34454 Federal Register / Vol. 61, No. 128 / Tuesday, July 2, 1996 / Notices

operator should be given Datagram

Identification Number N1023 and the

following message addressed to William

H. Bateman, Director, Project Directorate

IV–2: petitioner’s name and telephone

number, date petition was mailed, plant

name, and publication date and page

number of this Federal Register notice.

A copy of the petition should also be

sent to the Office of the General

Counsel, U.S. Nuclear Regulatory

Commission, Washington, DC 20555–

0001, and to T. E. Oubre, Esquire,

Southern California Edison Company, P.

O. Box 800, Rosemead, California

91770, attorney for the licensee.

Nontimely filings of petitions for

leave to intervene, amended petitions,

supplemental petitions and/or requests

for hearing will not be entertained

absent a determination by the

Commission, the presiding officer or the

presiding Atomic Safety and Licensing

Board that the petition and/or request

should be granted based upon a

balancing of the factors specified in 10

CFR 2.714(a)(1)(i)–(v) and 2.714(d).

For further details with respect to this

action, see the application for

amendment dated June 3, 1996, as

superseded by application dated June

25, 1996, which is available for public

inspection at the Commission’s Public

Document Room, the Gelman Building,

2120 L Street, NW., Washington, DC,

and at the local public document room

located at the Main Library, University

of California, P. O. Box 19557, Irvine,

California 92713.

Dated at Rockville, Maryland, this 26th day

of June 1996.

For the Nuclear Regulatory Commission.

Mel B. Fields,

Project Manager, Project Directorate IV–2,

Division of Reactor Projects III/IV, Office of

Nuclear Reactor Regulation.

[FR Doc. 96–16877 Filed 7–1–96; 8:45 am]

BILLING CODE 7590–01–P

Sunshine Act Meeting

AGENCY HOLDING THE MEETING: Nuclear

Regulatory Commission.

DATE: Weeks of July 1, 8, 15, and 22,

1996.

PLACE: Commissioners’ Conference

Room, 11555 Rockville Pike, Rockville,

Maryland.

STATUS: Public and Closed.

MATTERS TO BE CONSIDERED:

Week of July 1

Tuesday, July 2

10:00 a.m.

Briefing on Alternatives for Regulating

Fuel Cycle Facilities (Public Meeting)

(Contact: Ted Sherr, 301–415–7218)

Wednesday, July 3

10:00 a.m.

Briefing on BPR Project on Redesigned

Material Licensing Process (Public

Meeting)

(Contact: Pat Rathbun, 301–415–7178)

11:30 a.m.

Affirmation Session (Public Meeting) (if

needed)

Week of July 8—Tentative

Wednesday, July 10

11:30 a.m.

Affirmation Session (Public Meeting) (if

needed)

Week of July 15—Tentative

There are no meetings scheduled for the

Week of July 15.

Week of July 22—Tentative

There are no meetings scheduled for the

Week of July 22.

ADDITIONAL INFORMATION: By a vote of 3–

0 on June 26, the Commission

determined pursuant to U.S.C. 552b(e)

and § 9.107(a) of the Commission’s rules

that ‘‘Affirmation of Innovative

Weaponry, Inc.—Request for a Hearing’’

(Public Meeting) be held on June 26,

and on less than one weeks’ notice to

the public.

The schedule for Commission

meetings is subject to change on short

notice. To verify the status of meetings

call (Recording)—(301) 415–1292.

CONTACT PERSON FOR MORE INFORMATION:

Bill Hill (301 415–1661.

The NRC Commission Meeting Schedule

can be found on the Internet at:

http://www.nrc.gov/SECY/smj/schedule.htm.

This notice is distributed by mail to several

hundred subscribers; if you no longer wish

to receive it, or would like to be added to it,

please contact the Office of the Secretary,

Attn: Operations Branch, Washington, D.C.

20555 (301–415–1963).

In addition, distribution of this meeting

notice over the internet system is available.

If you are interested in receiving this

Commission meeting schedule electronically,

please send an electronic message to

alb@nrc.gov or dkw@nrc.gov.

Dated: June 28, 1996.

William M. Hill, Jr.,

SECY Tracking Officer, Office of the

Secretary.

[FR Doc. 96–17011 Filed 6–28–96; 2:29 pm]

BILLING CODE 7590–01–M

[Docket Nos. 50–528, 50–529 and 50–530]

Arizona Public Service Company; Palo

Verde Nuclear Generating Station, Unit

Nos. 1, 2, and 3; Issuance of Director’s

Decision Under 10 CFR § 2.206

Notice is hereby given that the

Director, Office of Nuclear Reactor

Regulation, has acted on a Petition for

action under 10 CFR § 2.206 received

from Mr. Thomas J. Saporito, Jr., on

behalf of Florida Energy Consultants,

Inc., dated May 27, 1994, as

supplemented on July 8, 1994, for the

Palo Verde Nuclear Generating Station,

Unit Nos. 1, 2, and 3.

In a letter dated May 27, 1994, the

Petitioner requested that the NRC (1)

institute a show-cause proceeding

pursuant to 10 CFR § 2.202 to modify,

suspend, or revoke the operating

licenses for Palo Verde; (2) issue a

notice of violation against the licensee

for continuing to employ The Atlantic

Group (TAG) as a labor contractor at

Palo Verde; (3) investigate alleged

material false statements made by

William F. Conway, Executive Vice

President at Palo Verde, during his

testimony at a Department of Labor

hearing (ERA Case No. 92–ERA–030)

and, in the interim, require that he be

relieved of any authority over

operations at Palo Verde; (4) investigate

the licensee’s statements in a letter of

August 10, 1993, from Mr. Conway to

the former NRC regional administrator,

Mr. Bobby H. Faulkenberry, that Mr.

Saporito gave materially false,

inaccurate, and incomplete information

on his application for unescorted access

to Palo Verde and that, as a result, he

lacks trustworthiness and reliability for

access to Palo Verde; (5) investigate the

circumstances surrounding the February

1994 termination of licensee employee

Joseph Straub, a former radiation

protection technician at Palo Verde, to

determine if his employment was

illegally terminated by the licensee

because he engaged in ‘‘protected

activity’’ during the course of his

employment; (6) require the licensee to

respond to a ‘‘chilling effect’’ letter

regarding the circumstances

surrounding Mr. Straub’s termination

from Palo Verde and to specify whether

any measures were taken to ensure that

his termination did not have a chilling

effect at Palo Verde; and (7) initiate

appropriate actions to require the

licensee to immediately conduct eddy

current testing on all steam generators at

Palo Verde because the steam generator

tubes were recently found to be subject

to cracking.

In a letter dated July 8, 1994, the

Petitioner raised six additional issues.

This supplemental Petition asked the

NRC to (1) institute a show-cause

proceeding pursuant to 10 CFR § 2.202

for the modification, suspension, or

revocation of the Palo Verde operating

licenses for Units 1, 2, and 3; (2) modify

the Palo Verde operating licenses to

require operation at 86-percent power or

less; (3) require the licensee to submit

a No Significant Hazards safety analysis
Federal Register / Vol. 61, No. 128 / Tuesday, July 2, 1996 / Notices 34455

1 Section 50.91 of the Commission’s regulations

provides that at the time a licensee requests an

amendment it must provide the NRC its analysis of

the issue of no significant hazards consideration,

using the standards of Section 50.92.

to justify operation of those units above

86-percent power; (4) take immediate

action (e.g., by confirmatory order) to

make the licensee reduce operation to

86-percent power or less; (5) require the

licensee to analyze a design-basis steam

generator tube rupture (SGTR) event to

show that the offsite radiological

consequences do not exceed a small

fraction of the limits of 10 CFR Part 100;

and (6) require the licensee to

demonstrate that its emergency

operating procedures for SGTR events

are adequate and that the plant

operators are sufficiently trained in

emergency operating procedures.

The Director of the Office of Nuclear

Reactor Regulation has determined that

requests 1, 2, 3, 5, and 6 of the July 8,

1994, Petition supplement should be

denied for the reasons stated in the

‘‘Director’s Decision Under 10 CFR

§ 2.206’’ (DD–96–08), the complete text

of which follows this notice and which

is available for public inspection at the

Commission’s Public Document Room,

the Gelman Building, 2120 L Street,

N.W., Washington, D.C. 20555, and at

the local public document room located

at the Phoenix Public Library, 1221 N.

Central Avenue, Phoenix, Arizona

85004. The Petitioners’ two requests for

immediate action (Request 7 of the May

27, 1994 Petition and Request 4 of the

July 8, 1994, Petition supplement) were

denied in a letter dated July 26, 1994.

The remaining requests are under

consideration and will be addressed in

a separate decision. A Director’s

Decision (DD–96–04) regarding Requests

1 through 6 in the Petition of May 27,

1994, was issued under separate cover

letter on June 3, 1996.

A copy of this Decision will be filed

with the Secretary for the Commission’s

review in accordance with 10 CFR

§ 2.206. As provided by the regulation,

the Decision will constitute the final

action of the Commission 25 days after

the date of issuance of the Decision

unless the Commission on its own

motion institutes a review of the

Decision within that time.

Dated at Rockville, Maryland, this 25th day

of June 1996.

For the Nuclear Regulatory Commission.

William T. Russell,

Director, Office of Nuclear Reactor

Regulation.

I. Introduction

On May 27, 1994, Florida Energy

Consultants, Inc. (FEC), by and through

Thomas J. Saporito, Jr. (Petitioners),

submitted a Petition pursuant to 10 CFR

§ 2.206 to the U.S. Nuclear Regulatory

Commission (NRC). The Petition

requested that the NRC (1) institute a

show-cause proceeding pursuant to 10

CFR § 2.202 to modify, suspend, or

revoke the operating licenses of Arizona

Public Service Company (licensee or

APS) for Palo Verde Nuclear Generating

Station (PVNGS or Palo Verde); (2) issue

a notice of violation against the licensee

for continuing to employ The Atlantic

Group (TAG) as a labor contractor at

Palo Verde; (3) investigate alleged

material false statements made by

William F. Conway, Executive Vice

President at Palo Verde, during his

testimony at a Department of Labor

hearing (ERA Case No. 92–ERA–030)

and, in the interim, require that he be

relieved of any authority over

operations at Palo Verde; (4) investigate

the licensee’s statements in a letter

dated August 10, 1993, from Mr.

Conway to the former NRC regional

administrator, Mr. Bobby H.

Faulkenberry, that Mr. Saporito gave

materially false, inaccurate, and

incomplete information on his

application for unescorted access to

Palo Verde and that, as a result, Mr.

Saporito lacks trustworthiness and

reliability for access to Palo Verde; (5)

investigate the circumstances

surrounding the February 1994

termination of licensee employee Joseph

Straub, a former radiation protection

technician at Palo Verde, to determine

if his employment was illegally

terminated by the licensee because he

engaged in ‘‘protected activity’’ during

the course of his employment; (6)

require the licensee to respond to a

‘‘chilling effect’’ letter regarding the

circumstances surrounding Mr. Straub’s

termination from Palo Verde and specify

whether any measures were taken to

ensure that his termination did not have

a chilling effect at Palo Verde; and (7)

initiate appropriate actions to require

the licensee to immediately conduct

eddy current testing (ECT) on all steam

generators (SGs) at Palo Verde because

the SG tubes were recently found to be

subject to cracking.

As the bases for these requests, the

Petitioners allege that (1) a show-cause

proceeding is necessary (a) because the

public health and safety concerns

alleged are significant and (b) to permit

public participation to provide NRC

with new and relevant information; (2)

past practices of TAG demonstrate that

employees of TAG were retaliated

against for having raised safety concerns

while employed at Palo Verde; (3)

citations to testimony from transcripts

and newspaper articles (appended as

exhibits to the Petition) demonstrate

that Mr. Conway’s testimony is not

credible; (4) statements in the letter of

August 10, 1993, are inaccurate and

materially false and characterize Mr.

Saporito as an individual lacking

trustworthiness and reliability for access

to Palo Verde, and that such negative

characterizations have caused the

nuclear industry to blacklist him from

continued employment, all in retaliation

for his raising safety concerns about

operations at Palo Verde; thus, the

Petitioners ask that these statements be

rescinded; (5) an investigation into the

termination of Mr. Straub is warranted

in view of the fact that the licensee has

engaged in similar illegal conduct in the

past for which the NRC has required the

licensee to pay fines; (6) Mr. Straub is

entitled to reinstatement with pay and

benefits pending the NRC’s

investigation into his termination to

offset the chilling effect his termination

had on the Palo Verde workforce; and

(7) in addition to cooling tower

problems, the stress-corrosion and

cracking in the SGs is a recurring

problem of which the licensee is aware

and has failed to properly correct, so

that the NRC should be concerned about

proper maintenance of safety systems

and equipment at Palo Verde.

On July 8, 1994, the Petitioners filed

a supplemental Petition (Petition

supplement) raising six additional

issues. The Petitioners requested that

the NRC (1) institute a show-cause

proceeding pursuant to 10 CFR § 2.202

for the modification, suspension, or

revocation of the Palo Verde operating

licenses for Units 1, 2, and 3; (2) modify

the Palo Verde operating licenses to

require operation at 86-percent power or

less; (3) require the licensee to submit

a No Significant Hazards safety

analysis 1 to justify operation of those

units above 86-percent power; (4) take

immediate action (e.g., by confirmatory

order) to require the licensee to reduce

operation to 86-percent power or less;

(5) require the licensee to analyze a

design-basis steam generator tube

rupture (SGTR) event to show that the

offsite radiological consequences do not

exceed a small fraction of the limits of

10 CFR Part 100; and (6) require the

licensee to demonstrate that its

emergency operating procedures (EOPs)

for steam generator (SG) tube rupture

events are adequate and the plant

operators are sufficiently trained in

EOPs.

As bases for these requests, the

Petitioners allege that (1) the licensee

experienced an SGTR in the free-span

area on Unit 2 on March 14, 1993; (2)

during a January 1994 inspection on
34456 Federal Register / Vol. 61, No. 128 / Tuesday, July 2, 1996 / Notices

2An AIT is an NRC inspection team composed of

experts from the responsible NRC Regional Office

augmented by personnel from NRC Headquarters

and others Regions with special technical

qualifications. The purpose of an AIT is to

determine the causes, conditions, and

circumstances relevant to an event and to

communicate its findings, safety concerns, and

recommendations to NRC management.

3The lowest level of emergency classification as

delineated in 10 C.F.R Part 50, Appendix E.

4The second lowest level of emergency

classification as delineated in 10 C.F.R. Part 50,

Appendix E.

5PVNGS Procedures providing operators’ actions

for responding to design basis events.

6The operational mode defined as cold shutdown

in plant technical specifications.

7See EA 93–119 (issued July 1, 1993) and EA 93–

039 (issued April 27, 1993). At the time, violations

were categorized in terms of five levels of severity.

Severity Level I and II violations were of very

significant regulatory concern. Severity III

violations were cause for significant regulatory

concern. Severity Level IV violations were less

serious but were of more than minor concern.

Severity Level V were of minor safety or

environmental concern. General Statement of Policy

and Procedure for NRC Enforcement Actions, 10

CFR Part 2, Appendix C, Section IV. Effective June

30, 1995, the NRC’s Enforcement Policy, as

published in the Federal Register (60 FR 34381), is

set forth in NUREG–1600.

8 This CAL set forth commitments made by the

licensee to the NRC staff on June 2, 1993, regarding

the SGTR event on Unit 2. In the CAL, the staff

confirmed the licensee’s commitment (1) to notify

the NRC prior to completion of ECT on the Unit 2

SGs; (2) to include the proposed operating interval

to the next SG tube inspection in its safety analysis;

and (3) not to restart Unit 2 until the NRC concurs

with the restart of the facility.

9 In this CAL, the staff confirmed the licensee’s

commitment to (1) shut down Unit 3 for ECT

inspection of both SGs; (2) continue the review of

Unit 3 ECT data to identify indications that were

not identified in refueling outage 3R3 by bobbin

coil ECT and to provide a written summary of the

review; (3) continue to implement the Unit 1 SG

inspection plan (SGIP); (4) implement changes to

emergency operating procedures (EOPs), operator

training, and leakage monitoring; and (5) continue

to operate Unit 3 to take advantage of some of the

preventive measures that can be taken to reduce

Unit 2, 85 axial indications were

identified, the longest indication being

7.5 inches; (3) as of May 1994, 28 axial

indications were found at Unit 2 and 9

axial indications were found at Unit 1

(more extensive testing will confirm the

existence of circumferential crack

indications in the expansion and

transition areas); (4) in May 1994, SG

sludge from Units 1 and 2 indicated a

lead content of 4,000 to 6,000 ppm,

which is unusually high, accelerates the

crevice corrosion process, and is

believed to be caused by a feedwater

source deficiency; (5) in eight instances,

the licensee failed to properly

implement operational procedures

during the SGTR event on March 14,

1993; (6) the licensee’s failure to comply

with approved procedures in the abovementioned event is indicative of a

problem plant that warrants further NRC

action; (7) in four instances, the NRC is

aware of additional licensee weaknesses

regarding the SGTR event; (8) the

licensee cannot ensure that the radiation

dose limits are satisfied for applicable

postulated accidents; (9) the licensee is

not maintaining an adequate level of

public protection in that the offsite dose

limits will be exceeded during an SGTR;

(10) the licensee cannot demonstrate

that a Palo Verde unit can safely be shut

down and depressurized to stop SG tube

leakage before a loss of reactor water

storage tank inventory; (11) SG tubes are

an integral part of the reactor coolant

boundary and tube failures could lead to

containment bypass and the escape of

radioactive fission products directly

into the environment and, therefore,

must be carefully considered by NRC

and the licensee; (12) the licensee

cannot demonstrate compliance with 10

CFR Part 50, Appendix A, which

establishes the fundamental

requirements for SG tube integrity; (13)

the licensee has failed to comply with

NRC recommendations under NUREG–

0800 to show that in the case of an

SGTR event, ‘‘the offsite conditions and

single failure do not exceed a small

fraction of the limits of 10 CFR Part

100’’; and (14) the licensee has posed an

unacceptable risk to public health and

safety by raising power on all three Palo

Verde units above 86 percent,

considering the severe degradation of

the SG tubes.

In a letter dated July 26, 1994, I

acknowledged receipt of the Petition of

May 27, 1994, and the Petition

supplement of July 8, 1994, and denied

the Petitioners’ two requests for

immediate action. The Petitioners

requested the initiation of actions to

require the licensee to immediately

conduct ECT on all SGs at Palo Verde

(Request 7 of the May 27, 1994, Petition)

and immediate action to cause the

licensee to reduce operation to 86-

percent power or less (Request 4 of the

July 8, 1994, Petition supplement).

Although these two requests for

immediate action were denied, the

concerns raised by the Petitioners

regarding their requests for ECT and

reduced power operation are addressed

in this Decision.

The staff informed the Petitioners that

the remaining requests were being

evaluated under 10 CFR § 2.206 of the

Commission’s regulations and that a

response would be forthcoming. This

Decision addresses the Petitioners’

concerns about ECT (Request 7 of the

May 27, 1994, Petition), steam generator

tube integrity, and emergency operating

procedures for SGTR events and the

remaining requests (Requests 1, 2, 3, 5,

and 6) of the July 8, 1994, supplement.

The staff has completed its review of the

remaining issues in your supplemental

Petition. A Director’s Decision (DD–96–

04) regarding Requests 1 through 6 in

the Petition of May 27, 1994, was issued

under separate cover letter on June 3,

1996. A discussion of the Director’s

Decision follows.

II. Background

The Petitioners’ concerns addressed

in this Decision appear to be based

largely on the March 1993 SGTR event

and the NRC staff findings concerning

that event set forth in the NRC

Augmented Inspection Team (AIT) 2

report. Palo Verde Unit 2 experienced

an SGTR event in SG No. 2 on March

14, 1993. At the time, the unit was at

about 98-percent power. The plant

operators manually tripped the reactor,

declared an Unusual Event,3 which was

subsequently upgraded to an Alert,4 and

entered the PVNGS Functional Recovery

Procedure 5 to mitigate the event. The

plant was cooled down and

depressurized, and the event was

terminated when Mode 5 6 was achieved

on March 15, 1993.

During the period March 17–25, 1993,

an NRC AIT conducted an inspection at

PVNGS Unit 2. Overall, the AIT

concluded that the response to the

SGTR succeeded in bringing the unit

safely to a cold-shutdown condition and

limiting the release of radioactivity so

that there was no threat to public health

and safety. However, the AIT identified

weaknesses in the licensee’s

implementation of emergency plan

actions, including event classification,

activation of the emergency response

facilities, and prompt assignment of

tasks to onsite personnel. Weaknesses

were also found in the procedures,

equipment, and training associated with

responding to an SGTR event. The AIT

inspection was documented in NRC

Inspection Report No. 50–529/93–14,

issued on April 16, 1993.

Enforcement action resulted from the

AIT inspection in several areas (e.g.,

emergency preparedness, chemistry and

radiation monitoring, and emergency

operating procedures). All violations

were issued as Severity Level IV.7

The NRC issued a confirmatory action

letter 8 (CAL) to the licensee on June 4,

1993, for Unit 2. The NRC issued a

safety evaluation by letter dated August

19, 1993, concluding that Unit 2 could

safely resume operation for 6 months,

the interval between steam generator

tube inspections. This safety evaluation

closed the CAL.

The NRC issued a second CAL 9 on

October 4, 1993, for Unit 3 (amended on
Federal Register / Vol. 61, No. 128 / Tuesday, July 2, 1996 / Notices 34457

outside-diameter stress corrosion cracking (ODSCC)

rates.

10 The Petitioner also mentioned cooling tower

problems in this basis, stating that ‘‘the NRC should

be concerned about proper maintenance of safety

systems and equipment there.’’ The cooling towers

at Palo Verde are not safety-related systems. If the

cooling towers of a unit were incapacitated, the unit

might operate less efficiently, but that would be an

economic penalty, rather than a safety problem. The

Petitioners did not provide any specific examples

of problems with the cooling towers, though the

staff is aware of the general maintenance problems

the licensee has had with the cooling towers. This

issue was the subject of a previous Director’s

Decision, Arizona Public Service Company, (Palo

Verde Nuclear Generating Station, Units 1, 2, and

3, DD–92–1, 35 NRC 133, 137 (1992), which found

no substantial nuclear safety concern with the

condition of the cooling towers.

11Unit 1 was not directly addressed in the SEs

because no free span axial indications were

identified on Unit 1 at the time.

12The Palo Verde operating cycle is normally 16–

18 months.

13The specific request for immediate action to

make the licensee reduce operation to 86-percent

power or less (Request 4) was denied by letter of

July 26, 1994. With regard to the request (Request

3) to require the licensee to submit a No Significant

Hazards safety analysis to justify operation of the

units above 86-percent power, the licensee is not

required by the NRC regulations to submit a no

significant hazards analysis, since a TS change was

not required to resume operation above 86-percent

power. The staff did, however, review a no

significant hazards analysis related to operation of

the Units at 100-percent power with a reduced hotleg temperature. These TS changes were submitted

by the licensee on February 18, 1994, for Units 1

and 3; and on July 1, 1994, for Unit 2. The NRC

staff review of these TS changes and support for

operation at a power level of 100 percent is

discussed at page 17, infra.

November 8 and 23, 1993), confirming

the commitments made by the licensee

in its September 29, 1993, letter. By

letter dated December 3, 1993, the

licensee reported that it had completed

the actions discussed in the CAL.

Satisfied that the licensee had

completed the conditions of the CAL,

the staff closed the CAL by letter dated

April 1, 1994.

The licensee voluntarily reduced

power to approximately 86-percent

power in the fall of 1993 to minimize

steam generator degradation. The

licensee evaluated and implemented

several improvements to the operation

of its steam generators, one of which

was a reduction in the reactor coolant

system hot-leg temperature. The units

were all returned to 100-percent power

by the fall of 1994.

Following a midcycle outage on Unit

2 and midcycle and refueling outages on

Unit 3, the NRC issued a safety

evaluation on June 22, 1994, which

concluded that both Unit 2 and 3 could

safely operate for 6 months between

steam generator tube inspections. Since

that time, there have been additional

midcycle outages on Units 2 and 3 and

a refueling outage on all three units.

Eddy current inspection results and

outage planning for the Units currently

support the following operating

intervals between inspections: Unit 1,

16 months; Unit 2, 12 months; and Unit

3, 11 months.

III. Discussion

A. Eddy Current Testing on All Steam

Generators at Palo Verde

Item 7 of the Petitioners’ letter of May

27, 1994, requested the NRC to require

the licensee to conduct immediate ECT

on all SGs at Palo Verde to ascertain the

integrity and life expectancy of the SG

tubes. Although, as indicated above, this

request for immediate action has been

denied, the Petitioners’ concerns

regarding ECT are addressed below.

The Petitioners assert as a basis

(Petition Basis 7) for their request

concerning ECT that the licensee’s SGs

have recently developed cracks in the

free-span portion of their internal

structure, that tube stress corrosion and

cracking is a recurring problem in SGs,

and that there is a risk the emergency

cooling system will be unable to prevent

the melting of the fuel because of tube

ruptures.10

The licensee has completed at least

two eddy current inspections on each of

the Palo Verde units since the SGTR

event in March 1993. The staff issued

safety evaluations (SEs) that addressed

Unit 2 and 3 operating intervals by

letters dated August 19, 1993, and June

22, 1994.11 These SEs were based on the

results of the licensee’s eddy current

inspections of Unit 1 in October 1993,

of Unit 2 in May 1993 and January 1994,

and of Unit 3 in December 1993 and

May 1994. In summary, the staff

concluded that Units 2 and 3 could be

safely operated for up to 6 months

between SG eddy current inspections.

The licensee conducted five of these

‘‘minicycles’’ 12 (three on Unit 2 and two

on Unit 3), thereby obtaining extensive

SG eddy current data, which it used to

validate models used for analysis. In

May 1995, the licensee submitted a

report supporting a cycle length of up to

11 months on Unit 3. Unit 1 completed

a 16-month operating cycle in June

1995. After meeting with the licensee,

the staff approved a Unit 3 cycle length

of 11 months in a meeting summary

dated August 22, 1995. During a

September 20, 1995, meeting with the

staff, the licensee presented its

submittal and arguments to support a

12-month cycle for Unit 2. The staff

incorporated data from the most recent

Unit 3 steam generator inspection in its

evaluation of the licensee’s conclusion

regarding a 12-month operating cycle on

Unit 2. The staff approved the 12-month

operating cycle by letter dated March 5,

1996.

In summary, the licensee performed

the necessary eddy current inspections,

and the staff extensively reviewed and

approved Palo Verde SG eddy current

inspection results and continues to

review additional information regarding

the integrity of the SG tubes. On the

basis of its review of ECT, the staff has

concluded that the Petitioners’ concerns

regarding the need for ECT have been

satisfactorily addressed by the licensee

and that no further action by the NRC

staff is warranted.

B. Operation Above 86–Percent Power

Requests 1, 2, 3, and 4 of the Petition

supplement, in essence, request actions

requiring the Palo Verde licenses to be

modified to require operation at 86-

percent power or less.13

As bases for these requests, the

Petitioners assert that on March 14,

1993, Palo Verde Unit 2 had an SGTR

in the free-span section between the

tube supports and that in January 1994,

an inspection of Palo Verde’s Unit 2 SGs

found 85 axial indications (longest

indication, 7.5 inches) (Petition

supplement, Basis 2); and that as of May

1994, 28 axial indications were found at

Unit 2 and 9 axial indications found at

Unit 1. The Petitioners believe that more

extensive testing will confirm the

existence of circumferential crack

indications in the expansion-transition

area (Petition supplement, Basis 3). The

Petitioners also assert that in May 1994,

Units 1 and 2 SG sludge indicated a lead

content of 4,000–6,000 ppm, which

would accelerate the crevice corrosion

cracking process (Petition supplement,

Basis 4). The Petitioners also stated that

the operation of Palo Verde units at

above 86-percent power is unacceptable

due to severe degradation of the SG

tubes (Petition supplement, Basis 14).

Axial and Circumferential Steam

Generator Tube Indications

With regard to the Petitioners’

concern about identifiable axial

indications (Petition supplement Basis

2), it is correct that 85 axial indications

in the free-span area (longest indication,

7.5 inches) were discovered on SG tubes

at Palo Verde Unit 2 during the January

1994 inspection. However, this number

was apparently based on preliminary

information from the licensee’s eddy

current inspection during the January

1994 eddy current inspection. The

licensee’s report of March 8, 1994,

stated that actually 330 free-span axial

indications were discovered during the

Unit 2 first midcycle outage: 22 in SG

1 of Unit 2 (SG 21) and 308 in SG 2 of
34458 Federal Register / Vol. 61, No. 128 / Tuesday, July 2, 1996 / Notices

14 Voltage is electrical force or potential

difference. Voltage measurements can be used to

estimate the severity of an indication.

15 In situ pressure tests were conducted to

determine whether the tubes could withstand the

pressure loading specified in NRC Regulatory Guide

1.121 (i.e., whether the SG tubes have adequate

structural integrity).

16The Staff’s reviews are documented in SEs

dated August 19, 1993, and June 22, 1994, and also

in meeting summaries dated August 22, 1995,

March 22, 1994, October 19, 1994, August 22, 1995,

and September 20, 1995.

17 During the Unit 2 midcycle outage in early

1994, the SGs were chemically cleaned before

sludge lancing; therefore, the composition of the

sludge was not tested.

18Burst region refers to the section of the crack

in a pulled tube that is exposed as the result of a

burst or rupture due to an applied pressure either

during plant operation or laboratory testing.

19The NRC inspection team compared Electric

Power Research Institue (EPRI) NP–6239, ‘‘PWR

Secondary Water Chemistry Guidelines,’’ Revisions

1 through 2, and EPRI TR–101230, ‘‘Interim PWR

Secondary Water Chemistry Recommendations for

IGA/IGSCC Control,’’ with the licensee’s secondary

water chemistry control program for PVNGS.

20PVNGS performed its own inspections and also

utilized contractors, ABB-Combustion Engineering

(ABB-CE) and Babcock and Wilcox Nuclear

Technologies (BWNT), to perform metallurgical

examinations. The inspections revealed minor

quantities of lead in surface deposits and films. See

NRC Inspection Report 50–528/50–529/50–530/94–

15, dated June 23, 1994.

Unit 2 (SG 22). Although a number of

axial indications were detected by the

licensee, it is not the number of

indications that is of a safety concern

but rather the severity of the indications

(i.e., severity in terms of whether the

tube indication had adequate structural

and leakage integrity). As noted in the

Petition supplement, the longest

indication was 7.5 inches long. The

safety significance of this indication, as

with any eddy current indication,

depends not only on the length of the

indication but also on the depth of the

indication. To assess the safety

significance and/or severity of an

indication, licensees size the indications

in terms of length, depth, and/or

voltage.14 However, eddy current testing

methods have not been qualified for

determining the depth of stress

corrosion cracks. Where qualified eddy

current methods do not exist, licensees

may pursue alternative methods such as

in situ pressure testing 15 to further

confirm or assess the condition of the

tube (i.e., to confirm that the tube

indication could withstand the required

pressure loadings; thereby

demonstrating that the tube had

adequate structural integrity). The

licensee did select nine tubes for in situ

pressure testing during the outage. The

7.5 inch long indication did not meet

the licensee’s screening criteria for

selecting the more severe indications.

The screening criteria, discussed in the

NRC staff’s SE of June 22, 1994,

considered the length, depth, and/or

voltage of the indication. All nine tubes

satisfactorily passed the in situ pressure

test thereby providing reasonable

assurance that the tube indications had

adequate structural integrity.

Furthermore, all tubes with axial free

span indications were plugged before

Unit 2 was returned to operation.

The Petitioners also assert as of May

1994, 28 axial indications were found

on Unit 2 and 9 axial indications found

at Unit 1 and that more extensive testing

would confirm the existence of

circumferential crack indications in the

expansion transition areas (Petition

supplement, Basis 3). These numbers

are incorrect. Neither Unit 1 nor Unit 2

was in an outage conducting eddy

current examinations in May 1994. Unit

1 had no axial indications identified as

of this date. The Unit 2 data is described

above. Unit 3 was in an outage at this

time and identified a total of 20 axial

indications. Regarding the performance

of more extensive testing to confirm the

existence of circumferential crack

indications at the expansion transition

area, the licensee has performed

inspections in this region. In general,

the licensee’s steam generator tube

inspection program consists of an initial

inspection sample which is expanded, if

necessary, based on the initial

inspection sample results. The licensee

has been examining the expansion

transition locations with a motorized

rotating pancake coil (MRPC) probe

since, at least, 1993. These examinations

permit the licensee to detect

circumferential crack indications. In its

SEs and meeting summaries, the NRC

staff has reviewed the licensee’s results

from its MRPC inspections and found

them acceptable.16 To date, Palo Verde

Units 2 and 3 have each exhibited a

small number of circumferential crack

indications per Unit. Unit 1 has

exhibited the most extensive

circumferential cracking both in terms

of number of indications and the

severity of the indications when

compared to Units 2 and 3. Nonetheless,

the staff concluded in a meeting

summary dated October 19, 1994, that

operating Unit 1 to the end of the

operating cycle (April 1995) did not

pose an undue risk to public health and

safety in view of (1) the absence of

detectable axial free-span cracks during

the previous refueling outage

inspection; (2) the improved secondary

water chemistry performance at Palo

Verde; (3) the reduced hot-leg

temperature, which is expected to

reduce crack growth rates; and (4) the

implementation of enhanced MRPC

inspection techniques at the expansion

transition locations. The licensee will

continue to perform extensive SG

inspections at the end of each operating

cycle to ensure continued safe operation

of SGs.

Lead Content in Steam Generator Tube

Sludge

The Petitioners assert without

providing any supporting basis that the

SG sludge of Units 1 and 2 has a lead

content of 4,000–6,000 ppm (Petition

supplement, Basis 4). The licensee

performed sludge analyses during two

consecutive Unit 1 outages. The data,

which were reported in a letter from the

licensee dated November 2, 1993,

indicate a lead content of 78 ppm (from

Unit 1, Refueling 3) and 98 ppm (Unit

1, Refueling 4).17 Sludge samples were

obtained from both Unit 2 SGs after the

March 1993 SGTR event. The data were

documented in the licensee’s report,

‘‘Equipment Root Cause of Failure.’’

Both the licensee and outside

contractors analyzed the samples; all

analyses indicated a lead content of 100

ppm or less.

The NRC staff conducted two Palo

Verde chemistry inspections (Inspection

Reports 94–15 and 94–27 on Units 50–

528/50–529/50–530). The staff reviewed

films and sludge for their lead content,

and the data were consistent with the

licensee’s reports. Inspection Report 50–

528/50–529/50–530/94–15 specifically

referred to the inspector’s determination

to note ‘‘whether lead was detected,

because of recent work which indicated

it may have a deleterious effect.’’ In

referring to examinations of the burst

region 18 of pulled tubes, the report

stated that insignificant levels of lead

were found in the sludge and in the

films examined.

Inspection Report 50–528/50–529/50–

530/94–15 also reviewed the licensee’s

secondary water chemistry control

program.19 The NRC inspection team

found that the program requirements

had fully conformed to the EPRI

guidelines throughout Palo Verde’s

operating history with respect to

chemical parameters, analytical

frequency, limits for critical parameters,

and required actions when critical

parameters were exceeded. In summary,

the Petitioners’ assertions regarding lead

content have not been substantiated and

do not agree with available data. The

licensee has verified 20 that lead content

in both Units 1 and 2 SGs is 100 ppm

or less, not 4,000–6,000 ppm as asserted

by the Petitioners. Additionally, NRC

Inspection Reports 94–15 and 94–27 on

Units 50–528/50–529/50–530 have not
Federal Register / Vol. 61, No. 128 / Tuesday, July 2, 1996 / Notices 34459

21Noticed in the Federal Register on June 22,

1994 (59 Fed. Reg. 32240).

22Noticed in the Federal Register on August 31,

1994 (59 Fed. Reg. 45038).

23Updated Final Safety Analysis Report (UFSAR)

Section 15.6.3.1.3.2 describes the radiological

consequences of an SGTR, and the results are

shown in UFSAR Table 15.6.3–5. The staff initially

reviewed PVNGS’s UFSAR in November 1981.

24 In 10 CFR Part 100, acceptance criteria are

specified for the dose analyzed during initial plant

licensing at the exclusion area boundary (EAB) and

low population zone (LPZ) for design-basis

accidents. The dose in 2 hours at the EAB is not

to exceed 25 rem to the whole body or 300 rem to

the thyroid. The dose in 30 days at the boundary

of the LPZ is not to exceed 25 rem to the whole

body or 300 rem to the thyroid. The staff reviewed

the licensee’s Unit 2 steam generator tube rupture

analysis, submitted by letter dated July 18, 1993,

and concluded that the methods used by the

licensee were acceptable. See the NRC staff’s safety

evaluation dated August 19, 1993.

The Petitioners assert that the licensee has failed

to comply with NUREG–0800 requirements

regarding consequences of a design basis SGTR

event. However, NUREG–0800 does not set forth

requirements; rather it sets forth acceptable

approaches to satisfying NRC requirements.

25The Petitioners reference portions of General

Design Criteria (GDC) 14, 15, 30, and 31 of

Appendix A to 10 CFR Part 50.

26The Petitioners assert (Petition supplement,

Basis 5) that the licensee (a) failed to classify the

event in accordance with the EOPs, (b) failed to

actuate the Emergency Operations Facility for the

1-hour time, (c) failed to activate the Emergency

Response Data System, (d) violated 10 CFR § 50.72

requirements, activation of the Emergency Response

Data System, (e) failed to take prompt corrective

actions to repair the condenser vacuum pump

exhaust radiation monitor, (f) failed to obtain

required approvals for alarm setpoint change on

waste gas area combined ventilation exhaust

monitor, (g) failed to fully implement an alarm

response procedure and, (h) failed to check the

owner-controlled area.

27The Petitioners assert (Petition supplement,

Basis 7) that the licensee’s (a) alert and alarm

setpoints for condenser vacuum pump exhaust and

main steam line radiation monitor limits appear to

be based on offsite dose limits rather on an SGTR

Continued

revealed any information about elevated

lead content.

Steam Generator Tube Degradation and

Operation at a Reduced Power Level

The Petitioners also assert that the

operation of Palo Verde units at above

86-percent power is unacceptable due to

severe degradation of SG tubes (Petition

supplement, Basis 14). In December

1993, the licensee volunteered to reduce

power in all three units to

approximately 86 percent as an interim

measure to curtail steam generator

degradation. The primary purpose of

this administrative power limit was to

operate with a lower reactor coolant

system hot-leg temperature in order to

reduce tube degradation. This specific

power level had been selected because

it provided for a Thot that approximated

the value that would be implemented if

the licensee’s proposed TS changes for

operating at 100% power with a

reduced Thot were approved by the NRC.

Additionally, the licensee’s thermalhydraulic analysis indicated that, at this

reduced power level, the potential for

freespan tube degradation from

corrosion is reduced. The licensee took

this action voluntarily to minimize

further degradation of the SGs until

corrective, mitigative, and preventive

actions could be implemented to reduce

steam generator tube degradation.

On June 7, 1994, the NRC issued a TS

change for Units 1 and 3 that permitted

the licensee to operate at full power

with a lower Thot temperature.21 The

Unit 2 TS change was reviewed

separately because the licensee was

continuing to perform analyses arising

from the SG tube plugging in Unit 2.

The staff issued this TS change on

August 12, 1994.22 These TS changes

permitted operation at a power level of

100 percent as did the staff’s post-March

1993 SGTR SEs dated August 19, 1993,

and June 22, 1994, regarding the length

of operating cycles of the Palo Verde

units. Furthermore, as stated above, the

staff did not impose any power

restrictions or limits on the licensee.

In summary, the Petitioners’ concerns

regarding operation of the Palo Verde

units above 86-percent power (including

bases relating to the March 1993 SGTR

event, identification of axial and

circumferential steam generator tube

indications, alleged elevated lead

contents in steam generator sludge) have

been satisfactorily addressed, and do

not warrant any further action by the

NRC staff.

C. Need To Reanalyze the Design-Basis

SGTR Event

Request 5 (of the Petition supplement)

is that the NRC require the licensee to

analyze a design-basis SGTR event to

show that the offsite radiological

consequences do not exceed a small

fraction of the limits of 10 CFR Part 100.

The staff requires an analysis such as

this to be completed for all pressurizedwater reactors (PWRs) and documented

in a final safety analysis report (FSAR)

before plant operation. The licensee

complied with this requirement.23

The Petitioners assert in the basis

(Petition supplement, Bases 8, 9, 10, 11

and 13) that the licensee cannot ensure

the dose limits are satisfied for

applicable postulated SGTR events; the

offsite dose limits would be exceeded

during an SGTR event and adequate

protection to the public would not be

maintained; the licensee cannot

demonstrate that the plant can be safely

shut down and depressurized to stop SG

tube leakage before reactor water storage

tank inventory is lost; the NRC and the

licensee must carefully consider SGTR;

and ‘‘the licensee has failed to comply

with NRC requirements under NUREG–

0800 insofar as the licensee is required

to analyze the consequences of a design

basis SGTR event to show that the

offsite conditions and single failure do

not exceed a small fraction of limits of

10 CFR Part 100.’’

The AIT report documents findings

regarding the Unit 2 SGTR event of

March 1993. The report stated that the

plant was safely brought to cold

shutdown and no radioactivity was

released off site. Additionally, the staff’s

SE, dated August 19, 1993, assessed a

single SGTR event and single and

multiple tube ruptures induced by a

major secondary-side rapid

depressurization and concluded that the

radiological consequences were within

applicable limits.24 Finally, in a

memorandum dated January 26, 1996,

the staff performed a confirmatory

review of the licensee’s updated SGTR

event analysis, submitted with Revision

6 to the FSAR (March 10, 1994), and

concluded that the results are

acceptable. The Petitioners also assert in

the basis (Petition supplement, Basis 12)

that the licensee cannot demonstrate

compliance with certain criteria of

Appendix A to 10 CFR Part 50,25 which

establishes the fundamental

requirements for steam generator tube

integrity. However, the Petitioners have

failed to provide any details or support

for this assertion.

In summary, on the basis of the NRC

staff’s review of the licensee’s designbasis SGTR event and more recent

confirmatory review, the staff has

concluded that the Petitioners have not

presented a basis for further NRC action.

D. Adequacy of Training and

Procedures for an SGTR Event

Regarding Request 6 of the Petition

supplement, that the NRC require the

licensee to demonstrate that its

emergency operating procedures (EOPs)

for SGTR events are adequate and the

plant operators are sufficiently trained

in EOPs, the staff has already taken

sufficient action. The Petitioners allege

(Petition supplement, Bases 5, 6, and 7,

respectively) that the licensee failed to

properly implement operational

procedures regarding the SGTR event of

March 14, 1993, citing eight instances in

Basis 5 26; that the licensee’s failure to

comply with approved procedures in

this event is indicative of a problem

plant that warrants further NRC

attention (Basis 6); and that the NRC is

aware of additional licensee weaknesses

regarding the SGTR event, citing four

instances in Basis 7.27 These bases
34460 Federal Register / Vol. 61, No. 128 / Tuesday, July 2, 1996 / Notices

event, (b) simulator alarms occur within 2–3

minutes of an SGTR event, contrary to control room

indications, (c) plant staff failed to fully respond to

assembly notification, (d) plant staff failed to

perform a formal evaluation of the safety

significance of an abnormal crack growth in the

Unit 2 SG.

28The licensee addressed the issues raised in the

AIT report by implementing the necessary

procedural changes and providing training. For

example, with regard to the AIT finding

(summarized by the Petitioners) regarding

differences between alarm response on the

simulator and in the control room, the staff’s safety

evaluation of August 19, 1993, stated that ‘‘the

simulator has been modified to more realistically

model the plant, particularly the response of the

radiation monitoring system to an SGTR.’’

29A letter from the NRC to Combustion

Engineering dated August 2, 1988, stated that,

‘‘pending NRC final review and approval, CE

facilities may base their plant-specific emergency

operating procedures on Revision 3 of CEN–152.

Should future NRC review reveal modifications to

Revision 3 to be necessary, CE facilities would be

expected to update their procedures to reflect the

identified changes. Schedules for such changes

should be based on perceived safety significance of

the changes.’’ The objective of the CEN–152 report

is to describe the CEOG emergency procedure

guidelines system. The report contains the

methodology used to develop and validate the

licensee’s emergency procedure guidelines and

information on the implementation of guidelines.

largely concern areas the staff reviewed

after the SGTR event on March 14, 1993.

Specifically, the Petitioners repeated

several of the procedural and operator

weaknesses that were described and

evaluated in the staff’s AIT report

(Inspection Report 50–529/93–14, dated

April 16, 1993).28 Specifically, the AIT

report stated that the use of a diagnostic

logic tree caused the operators to

misdiagnose the SGTR event twice and

subsequently enter a Functional

Recovery Procedure, contributing

substantially to the delay in isolating

the faulted steam generator. The staff

concluded in its safety evaluation of

August 19, 1993, that the licensee’s

modifications to the EOPs and the

subsequent operator training provide

sufficient enhancement for both

diagnosis and mitigation of various

SGTR scenarios.

Additionally, the licensee recently

revised its EOPs to make them

consistent with Combustion Engineering

Owners Group (CEOG) guidance (CEN

0152, Rev. 3 29). NRC Inspection Report

50–528/50–529/50–530/95–12, dated

July 27, 1995, documents the staff’s

observations on the ‘‘high intensity

team’’ training conducted for each crew

in preparation for implementing the

EOPs. In the inspection report, the staff

stated that the EOPs enhanced crew

performance and allowed for greater

flexibility in responding to events. As

an example, during the simulator-based

SGTR scenario, the crew was able to

isolate the faulted SG within 14 minutes

of the start of the event. In contrast,

during the March 1993 Unit 2 SGTR

event, operators took about 3 hours to

isolate the faulted SG, partly because of

restrictions in the EOPs in use at the

time. The staff will further evaluate the

effectiveness of EOPs during future

licensed operator examinations.

On the basis of its review of the

Petitioners’ request that the licensee

demonstrate that its EOPs for SGTR

events are adequate and that plant

operators are sufficiently trained in

EOPs, the staff has concluded that the

Petitioners have not presented a basis

for further NRC action.

III. Conclusion

The institution of proceedings in

response to a request pursuant to

Section 2.206 is appropriate only when

substantial health or safety issues have

been raised. See Consolidated Edison

Co. of New York (Indian Point, Units 1,

2, and 3), CLI–75–8, 2 NRC 173, 176

(1975), and Washington Public Power

Supply System (WPPSS Nuclear Project

No. 2), DD–84–7, 19 NRC 899, 923

(1984). This standard has been applied

to the concerns raised by the Petitioners

to determine whether the actions

requested by the Petitioners are

warranted. With regard to the specific

requests made by the Petitioners

discussed herein, the NRC staff finds no

basis for taking additional actions

beyond those described above.

Accordingly, the Petitioners’ requests

for additional actions pursuant to

Section 2.206, specifically Requests 1, 2,

3, 5, and 6 submitted in the Petitioners’

supplement dated July 8, 1994, are

denied. Accordingly, no action pursuant

to Section 2.206 is being taken in this

matter.

A copy of this Decision will be filed

with the Secretary of the Commission

for Commission review in accordance

with 10 CFR § 2.206(c) of the

Commission’s regulations. As provided

by this regulation, the Decision will

constitute the final action of the

Commission 25 days after issuance,

unless the Commission, on its own

motion, institutes a review of the

Decision within that time.

Dated at Rockville, Maryland, this 25th day

of June 1996.

For the Nuclear Regulatory Commission.

William T. Russell,

Director, Office of Nuclear Reactor

Regulation.

[FR Doc. 96–16878 Filed 7–1–96; 8:45 am]

BILLING CODE 7590–01–P

POSTAL SERVICE

Specifications for Postal Security

Devices and Indicia (Postmarks)

AGENCY: Postal Service.

ACTION: Notice of proposed

specifications with request for

comments.

SUMMARY: Historically, postage meters

have been mechanical and

electromechanical devices that (1)

maintain through mechanical or

electronic ‘‘registers’’ (postal security

devices) an account of all postage

printed and the remaining balance of

prepaid postage, and (2) print postage

postmarks (indicia) that are accepted by

the Postal Service as evidence of the

prepayment of postage. Two proposed

specifications have been developed on

these subjects, and are entitled

‘‘Information Based Indicia Program

(IBIP) PSD Specification’’ and

‘‘Information Based Indicia Program

(IBIP) Indicia Specification.’’ The U.S.

Postal Service is seeking comments on

these specifications.

The Postal Service also seeks

comments on intellectual property

issues raised by the specifications if

adopted in present form. If an

intellectual property issue includes

patents or patent applications covering

any implementations of the

specifications, the comment should

include a listing of such patents and

applications and the license terms

available for such patents and

applications.

DATES: Comments on the two

specifications must be received on or

before September 30, 1996. Comments

addressing intellectual property issues

must be received on or before July 15,

1996. A general meeting on this subject

is being planned for mid-July in

Washington, DC. All persons who have

expressed an interest in the proposed

specifications will be invited to attend

the meeting. This meeting will focus

solely on technical aspects of the two

specifications. Interested parties may

submit questions by July 1, 1996 which

will be considered for incorporation

into the meeting presentations.

ADDRESSES: Copies of the Indicium and

Postal Security Device Specifications

may be obtained from: Terry Goss,

United States Postal Service, 475

L’Enfant Plaza SW, Room 8430,

Washington, DC 20260–6807. Mail or

deliver written comments to: Manager,

Retail Systems and Equipment, United

States Postal Service, 475 L’Enfant Plaza

SW, Room 8430, Washington, DC

20260–6807. Copies of all written

comments may be inspected and