Federal Register / Vol. 62, No. 42 / Tuesday, March 4, 1997 / Notices 9763

constraints, Southeastern has had

difficulty in obtaining these

appropriations. This difficulty has

compelled Southeastern to consider

selling the government power at the bus

bar of the projects. Southeastern

requests comments on this change in its

marketing policy. The current policy

does not contemplate such a disposition

of the power from the projects.

Issued in Elberton, Georgia, February 20,

1997.

Charles A. Borchardt,

Administrator.

[FR Doc. 97–5258 Filed 3–3–97; 8:45 am]

BILLING CODE 6450–01–P

Southeastern Power Administration

Intent To Formulate Revised Power

Marketing Policy Kerr-Philpott System

of Projects

AGENCY: Southeastern Power

Administration, DOE.

ACTION: Notice.

SUMMARY: Pursuant to its Procedure for

Public Participation in the Formulation

of Marketing Policy published in the

Federal Register of July 6, 1978,

Southeastern intends to revise its

marketing policy for future disposition

of power from its Kerr-Philpott System

of Projects. The current power

marketing policy published on July 29,

1985, for the Southeastern Power

Administration’s (Southeastern) KerrPhilpott System is reflected in contracts

for the sale of system power which are

maintained in Southeastern’s

headquarter’s offices. Proposals and

recommendations for consideration in

formulating the proposed revised

marketing policy are solicited, as are

requests for further information or

consultation.

EFFECTIVE DATE: Comments must be

submitted on or before May 5, 1997.

ADDRESSES: Five copies of written

proposals or recommendations should

be submitted to the Administrator,

Southeastern Power Administration,

Elberton, Georgia 30635, (706) 213–

3800.

FOR FURTHER INFORMATION CONTACT:

Charles A. Borchardt, Administrator,

Southeastern Power Administration,

Elberton, Georgia 30635, (706) 213–

3800.

SUPPLEMENTARY INFORMATION: A ‘‘Final

Power Marketing Policy for the KerrPhilpott System of Projects’’ was

developed and published in the Federal

Register on July 29, 1985, 50 FR 30752

by Southeastern. Transmission contracts

under this policy were effective with

Virginia Electric and Power Company

(VEPCO) and Carolina Power & Light

Company (CP&L) on February 1, 1987,

and Appalachian Power Company

(APCO) on June 30, 1987.

The Kerr-Philpott System consists of

two projects, the John H. Kerr and the

Philpott project. The power from the

projects is currently marketed to

Preference Customers located in the

service areas of VEPCO, CP&L and

APCO. The policy establishes the

marketing area for system power and

deals with the utilization of area utility

systems for essential purposes. The

policy also deals with wholesale rates,

resale rates, and conservation measures.

Under Section 5 of the Flood Control

Act of 1944 (16 U.S.C. 825s),

Southeastern is responsible for the

transmission and disposition of electric

power and energy from reservoir

projects operated by the Department of

Army. Southeastern has negotiated

transmission contracts with area

utilities described previously under this

authority. To pay the transmission fees

under these contracts to area utilities

Southeastern must obtain an

appropriation each year in a budget

approved by Congress and the

President. Because of budget

constraints, Southeastern has had

difficulty in obtaining these

appropriations. This difficulty has

compelled Southeastern to consider

selling the government power at the bus

bar of the projects. Southeastern

requests comments on this change in its

marketing policy. The current policy

does not contemplate such a disposition

of the power from the projects.

Issued in Elberton, Georgia, February 20,

1997.

Charles A. Borchardt,

Administrator.

[FR Doc. 97–5259 Filed 3–3–97; 8:45 am]

BILLING CODE 6450–01–M

Western Area Power Administration;

Proposed Rates for Central Valley and

California-Oregon Transmission

Project

AGENCY: Western Area Power

Administration, DOE.

ACTION: Notice of proposed rates.

SUMMARY: The Western Area Power

Administration (Western) is proposing

rates (Proposed Rates) for Central Valley

Project (CVP) commercial firm power,

power scheduling service, CVP

transmission, transmission of CVP

power by others, network transmission,

California-Oregon Transmission Project

(COTP) transmission, and ancillary

services. The current rates expire April

30, 1998. The Proposed Rates will

provide sufficient revenue to pay all

annual costs, including interest

expense, and repayment of required

investment within the allowable period.

The rate impacts are detailed in a rate

brochure to be provided to all interested

parties. The Proposed Rates are

scheduled to go into effect on October

1, 1997, to correspond with the start of

the Federal fiscal year, and will remain

in effect through September 30, 2002.

This Federal Register notice initiates

the formal process for the Proposed

Rates.

DATES: The consultation and comment

period will begin from the date of

publication of this Federal Register

notice and will end June 2, 1997. A

public information forum at which

Western will present a detailed

explanation of the Proposed Rates is

scheduled for March 25, 1997,

beginning at 9 a.m. PST, at the Sierra

Nevada Region, Western Area Power

Administration, 114 Parkshore Drive,

Folsom, CA 95630–4710. A public

comment forum at which Western will

receive oral and written comments is

scheduled for April 22, 1997, beginning

at 9 a.m. PDT, at the same location.

Western should receive written

comments by the end of the

consultation and comment period to be

assured consideration.

ADDRESSES: Written comments are to be

sent to: James C. Feider, Regional

Manager, Sierra Nevada Region,

Western Area Power Administration,

114 Parkshore Drive, Folsom, CA

95630–4710.

FOR FURTHER INFORMATION CONTACT:

Debbie Dietz, Rates Manager, Sierra

Nevada Region, Western Area Power

Administration, 114 Parkshore Drive,

Folsom, CA 95630–4710, (916) 353–

4453.

SUPPLEMENTARY INFORMATION: The

Proposed Rates for CVP commercial

firm power are designed to recover an

annual revenue requirement that

includes the investment repayment,

interest, purchase power, and operation

and maintenance expense. A cost of

service study allocates the projected

annual revenue requirement for

commercial firm power between

capacity and energy. The capacity

revenue requirement includes 100

percent of capacity purchase costs, 50

percent of the investment repayment,

interest expense, and power operation

and maintenance expense allocated to

commercial power, and 100 percent of

fixed transmission expense. These

annual costs are reduced by the

projected revenue from sales of CVP

transmission to determine the capacity
9764 Federal Register / Vol. 62, No. 42 / Tuesday, March 4, 1997 / Notices

revenue requirement. The energy

revenue requirement includes 100

percent of energy purchase costs and 50

percent of the investment repayment,

interest expense, and power operation

and maintenance expense allocated to

commercial power. These annual costs

are reduced by the projected revenue

from sales of surplus power to

determine the energy revenue

requirement. The resulting capacity/

energy revenue requirement split varies

from 51 percent allocated to capacity in

fiscal year (FY) 1998 to 44 percent

allocated to capacity in FY 2002. The

average capacity/energy revenue

requirement split for the five-year

period is 47 percent to capacity and 53

percent to energy.

The Proposed Rates will also include

an Annual Energy Rate Alignment

(AERA). The AERA will be applied to

firm energy purchases from Western at

or above an average annual load factor

of 80 percent. The AERA is the

difference between the estimated market

purchase rate used in the cost of service

study for CVP commercial firm power

and the CVP energy rate. The billing for

the AERA will occur at the end of each

fiscal year.

The Proposed Rates for CVP

commercial firm power, applicable

revenue requirement split between

capacity and energy, and the AERA are

provided in Table 1 below.

TABLE 1.—PROPOSED COMMERCIAL FIRM POWER RATES

Effective period

Total

composte

(mills/kWh)

Capacity

($/kW-mo)

Energy

(mills/kWh)

Capacity/

energy split

AERA

(mills/kWh)

10/01/97 to 09/30/98 ................................................................................. 20.64 5.00 10.11 51/49 3.06

10/01/98 to 09/30/99 ................................................................................. 19.59 4.57 9.98 49/51 3.65

10/01/99 to 09/30/00 ................................................................................. 19.59 4.51 10.10 49/51 4.01

10/01/00 to 09/30/01 ................................................................................. 18.59 3.95 10.30 45/55 4.30

10/01/01 to 09/30/02 ................................................................................. 20.09 4.15 11.35 44/56 3.76

The Deputy Secretary of the

Department of Energy (DOE), approved

the existing Rate Schedule CV–F8 for

CVP commercial firm power on

September 19, 1995 (Rate Order No.

WAPA–72, 60 FR 52671, October 10,

1995), and the Federal Energy

Regulatory Commission (FERC)

confirmed and approved the rate

schedule on March 14, 1996, under

FERC Docket No. EF95–5012–000 (74

FERC ¶ 62,136). The existing Rate

Schedule CV–F8 became effective on

October 1, 1995, for the period ending

April 30, 1998. Under Rate Schedule

CV–F8, the composite rate on October 1,

1997, is 26.50 mills per kilowatt-hour

(mills/kWh), the base energy rate is

16.93 mills/kWh, the tier energy rate is

26.48 mills/kWh, and the capacity rate

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

The Proposed Rates for CVP commercial

firm power will result in an overall

composite rate decrease of

approximately 22 percent on October 1,

1997, when compared with the current

CVP commercial firm power rates under

Rate Schedule CV–F8. Table 2 provides

a comparison of the current rates in Rate

Schedule CV–F8 and the Proposed Rates

along with the percentage change in the

rates.

TABLE 2.—COMPARISON OF CURRENT AND PROPOSED RATES

[Percentage Change in Commercial Firm Power Rates]

Effective period

Total

composite

(mills/kWh)

Percent

change

Capacity

($/kW-mo)

Percent

change

Base

energy

(mills/kWh)

Percent

change

Current Rate Schedule

Existing 10/01/97 and thereafter ....................................... 26.50 .................... 4.58 .................... 16.93 ....................

Proposed Rates

10/01/97 to 09/30/98 ......................................................... 20.64 ¥22 5.00 +9 10.11 ¥40

10/01/98 to 09/30/99 ......................................................... 19.59 ¥26 4.57 .................... 9.98 ¥41

10/01/99 to 09/30/00 ......................................................... 19.59 ¥26 4.51 ¥2 10.10 ¥40

10/01/00 to 09/30/01 ......................................................... 18.59 ¥30 3.95 ¥14 10.30 ¥39

10/01/01 to 09/30/02 ......................................................... 20.09 ¥24 4.15 ¥9 11.35 ¥33

Adjustment Clauses Associated With

the Proposed Rates for CVP

Commercial Firm Power

Power Factor Adjustment

This provision contained in Rate

Schedule CV–F8, will remain the same

under the Proposed Rates for CVP

commercial firm power.

Low Voltage Loss Adjustment

This provision contained in Rate

Schedule CV–F8, will remain the same

under the Proposed Rates for CVP

commercial firm power.

Revenue Adjustment

The methodology for the Revenue

Adjustment contained in Rate Schedule

CV–F8, will remain the same under the

Proposed Rates for CVP commercial

firm power.

Proposed Rate for Power Scheduling

Service

The Proposed Rate for power

scheduling service is $73.80 per hour

and is based on an estimated time to

provide the service. Power scheduling

service provides for the scheduling of

resources to meet loads and reserve

requirements.
Federal Register / Vol. 62, No. 42 / Tuesday, March 4, 1997 / Notices 9765

Proposed Rates for CVP Transmission

The Proposed Rate for firm CVP

transmission service is $0.48 per kWmo., an 11.6 percent increase from the

existing rate of $0.43 per kW-mo.

currently under Rate Schedule CV–FT2.

The Proposed Rate for non-firm CVP

transmission service is 1.00 mill/kWh,

an 18.7 percent reduction in the existing

1.23 mills/kWh rate. Service of firm or

non-firm transmission for one year or

less may be at rates lower than the

Proposed Rates.

The Proposed Rates for CVP

transmission service are based on a

revenue requirement that recovers: (i)

The CVP transmission system costs for

facilities associated with providing all

transmission service; and (ii) the nonfacilities costs allocated to transmission

service. These rates include the cost for

scheduling, system control and dispatch

service, and reactive supply and voltage

control associated with the transmission

service. The Proposed Rates are

applicable to existing CVP firm

transmission service and future pointto-point transmission service.

Proposed Rate for Transmission of CVP

Power by Others

Transmission service costs incurred

by Western in the delivery of CVP

power over a third party’s transmission

system to a CVP customer, will be

directly passed through to that CVP

customer. Rates under this schedule are

proposed to be automatically adjusted

as third party transmission costs are

adjusted.

Proposed Rate for Network

Transmission

The Proposed Rate for network

transmission service, if offered by

Western, is the product of the network

customer’s load ratio share times onetwelfth (1⁄12) of the annual network

transmission revenue requirement. The

load ratio share is based on the network

customer’s hourly load coincident with

Western’s monthly CVP transmission

system peak minus coincident peak for

all firm CVP (including reserved

capacity) point-to-point transmission

service. The Proposed Rate for network

transmission service is based on a

revenue requirement that recovers: (i)

The CVP transmission system costs for

facilities associated with providing all

transmission service; and (ii) the nonfacilities costs allocated to transmission

service. These rates include the cost for

scheduling, system control and dispatch

service, and reactive supply and voltage

control needed to provide the

transmission service.

Proposed Rates for COTP Transmission

The Proposed Rates for firm

transmission service for Western’s share

of the California-Oregon Transmission

Project (COTP) are $1.66 per kW-mo. for

FY 1998 and $1.12 per kW-mo. for FY

1999 through FY 2002. These Proposed

Rates for firm COTP transmission

service result in 18.2 percent (FY 1998)

and 44.8 percent (FY 1999 through FY

2002) reductions in the existing rate of

$2.03 per kW-mo. The Proposed Rates

for non-firm COTP transmission service

are 2.28 mills/kWh for FY 1998 and 1.54

mills/kWh for FY 1999 through FY

2002. These Proposed Rates for non-firm

COTP transmission service result in

18.0 percent (FY 1998) and 44.6 percent

(FY 1999 through FY 2002) reductions

in the existing rate of 2.78 mills/kWh.

Service of firm or non-firm transmission

for one year or less may be at rates lower

than the Proposed Rates.

The Proposed Rates for COTP

transmission service are based on a

revenue requirement that recovers the

costs associated with: (i) Western’s

participation in the COTP; (ii) the

offering of this service; and (iii)

scheduling, system control and dispatch

service, and reactive supply and voltage

control needed to provide the

transmission service. The Proposed

Rates are applicable 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 listed in Table 3. The

Proposed Rates are designed to recover

only the costs incurred by Western for

providing the service(s). Sales of

ancillary services of one year or less

may be at rates lower than the Proposed

Rates.

TABLE 3.—PROPOSED CVP ANCILLARY SERVICES RATES

Ancillary service type Rate

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

into a control area

Included in appropriate transmission rates.

Reactive Supply and Voltage Control—is reactive power support provided from generation facilities that is necessary to maintain transmission voltages within acceptable limits of the systemIncluded in appropriate transmission rates.

Regulation and Frequency Response Service—providing generation to

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

Monthly: $1.39 per kW-mo.

Weekly: $0.3192 per kW-week.

Daily: $0.0456 per kW-day.

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

a generation resource within a control area over a single month

Within Limits of Deviation Band:

Accumulated deviations are to be corrected or eliminated within 30

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

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

energy or charged at the composite rate for CVP commercial firm

power, then in effect.

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

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

Outside Limits of Deviation Band:

(I) Positive Deviations—no charge, lost to the system.

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

the Proposed Rates for CVP commercial firm power or any additional cost incurred. During off-peak hours, the greater of the Proposed Rates for CVP commercial firm power or any additional cost

incurred.

Spinning Reserve Service—is providing capacity that is available the

first ten minutes to take load and is synchronized with the power system

Monthly: $1.14 per kW-mo. plus adder.

Weekly: $0.2688 per kW-wk. plus adder.

Daily: $0.0384 per kW-day plus adder.

Hourly: $0.0016 per kWh plus adder.

Adder for purchasing energy to motor unit will be at market purchase

rate.
9766 Federal Register / Vol. 62, No. 42 / Tuesday, March 4, 1997 / Notices

TABLE 3.—PROPOSED CVP ANCILLARY SERVICES RATES—Continued

Ancillary service type Rate

Supplemental Reserve Service—is providing capacity that is not synchronized, but can be available to serve loads within ten minutesMonthly: $1.14 per kW-mo.

Weekly: $0.2688 per kW-wk.

Daily: $0.0384 per kW-day.

Hourly: $0.0016 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,

both a public information forum and a

public comment forum will be held.

After review of public comments,

Western will recommend the Proposed

Rates (and as amended) for approval on

an interim basis by the Deputy Secretary

of DOE.

Power and transmission rates for the

CVP are established pursuant to the

Department of Energy Organization Act

(42 U.S.C. 7101 et seq.) and the

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

et seq.), as amended and supplemented

by subsequent enactments, particularly

section 9(c) of the Reclamation Project

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

of Congress approved August 26, 1937

(50 Stat. 844, 850); August 12, 1955 (69

Stat. 719); and October 23, 1962 (76

Stat. 1173, 1191), and Acts amendatory

or supplementary thereof.

By Amendment No. 3 to Delegation

Order No. 0204–108, published

November 10, 1993 (58 FR 59716), the

Secretary of DOE delegated (1) the

authority to develop long-term power

and transmission rates on a

nonexclusive basis to the Administrator

of Western; (2) the authority to confirm,

approve, and place such rates into effect

on an interim basis to the Deputy

Secretary; and (3) the authority to

confirm, approve, and place into effect

on a final basis, to remand, or to

disapprove such rates to the FERC.

Existing DOE procedures for public

participation in power rate adjustments

(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 and will be

made available for inspection and

copying at the Sierra Nevada Region

Office, located at 114 Parkshore Drive,

Folsom, California 95630–4710.

Regulatory Procedure Requirements

Regulatory Flexibility Analysis

Pursuant to the Regulatory Flexibility

Act of 1980 (5 U.S.C. 601, et seq.), each

agency, when required to publish a

proposed rule, is further required to

prepare and make available for public

comment an initial regulatory flexibility

analysis to describe the impact of the

proposed rule on small entities. Western

has determined that (1) this rulemaking

relates to services offered by the Sierra

Nevada Region and therefore is not a

rule within the purview of the Act, and

(2) the proposed rates for the services

offered by the Sierra Nevada Region

would not cause an adverse economic

impact to such entities. The

requirements of this Act can be waived

if the head of the agency certifies that

the rule will not, if promulgated, have

a significant economic impact on a

substantial number of small entities. By

his execution of this Federal Register

notice, Western’s Administrator certifies

that no significant economic impact on

a substantial number of small entities

will occur.

Environmental Compliance

Pursuant to the National

Environmental Policy Act of 1969 (42

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

Environmental Quality Regulations for

implementing NEPA (40 CFR Parts 1500

through 1508); and the DOE NEPA

Implementing Procedures and

Guidelines (10 CFR Part 1021), Western

conducts environmental evaluations of

the proposed rates and develops the

appropriate level of environmental

documentation.

Review Under the Paperwork Reduction

Act

In accordance with the Paperwork

Reduction Act of 1980, 44 U.S.C. 3501–

3520, Western has received approval

from the Office of Management and

Budget for the collection of customer

information in this rule, under control

number 1910–1200.

Determination Under Executive Order

12866

DOE has determined that this is not

a significant regulatory action because it

does not meet the criteria of Executive

Order 12866, 58 FR 51735. Western has

an exemption from centralized

regulatory review under Executive

Order 12866; accordingly, no clearance

of this notice by Office of Management

and Budget is required.

Issued at Golden, Colorado, February 20,

1997.

J.M. Shafer,

Administrator.

[FR Doc. 97–5256 Filed 3–4–97; 8:45 am]

BILLING CODE 6450–01–P

FEDERAL COMMUNICATIONS

COMMISSION

[CC Docket No. 92–237]

Change in Time for March 11, 1997

Meeting of the North American

Numbering Council

AGENCY: Federal Communications

Commission.

ACTION: Notice.

SUMMARY: On February 27, 1997, the

Commission released a public notice

announcing a change in the time for the

March 11 meeting of the North

American Numbering Council (NANC).

The March 11 meeting and its agenda

had been announced in a public notice

published in the Federal Register on

February 26, 1997 (See 62 FR 8741). The

intended effect of this action is to make

the public aware that the time of the

March 11 NANC meeting has changed

from 9:30 A.M. EST, to 8:30 A.M. EST.

FOR FURTHER INFORMATION CONTACT:

Linda Simms, Administrative Assistant

of the NANC, (202) 418–2330. The

address is: Network Services Division,

Common Carrier Bureau, Federal

Communications Commission, 2000 M

Street, NW, Suite 235, Washington, D.C.

20054. The fax number is: (202) 418–

2345. The TTY number is: (202) 418–

0484.