48272 Federal Register / Vol. 62, No. 178 / Monday, September 15, 1997 / Notices

unnecessary for Atmos to appear or to

be represented at the hearing.

Lois D. Cashell,

Secretary.

[FR Doc. 97–24357 Filed 9–12–97; 8:45 am]

BILLING CODE 6717–01–M

DEPARTMENT OF ENERGY

Federal Energy Regulatory

Commission

[Docket No. TM98–1–43–000]

Williams Natural Gas Company; Notice

of Proposed Changes in FERC Gas

Tariff

September 9, 1997.

Take notice that on September 3,

1997, Williams Natural Gas Company

(WNG) tendered for filing to become

part of its FERC Gas Tariff, Second

Revised Volume No. 1, Twenty Second

Revised Sheet No. 6A. The proposed

effective date of this tariff sheet is

October 1, 1997.

WNG states that pursuant to Article

26 of the General Terms and Conditions

of its FERC Gas Tariff, and FERC

Annual Charges Billing under 18 CFR

Part 382, dated August 1, 1997, WNG is

filing to reflect an increase in the FERC

Annual Charge Adjustment from $.0020

to $.0022 per Dth for the fiscal year

beginning October 1, 1997. The unit

charge factor of $.0020 per Dth,

approved by the Commission, is

adjusted by the debit amount related to

the previous fiscal year to arrive at a

total ACA unit charge factor of $.0022.

WNG states that a copy of its filing

was served on all jurisdictional

customers and interested state

commissions.

Any person desiring to be heard or to

protest this filing should file a motion

to intervene or a protest with the

Federal Energy Regulatory Commission,

888 First Street, N.E., Washington, D.C.

20426, in accordance with Sections

385.214 and 385.211 of the

Commission’s Rules and Regulations.

All such motions or protests must be

filed as provided in Section 154.210 of

the Commission’s Regulations. Protests

will be considered by the Commission

in determining the appropriate action to

be taken, but will not serve to make

protestants parties to the proceedings.

Any person wishing to become a party

must file a motion to intervene. Copies

of this filing are on file with the

Commission and are available for public

inspection in the Public Reference

Room.

Lois D. Cashell,

Secretary.

[FR Doc. 97–24368 Filed 9–12–97; 8:45 am]

BILLING CODE 6717–01–M

DEPARTMENT OF ENERGY

Western Area Power Administration

Transmission and Ancillary Services

Rates, Pick-Sloan Missouri Basin,

Eastern Division

AGENCY: Western Area Power

Administration, DOE.

ACTION: Notice of proposed rate

adjustments.

SUMMARY: The Western Area Power

Administration (Western) is proposing

transmission service and ancillary

service rate adjustments for Pick-Sloan

Missouri Basin Program, Eastern

Division (P–SMBP–ED). The proposed

formula rates will provide sufficient

revenue to repay all annual costs and

assigned investment within the

allowable time periods. The proposed

formula rates are scheduled to go into

effect May 1, 1998. This Federal

Register notice continues the procedure

for public participation in the

transmission and ancillary service rate

adjustments, which began with

Western’s Advance Announcement

dated March 28, 1997.

DATES: The consultation and comment

period for the proposed transmission

service and ancillary service rates will

end November 14, 1997. Written

comments should be received by

Western by the end of the comment

period to be assured consideration.

Western will present a detailed

explanation of the proposed rate at the

public information forums which will

be held at the following dates and times:

1. October 16, 1997—9 a.m. MDT,

Billings, Montana.

2. October 17, 1997—9 a.m. CDT,

Sioux Falls, South Dakota.

Western will receive written and oral

comments at the public comment

forums which will be held at the

following times:

3. November 13, 1997—9 a.m. MST,

Billings, Montana.

4. November 14, 1997—9 a.m. CST,

Sioux Falls, South Dakota.

ADDRESSES: Western’s public

information forums will be held at the

following places:

1. Radisson Northern Hotel, Broadway

& 1st Avenue North, Billings, Montana.

2. Howard Johnson, 3300 West

Russell Street, Sioux Falls, South

Dakota.

Western’s public comment forums

will be held at the following places:

3. Radisson Northern Hotel, Broadway

& 1st Avenue North, Billings, Montana.

4. Howard Johnson, 3300 West

Russell Street, Sioux Falls, South

Dakota.

Written comments should be sent to:

Gerald C. Wegner, Regional Manager,

Upper Great Plains Region, Western

Area Power Administration, P.O. Box

35800, Billings, MT 59107–5800.

FOR FURTHER INFORMATION CONTACT:

Robert F. Riehl, Rates Manager, Upper

Great Plains Region (UGPR), Western

Area Power Administration, P.O. Box

35800, Billings, MT 59107–5800, (406)

247–7388. E-mail riehl@wapa.gov or

visit UGPR’s home page at http://

www.wapa.gov/ugp/.

SUPPLEMENTARY INFORMATION:

Table of Contents

I. Introduction/Background

II. Western’s Proposal

III. Proposed Rates

IV. Cost Shifting

V. Other Options

VI. Authorities

I. Introduction/Background

Western initiated a public process to

establish long-term open access

transmission and ancillary service rates

for the P–SMBP–ED with its advance

announcement of March 28, 1997.

Several options were identified and

comments and ideas were solicited on

these options. Forty-five letters were

received as a result of the solicitation.

The letters commented on fourteen

issues. The most constant and

consistent message received from the

comments was that Western should

choose a proposal that would have the

least impact upon the P–SMBP–ED firm

power rate. This Federal Register notice

continues that process.

II. Western’s Proposal

1. Honor Existing Contract

Arrangements

Western presently has the following

transmission and related services

contract agreements. Western intends to

abide by the terms of these agreements

and sustain the benefits incurred from

these agreements.

Basin Electric Power Cooperative

(Basin Electric) has a bilateral Contract,

90–BAO–415, with Western for Joint

Transmission System services. The

Contract became effective on the first

day of the first full billing period

following the date of its execution,

January 5, 1995, and remains in effect
Federal Register / Vol. 62, No. 178 / Monday, September 15, 1997 / Notices 48273

through the hour ending 2400 of

December 31, 2039. Basin Electric also

has a Contract, 90–BAO–431, with

Western for transmission service on the

Montana Power Company (MPC)

system. The Contract became effective

on the date of its execution, November

6, 1990, and remains in effect through

the hour 2400 on December 31, 2033.

Black Hills Corporation has a bilateral

Contract, 88–BAO–320, with Western

for transmission service. The Contract

became effective October 1, 1988, and

terminates at 12:01 a.m., October 1,

1998, as specified by the Contract.

Heartland Consumers Power District

(Heartland) has a bilateral Contract, 89–

BAO–344, with Western for Joint

Transmission System services. The

Contract became effective on the first

billing day of the first full billing period

following the date of its execution,

December 28, 1995, and remains in

effect through the hour ending 2400 on

December 31, 2039.

Minnkota Power Cooperative, Inc. has

a bilateral Contract, 88–BAO–313, with

Western for transmission service. The

Contract became effective the first day

of the first billing period after the date

of execution, October 6, 1989, and

remains in effect through December 31,

2020, as specified in the Contract.

Missouri Basin Municipal Power

Agency has a bilateral Contract, 8–07–

60–P0002, with Western for use of the

Joint Transmission System. The

Contract became effective on the first

day of the November 1977 billing period

and remains in effect until midnight of

December 31, 1997, as defined in the

Contract.

Montana-Dakota Utilities Company

has a bilateral Contract, 88–BAO–308,

with Western for transmission service.

The Contract became effective on its

date of execution, July 1, 1988, and

remains in effect until December 31,

2015.

MPC has a bilateral Contract, 4–07–

60–P0228, with Western for

transmission service. The Contract

became effective October 15, 1984.

Notice to terminate this Contract has

been served and the Contract will

terminate on or about June 30, 1998.

Northwestern Public Service

Company has a bilateral Contract, 4–07–

60–P0223, with Western for

transmission service. The Contract

became effective on April 1, 1984, and

remains in effect until December 31,

2000.

Northern States Power Company has

a Contract, 6–07–60–P0236, with

Western for transmission service. The

Contract became effective on the date of

its execution, June 2, 1986. Notice to

terminate this Contract has been served

and the Contract will terminate on

January 31, 2001.

2. The Integrated System Will Be Used

for Transmission Service in All New

Electric Service Arrangements

Western, Basin Electric, and

Heartland have combined their

transmission facilities to form an

Integrated System (IS) and herein

developed transmission and ancillary

service rates using a Federal Energy

Regulatory Commission (FERC)

approved rate design. Western has been

designated as the operator of the IS by

the other participants. The IS consists of

the transmission facilities owned by

Basin Electric, and Heartland east of the

east-west electrical separation in the

United States, the transmission facilities

owned by Western in the P–SMBP–ED,

and the Miles City DC Tie owned by

Western and Basin Electric. These

facilities interconnect with utilities in

the States of Montana, North Dakota,

South Dakota, Nebraska, Iowa,

Colorado, Minnesota, and Missouri and

in addition include facilities which

interconnect with Canada.

Our approach for formation of the IS

was to include facilities which followed

the spirit and intent of the order and to

make the system most useful to the

transmission requesters. For these

reasons we included several major

facilities which were not a part of the

Joint Transmission System. We

included the second 345-kV

transmission line between the Antelope

Valley and Leland Olds generating

stations; which follows the definitions

used for acceptable transmission

facilities in other filings. The 230-kV

transmission line between Tioga, North

Dakota, and Boundary Dam, which

provides access to loads in Canada, has

been included in the IS. The Miles City

DC Tie, which provides for the

transmission of electricity between the

east-west electrical separation of the

United States and increases access to

transmission on the IS. The IS also

differs from the Joint Transmission

System in that it does not include the

transmission facilities owned by the

joint owners of the Laramie River

Generating Station, which require the

agreement of all participants prior to

inclusion. Basin Electric, and Heartland

do not constitute all the owners in the

Laramie River Generating Station. If

they reach agreement, Western, Basin

Electric, and Heartland may consider

inclusion of those facilities in the IS rate

and tariff.

For each of their new electric service

arrangements crossing the IS facilities,

Western, Basin Electric, and Heartland

will take service under the proposed IS

rates. To avoid double charging for

transmission services, credit will be

given for transmission capacity

reservations in existing Joint

Transmission System service contracts

for new transactions from existing

resources. Western, as operator of the IS,

will bill for service, collect payments,

and distribute revenue to each

participant.

III. Proposed Rates

The proposed rates conform to the

spirit and intent of FERC Order Nos. 888

and 888–A. An Open Access

Transmission Tariff (Tariff), specifying

terms and conditions, is being

developed under a separate process.

Once implemented, Western, Basin

Electric, Heartland, and others will take

service under the proposed Tariff and

rates for all new transmission and/or

electric sales arrangements. Western is

requesting public comment on a

proposed rate formula that would be

adjusted annually, on or about May 1 of

each year, by inserting the previous

year’s data into the formula. The data

herein is fiscal year 1996 data. These

rates will support Western’s Tariff and

conform with the spirit and intent of

FERC Order Nos. 888 and 888–A.

Supporting information and impacts of

these rates are detailed in a rate

brochure available to all interested

parties.

1. Proposed Revenue Requirement for IS

Transmission Service

The proposed rate for IS transmission

service (Network and Point to Point) is

based on a revenue requirement that

recovers: (i) The IS investment and

interest cost for Western, Basin Electric,

and Heartland facilities associated with

providing IS transmission service; and

(ii) the operation, maintenance,

administrative and general cost for

Western, Basin Electric and Heartland

allocated to IS transmission service.

This revenue requirement is offset by

appropriate transmission revenues.

Rates will be recalculated every year on

or about May 1 based on the previous

year’s data. The previous year’s data to

be used in the recalculation will be

made available for review 30 days

before the new rates are implemented.

Firm and Non-Firm Point to Point

transmission service rates will be

offered on an up-to basis to promote

maximum usage and transmission

revenues from the IS.

2. Proposed Rate for Network IS

Transmission Service

The proposed rate for monthly

Network IS transmission service is the

product of the network customer’s load
48274 Federal Register / Vol. 62, No. 178 / Monday, September 15, 1997 / Notices

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

annual network transmission revenue

requirement. The network transmission

revenue requirement is derived by

annualizing the IS transmission

investment, and adding transmission

related annual costs, including

operation, maintenance, interest,

administrative and general costs. The

annual costs are reduced by revenue

credit for the Non-Firm transmission

service. The load ratio share is based on

the network customer’s hourly load

coincident with the IS monthly

transmission system peak minus the

coincident peak for all IS Firm Point-toPoint transmission service plus the

point-to-point reservations. The

Network rate includes the cost for

scheduling, system control, and

dispatch service needed to provide

transmission service.

3. Proposed Rate for Firm Point-to-Point

IS Transmission Service

The proposed Firm Point-to-Point IS

rate is based on a revenue requirement

derived by annualizing the IS

transmission investment, and adding

transmission related annual costs. These

transmission related annual costs

include operation, maintenance,

interest, administrative and general

costs. The annual costs are reduced by

revenue credits for Non-Firm

transmission. The resultant net annual

cost to be recovered is divided by the

capacity reservation needed for the

annual average monthly IS transmission

load. Using 1996 data, this methodology

produced a charge of $3.07/kW-month

for Firm Point-to-Point transmission

service. This proposed rate may be

adjusted each year on or about May 1,

by a recalculation based on the previous

years data using the formula: (Total

Annual Revenue Requirement—Non

Firm Revenue Credits)/Annual Average

Transmission System Monthly Peak

Load/12 months. The point-to-point rate

includes the cost for scheduling, system

control, and dispatch service needed to

provide transmission service.

4. Proposed Rate for Non-Firm Point-toPoint Service

The proposed rate for Non-Firm

Point-to-Point IS transmission service is

an energy rate up-to but never higher

than the Firm Point-to-Point rate. This

rate will remain in effect concurrently

with the Firm Point-to-Point rate. The

Non-Firm Point-to-Point rate includes

the cost for scheduling, system control,

and dispatch service needed to provide

transmission service.

5. Proposed Rates for Ancillary Services

Western will provide ancillary

services, subject to availability, as

described below and as listed in Table

1. The rates are designed to recover only

the costs incurred for providing the

service(s).

6. Proposed Rate for Scheduling, System

Control and Dispatch Service

Western’s annualized costs for

scheduling, system control and dispatch

service is determined by multiplying the

portion of the Watertown Operations

Office net plant and communications

facilities net plant associated with

scheduling, system control and dispatch

service by the transmission fixed charge

rate. The annual cost for scheduling,

system control and dispatch service is

then divided by the number of daily

schedules in FY 1996. Using 1996 data,

this methodology for determining the

scheduling, system control and dispatch

service rate has produced a charge of

$54.50/schedule/day. This rate and rate

design is recovering only Western’s

revenue requirement.

7. Proposed Rate for Reactive Supply

and Voltage Control Service

Western’s annualized cost for reactive

supply and voltage control is

determined by multiplying the total P–

SMBP–ED generation net plant by the

generation fixed charge rate. The

annualized cost is multiplied by the

capability used for reactive support to

determine Western’s reactive service

revenue requirement. Basin Electric’s

and Heartland’s annual revenue

requirements are based upon the

annualized cost of equipment installed

on their generators to provide this

service. Western’s, Basin Electric’s, and

Heartland’s revenue requirements are

summed for the total revenue

requirement. The reactive supply and

voltage control service charge is then

derived by dividing the revenue

requirement by the total load in

Western’s control area. The annual cost

is then divided by 12 months to obtain

a monthly charge. Using 1996 data, this

methodology for determining the rate

for reactive supply and voltage control

has produced a charge of $0.08/kWmonth for transmission capacity

reserved.

8. Proposed Rate for Regulation and

Frequency Response Service

Regulation and frequency response

service in the east side of the control

area is provided primarily by Oahe

generation and in the west side of the

control area by Fort Peck, both of which

are Corps of Engineers (Corps) facilities.

The Corps generation fixed charge rate

is applied to Oahe and Fort Peck net

plant costs producing an annual

generation revenue requirement for the

Oahe and Fort Peck power plants. This

revenue requirement is divided by the

capacity at the plants to derive a dollar

per kilowatt charge for Oahe’s and Fort

Peck’s installed capacity. This dollar per

kilowatt charge is then applied to

capacity used at Oahe and Fort Peck for

regulation and frequency response

service in the control area. The capacity

used for regulation and frequency

response service has been determined to

be 4 percent of the annual peak load.

The 4 percent value was derived by

averaging the incremental change in

hourly load in the control area for the

calendar year. The annual revenue

requirement for regulation and

frequency response service is

determined by applying the dollar per

kilowatt charge to the capacity used for

regulation and frequency response. The

regulation and frequency response

service charge is then determined by

dividing the revenue requirement by

Western’s load in the control area. The

annual cost is then divided by 12

months to obtain a monthly charge.

Using 1996 data, this methodology for

determining the rate for regulation and

frequency response produced a charge

of $0.09/kW-month of load for which

Western is providing this service. This

rate and rate design is recovering

Western’s revenue requirement only.

Credit will be given to those

transmission customers who provide

Western with Automatic Generation

Control (AGC) of generation facilities

capable of providing this service.

9. Proposed Rate for Energy Imbalance

Service

This service is not intended to

provide backup for generation supply.

Energy shall be returned with like

energy (on peak with on peak, etc.) and

accounts zeroed out monthly. Western

reserves the right to apply a penalty to

energy imbalances outside a 3 percent

bandwidth (+/-1.5 percent deviation).

The penalty for under deliveries outside

the 3 percent bandwidth is 100 mills/

kWh. Over deliveries outside the 3

percent bandwidth will be forfeited to

the control area

10. Proposed Rate for Reserves

Western’s annualized cost for reserves

is determined by multiplying the P–

SMBP–ED generation net plant costs by

the generation fixed charge rate. The

cost/kW-year is determined by dividing

the plant costs by the plant capacity.

The capacity used for reserves is

determined by multiplying the peak IS

load in the control area by the MAPP
Federal Register / Vol. 62, No. 178 / Monday, September 15, 1997 / Notices 48275

operating reserve requirement. The cost/

kW-year is multiplied by the capacity

used for reserves to determine the

annual cost of reserves. The annual cost

of reserves is divided by Western’s peak

load in the control area to calculate the

annual charge. The annual cost is then

divided by 12 months to obtain a

monthly charge. Using 1996 data, this

methodology for determining the

reserve rate has produced a charge of

$0.12/kW-month of customer load. This

rate and rate design is recovering only

Western’s revenue requirement. If

energy is taken under this service the

energy charge will be the MAPP Rate for

Emergency Energy, which is currently

30 mills/kWh.

TABLE 1.—PROPOSED SERVICE RATE FORMULAS FOR NEW TRANSACTIONS

Service Rate formula 1996 data Rate based on 1996 data

Network Transmission .................. Customer’s Load Ratio Share * 1/

12 * (Annual Transmission Revenue Requirement—Non-Firm

Revenue Credits).

Customer’s Load Ratio Share * 1/

12 * ($116.4M—$12.6M).

For comparison estimate at $3.07/

kW-Mo.

Firm Point-to-Point Transmission .. (Total Annual Revenue Requirement—Non-Firm Revenue

Credits)/Annual Average Transmission System Monthly Peak

Load/12 months.

($116.4M—$12.6M)/2,819 MW/12

months.

$3.07/kW-Mo.

Non-Firm Point-to-Point Transmission.Firm Point-to-Point rate/730 hours

per month.

$3.07/kW—Mo/730 hours/month .. 4.20 Mills/kWh.

Scheduling, System Control, and

Dispatch.

Transmission fixed charge rate*

((.4137 * Watertown net plant) +

(.384 * communications net

plant))/number of daily schedules per year.

20.59% * $6.86M/25,915 daily

schedules per year.

$54.50/schedule/day.

Reactive Supply and Voltage Control.((Generation fixed charge rate *

generation net plant cost * capability used for reactive support) + Basin Electric and

Heartland revenue requirement)/load in control area/12

months.

((12.3%* $613.2M * 2.02%) +

$1M)/2,532 MW-yr/12 months.

$0.08/kW-Mo.

Regulation and Frequency Response.COE fixed charge rate * COE

generation net plant cost/plant

capacity * capacity used for regulation/Western’s load in control

area/12 months.

10.4% * $251.6M/937 MW * 64.6

MW/1,615 MW/12 months.

$0.09/kW-Mo.

Energy Imbalance ......................... Penalty .......................................... 100 mills/kWh charge for under

deliveries outside 3% bandwidth(+/¥1.5%). Over deliveries

outside 3% bandwidth forfeited

to the control area.

Reserves ....................................... Generation fixed charge rate *

generation net plant cost/plant

capacity * capacity used for reserves/Western’s load in control

area/12 months.

12.3% * $613.2M/2,517 MW *

80.75 MW/1,615 MW/12 months.

$0.12/kW-Mo.

IV. Cost Shifting

There is no immediate impact to the

P–SMBP–ED firm power rate. In the first

few years as new electric service

arrangements move to the IS, costs will

shift between the IS participants.

Western will incur approximately $1

million/year of additional transmission

cost, Heartland will incur

approximately $200,000/year of

additional transmission cost and Basin

Electric’s costs will be reduced

approximately $2.4 million/year, based

upon average Pick-Sloan generation.

Western’s increased transmission costs

will have minimal impact to the P–

SMBP–ED firm power rate. Although it

is difficult to project cost shifting among

the IS participants beyond the first few

years following the implementation of

this proposal, additional usage, and

increased revenues should occur as

existing transmission contracts

terminate and are reformulated. This

should mitigate the impact to the

participants. Transition payments

among the IS participants may be

considered to mitigate impacts or cost

shifts if in this public process the

impacts are determined to be too severe.

V. Other Options

All other options mentioned in the

Advance Announcement are evaluated

in the customer rate brochure. The

additional comment item of generation

based rates is also examined in the

customer rate brochure.

VI. Authorities

Transmission and ancillary services

rates for the P–SMBP–ED are being

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

section 5 of the Flood Control Act of

1944 (16 U.S.C. 825s) and other acts

specifically applicable to the projects

involved.

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
48276 Federal Register / Vol. 62, No. 178 / Monday, September 15, 1997 / Notices

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

are found at 10 CFR part 903.

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. In this

instance the initiation of the IS

transmission rate and ancillary service

rate adjustments are related to nonregulatory services provided by Western

at particular rates. Under 5 U.S. C.

601(2), rules of particular applicability

relating to rates or services are not

considered rules within the meaning of

the act. Since the IS transmission rates

and ancillary services are of limited

applicability, no flexibility analysis is

required.

Environmental Compliance

Western will conduct an

environmental evaluation of the

proposed rates and develop the

appropriate level of environmental

documentation pursuant to the National

Environmental Policy Act (NEPA) 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).

Review Under the Paperwork Reduction

Act

In accordance with the Paperwork

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

et. seq.), Western has received approval

from the Office of Management and

Budget for the collection of customer

information in this rule, under control

number 1910–0100.

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.

Availability of Information

All brochures, studies, comments,

letters, memoranda, or other documents

made or kept by Western for developing

the proposed rates, will be made

available for inspection and copying at

the Upper Great Plains Regional Office,

located at 2900 4th Avenue North,

Billings, MT 59107–5800, during

normal business hours.

Dated: September 5, 1997.

Michael S. Hacskaylo,

Acting Administrator.

[FR Doc. 97–24346 Filed 9–12–97; 8:45 am]

BILLING CODE 6450–01–P

ENVIRONMENTAL PROTECTION

AGENCY

[OPPTS–400116; FRL–5745–7]

Toxics Data Reporting Committee of

the National Advisory Council for

Environmental Policy and Technology;

Notice of Public Meeting

AGENCY: Environmental Protection

Agency (EPA).

ACTION: Notice of public meeting.

SUMMARY: Under the Federal Advisory

Committee Act, EPA gives notice of a 2–

day meeting of the Toxics Data

Reporting Committee of the National

Advisory Council for Environmental

Policy and Technology. This will be the

first meeting of the Toxics Data

Reporting (TDR) Committee, whose

mission is to provide advice to EPA

regarding the Agency’s Toxics Release

Inventory (TRI) Program.

DATES: The public meeting will take

place on September 29-30, 1997, from

8:30 a.m. to 5 p.m. Written and

electronic comments in response to this

Federal Register should be received by

September 18, 1997.

ADDRESSES: For the meeting location

contact Cassandra Vail after September

18, 1997, at (202) 260–0675. Written

comments should be submitted in

triplicate to: OPPT Docket Clerk, TSCA

Document Receipt Office (7407), Office

of Pollution Prevention and Toxics,

Environmental Protection Agency, Rm.

E–G099, 401 M St., SW., Washington,

DC 20460.

Comments and data may also be

submitted electronically by following

the instructions under Unit II. of this

document. No Confidential Business

Information (CBI) should be submitted

through e-mail.

FOR FURTHER INFORMATION CONTACT:

Cassandra Vail, telephone: (202) 260–

0675, fax number: (202) 401–8142, email: vail.cassandra@epamail.epa.gov.

or Michelle Price, telephone: (202) 260–

3372, fax number: (202) 410–8142, email: price.michelle@epamail.epa.gov.

SUPPLEMENTARY INFORMATION:

I. Background

EPA is proposing that the TDR

committee discuss the following

subjects regarding the TRI reporting

forms, Forms R and Form A: (1)

Formatting of the Form R; (2)

nomenclature used in the Form R; (3)

opportunities for burden reduction in

both Form R and Form A; and (4)

additional clarification of the elements

in the Form R and EPA’s presentation of

the data in public information

documents. EPA also expects to receive

specific recommendations from the TDR

committee for changes, modifications,

deletions, and/or additions of data

elements to the Form R and Form A.

The purpose of the first meeting will be

to discuss section 5 of the Form R with

regard to the definition of release.

Oral presentations or statements by

interested parties will be limited to 5

minutes. Interested parties are

encouraged to contact Cassandra Vail, to

schedule presentations before the

committee.

II. Public Record

A record has been established for this

action under docket control number

‘‘OPPTS–400116’’ (including comments

and data submitted electronically as

described below). A public version of

this record, including printed, paper

versions of electronic comments, which

does not include any information

claimed as CBI, is available for

inspection from noon to 4 p.m., Monday

through Friday, excluding legal

holidays. The public record is located in

the TSCA Nonconfidential Information

Center, Rm. NE-B607, 401 M St., SW.,

Washington, DC 20460.

Electronic comments can be sent

directly to EPA at:

oppt.ncic@epamail.epa.gov

Electronic comments must be

submitted as an ASCII file avoiding the

use of special characters and any form

of encryption.

The official record for this action, as

well as the public version, as described

above will be kept in paper form.

Accordingly, EPA will transfer all

comments received electronically into

printed, paper form as they are received

and will place the paper copies in the

official record which will also include

all comments submitted directly in

writing. The official record is the paper

record maintained at the address in

ADDRESSES at the beginning of this

document.