Federal Register / Vol. 65, No. 217 / Wednesday, November 8, 2000 / Notices 66989

for assistance. A copy is also available

for inspection and reproduction at the

address in item h above.

m. Individuals desiring to be included

on the Commission’s mailing list should

so indicate by writing to the Secretary

of the Commission.

Comments, Protests, or Motions to

Intervene—Anyone may submit

comments, a protest, or a motion to

intervene in accordance with the

requirements of Rules of Practice and

Procedure, 18 CFR 385.210, .211, .214.

In determining the appropriate action to

take, the Commission will consider all

protests or other comments filed, but

only those who file a motion to

intervene in accordance with the

Commission’s Rules may become a

party to the proceeding. Any comments,

protests, or motions to intervene must

be received on or before the specified

comment date for the particular

application.

Filing and Service of Responsive

Documents—Any filings must bear in

all capital letters the title

‘‘COMMENTS’’,

‘‘RECOMMENDATIONS FOR TERMS

AND CONDITIONS’’, ‘‘PROTEST’’, OR

‘‘MOTION TO INTERVENE’’, as

applicable, and the Project Number of

the particular application to which the

filing refers. Any of the above-named

documents must be filed by providing

the original and the number of copies

provided by the Commission’s

regulations to: The Secretary, Federal

Energy Regulatory Commission, 888

First Street, NE., Washington, DC 20426.

A copy of any motion to intervene must

also be served upon each representative

of the Applicant specified in the

particular application.

Agency Comments—Federal, state,

and local agencies are invited to file

comments on the described application.

A copy of the application may be

obtained by agencies directly from the

Applicant. If an agency does not file

comments within the time specified for

filing comments, it will be presumed to

have no comments. One copy of an

agency’s comments must also be sent to

the Applicant’s representatives.

David P. Boergers,

Secretary.

[FR Doc. 00–28631 Filed 11–7–00; 8:45 am]

BILLING CODE 6717–01–M

DEPARTMENT OF ENERGY

Federal Energy Regulatory

Commission

Notice of Application for Amendment

of License and Soliciting Comments,

Motions To Intervene, and Protests

November 2, 2000.

Take notice that the following

hydroelectric application has been filed

with the Commission and is available

for public inspection:

a. Application: Amendment of

License.

b. Project No.: 10228–015.

c. Date Filed: July 21, 2000.

d. Applicant: Cannelton Hydroelectric

Project, L.P.

e. Name of Project: Cannelton.

f. Location: The project is located on

the Ohio River in Hancock County,

Kentucky, at the U.S. Army Corps of

Engineers’ Cannelton Locks and Dam.

g. Filed Pursuant to: Federal Power

Act, 16 U.S.C. 791(a)–825(r).

h. Applicant Contact: Cannelton

Hydroelectric Project, L.P., 120 Calumet

Ct., Aiken, SC 29803, (803) 642–2749.

i. FERC Contact: Any questions on

this notice should be addressed to Dave

Snyder at (202) 219–2385.

j. Deadline for filing comments and/

or motions: December 8, 2000. All

documents (original and eight copies)

should be filed with: David P. Boergers,

Secretary, Federal Energy Regulatory

Commission, 888 First Street, NE.,

Washington, DC 20426. Comments and

protests may be filed electronically via

the internet in lieu of paper. See, 18

CFR 385.2001(a)(1)(iii) and the

instructions on the Commission’s web

site at http://www.ferc.fed.us/efi/

doorbell.htm.

Please include the Project Number

(10228–015) on any comments or

motions filed.

k. Description of Filing: Pursuant to

§ 4.200(c) and § 4.202(a) of the

Commission’s Rules of Practice and

Procedure (18 CFR), Cannelton

Hydroelectric Project, L.P., requests,

among other things, an extension of

time until December 2005 to complete

construction of the Cannelton Project.

l. Locations of the Application: A

copy of the application is available for

inspection and reproduction at the

Commission’s Public Reference Room,

located at 888 First Street, NE., Room

2A, Washington, DC 20426, or by calling

(202) 208–1371. The application may be

viewed on the web at www.ferc.fed.us/

online/rims.htm. Call (202) 208–2222

for assistance. A copy is also available

for inspection and reproduction at the

address in item h above.

m. Individuals desiring to be included

on the Commission’s mailing list should

so indicate by writing to the Secretary

of the Commission.

Comments, Protests, or Motions to

Intervene—Anyone may submit

comments, a protest, or a motion to

intervene in accordance with the

requirements of Rules of Practice and

Procedure, 18 CFR 385.210, .211, .214.

In determining the appropriate action to

take, the Commission will consider all

protests or other comments filed, but

only those who file a motion to

intervene in accordance with the

Commission’s Rules may become a

party to the proceeding. Any comments,

protests, or motions to intervene must

be received on or before the specified

comment date for the particular

application.

Filing and Service of Responsive

Documents—Any filings must bear in

all capital letters the title

‘‘COMMENTS’’,

‘‘RECOMMENDATIONS FOR TERMS

AND CONDITIONS’’, ‘‘PROTEST’’, OR

‘‘MOTION TO INTERVENE’’, as

applicable, and the Project Number of

the particular application to which the

filing refers. Any of the above-named

documents must be filed by providing

the original and the number of copies

provided by the Commission’s

regulations to: The Secretary, Federal

Energy Regulatory Commission, 888

First Street, NE., Washington, DC 20426.

A copy of any motion to intervene must

also be served upon each representative

of the Applicant specified in the

particular application.

Agency Comments—Federal, state,

and local agencies are invited to file

comments on the described application.

A copy of the application may be

obtained by agencies directly from the

Applicant. If an agency does not file

comments within the time specified for

filing comments, it will be presumed to

have no comments. One copy of an

agency’s comments must also be sent to

the Applicant’s representatives.

David P. Boergers,

Secretary.

[FR Doc. 00–28632 Filed 11–7–00; 8:45 am]

BILLING CODE 6717–01–M

DEPARTMENT OF ENERGY

Western Area Power Administration

Proposed Rates for the Central Valley

and California-Oregon Transmission

Projects

AGENCY: Western Area Power

Administration, DOE.

66990 Federal Register / Vol. 65, No. 217 / Wednesday, November 8, 2000 / Notices

ACTION: Notice of Proposed Rates.

SUMMARY: The Western Area Power

Administration (Western) is proposing

new rates for Central Valley Project

(CVP) firm power, power scheduling,

scheduling coordinator, transmission,

California-Oregon Transmission Project

(COTP) transmission, and CVP ancillary

services. The current rates expire

September 30, 2002. The current power

rates are insufficient due to significant

increases in the prices of energy in the

California electric markets. Proposing

new rates for all the services listed

above extends the rates for these

services through the end of the current

CVP Power Marketing Plan.

A rate increase will provide sufficient

revenue to repay all annual costs,

including interest expense, and repay

required investment within the

allowable period. Rate impacts are

detailed in a rate brochure to be

provided to all interested parties. The

proposed new rates are scheduled to go

into effect on April 1, 2001, and will

remain in effect through December 31,

2004, which is the end of the current

CVP Power Marketing Plan. This

Federal Register notice initiates the

public process to replace the existing

approved rates that expire September

30, 2002.

Western previously proposed rates

that were published in the Federal

Register, March 3, 2000. The

publication of this Federal Register

notice rescinds those proposed rates.

Western will disregard all public input

associated with the rescinded proposed

rates.

DATES: The consultation and comment

period will begin November 8, 2000 and

will end December 29, 2000. Western

will present a detailed explanation of

these new proposed rates at a public

information forum scheduled for

November 17, 2000, beginning at 1 p.m.

Pacific Standard Time (PST), at the

Sierra Nevada Regional Office. Western

will receive oral and written comments

at a public comment forum scheduled

for December 13, 2000, beginning at 1

p.m. PST, at the Sierra Nevada Regional

Office. Western must receive all

comments by the end of the

consultation and comment period to

assure consideration of the comments.

ADDRESSES: Send written comments to

Mr. Jerry W. Toenyes, Regional

Manager, Sierra Nevada Customer

Service Region, Western Area Power

Administration, 114 Parkshore Drive,

Folsom, CA 95630–4710, e-mail

toenyes@wapa.gov.

FOR FURTHER INFORMATION CONTACT: Ms.

Debbie Dietz, Rates Manager, Sierra

Nevada Customer Service Region,

Western Area Power Administration,

114 Parkshore Drive, Folsom, CA

95630–4710, (916) 353–4453, e-mail

ddietz@wapa.gov.

SUPPLEMENTARY INFORMATION: With the

publication of this notice Western is

withdrawing the previously proposed

rates published on March 3, 2000 (65 FR

11569). Due to significant unexpected

increases in the prices of energy in the

California electric markets, the rates

proposed in the March 3, 2000, Federal

Register notice would be insufficient to

recover the project costs. Therefore,

Western rescinds those proposed rates

and will disregard all public input

associated with the rescinded proposed

rates.

This Federal Register notice will

initiate the public process to replace the

existing approved rates that expire

September 30, 2002. The proposed new

rates for CVP firm power are designed

to recover an annual revenue

requirement that includes the

investment repayment, interest,

purchase power costs, transmission,

operation and maintenance expense,

and any charges or credits associated

with the creation, termination, or

modification to any tariff, contract, or

schedule approved by the Federal

Energy Regulatory Commission (FERC).

A cost-of-service study allocates the

projected annual revenue requirement

for firm power between capacity and

energy.

The capacity revenue requirement

includes: (i) 100 percent of capacity

purchase costs; (ii) 50 percent of the

investment repayment; (iii) 50 percent

of the interest expense; (iv) 50 percent

of the operation and maintenance

expense allocated to power; and (v) 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 determine

the capacity revenue requirement.

The energy revenue requirement

includes: (i) 100 percent of energy

purchase costs; (ii) 50 percent of the

investment repayment; (iii) 50 percent

of the interest expense; and (iv) 50

percent of the operation and

maintenance expense allocated to

power. Projected surplus power revenue

and 50 percent of projected CVP project

use revenue reduce annual costs to

determine the energy revenue

requirement.

The resulting capacity/energy revenue

requirement split varies from 30 percent

allocated to capacity from April 1, 2001,

through September 30, 2001, to 15

percent allocated to capacity from

October 1, 2004, through December 31,

2004. The average capacity/energy

revenue requirement split for the rate

period is 22 percent to capacity and 78

percent to energy. The variation in the

capacity/energy revenue requirement

split is due to fluctuations in energy

purchase costs and seasonal CVP hydro

generation.

Western also developed new

proposed rates for CVP firm power 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)

and if the CAISO uses the transmission

revenue requirement to develop a

regional transmission rate. Western has

not made a decision on joining the

CAISO. The decision to join the CAISO

is not part of this rate adjustment public

process. These new proposed power

rates with the transmission revenue

requirement removed are designed to

recover an annual revenue requirement

that includes investment repayment,

interest, purchase power, operation and

maintenance expense, and any charges

or credits associated with the creation,

termination, or modification to any

tariff, contract, or schedule approved by

FERC.

A cost-of-service study allocates

projected annual revenue requirement

for firm power between capacity and

energy. The capacity revenue

requirement includes: (i) 100 percent of

capacity purchase costs; (ii) 50 percent

of the investment repayment; (iii) 50

percent of the interest expense; and (iv)

50 percent of the operation and

maintenance expense allocated to

power.

Fifty percent of the projected CVP

project use revenue reduces the annual

cost to determine the capacity revenue

requirement. The energy revenue

requirement includes: (i) 100 percent of

energy purchase costs; (ii) 50 percent of

the investment repayment; (iii) 50

percent of the interest expense; and (iv)

50 percent of the operation and

maintenance expense allocated to

power. Projected surplus power revenue

and 50 percent of the projected CVP

project use revenue reduce the annual

cost to determine the energy revenue

requirement.

The resulting capacity/energy revenue

requirement split varies from 24 percent

allocated to capacity from April 1, 2001,

through September 30, 2001, to 11

percent allocated to capacity from

October 1, 2004, through December 31,

2004. The average capacity/energy

revenue requirement split for the rate

period is 17 percent to capacity and 83

percent to energy. The variation in the

Federal Register / Vol. 65, No. 217 / Wednesday, November 8, 2000 / Notices 66991

capacity/energy revenue requirement

split is due to fluctuations in energy

purchase costs and seasonal CVP hydro

generation.

For both sets of firm power rates

described above, Western will pass

through to its customers any additional

costs or credits that may be charged or

credited to Western as the result of the

creation, termination, or modification of

any tariff, contract, schedule or other

documents approved by FERC. When

possible, Western will pass through

directly to each customer FERC

approved costs or credits in the same

manner Western receives these costs or

credits. If the FERC approved costs or

credits are charged to Western in such

a way that a direct pass through to each

customer is not possible, Western will

distribute the FERC approved costs or

credits to each customer in a manner

consistent with the rate design used in

developing the proposed rates.

The new proposed rates for CVP firm

power and the applicable revenue

requirement split between capacity and

energy are in Table 1.

TABLE 1.—PROPOSED FIRM POWER RATES

Effective period

Total

composite

mills/

kWh

Capacity

$/

kWmonth

Energy

mills/

kWh

Capacity/energy split

04/01/01 to 09/30/01 ........................................................................................................................ 22.71 3.81 15.99 30/70

10/01/01 to 09/30/02 ........................................................................................................................ 26.16 3.34 20.64 21/79

10/01/02 to 09/30/03 ........................................................................................................................ 26.96 3.48 21.24 21/79

10/01/03 to 09/30/04 ........................................................................................................................ 26.46 3.41 20.85 21/79

10/01/04 to 12/31/04 ........................................................................................................................ 29.62 2.96 25.06 15/85

The proposed rates for CVP firm

power with the transmission revenue

requirement removed and applicable

revenue requirement split between

capacity and energy are in Table 1A.

TABLE 1A.—PROPOSED FIRM POWER RATES WITH THE TRANSMISSION REVENUE REQUIREMENT REMOVED FROM THE

FIRM POWER REVENUE REQUIREMENT

Effective period

Total

composite

mills/

kWh

Capacity

$/

kWmonth

Energy

mills/

kWh

Capacity/energy

split

04/01/01 to 09/30/01 .............................................................................................................................. 21.04 2.86 15.99 24/76

10/01/01 to 09/30/02 .............................................................................................................................. 24.74 2.48 20.64 17/83

10/01/02 to 09/30/03 .............................................................................................................................. 25.57 2.63 21.24 17/83

10/01/03 to 09/30/04 .............................................................................................................................. 25.08 2.57 20.85 17/83

10/01/04 to 12/31/04 .............................................................................................................................. 28.22 2.05 25.06 11/89

The Deputy Secretary of the

Department of Energy (DOE), approved

the existing Rate Schedule CV–F9 for

CVP commercial firm power on

September 19, 1997 (Rate Order No.

WAPA–77, 62 FR 50924, September 29,

1997). FERC confirmed and approved

the rate schedule on January 8, 1998,

under FERC Docket No. EF97–5011–000

(82 FERC ¶ 62,006). The existing Rate

Schedule CV–F9 became effective on

October 1, 1997, for the period ending

September 30, 2002. Under Rate

Schedule CV–F9, the composite rate on

October 1, 2000, is 18.56 mills per

kilowatthour (mills/kWh), the base

energy rate is 10.51 mills/kWh and the

capacity rate is $3.81 per kilowattmonth

(kWmonth).

The proposed rates for CVP firm

power will result in an overall

composite rate increase of

approximately 22 percent on April 1,

2001, when compared with the current

CVP commercial firm power rates under

Rate Schedule CV–F9. Table 2 provides

a comparison of the current rates in Rate

Schedule CV–F9 and the proposed rates

along with the percentage change in the

rates.

TABLE 2.—COMPARISON OF CURRENT AND PROPOSED RATES

Effective period

Total

composite

rate

Percent

change

Capacity

$/kW

month

Percent

change

Energy

mills/

kWh

Percent

change

Percentage Change in Firm Power Rates

Current Rate Schedule

Existing 10/01/00 to 09/30/01 ..................................................................................... 18.56 ............ 3.81 ............ 10.51 ............

66992 Federal Register / Vol. 65, No. 217 / Wednesday, November 8, 2000 / Notices

TABLE 2.—COMPARISON OF CURRENT AND PROPOSED RATES—Continued

Effective period

Total

composite

rate

Percent

change

Capacity

$/kW

month

Percent

change

Energy

mills/

kWh

Percent

change

Proposed Rates

04/01/01 to 09/30/01 .................................................................................................. 22.71 22 3.81 0 15.99 52

10/01/01 to 09/30/02 .................................................................................................. 26.16 41 3.34 ¥12 20.64 96

10/01/02 to 09/30/03 .................................................................................................. 26.96 45 3.48 ¥9 21.24 102

10/01/03 to 09/30/04 .................................................................................................. 26.46 43 3.41 ¥10 20.85 98

10/01/04 to 12/31/04 .................................................................................................. 29.62 60 2.96 ¥22 25.06 138

The proposed rates for CVP firm

power with the transmission revenue

requirement removed will result in an

overall composite rate increase of

approximately 13 percent on April 1,

2001, when compared with the current

CVP commercial firm power rates under

Rate Schedule CV–F9. Table 2A

provides a comparison of the current

rates in Rate Schedule CV–F9 and the

proposed rates with the Transmission

Revenue Requirement removed along

with the percentage change in the rates.

TABLE 2A.—COMPARISON OF CURRENT AND PROPOSED RATES WITH THE TRANSMISSION REVENUE REQUIREMENT

REMOVED 1

Effective period

Total

composite

rate

Percent

change

Capacity

$/kW

month

Percent

change

Energy

mills/

kWh

Percent

change

Percentage Change in Firm Power Rates

Current Rate Schedule

Existing 10/01/00 to 09/30/01 ..................................................................................... 18.56 ............ 3.81 ............ 10.51 ............

Proposed Rates With the Transmission Revenue Requirement Removed

04/01/01 to 09/30/01 .................................................................................................. 21.04 13 2.86 ¥25 15.99 52

10/01/01 to 09/30/02 .................................................................................................. 24.74 33 2.48 ¥35 20.64 96

10/01/02 to 09/30/03 .................................................................................................. 25.57 38 2.63 ¥31 21.24 102

10/01/03 to 09/30/04 .................................................................................................. 25.08 35 2.57 ¥33 20.85 98

10/01/04 to 12/31/04 .................................................................................................. 28.22 52 2.05 ¥46 25.06 138

1These rates do not include the cost of transmission; therefore, the customer is required to buy transmission at an additional cost.

Adjustment Clauses Associated With

the Proposed Rates for CVP Firm Power

Power Factor Adjustment

This provision in Rate Schedule CV–

F9 will remain the same under the

proposed rates for CVP firm power.

Low Voltage Loss Adjustment

This provision in Rate Schedule CV–

F9 will remain the same under the

proposed rates for CVP firm power.

Revenue Adjustment

The Revenue Adjustment Clause

(RAC) provides for a comparison

between the projected net revenues in

the rate adjustment power repayment

study 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 RAC credit or surcharge is

$20 million, plus any purchase 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 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

purchase power contract adjustments

applied to the April to September 2005

bills.

Proposed Rate for Power Scheduling

Service

The proposed rate for power

scheduling service is $76.65 per hour

and is based on costs incurred to

provide the service. Power scheduling

service provides for scheduling

resources to meet load and reserve

requirements.

Proposed Rate for Scheduling

Coordinator Service

The proposed rate for scheduling

coordinator service is $76.65 per hour

and is based on costs incurred to

provide the service. Scheduling

coordinator service provides

scheduling, real-time dispatching, and

financial settlements with the CAISO

and/or power exchanges.

Federal Register / Vol. 65, No. 217 / Wednesday, November 8, 2000 / Notices 66993

Proposed Formula Rate for CVP

Transmission

The proposed formula rate for firm

CVP transmission includes two

components:

Component 1: Transmission revenue

requirement/(CVP capacity + total

transmission capacity under longterm contracts). Component 1 is the

ratio of Western’s transmission

revenue requirement to the sum of

the maximum operating capacity of

the Northern CVP power plants

under normal operating conditions

(CVP capacity) and the total

transmission capacity under longterm contracts between Western

and other parties. Northern CVP

power plants are J.F. Carr, Folsom,

Keswick, Nimbus, Shasta, Spring

Creek, and Trinity.

Component 2: Pass through of any

transmission-related costs or credits

incurred by Western due to electric

industry restructuring or other

changes in the industry. The costs

or credits in component 2, as well

as any changes to these costs or

credits, will be passed through to

each appropriate transmission

customer.

Western will revise the rate from

component 1 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 component 1 of the

CVP firm transmission rate of at least

$.05 per kWmonth. The estimated rate

resulting from the proposed formula rate

for firm CVP transmission for April to

September 2001 is $0.70 per kWmonth,

a 37-percent increase from the existing

rate of $0.51 per kWmonth, under Rate

Schedule CV–FT3. Based on a contract

agreement to provide transmission

service in the future, the estimated rate

resulting from the proposed formula rate

for firm CVP transmission for FY 2002

is $.56 per kWmonth, a 10-percent

increase from the existing rate of $.51

per kWmonth.

The estimated rate resulting from the

proposed formula rate for nonfirm CVP

transmission service for April to

September 2001 is 1.00 mill/kWh. The

proposed formula rate for nonfirm CVP

transmission is based on the same two

components used in the proposed

formula rate for firm CVP transmission.

A revision to the nonfirm rate resulting

from component 1 will occur whenever

component 1 of the firm transmission

rate is revised. If the rates 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 proposed formula rate for CVP

transmission service is based on a

revenue requirement that recovers: (i)

The costs for facilities that support the

transfer capability of the CVP

transmission system (excluding

generation facilities and radial lines);

(ii) the nonfacilities costs allocated to

transmission; and (iii) any transmissionrelated costs or credits incurred by

Western due to electric industry

restructuring or other changes in the

industry. The proposed formula rate

includes Western’s cost for scheduling,

system control and dispatch service,

and reactive supply and voltage control

service associated with the transmission

service. The proposed formula rate is

applicable to existing CVP firm

transmission service and future pointto-point transmission service.

Proposed Rate for Transmission of CVP

Power by Others

Western will pass through

transmission service costs or credits it

incurs for delivering CVP power over a

third party’s transmission system to the

requesting CVP customer. Rates under

this schedule will be automatically

adjusted as third party transmission

costs or credits are adjusted.

Proposed Formula Rate for Network

Integration Transmission

If Western offers network integration

transmission service, it will be

consistent with FERC Order No. 888.

The proposed formula rate is the

product of the network customer’s load

ratio share times one-twelfth of the

annual network integration 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-topoint transmission service, plus the

reserved capacity of all firm point-topoint transmission service customers.

The proposed formula rate for

network integration transmission

service is based on a revenue

requirement that recovers: (i) The costs

for facilities that support the transfer

capability of the CVP transmission

system (excluding generation facilities

and radial lines); (ii) the nonfacilities

costs allocated to transmission; and (iii)

any transmission-related costs or credits

incurred by Western due to electric

industry restructuring or other changes

in the industry. The proposed formula

rate includes Western’s cost for

scheduling, system control and dispatch

service, and reactive supply and voltage

control service needed to provide the

transmission service.

Proposed Formula Rate for COTP

Transmission

The proposed formula rate for COTP

transmission includes two components:

Component 1: Transmission Revenue

Requirement/Western’s share of

COTP Seasonal Capacity.

Component 1 is the ratio of the

transmission revenue requirement

to Western’s share of COTP

seasonal capacity. Western will

update the rate resulting from

component 1 at least 15 days before

the start of each California-Oregon

Intertie rating season. Seasonal

definitions for summer, winter, and

spring are June through October,

November through March, and

April through May, respectively.

Component 2: Pass through of any

transmission-related costs or credits

incurred by Western due to electric

industry restructuring or other

changes in the industry. The costs

or credits in component 2, as well

as any changes to these costs or

credits, will be passed through to

each appropriate transmission

customer.

The estimated rates resulting from the

proposed formula rate for firm COTP

transmission service for April 2001 to

March 2002 are: Summer—$0.94 per

kWmonth, winter—$1.12 per kWmonth,

and spring—$1.00 per kWmonth. These

rates resulting from the proposed

formula rate result in a 30-percent

decrease during the summer, a 16-

percent decrease during the winter, and

a 25-percent decrease during the spring

compared to the existing rate of $1.34

per kWmonth.

The proposed formula rate for

nonfirm COTP transmission is based on

the same two components used in the

proposed formula rate for firm COTP

transmission. The estimated rates

resulting from the proposed formula rate

for nonfirm transmission service for

April 2001 to March 2002 are:

Summer—1.29 mills/kWh, winter—1.54

mills/kWh, and spring—1.37 mills/

kWh. These rates for nonfirm COTP

transmission service result in an 11-

percent decrease during the summer, a

6-percent increase during the winter,

and a 5-percent decrease during the

spring compared to the existing rate of

1.45 mills/kWh. If the rates 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.

Rates resulting from the proposed

formula rate for COTP transmission

service are based on a revenue

requirement that recovers: (i) Western’s

share of costs for facilities that support

66994 Federal Register / Vol. 65, No. 217 / Wednesday, November 8, 2000 / Notices

the transfer capability of the COTP; (ii)

Western’s share of the nonfacilities costs

allocated to transmission; and (iii) any

transmission-related costs or credits

incurred by Western due to electric

industry restructuring or other changes

in the industry. The rates resulting from

the proposed formula rate include

Western’s cost for scheduling, system

control and dispatch service, and

reactive supply and voltage control

service associated with transmission

service. The proposed formula rate

would apply to existing COTP

transmission service and future pointto-point transmission service.

Proposed Rates for Ancillary Services

Western will provide ancillary

services, subject to availability, at the

proposed rates in Table 3. Western

designed these proposed rates to recover

only the costs it incurs for providing the

service(s). If these cost-based rates are

higher than other ancillary service rates

in California, sales of ancillary services

of 1 year or less may be sold at lower

rates.

TABLE 3.—PROPOSED RATES FOR ANCILLARY SERVICES

Ancillary service type Rate

Transmission Scheduling, System Control and Dispatch Service—required to schedule movement of power through, out of, within, or into

a control area.

Appropriate transmission rates include Western’s cost.

Reactive Supply and Voltage Control Service—reactive power support

provided from generation facilities necessary to maintain transmission

voltages within acceptable limits of the system.

Appropriate transmission rates include Western’s cost.

Regulation and Frequency Response Service—provides generation to

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

Monthly: $2.496 per kWmonth.

Weekly: $0.574 per kWweek.

Daily: $0.082 per kWday.

Energy Imbalance Service—provied 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.

Within Limits of deviation Band:

Accumulated deviations are to be corrected or eliminated within 30

days. Any net deviations that are accumulated at the end of the

month (positive or negative) are to be exchanged with like hours of

energy or charged at the composite rate for CVP firm power then in

effect.

Hourly Deviation (MW)—net scheduled amount of energy for the hour

minus the hourly net metered (actual delivered) amount.

Outside Limits of Deviation Band:

(i) Positive Deviations—the greater of no charge, or any additional cost

incurred.

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

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

CVP firm power or any additional cost incurred.

Spinning Reserve Service—provides capacity available the first 10 minutes to take load and is synchronized with the power system.Monthly: $2.946 per kWmonth.

Weekly: $0.672 per kWweek.

Daily: $0.096 per kWday.

Hourly: $0.0040 per kWh.

Supplemental Reserve Service—provides capacity not synchronized,

but can be available to service loads within 10 minutes.

Monthly: $2.491 per kWmonth.

Weekly: $0.574 per kWweek.

Daily: $0.082 per kWday.

Hourly: $0.0034 per kWh.

Since the proposed rates constitute a

major rate adjustment as defined by the

procedures for public participation in

general rate adjustments, as cited below,

Western will hold both a public

information forum and a public

comment forum. After reviewing public

comments, Western will recommend

provisional rates for approval on an

interim basis by the DOE Deputy

Secretary.

These proposed rates for the CVP and

COTP are established pursuant to the

DOE Organization Act, 42 U.S.C. 7101–

7352; 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 projects

involved.

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. Existing DOE

procedures for public participation in

power rate adjustments (10 CFR part

903) became effective on September 18,

1985 (50 FR 37835).

Availability of Information

All brochures, studies, comments,

letters, memoranda, or other documents

made or kept by Western for developing

the proposed rates are available for

inspection and copying at the Sierra

Nevada Regional Office, 114 Parkshore

Drive, Folsom, California.

Regulatory Procedural Requirements

Regulatory Flexibility Analysis

The Regulatory Flexibility Act of 1980

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

agencies to perform a regulatory

flexibility analysis if a final rule is likely

to have a significant economic impact

on a substantial number of small entities

and there is a legal requirement to issue

a general notice of a proposed

rulemaking. Western has determined

that this action does not require a

Regulatory Flexibility analysis since it is

a rulemaking involving rates or services

for public property.

Environmental Compliance

In compliance with the National

Environmental Policy Act (NEPA) of

Federal Register / Vol. 65, No. 217 / Wednesday, November 8, 2000 / Notices 66995

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

has determined that this action is

categorically excluded from the

preparation of an environmental

assessment or an environmental impact

statement.

Determination Under Executive Order

12866

Western has an exemption from

centralized regulatory review under

Executive Order 12866; accordingly, no

clearance of this notice by Office of

Management and Budget is required.

Small Business Regulatory Enforcement

Fairness Act

Western has determined that this rule

is exempt from congressional

notification requirements under 5 U.S.C.

801 because the action is a rulemaking

of particular applicability relating to

rates or services and involves matters of

procedure.

Dated: October 16, 2000.

Michael S. Hacskaylo,

Administrator.

[FR Doc. 00–28626 Filed 11–07–00; 8:45 am]

BILLING CODE 6450–01–P

DEPARTMENT OF ENERGY

Western Area Power Administration

Proposed Salt Lake City Area

Integrated Projects Firm Power Rate

Formula Adder

AGENCY: Western Area Power

Administration, DOE.

ACTION: Notice of proposed rates.

SUMMARY: The Western Area Power

Administration’s (Western) Colorado

River Storage Project (CRSP)

Management Center (MC) is proposing a

rate formula adder to the existing rate

for firm long-term sales of Salt Lake City

Area Integrated Projects (SLCA/IP)

power. The SLCA/IP consists of the

CRSP, Collbran, and Rio Grande Projects

which were integrated for marketing

and ratemaking purposes on October 1,

1987. The CRSP described here includes

two CRSP participating projects which

have power facilities, Dolores and

Seedskadee Projects.

In the long term, the existing SLCA/

IP composite rate of 17.57 mills/

kilowatthour (kWh) is sufficient to pay

for all costs including operation,

maintenance, replacement, and interest

expenses and to repay investment and

irrigation assistance obligations within

the required period. CRSP MC staff will

continue to monitor the long-term firm

power rate for the SLCA/IP to determine

if a long-term rate adjustment will need

to be placed into effect.

The proposed rate formula adder is

needed to provide additional revenue in

the CRSP Basin Fund, a revolving fund

in the United States Treasury, to pay for

near-term purchase power costs and to

increase the working capital in the

CRSP Basin Fund. The proposed rate

formula adder scheduled to go into

effect on February 1, 2001, will remain

in effect until September 30, 2003, or

until superseded by another rate

adjustment, whichever occurs first. This

Federal Register notice initiates the

formal process for the proposed rate

formula adder.

DATES: The consultation and comment

period will begin when this Federal

Register notice is published and will

end December 8, 2000. Public

information forum and public comment

forum meeting dates are scheduled for

these locations:

1. Public information forum—

November 20, 2000, 10:30 a.m., Salt

Lake City, Utah; Public comment

forum—November 20, 2000, 2 p.m., Salt

Lake City, Utah.

2. Public information forum—

November 21, 2001, 10:30 a.m.,

Phoenix, Arizona; Public comment

forum—November 21, 2001, 2 p.m.,

Phoenix, Arizona.

ADDRESSES: The address for the Salt

Lake meetings is at the Sheraton Hotel

(formerly the Hilton), 150 West 500

South, Salt Lake City, Utah. The address

for the meetings in Phoenix is Western

Area Power Administration, Desert

Southwest Region, 615 South 43rd

Avenue, Phoenix, Arizona. Written

comments may be sent to: Mr. Dave

Sabo, CRSP Manager, CRSP

Management Center, Western Area

Power Administration, P.O. Box 11606,

Salt Lake City, UT 84147–0606, e-mail

sabo@wapa.gov. Western should receive

written comments by the end of the

consultation and comment period to be

assured they are considered. Oral

comments will be received at the public

comment meetings.

FOR FURTHER INFORMATION CONTACT: Ms.

Carol Loftin, Rates Manager, CRSP

Management Center, Western Area

Power Administration, P.O. Box 11606,

Salt Lake City, UT 84147–0606,

telephone (801) 524–6380, e-mail

loftinc@wapa.gov, or visit CRSP MC’s

home page at: www.wapa.gov/crsp/

crsp.htm.

SUPPLEMENTARY INFORMATION: The

existing long-term rate for SLCA/IP firm

power is designed to recover an annual

revenue requirement based on repaying

power investment; paying interest,

purchased power, operation,

maintenance, and replacement

expenses; and repaying irrigation

assistance costs, as required by law.

The Deputy Secretary of the

Department of Energy (DOE) approved

the existing Rate Schedule SLIP–F6 for

SLCA/IP firm power on March 23, 1998

(Rate Order No. WAPA–78). The Federal

Energy Regulatory Commission (FERC)

confirmed and approved the rate

schedule on July 17, 1998, in FERC

Docket No. EF98–5171–000. The

existing Firm Power Rate Schedule

expires on March 31, 2003. Under Rate

Schedule SLIP–F6, the energy rate is

8.10 mills/kWh, and the capacity rate is

$3.44 per kilowattmonth (kWmonth).

The composite rate (revenue

requirements per kWh usage) is 17.57

mills/kWh.

The proposed rate formula adder is

needed to provide additional revenue to

fund near-term purchased power costs

and to increase the working capital

balance in the CRSP Basin Fund.

Higher-than-normal purchased power

expenses have resulted from lower-thanexpected hydrology conditions, higherthan-normal purchase power prices, and

the summer test release for endangered

fish from Glen Canyon Dam (GCD).

The rate formula adder will be

applied during the next 3 fiscal years

(FY) from February 1, 2001, through

September 30, 2003. The following

proposed formulas will be used to

determine the rate formula adder:

(1) BB + ER—PP—O&M = EB

BB = CRSP Basin Fund balance at the

beginning of the FY

ER = expected revenues for the

current FY

PP = estimated purchase power costs

which could include nonreimbursable purchase power costs

O&M = operation and maintenance

expenses which includes nonreimbursable expenses,

replacements, and transmission

expenses

EB = CRSP Basin Fund balance at the

end of the FY

(2) RB—EB = RN

RB = minimum required balance in

the CRSP Basin Fund at the end of

the FY (FY 2001 = $35 million, FY

2002 = $50 million, FY 2003 = $60

million)

RN = additional revenue needed

The RN is divided by the projected

energy sales as shown in the existing

ratesetting study to determine the

additional composite rate needed.