5 periods ................................................................................................................................................ 21 79

Power Factor Adjustment

The power factor adjustment under

existing Rate Schedule CV–F9 will

continue and is included in the

provisional rates for CVP firm power.

The low power factor charge (LPF

charge) will continue to encourage

preference customers to monitor and

maintain power factors at 95 percent or

greater. Western will continue the

existing LPF charge under Rate

Schedule CV–F10, which includes a rate

of $2.50/kvar for additional kvar

required to raise the customer’s power

factor to 95 percent. The $2.50/kvar rate

is the estimated cost of Western

purchasing and installing equipment to

increase a customer’s power factor plus

an additional charge to encourage

customers to monitor poor power

factors. The LPF charge will be applied

when the customer does not maintain a

calculated 95 percent or greater power

factor.

The customer’s computed power

factor used to decide if a charge will be

assessed is the arithmetic mean of the

customer’s measured monthly average

power factor and the measured monthly

on-peak power factor, rounded to the

nearest whole percent with 0.5 percent

or greater rounded to the next higher

percent. As recorded at the customer’s

point of delivery, the measured on-peak

power factor is equal to the power factor

measured during a customer’s

maximum peak demand for each month.

If multiple occurrences of the same peak

demand occur, the lowest associated

power factor will be used. The

measured average power factor will be

the average power factor for the billing

month. Those customers with multiple

meter points will be charged for the

‘‘totalizer’’ of the multiple meter points.

The monthly on-peak and average

power factors are those recorded for

CVP power only.

Low Voltage Loss Adjustment

The low voltage adjustment under

existing Rate Schedule CV–F9 will

continue and is included in the

provisional rates for CVP firm power. A

loss adjustment factor of 1.035 will be

applied to the billed amounts for low

voltage CVP power deliveries on PG&E’s

system under Contract 2948A.

Federal Register / Vol. 66, No. 82 / Friday, April 27, 2001 / Notices 21213

Revenue Adjustment Clause

The RAC provides for a comparison

between the projected net revenues in

the rate adjustment PRS to the actual net

revenues. If the actual net revenue is

more than the projected net revenue,

CVP preference customers receive a

credit. If actual net revenue is less than

the projected net revenue, CVP

preference customers may pay a

surcharge, if needed, to make a

minimum investment payment. The

limit for the annual RAC credit or

surcharge is $20 million, plus any

purchase or exchange power contract

adjustments during the FY for which the

RAC is being calculated. The RAC is

calculated annually and the associated

distribution of the RAC credit or

surcharge occurs during a 9-month

period on power bills issued January

through September. For customers

whose RAC credits cannot be fully

credited through nine equal monthly

amounts, Western has the option to

increase the RAC credit during August

and September. The FY 2001 RAC

calculation will be based on the net

revenue for FY 2001, including

revenues and expenses for October 2000

to March 2001, which is outside of the

rate adjustment period. A RAC will be

calculated for October through

December 2004. The maximum RAC

credit or surcharge for October through

December 2004 is $10 million plus any

purchase or exchange power contract

adjustments applied to the April to

September 2005 bills.

CVP Transmission Services and

Transmission of CVP Power by Others

Provisional formula rates developed

for CVP firm and nonfirm transmission

services are consistent with FERC Order

No. 888. The estimated rate from the

provisional formula rate for firm CVP

transmission service on April 1, 2001, is

$0.70/kWmonth, a 37-percent increase

from the existing rate of $0.51/kWmonth

under Rate Schedule CV–FT3. Based on

an Open Access Transmission Tariff

service agreement to supply CVP

transmission service in the future, on

October 1, 2001, the estimated rate from

the provisional formula rate in Rate

Schedule CV–FT4 will be $.56/

kWmonth. The estimated rate resulting

from the formula rate for CVP nonfirm

transmission service will be 1.00 mills/

kWh, which is the same as the existing

rate under Rate Schedule CV–NFT3.

There are two primary reasons for the

increase in CVP firm transmission rates.

The first reason is including in the

transmission revenue requirement the

costs associated with facilities that

support the transfer capability of the

CVP transmission system (excluding

generation facilities and radial lines).

The second reason is the increase in

transmission O&M expenses. O&M not

directly charged to a facility is charged

to transmission based on a ratio of

transmission plant to total plant.

Western will pass on to the CVP

customer transmission service costs

Western incurs in the delivery of CVP

power over a third party’s transmission

system. Annual transmission pass

through revenues and expenses are

included in the PRS to account for all

charges, even though the net effect is

zero. Transmission pass through

revenues and expenses are estimated

using existing customer load forecasts

and project use requirements and

applicable transmission service rates.

Transmission pass through revenues

and expenses primarily consist of

payments to PG&E for transmission

services to preference and project use

loads and payments to the Sacramento

Municipal Utility District for

transmission service to preference

customers.

Network Integration Transmission

Service

If Western offers network integration

transmission service, it will be

consistent with FERC Order No. 888.

Due to existing contractual

arrangements, Western may not be able

to supply network integration

transmission service; however, a

formula rate is included in case Western

offers the service.

Ancillary Services

Western allocates most of its power

resources to preference entities under

long-term commitments; therefore,

availability and type of ancillary service

will be based on excess resources at the

time the service is requested, except for

the two ancillary services supplied with

the sale of CVP and/or COTP

transmission services. The appropriate

transmission services rates include costs

for scheduling, system control and

dispatch and reactive supply and

voltage control services.

The provisional rates for ancillary

services are designed to recover the

costs for these services. The primary

reason for the 69-percent increase in the

monthly regulation and frequency

response service rate, 118-percent

increase in the monthly spinning

reserve rate, and 96-percent increase in

the monthly supplemental reserve

service rate is the increase in the

Reclamation O&M expenses. Standards

and practices used in the electric utility

industry are the basis for the provisional

rate for energy imbalance service.

Western used a detailed cost-of-service

study for developing the provisional

rates for regulation and frequency

response, spinning reserve, and

supplemental reserve services. These

rates are based on the costs of CVP

facilities used in supplying the service.

The CVP facilities used to supply

regulation and frequency response,

spinning reserve, and supplemental

reserve services are the Shasta, Folsom,

Trinity, New Melones, Spring Creek,

and Judge F. Carr Powerplants. The

Nimbus and Keswick Powerplants are

not available because of river run

conditions. There are no governors at

the O’Neill Powerplant and the W. R.

Gianelli pump-generator, which makes

them unavailable for supplying the

services.

Power Scheduling Service

Western supplies power scheduling

service for scheduling resources to meet

load and reserve requirements. The

provisional rate for power scheduling

service is designed to recover only the

cost incurred by Western for supplying

the service. This results in a 1-percent

increase compared to the existing rate in

Rate Schedule CV–PSS1 of $75.80 per

hour on April 1, 2001. The provisional

rate includes two cost components. The

first is the FY 2000 hourly cost for

dispatcher and/or scheduler resources,

escalated for the rate adjustment period

to calculate an average hourly cost. The

second is an hourly cost for equipment

necessary to supply the service.

Scheduling Coordinator Service

Scheduling coordinator service is a

new service offered by Western that

allows for scheduling, real-time

dispatching, and financial settlements

with the CAISO and/or power

exchanges. The rate is designed to

recover only the cost incurred for

supplying the service. The provisional

rate includes two cost components. The

first is the FY 2000 hourly cost for

scheduling, dispatching, settlements,

supervisory control and data

acquisition, and other resources,

escalated for the rate adjustment period

to calculate an average hourly cost. The

second is an hourly cost for equipment

necessary to supply the service.

COTP Transmission Services

Provisional formula rates developed

for COTP firm and nonfirm transmission

services are consistent with FERC Order

No. 888. The estimated rates from the

provisional formula rate for firm

transmission service for Western’s share

of the COTP will result in a 30-percent

decrease in the summer, a 16-percent

decrease in the winter, and a 25-percent

21214 Federal Register / Vol. 66, No. 82 / Friday, April 27, 2001 / Notices

decrease in the spring compared to the

existing rate of $1.34/kWmonth on April

1, 2001. The estimated rates from the

provisional formula rate for COTP firm

transmission service for April 1, 2001,

through March 31, 2002, are: summer—

$.94/kWmonth, winter—$1.12/

kWmonth, and spring—$1.00/

kWmonth. The estimated rates from the

provisional formula rate for nonfirm

COTP transmission service will result in

an 11-percent decrease in the summer,

a 6-percent increase in the winter, and

a 6-percent decrease in the spring

compared to the existing rate of 1.45

mills/kWh on April 1, 2001. The

estimated rates from the provisional

formula rates for COTP nonfirm

transmission service for April 1, 2001,

through March 31, 2002, are: summer—

1.29 mills/kWh, winter—1.54 mills/

kWh, and spring—1.37 mills/kWh. In

the previous rate case, Western

developed COTP rates based on the

entire transfer capability of the COI,

which is 4,800 MW. However, due to

the variability of the COI transfer

capability, which impacts Western’s

share of the COTP capacity available for

sale, Western developed formula rates

for COTP transmission services. The

primary factor for the decrease in the

firm and nonfirm COTP rates is the

termination of a contractual obligation

to provide standby transmission service

which increases the capacity available

for sale.

Statement of Revenue and Related

Expenses

The following table gives a summary

of revenues and expenses for the

existing 5-year rate period and the

provisional rate period.

CVP COST EVALUATION RATE PERIOD

[Revenues and Expenses, in thousands of dollars]

Existing rates FY

1998–FY 2002

Provisional rates

April 1, 2001—December 2004Difference

Total revenues ........................................................................................................ 824,651 928,925 104,274

Revenue distribution:

O&M ............................................................................................................................ 216,776 187,600 (29,176)

Purchase power .......................................................................................................... 390,689 609,623 218,934

Transmission .............................................................................................................. 80,335 57,229 (23,106)

Interest ........................................................................................................................ 54,536 21,486 (33,050)

Other ........................................................................................................................... 9,073 13,568 4,495

Investment repayment ................................................................................................ 73,242 39,419 (33,823)

Note: The revenues and expenses for the existing rates are for 5 years. Those for the provisional rates are for 3 years and 9 months.

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

rate periods.

CVP COMPARISON OF COST EVALUATION RATE PERIOD

[Average Annual Revenues and Expenses, in thousands of dollars]

Existing rates average annualProvisional rates

average annual Difference

Total Revenues ....................................................................................................... 164,930 247,713 82,783

Revenue distribution:

O&M ............................................................................................................................ 43,355 50,027 6,672

Purchase power .......................................................................................................... 78,138 162,566 84,428

Transmission .............................................................................................................. 16,067 15,261 (806)

Interest ........................................................................................................................ 10,907 5,730 (5,177)

Other ........................................................................................................................... 1,815 3,618 1,803

Investment repayment ................................................................................................ 14,648 10,512 (4,136)

Basis for Rate Development

The existing rates for CVP commercial

firm power, CVP transmission services,

transmission of CVP power by others,

network transmission service, ancillary

services, and power scheduling service

in Rate Schedules CV–F9, CV–FT3, CV–

NFT3, CV–TPT4, CV–NWT1, CV–RFS1,

CV–EID1, CV–SPR1, CV–SUR1, and

CV–PSS1, expire September 30, 2002.

Scheduling coordinator service is a new

service offered by Western. The rate

adjustment contains rates that replace

the existing rates and adds a rate for the

new service. The adjusted rates reflect

increases in customers’ CVP power

purchases, purchase power costs, and

Reclamation O&M costs. The adjusted

rates also reflect the pass through of

FERC-accepted or -approved costs or

credits, and changes in transmission

rate methodology. The provisional rates

will provide sufficient revenue to pay

all annual costs, including interest

expense and FERC-accepted or

-approved costs or credits, and

repayment of required investment in the

allowable period. The provisional rates

are scheduled to go in effect on April 1,

2001, and remain in effect through

December 31, 2004.

The provisions for power factor

adjustment, low voltage loss adjustment,

and revenue adjustment are part of the

provisional rates for CVP firm power.

The provisions and methodologies for

power factor adjustment and low

voltage loss adjustment are not being

modified and will remain as specified in

Rate Schedule CV–F9. The methodology

for revenue adjustment has been

modified to reflect the expanded limit

for the RAC credit or surcharge of $20

million, $10 million for October to

December 2004, plus any purchase

power or exchange contract adjustments

during the FY for which the RAC is

being calculated.

Federal Register / Vol. 66, No. 82 / Friday, April 27, 2001 / Notices 21215

Update to the Proposed Rates

During the public process, changes

were made to the proposed rates for

CVP firm power. On November 17,

2000, during the public information

forum, Western told all interested

parties of its intent to update the

proposed CVP firm power rates.

Western presented these updates to the

proposed rates at the December 13,

2000, public comment forum. The

updates are detailed below.

Firm Power

1. Western added purchase power

costs required to support PDC. Western

expects PDC support purchases to occur

in the rate case period due to recent

purchases made for that purpose.

2. Western has suspended its

Northwest purchase power contracts. As

a result, Western will be buying more

capacity from PG&E at the DLL and will

also be buying more energy from PG&E.

The contract suspensions also cause

EA2 to be depleted in September 2001.

3. Western will also pass any charges

or credits associated with the creation,

termination, or modification to any

tariff, contract, or schedule accepted or

approved by FERC.

4. Western updated PG&E rates for

capacity and energy based on current

agreements. Western also increased the

capacity purchased under the DLL.

5. Western also made adjustments to

data in the firm power rate design

model to reconcile that data to the data

in the PRS and CVP transmission rate

cost-of-service study.

6. In the RAC limit, Western included

exchange energy contract language.

After the public process was complete

it was necessary to change the CVP

power repayment study as was

contemplated during the December 13,

2000, public comment forum. This

change is due to purchase power costs

for PDC support for October 2000

through March 2001. As a result of this

change, there is less net revenue and

slightly higher interest expense for the

rate adjustment period, but all costs are

recovered and repayment criteria met

within the allowable timer limits. No

changes were made to composite power

rates. The energy and capacity rates

changed slightly due to the change in

net revenue and interest expense.

Comments

During the public consultation and

comment period, Western received 5

written comments from 4 customers on

the rate adjustment. In addition, two

customer representatives commented

during the December 13, 2000, public

comment forum. All comments received

by the end of the public consultation

and comment period, December 29,

2000, were reviewed and considered in

this rate order.

Written comments were received from

the following sources: City of Redding

(California), Trinity County Public

Utility District (California), City of

Roseville (California), Sacramento

Municipal Utility District (California)

Comments received addressed the

CVP energy rates, forecasted market

rates, RAC limits, simplification of CVP

firm power rate structure, pass through

of FERC-approved charges or credits,

power rates with the transmission

revenue requirement removed, CAISO

pass through costs, and CVP

transmission rates. The following

summarizes comments received and

Western’s responses to those comments.

Specific comments are used for

clarification where necessary.

CVP Power Rates

Comment: Allowing adjustment

without limitation to CVP energy rates

leaves the customer with no ability to

predict its Western costs. The rates

should be developed using contractual

conditions as they exist today. Under

that premise, Western’s major wholesale

power costs are predictable enough that

unlimited changes to the energy rate are

unnecessary. If at some point in the

future a significant change occurs to

Western’s cost structure, Western

should implement another rate case.

Response: The comment addresses a

rate proposal that was discussed during

the informal process and was not part of

the proposed or updated proposed rates

for CVP firm power.

Comment: The forecasted market rates

for Western’s long-term Northwest

contracts are too high.

Response: The suspension of the

Northwest contracts for the rate

adjustment period was included in the

updates to the proposed rates. This

comment is not relevant to the updated

proposed rates.

Comment: The annual RAC limit of

$20 million ($10 million for October

through December 2004) plus any

adjustment to Western’s purchased

power contract expenses is not

appropriate. This RAC limit provides no

assurance of maximum cost to

customers and no guidance to Western

on a reasonable range of operating cost

variance. Western should develop a

hedging strategy for PDC support

purchases to keep Western within a

RAC limit of $20 million.

Response: Western is willing to work

with the customers on developing a

hedging strategy for PDC support

purchases. As part of the updates to the

proposed rates, Western added language

to the RAC limit to allow for exchanges

of power in addition to purchases of

power, which should aid in limiting

Western’s exposure to market prices for

PDC support. Due to the many factors

outside of Western’s control that can

contribute to the need for PDC support

purchases, Western feels it is prudent to

retain the updated proposed RAC limit.

These factors include changes in project

water deliveries due to environmental

requirements, project use pumping, and

unscheduled maintenance outages.

Maintaining the updated proposed RAC

limit ensures timely repayment of

project expenses and capital investment.

Comment: A rate schedule without

tiered capacity or energy rates or the

Annual Energy Rate Alignment (AERA)

is appreciated. There is no legitimate

purpose for Western to apply an AERA

once EA2 is depleted.

Response: Western simplified the rate

structure because the benefit of using

the tiered rates and AERA is negligible,

given the condition of the electric power

industry.

Pass Through of FERC-Approved

Charges and Credits

Comment: The pass through of FERCapproved charges or credits is

unacceptable. The pass through results

in an unlimited right to change CVP

power rates and makes it impossible to

predict Western power costs. If there is

a material change in the expected

overall purchase power costs to

Western, Western should initiate

another rate case. If the cumulative

effect of all FERC pass through costs

increases Western’s composite rates by

more than 10 percent, Western should

complete a new rate case within 6

months.

Response: Western feels it is

necessary to include the pass through of

FERC-approved charges or credits in the

updated proposed rates because of

Western’s exposure to changes in FERCapproved charges or credits under its

existing contracts that support

Western’s power marketing program. In

the recent past, there has been an

increase in Western costs that were

approved by FERC subject to refund.

Western needs to recover FERCapproved charges or refund credits from

its customers in a timely manner to

ensure appropriate repayment of project

expenses and capital investment.

Additionally, adopting this comment

could impact our ability to finance our

purchase power program. Western

understands customers’ concerns about

the inability to predict Western’s costs

and will make every effort to notify the

21216 Federal Register / Vol. 66, No. 82 / Friday, April 27, 2001 / Notices

customers of pending changes to

Western’s costs due to FERC actions.

FERC-approved charges or credits can

go into effect within 60 days. Western

cannot complete a rate case in that time.

When FERC makes a final determination

on costs paid by Western under its

existing contracts, Western will evaluate

the need for another rate case.

CAISO/Electric Utility Restructuring

Comment: It is premature for Western

to set rate policy that speculates on

Western’s joining the CAISO or an RTO,

or the pass through of costs that may

exist after Western joins an CAISO or an

RTO.

Response: Western’s decision to join

the CAISO or an RTO is not part of this

rate process. However, Western believes

it is prudent to develop rates that would

accommodate Western’s joining the

CAISO or an RTO, particularly in light

of FERC Order No. 2000. The pass

through of CAISO- or RTO-related costs

can occur independent of Western’s

decision to join or not to join the CAISO

or an RTO. For example, in June 2000

FERC approved, subject to refund,

payment of Reliability Service costs that

are CAISO-related costs, by Western

customers.

CVP Transmission Service Rates

Comment: The rate increase up to

$.70/kW-month and then down to $.56/

kW-month is not appropriate and

creates rate shock for the transmission

customers. There has been no real

change in the transmission service or

addition to transmission facilities to

justify the rate increase. The rate

increase results from the reclassification

of a significant portion of existing CVP

facilities from the generation category to

the transmission category. Western

should limit the increase to 10 percent,

which is supported by FERC precedent.

Western should levelize the rate impact.

Response: Western reviewed the

function of CVP facilities as part of the

development of the transmission rate.

Facilities that support the transfer

capability of the transmission system

were included in the transmission

revenue requirement. Facilities that did

not, such as generation tie lines and

radial lines, were not included in the

transmission revenue requirement. As a

result of this review, there were only a

few substations for which transmission

costs were adjusted. The annual cost

component for capital investment

changed by less than $500,000 from the

current transmission rates to the

proposed transmission rates. The main

reason for the increase in the CVP

transmission rates is the increase in

transmission O&M expenses. The

transmission O&M expenses consist of

O&M expenses directly charged to

transmission facilities and non-direct

charged O&M expenses. The non-direct

charged O&M is allocated based on a

ratio of transmission plant to total plant.

This treatment of O&M expenses is

consistent with utility industry

standards and accepted by FERC.

Increasing the rate by 10 percent or

levelizing the rate is not consistent with

a formula rate and would not meet the

comparability standard set by FERC. A

levelized rate would result in Western

charging transmission customers less

than what it charges itself for

transmission service. Western believes

the CVP transmission rate design meets

the spirit and intent of FERC Order No.

888.

Environmental Compliance

In compliance with the NEPA of 1969,

42 U.S.C. 4321, et seq.; Council on

Environmental Quality Regulations, 40

CFR parts 1500–1508; and DOE NEPA

Regulations, 10 CFR part 1021, Western

determined this action is categorically

excluded from the preparation of an

environmental assessment or an

environmental impact statement.

Determination Under Executive Order

12866

Western has an exemption from

centralized regulatory review under

Executive Order 12866. This notice is

not required to be cleared by the Office

of Management and Budget.

Regulatory Flexibility Analysis

The Regulatory Flexibility Act of 1980

(5 U.S.C. 601, et seq.) requires Federal

agencies to perform a regulatory

flexibility analysis if a final rule is likely

to have a significant economic impact

on a substantial number of small entities

and there is a legal requirement to issue

a general notice of proposed

rulemaking. Western has determined

this action does not require a regulatory

flexibility analysis since it is a

rulemaking of particular applicability

involving rates or services applicable to

public property.

Small Business Regulatory Enforcement

Fairness Act

Western determined this rule is

exempt from congressional notification

requirements under 5 U.S.C. 801

because the action is a rulemaking of

particular applicability relating to rates

or services and involves matters of

procedure.

Availability of Information

Information about this rate

adjustment, including PRS, comments,

letters, memorandums, and other

supporting material made or kept by

Western used to develop the provisional

rates, is available for public review. This

information is in the Power Marketing

Manager’s office, Sierra Nevada

Customer Service Region, Western Area

Power Administration, 114 Parkshore

Drive, Folsom, California.

Submission to the Federal Energy

Regulatory Commission

The provisional rates herein

confirmed, approved, and placed into

effect, together with supporting

documents, will be submitted to FERC

for confirmation and final approval.

Order

In view of the foregoing and under the

authority delegated to me by the

Secretary of Energy, I confirm and

approve on an interim basis, effective

April 1, 2001, Rate Schedules CV–F10,

CV–FT4, CV–NFT4, CV–TPT5, CV–

NWT2, CV–RFS2, CV–EID2, CV–SPR2,

CV–SUR2, CV–PSS2, CV–SCS1, COTP–

FT2, and COTP–NFT2 for the Central

Valley Project and for the CaliforniaOregon Transmission Project, for the

Western Area Power Administration. On

April 10, 2001, by Amendment No. 4 to

Delegation Order No. 0204–108, the

Secretary of Energy delegated to

Western’s Administrator the authority to

confirm, approve, and place into effect

on an interim basis the rates in the

Central Valley Project and CaliforniaOregon Transmission Project-Rate Order

No. WAPA–95. The rate schedules will

remain in effect on an interim basis,

pending FERC confirmation and

approval of them or substitute rates on

a final basis through December 31, 2004.

Dated: April 13, 2001.

Michael S. Hacskaylo,

Administrator.

Rate Schedule CV–F10

(Supersedes Schedule CV–F9)

Central Valley Project

Schedule of Rates for Firm Power

Effective

The first day of the first full billing

period beginning on or after April 1,

2001, through December 31, 2004.

Available

Within the marketing area served by

the Sierra Nevada Customer Service

Region.

Applicable

To the firm power customers for

general power service.

Federal Register / Vol. 66, No. 82 / Friday, April 27, 2001 / Notices 21217

Character and Conditions of Service

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

voltages and points established by

contract.

Monthly Rates With Transmission

Revenue Requirement Included

Period Capacity Energy

04/01/01–09/30/01 .............................................................. $3.44/kWmonth .................................................................. 14.01 mills/kWh.

10/01/01–09/30/02 .............................................................. $3.73/kWmonth .................................................................. 17.68 mills/kWh.

10/01/02–09/30/03 .............................................................. $3.89/kWmonth .................................................................. 18.22 mills/kWh.

10/01/03–09/30/04 .............................................................. $3.86/kWmonth .................................................................. 18.38 mills/kWh.

10/01/04–12/31/04 .............................................................. $3.80/kWmonth .................................................................. 24.97 mills/kWh.

The table below contains rates with

the transmission revenue requirement

removed from the firm power revenue

requirement. These rates would apply if

Western joins the California

Independent System Operator (CAISO)

or Regional Transmission Organization

(RTO) and if the CAISO or RTO uses the

transmission revenue requirement to

develop a regional transmission rate.

Monthly Rates With Transmission

Revenue Requirement Removed

Period Capacity Energy

04/01/01–09/30/01 .............................................................. $2.55/kWmonth .................................................................. 14.01 mills/kWh.

10/01/01–09/30/02 .............................................................. $2.91/kWmonth .................................................................. 17.68 mills/kWh.

10/01/02–09/30/03 .............................................................. $3.08/kWmonth .................................................................. 18.18 mills/kWh.

10/01/03–09/30/04 .............................................................. $3.05/kWmonth .................................................................. 18.38 mills/kWh.

10/01/04–12/31/04 .............................................................. $2.92/kWmonth .................................................................. 24.97 mills/kWh.

Pass Through of FERC–Accepted or

–Approved Charges or Credits

Any charges or credits associated with

the creation, termination, or

modification to any tariff, contract, or

schedule accepted or approved by

FERC, under which Western takes

service, will be passed on to each

appropriate customer. These FERCaccepted or -approved charges or credits

are applicable to both sets of capacity

and energy rates described above.

When possible, Western will pass

through directly to the appropriate

customer the FERC-accepted or

-approved charges or credits in the same

manner Western is charged or credited.

If the FERC-accepted or -approved

charges or credits cannot be passed

through directly to the appropriate

power customer, the charges or credits

will be passed through using the CVP

firm power rate design methodology.

The rate design consists of the following

allocation of costs. The capacity revenue

requirement includes 100 percent of

capacity purchase costs, 100 percent of

CVP and COTP transmission expense,

and 50 percent of the annual investment

repayment, interest expense, and O&M

expense allocated to power. These

annual costs are reduced by the

projected CVP and COTP transmission

revenues and 50 percent of the projected

CVP project use revenue to determine

the capacity revenue requirement. The

capacity revenue requirement for the

rates that have the transmission revenue

requirement removed is the same,

except the CVP and COTP transmission

expense and revenue are excluded from

the calculation. The energy revenue

requirement for both sets of proposed

rates includes 100 percent of energy

purchase costs and 50 percent of the

annual investment repayment, interest

expense, and O&M expense allocated to

power. These annual costs are reduced

by 50 percent of the projected project

use revenues and the projected revenue

from surplus power sales to determine

the energy revenue requirement.

Billing

Demand: The rates listed above for

capacity will be the charge per kilowatt

(kW) of billing demand. The billing

demand is the highest 30-minute

integrated demand measured or

scheduled during the month up to, but

not in excess of, the delivery obligation

under the power sales contract.

Adjustments

Billing for Unauthorized Overruns

For each billing period in which there

is a contract violation involving an

unauthorized overrun of the contractual

obligation for capacity and/or energy,

the overrun will be billed at 10 times

the applicable rates above.

For Revenue Adjustment

The following method will be used for

the revenue adjustment clause (RAC)

calculation:

1. If the actual net revenue is greater

than the projected net revenue for the

RAC calculation period, a revenue

credit will be allocated during the RAC

adjustment period. The credit will equal

the difference between the actual net

revenue and projected net revenue,

represented by the following formula:

If ANR > PNR then C = ANR ¥ PNR

Where:

ANR = Actual Net Revenue

PNR = Projected Net Revenue

C = Credit

2. If actual net revenue is less than the

projected net revenue for the RAC

calculation period, a revenue surcharge

will be allocated during the RAC

adjustment period.

2.1 If the actual net revenue is

negative, the surcharge will be equal to

the minimum investment payment plus

the annual deficit, represented by the

following formula:

If ANR < PNR and < 0 then S = MIP +

AD

Where:

ANR = Actual Net Revenue

PNR = Projected Net Revenue

MIP = Minimum Investment Payment

AD = Annual Deficit

S = Surcharge

2.2 If the actual net revenue is

positive, the surcharge will equal the

minimum investment payment less the

actual net revenue, represented by the

following formula:

If ANR < PNR and > 0 then S = MIP ¥

ANR (if ANR > MIP, S = 0)

Where:

ANR = Actual Net Revenue

PNR = Projected Net Revenue

MIP = Minimum Investment Payment

S = Surcharge

If the actual net revenue is greater

than the minimum investment payment,

there is no surcharge.

21218 Federal Register / Vol. 66, No. 82 / Friday, April 27, 2001 / Notices

3. The maximum RAC credit or

surcharge is $20 million, $10 million for

October through December 2004, plus

the amount of purchase or exchange

power contract adjustments used in

recording associated expense.

4. The RAC credit or surcharge will be

allocated to each CVP firm power

customer based on the proportion of the

customer’s billed obligation to Western

for CVP firm capacity and energy to the

total billed obligation for all CVP firm

power customers for CVP firm capacity

and energy for the RAC calculation

period.

5. For purposes of the RAC

computation, the following terms are

defined:

5.1 Actual Net Revenue—The

recorded net revenue.

5.2 Annual Deficit—The amount of

recorded annual expenses, including

interest, exceeding recorded annual

revenues.

5.3 Minimum Investment Payment—

The lesser of 1 percent of the recorded

unpaid investment balance at the end of

the FY prior to the RAC calculation

period, or the projected net revenue.

5.4 Projected Net Revenue—The

annual net revenue available for

investment repayment projected in the

rate adjustment power repayment study

(PRS) during the FY that RAC is being

calculated (see Table 1).

5.5 RAC Adjustment Period—The

period January 1 through September 30,

following the RAC calculation period

when credits or surcharges will be

applied to the power bills. For

customers whose RAC credits cannot be

fully credited through nine equal

monthly amounts, Western may

increase the RAC credit on the August

and September power bills. For October

1 through December 31, 2004, see item

6 below.

5.6 RAC Calculation Period—The

last recorded FY (October 1 through

September 30). For October 1 through

December 31, 2004, see item 6 below.

5.7 Recorded Net Revenue—The

annual net revenue available for

repayment recorded in the PRS for the

FY the RAC is being calculated.

5.8 RAC will be calculated for FY

2001, even though the October 2000 to

March 2001 portion of the FY is outside

the rate case period. The revenues and

expenses for FY 2001 will be used to

determine the RAC for FY 2001.

6. A RAC will be calculated for

October through December 2004. It will

be allocated to each CVP firm power

customer consistent with the procedure

in item 4 above. The resulting RAC

credit or surcharge will be applied to

power bills issued from April to

September 2005, if the customer has a

power contract with Western during

2005. If the customer does not, Western

will issue a bill or check for the October

to December 2004 RAC surcharge or

credit in April 2005.

TABLE 1.—PROJECTED NET REVENUE AVAILABLE FOR INVESTMENT REPAYMENT FOR REVENUE ADJUSTMENT CLAUSE

Period Projected net

revenue

October 1, 2000–September 30, 2001 ................................................................................................................................................ $4,923,466

October 1, 2001–September 30, 2002 ................................................................................................................................................ 11,887,939

October 1, 2002–September 30, 2003 ................................................................................................................................................ 10,426,583

October 1, 2003–September 30, 2004 ................................................................................................................................................ 12,905,190

October 1, 2004–December 31, 2004 ................................................................................................................................................. 1,737,596

For Transformer Losses

If delivery is made at transmission

voltage but metered on the low voltage

side of the substation, the meter

readings will be increased to

compensate for transformer losses as

stated in the contract.

For Power Factor Adjustment

The customer must maintain a power

factor at all points of measurement

between 95 percent lagging and 95

percent leading. The low power factor

(LPF) charge will be applied when the

customer does not maintain a 95 percent

or greater power factor. The charge for

additional kilovolt ampere reactive

(kvar) required to raise the customer’s

power factor to 95 percent will be

calculated by multiplying the

customer’s monthly maximum peak

demand by the LPF charge for the

customer’s calculated power factor in

Table 2. The kvar rate in the LPF charge

is $2.50 per kvar.

TABLE 2.—LOW POWER FACTOR

CHARGE

Calculated power factor

LPF

Charge

($/kW)

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

0.75 and below ............................. 1.38

The rules and limitations of the LPF

charge are as follows:

1. The calculated power factor used to

determine if a charge will be assessed is

the arithmetic mean of the customer’s

measured monthly average power factor

and their measured monthly on-peak

power factor, rounded to the nearest

whole percent with 0.5 percent or

greater rounded to the next higher

percent.

2. The measured on-peak power factor

equals the power factor measured

during the customer’s maximum peak

demand for each month, as recorded at

the customer’s point of delivery. If there

are multiple occurrences of the same

peak demand, the lowest associated

power factor will be used. The

measured average power factor will be

the average power factor for the billing

month. If the customer has multiple

points of delivery, the power factor will

be determined from the total

information from the points of delivery.

The monthly average and on-peak

power factors are those recorded for

CVP power only.

3. The upper limit for both the

monthly average and measured on-peak

power factors is 95 percent. Customers

will receive no credit for operating

between 100 percent and 95 percent

power factors.

Federal Register / Vol. 66, No. 82 / Friday, April 27, 2001 / Notices 21219

4. The LPF charge will apply to

calculated power factors less than 95

percent, lagging or leading.

5. Customers with a monthly

maximum peak demand less than or

equal to 50 kW will not be subject to the

LPF charge.

6. Western may waive the LPF charge

for good cause in whole or in part.

Rate Schedule CV–FT4

(Supersedes Schedule CV–FT3)

Schedule of Rate for Firm Transmission

Service

Effective

The first day of the first full billing

period beginning on or after April 1,

2001, through December 31, 2004.

Available

Within the marketing area served by

the Sierra Nevada Customer Service

Region.

Applicable

To firm transmission service where

power is received into the CVP system

at points of receipt with other systems

and transmitted and delivered to points

of delivery on the CVP system as agreed

to by the parties.

Character and Conditions of Service

Transmission service for three-phase

alternating current at 60 hertz, delivered

and metered at the voltages and points

of delivery. It includes scheduling,

system control and dispatch service and

reactive supply and voltage control

service needed to support the

transmission service.

Formula Rate

The formula rate for firm CVP

transmission has two components.

Component 1 is the following

formula:

TRR

CVPc TTc +

Where:

TRR = Transmission Revenue

Requirement—the costs associated

with facilities that support the

transfer capability of the CVP

transmission system, excluding

generation facilities and radial lines.

These costs include investment cost,

interest expense, and operation and

maintenance (O&M) expense, less

revenue credits.

CVPc = CVP Capacity—the sum of the

maximum operating capacity of the

Northern CVP powerplants under

normal operating conditions.

Northern CVP powerplants are Judge

Francis Carr, Folsom, Keswick,

Nimbus, Shasta, Spring Creek, and

Trinity.

TTc = Total Transmission Capacity—the

total transmission capacity under

long-term contract between Western

and other parties.

Component 2 is any transmissionrelated costs incurred by Western due to

electric industry restructuring or other

industry changes associated with

providing CVP transmission service.

The costs in component 2, and any

changes to these costs, will be passed

through to each appropriate

transmission customer.

Western will revise the rate from

component 1, as of April 30 of each

year, based on previous year’s annual

financial data available. In addition to

the annual update on April 30 of each

year, Western will also revise the rate

from component 1 if there is a change

in the numerator or denominator that

results in a rate change of at least $.05

per kilowattmonth. Customers will be

notified of the rate change 30 days

before the first bill is issued using the

changed rates.

If the rates from the formula rate are

higher than other transmission rates in

California, transmission service for 1

year or less may be sold at a lower rate.

Billing

The rate from the formula rate listed

above will be applied monthly to the

maximum amount of capacity reserved,

payable whether used or not.

Adjustments

For Losses

Losses incurred from the transmission

and delivery of power under this rate

schedule will be accounted for as agreed

to by the parties.

Rate Schedule CV–NFT4

(Supersedes Schedule CV–NFT3)

Schedule of Rate for Nonfirm

Transmission Service

Effective

The first day of the first full billing

period beginning on or after April 1,

2001, through December 31, 2004.

Available

Within the marketing area served by

the Sierra Nevada Customer Service

Region.

Applicable

To nonfirm transmission service

where power is received into the CVP

system at points of receipt with other

systems and transmitted and delivered,

subject to the availability of

transmission capacity, to points of

delivery on the CVP system as agreed to

by the parties.

Character and Conditions of Service

Transmission service on an

intermittent basis for three-phase

alternating current at 60 hertz, delivered

and metered at the voltages and points

of delivery. It includes scheduling,

system control and dispatch service and

reactive supply and voltage control

service needed to support the

transmission service.

Formula Rate

The formula rate for nonfirm CVP

transmission has two components.

Component 1 is the following formula:

TRR

CVPe TTe +

Where:

TRR = Transmission Revenue

Requirement—the costs associated

with facilities that support the

transfer capability of the CVP

transmission system, excluding

generation facilities and radial lines.

These costs include investment cost,

interest expense, and operation and

maintenance (O&M) expense, less

revenue credits.

CVPe = CVP energy—the energy

associated with the maximum

operating capacity of the Northern

CVP powerplants under normal

operating conditions. Northern CVP

powerplants are Judge Francis Carr,

Folsom, Keswick, Nimbus, Shasta,

Spring Creek, and Trinity.

TTe = Total Transmission energy—the

energy associated with the total

transmission capacity under longterm contract between Western and

other parties.

Component 2 is any transmissionrelated costs incurred by Western due to

electric industry restructuring or other

industry changes associated with

providing CVP transmission service.

The costs in component 2, as well as

any changes to these costs, will be

passed through to each appropriate

transmission customer.

Western will revise the rate from

component 1, as of April 30 of each

year, based on previous year’s annual

financial data available. Western will

also revise the rate from component 1 if

there is a change in component 1 of the

CVP firm transmission rate of at least

$.05 per kilowattmonth. Customers will

be notified of the rate change 30 days

before the first bill is issued using the

changed rates.

If the rates from the formula rate are

higher than other transmission rates in

21220 Federal Register / Vol. 66, No. 82 / Friday, April 27, 2001 / Notices

California, transmission service for 1

year or less may be sold at a lower rate.

Billing

The rate resulting from the formula

rate listed above will be applied to each

kWh delivered at the point of delivery,

as specified in the service contract.

Adjustments

For Losses

Losses incurred in connection with

the transmission and delivery of power

under this rate schedule will be

accounted for as agreed to by the

parties.

Rate Schedule CV–TPT5

(Supersedes Schedule CV–TPT4)

Schedule of Rate for Transmission of

CVP Power by Others

Effective

The first day of the first full billing

period beginning on or after April 1,

2001, through December 31, 2004.

Available

Within the marketing area served by

the Sierra Nevada Customer Service

Region.

Applicable

To power service customers of the

CVP who require transmission service

by a third party to receive power sold

by Western.

Character and Conditions of Service

Transmission service for three-phase

alternating current at 60 hertz, delivered

and metered at the voltages and points

of delivery as agreed to by the parties.

Formula Rate

When Western incurs costs for using

transmission facilities, other than its

own, in supplying service under a

customer’s power sales contract, the

customer will pay all costs, including

transmission losses, incurred in the

delivery of power. For billing purposes,

transmission losses will be added to the

meter readings of the capacity and

energy delivered to the customer under

the customer’s power sales agreement

with Western. For power deliveries

under Contract No. 14–06–200–2948A

(Contract 2948A) on the Pacific Gas and

Electric Company’s system, the

transmission losses charged to the

customer will be those losses that are in

excess of the ‘‘at or above 44-kilovolt’’

transmission losses specified by

Contract 2948A.

Rate Schedule CV–NWT2

(Supersedes Schedule CV–NWT1)

Schedule of Rate for Network

Integration Transmission Service

Effective

The first day of the first full billing

period beginning on or after April 1,

2001, through December 31, 2004.

Available

Within the marketing area served by

the Sierra Nevada Customer Service

Region.

Applicable

To customers who receive network

integration transmission service, subject

to the availability of transmission

capacity, to points of delivery specified

in the service agreement.

Character and Conditions of Service

Transmission service for three-phase,

alternating current at 60 hertz, delivered

and metered at the voltages and points

of delivery. It includes scheduling,

system control and dispatch service and

reactive supply and voltage control

service needed to support the

transmission service.

Formula Rate

The formula rate for network

transmission service consists of two

components.

Component 1 is the product of the

network customer’s load ratio share

times 1⁄12 of the annual network

transmission revenue requirement. The

load ratio share is the network

customer’s hourly load coincident with

Western’s monthly CVP transmission

system peak, minus the coincident peak

for all firm CVP (including reserved

capacity) point-to-point transmission

service, plus the reserved capacity of all

firm point-to-point transmission service

customers. The network transmission

revenue requirement is the cost

associated with facilities that support

the transfer capability of the CVP

transmission system, excluding

generation facilities and radial lines.

Component 2 is for any transmissionrelated costs incurred by Western due to

electric industry restructuring or other

industry changes associated with

providing network integration

transmission service. The costs in

component 2, as well as any changes to

these costs, will be passed through to

each appropriate transmission customer

as part of the network integration

transmission revenue requirement.

Billing

Billing determinants for the formula

rate above will be as specified in the

service agreement.

Adjustments

For Losses

Losses incurred in connection with

the transmission and delivery of power

under this rate schedule will be

accounted for as stated in the service

agreement.

Rate Schedule CV–RFS2

(Supersedes Schedule CV–RFS1)

Schedule of Rates for Regulation and

Frequency Response Service

Effective

The first day of the first full billing

period beginning on or after April 1,

2001, through December 31, 2004.

Available

Within the marketing area served by

the Sierra Nevada Customer Service

Region.

Applicable

To customers receiving regulation and

frequency response service.

Character and Conditions of Service

Regulation and frequency response

service provides generation to match

resources and loads on a real-time

continuous basis.

Rates

Regulation and Frequency Service

Charge:

Monthly: $2.496 per kilowattmonth.

Weekly: $0.574 per kilowattweek.

Daily: $0.082 per kilowattday.

Billing

The rates listed above will be applied

to the maximum service amount in

kilowatts agreed to in the service

agreement, payable whether used or not.

Rate Schedule CV–EID2

(Supersedes Schedule CV–EID1)

Schedule of Rate for Energy Imbalance

Service

Effective

The first day of the first full billing

period beginning on or after April 1,

2001, through December 31, 2004.

Available

Within the marketing area served by

the Sierra Nevada Customer Service

Region.

Applicable

To customers receiving energy

imbalance service.

Federal Register / Vol. 66, No. 82 / Friday, April 27, 2001 / Notices 21221

Character and Conditions of Service

Energy imbalance service supplies

energy when a difference occurs

between the scheduled and actual

delivery of energy to a load or from a

generation resource within a control

area over a single month. The hourly

deviation, in megawatt units, is the net

scheduled amount of energy for the

hour minus the hourly net metered

(actual delivered) amount.

Formula Rate

Within Limits of Deviation Band

Accumulated deviations are to be

corrected or eliminated within 30 days.

Any net deviations accumulated at the

end of the month (positive or negative)

are to be exchanged with like hours of

energy or charged at the composite rate

for CVP firm power then in effect.

Outside Limits of Deviation Band

1. Positive Deviations—the greater of

no charge, or any additional cost

incurred.

2. Negative Deviations—during onpeak hours, the greater of three times

the rate for CVP firm power or any

additional cost incurred. During offpeak hours, the greater of the rate for

CVP firm power or any additional cost

incurred.

Billing

The billing determinants for the above

formula rate will be specified in the

service agreement.

Rate Schedule CV–SPR2

(Supersedes Schedule CV–SPR1)

Schedule of Rates for Spinning Reserve

Service

Effective

The first day of the first full billing

period beginning on or after April 1,

2001, through December 31, 2004.

Available

Within the marketing area served by

the Sierra Nevada Customer Service

Region.

Applicable

To customers receiving spinning

reserve service.

Character and Conditions of Service

Spinning reserve service supplies

capacity that is available the first 10

minutes to take load and is

synchronized with the power system.

Rates

Spinning Reserve Service Charge:

Monthly: $2.946 per kilowattmonth.

Weekly: $0.672 per kilowattweek.

Daily: $0.096 per kilowattday.

Hourly: $0.0040 per kilowatthour.

Billing

The rates listed above will be applied

to the maximum service amount in

kilowatts agreed to in the service

agreement, payable whether used or not.

Rate Schedule CV–SUR2

(Supersedes Schedule CV–SUR1)

Schedule of Rates for Supplemental

Reserve Service

Effective

The first day of the first full billing

period beginning on or after April 1,

2001, through December 31, 2004.

Available

Within the marketing area served by

the Sierra Nevada Customer Service

Region.

Applicable

To customers receiving supplemental

reserve service.

Character and Conditions of Service:

Supplemental reserve service supplies

capacity that is not synchronized with

the power system but can be available

to serve load within 10 minutes.

Rates

Supplemental Reserve Service Charge:

Monthly: $2.491 per kilowattmonth.

Weekly: $0.574 per kilowattweek.

Daily: $0.082 per kilowattday.

Hourly: $0.0034 per kilowatthour.

Billing:

The rates listed above will be applied

to the maximum service amount in

kilowatts agreed to in the service

agreement, payable whether used or not.

Rate Schedule CV–PSS2

(Supersedes Schedule CV–PSS1)

Schedule of Rate for Power Scheduling

Service

Effective

The first day of the first full billing

period beginning on or after April 1,

2001, through December 31, 2004.

Available

Within the marketing area served by

the Sierra Nevada Customer Service

Region.

Applicable

To customers receiving power

scheduling service.

Character and Conditions of Service

Power scheduling service provides for

the scheduling of resources to meet

loads and reserve requirements.

Rate

$76.65 per hour.

Billing

The rate listed above will be applied

as stated in the service agreement.

Rate Schedule CV–SCS1

Schedule of Rate for Scheduling

Coordinator Service

Effective

The first day of the first full billing

period beginning on or after April 1,

2001, through December 31, 2004.

Available

Within the marketing area served by

the Sierra Nevada Customer Service

Region.

Applicable

To customers receiving scheduling

coordinator service.

Character and Conditions of Service

Scheduling Coordinator service

provides for the scheduling, real-time

dispatching, and financial settlements

with the California Independent System

Operator and/or power exchanges.

Rate

$76.65 per hour.

Billing

The rate listed above will be applied

as stated in the service agreement.

Rate Schedule COTP–FT2

(Supersedes Schedule COTP–FT1)

Schedule of Rate for Firm Transmission

Service

Effective

The first day of the first full billing

period beginning on or after April 1,

2001, through December 31, 2004.

Available

Within the marketing area served by

the Sierra Nevada Customer Service

Region.

Applicable

To firm transmission service

customers where power is received into

the California-Oregon Transmission

Project (COTP) at points of receipt with

other systems and transmitted and

delivered to points of delivery on the

COTP as agreed to by the parties.

Character and Conditions of Service

Transmission service for three-phase,

alternating current at 60 hertz, delivered

and metered at the voltages and points

of delivery. It includes scheduling,

system control and dispatch service and

21222 Federal Register / Vol. 66, No. 82 / Friday, April 27, 2001 / Notices

reactive supply and voltage control

service needed to support the

transmission service.

Formula Rate

The formula rate for COTP firm

transmission includes two components.

Component 1 is the following

formula:

TRR

COTPsc

Where:

TRR = Transmission Revenue

Requirement—Western’s share of the

costs associated with facilities that

support the transfer capability of the

COTP. These costs include

investment cost, interest expense,

operation and maintenance (O&M)

expense, less revenue credits.

COTPsc = COTP seasonal capacity—

Western’s share of capacity under the

then current California-Oregon

Intertie transfer capability for the

season. Seasonal definitions for

summer, winter, and spring are June

through October, November through

March, and April through May,

respectively.

Western will update component 1 at

least 15 days before the start of each

season. Notification of rate changes will

occur through the posting of the rate on

the open access same time information

system.

Component 2 is any transmissionrelated costs incurred by Western due to

electric industry restructuring or other

industry changes associated with

providing COTP transmission service.

The costs in component 2, as well as

any changes to these costs, will be

passed through to each appropriate

transmission customer.

If the rates from the formula rate are

higher than other transmission rates in

California, transmission service for 1

year or less may be sold at a lower rate.

Billing

The rates listed above will be applied

monthly to the maximum amount of

capacity reserved, payable whether used

or not.

Adjustments

For Losses

Losses incurred in connection with

the transmission and delivery of power

under this rate schedule will be

accounted for as agreed to by the

parties.

Rate Schedule COTP–NFT2

(Supersedes Schedule COTP–NFT1)

Schedule of Rate for Nonfirm

Transmission Service

Effective

The first day of the first full billing

period beginning on or after April 1,

2001, through December 31, 2004.

Available

Within the marketing area served by

the Sierra Nevada Customer Service

Region.

Applicable

To nonfirm transmission service

customers where power is received into

the California-Oregon Transmission

Project (COTP) at points of receipt with

other systems and transmitted and

delivered, subject to the availability of

transmission capacity, to points of

delivery on the COTP as agreed to by

the parties.

Character and Conditions of Service

Transmission service on an

intermittent basis for three-phase,

alternating current at 60 hertz, delivered

and metered at the voltages and points

of delivery. It includes scheduling,

system control and dispatch service and

reactive supply and voltage control

service needed to support the

transmission service.

Rate

The formula rate for COTP nonfirm

transmission includes two components.

Component 1 is the following

formula:

TRR

COTPe

Where:

TRR = Transmission Revenue

Requirement—Western’s share of the

costs associated with facilities that

support the transfer capability of the

COTP. These costs include

investment cost, interest expense,

operation and maintenance expense,

less revenue credits.

COTPe = Energy associated with COTP

Seasonal Capacity—the energy

associated with Western’s share of

capacity under the then current

California-Oregon Intertie (COI)

transfer capability for the season.

Seasonal definitions for summer,

winter, and spring are June through

October, November through March,

and April through May, respectively.

Western will update component 1 at

least 15 days before the start of each

season. Notification of rate changes will

occur through the posting of the rate on

the open access same time information

system.

Component 2 is any transmissionrelated costs incurred by Western due to

electric industry restructuring or other

industry changes associated with

providing COTP transmission service.

The costs in component 2, as well as

any changes to these costs, will be

passed through to each appropriate

transmission customer.

If the rates resulting from the formula

rate are higher than other transmission

rates in California, transmission service

for 1 year or less may be sold at a lower

rate.

Billing

The rates listed above will be applied

to each kilowatthour delivered at the

point of delivery, as specified in the

service contract.

Adjustments

For Losses

Losses incurred in connection with

the transmission and delivery of power

and energy under this rate schedule will

be accounted for as agreed to by the

parties.

[FR Doc. 01–10227 Filed 4–26–01; 8:45 am]

BILLING CODE 6450–01–P