18152 Federal Register / Vol. 60, No. 68 / Monday, April 10, 1995 / Notices

licensee’s activities create or tend to

create a situation inconsistent with the

antitrust laws. The Commission

delegated the authority to make the

significant change determination to the

Director, Office of Nuclear Reactor

Regulation (NRR).

Based upon an analysis of the

extensive comments received in

response to the initial decision

published in the Federal Register on

October 20, 1993 (58 FR 54175),

information presented in other

regulatory proceedings involving the

proposed merger of Gulf States Utilities

Company (GSU) and Entergy

Corporation (Entergy), the staff

concludes that the changes in GSU’s

activities which have been identified by

the staff do not constitute significant

changes as envisioned by the

Commission in its Summer decision.

The conclusion of the staff analysis is as

follows:

Where appropriate, the staff considered the

testimony and information submitted to other

regulatory agencies in developing a record

necessary to satisfy its own regulatory

mandate. From the information made

available to the staff, the staff was able to

determine that the concerns raised by the

commenters are covered by and should be

resolved before the NRC by existing license

conditions. The staff does not believe that the

outstanding issues raised before the NRC are

germane to a licensing proceeding.

Consequently, the staff is providing the

commenters the opportunity to resolve their

NRC concerns in a Section 2.206 enforcement

proceeding.

Based upon the staff analysis, it is my

finding that there have been no

‘‘significant changes’’ in the licensee’s

activities or proposed activities since

the completion of the previous antitrust

review of the River Bend Station that

would warrant the initiation of a new

antitrust review. Signed this 5th day of

April, 1995.

Any person whose interest may be

affected by this finding, may file, with

full particulars, a request for

reevaluation, not to exceed 10 pages in

length including attachments, with the

Director of the Office of Nuclear Reactor

Regulation, U.S. Nuclear Regulatory

Commission, Washington, DC 20555.

The requests must be received by the

Commission within 10 days of the

initial publication of this notice in the

Federal Register. Requests for

reevaluation of the no significant

changes determination should be

limited to new information not

previously submitted in connection

with the Director’s Reevaluation

Finding published in the Federal

Register on December 13, 1993 (58 FR

65200), such as information about facts

or events of antitrust significance that

have occurred since that date, or

information that could not reasonably

have been submitted prior to that date.

Dated at Rockville, Maryland the 5th day

of April 1995.

For the Nuclear Regulatory Commission.

William T. Russell,

Director, Office of Nuclear Reactor

Regulation.

[FR Doc. 95–8834 Filed 4–7–95; 8:45 am]

BILLING CODE 7590–01–M

[Docket No. 50–318]

Exemption

In the matter of Baltimore Gas and Electric

Comp. (Calvert Cliffs Nuclear Power Plant

Unit No. 2).

I

Baltimore Gas and Electric Company

(BG&E or the licensee) is the holder of

Facility Operating License No. DPR–69,

which authorizes operation of Calvert

Cliffs Nuclear Power Plant Unit No. 2

(the facility/CC–2), at a steady-state

reactor power level not in excess of

2700 megawatts thermal. The facility is

a pressurized water reactor located at

the licensee’s site in Calvert County,

Maryland. The license provides among

other things, that it is subject to all

rules, regulations, and Orders of the

U.S. Nuclear Regulatory Commission

(the Commission or NRC) now or

hereafter in effect.

II

Section III.D.1.(a) of appendix J to 10

CFR part 50 requires the performance of

three Type A containment integrated

leakage rate tests (ILRTs), at

approximately equal intervals during

each 10-year service period of the

primary containment. The third test of

each set shall be conducted when the

plant is shutdown for the 10-year

inservice inspection of the primary

containment.

III

By letter dated February 24, 1995,

BG&E requested temporary relief for

CC–2 from the requirement to perform

a set of three Type A tests at

approximately equal intervals during

each 10-year service period of the

primary containment. The requested

exemption would permit a one-time

interval extension of the second Type A

test by approximately 24 months (from

the 1995 refueling outage, currently

scheduled to begin in March 1995, to

the spring 1997 refueling outage) and

would permit the third Type A test to

be performed during the spring 1999

refueling outage, coincident with the

end of the current American Society of

Mechanical Engineers Boiler and

Pressure Vessel Code (ASME Code)

inservice inspection interval. This

would extend the CC–2 second 10-year

service period to 12 years.

The licensee’s request cites the

special circumstance of 10 CFR 50.12,

paragraph (a)(2)(ii), as the basis for the

exemption. The existing Type B and C

testing programs are not being modified

by this request and will continue to

effectively detect containment leakage

caused by the degradation of active

containment isolation components as

well as containment penetrations. The

licensee has analyzed the results of the

previous Type A tests performed at CC–

2. Four Type A tests have been

conducted from 1979 to date. The initial

Type A test failed; however, prompt

corrective actions were taken and the

subsequent tests were successful as

detailed in Section IV of this

Exemption. It is also noted that the

licensee, as a condition of the proposed

exemption, will perform the visual

containment inspection although it is

only required by Appendix J to be

conducted in conjunction with Type A

tests. The NRC staff considers that these

inspections, though limited in scope,

provide an important added level of

confidence in the continued integrity of

the containment boundary. Therefore,

application of the regulation in this

particular circumstance is not necessary

to achieve the underlying purpose of the

rule.

IV

Section III.D.1.(a) of appendix J to 10

CFR part 50 states that a set of three

Type A leakage rate tests shall be

performed at approximately equal

intervals during each 10-year service

period.

The licensee proposes an exemption

to this section which would provide a

one-time interval extension for the

second Type A test by approximately 24

months. This would permit the test to

be performed during the spring 1997

refueling outage, as noted above, and

would extend the second 10-year

service period to 12 years. The

Commission has determined, for the

reasons discussed below, that pursuant

to 10 CFR 50.12(a)(1) this exemption is

authorized by law, will not present an

undue risk to the public health and

safety, and is consistent with the

common defense and security. The

Commission further determines that

special circumstances, as provided in 10

CFR 50.12(a)(2)(ii), are present justifying

the exemption; namely, that application

of the regulation in the particular

circumstances is not necessary to
Federal Register / Vol. 60, No. 68 / Monday, April 10, 1995 / Notices 18153

achieve the underlying purpose of the

rule. The underlying purpose of the

requirement to perform Type A

containment leak rate tests at intervals

during the 10-year service period, is to

ensure that any potential leakage

pathways through the containment

boundary are identified within a time

span that prevents significant

degradation from continuing or

becoming unknown. The NRC staff has

reviewed the basis and supporting

information provided by the licensee in

the exemption request.

As previously noted, the initial Type

A test failed. This failure was due to

three sources: (1) The containment

recirculation sump isolation valve,

MOV–4145; (2) the temporary level

indicators on the steam generators; and

(3) the packing gland of a main steam

line inboard vent valve. The first

leakage source was identified as a

problem with the limit switch setting on

MOV–4145 that prevented full closure.

Resetting the switches and closing the

valve electrically corrected the source of

leakage. This valve is now tested

periodically to ensure the limit switch

settings allow full closure, and the value

has not demonstrated excessive leakage

in any subsequent Type A test. The

temporary level indicators, are

components which are only in place

while the plant is shutdown. Upon

identification of the leakage path, the

temporary configuration was isolated

and has not resulted in any further

leakage. The third component condition

which led to an excessive leakage rate

during this test was attributed to a

packing failure in the main steam

inboard vent valves. This condition was

corrected by backseating the vent valves

to eliminate leakage. In a subsequent

refueling outage, the vent valves were

removed and the connection was sealed

with blind flanges. Following the

licensee’s prompt identification and

corrective actions, three additional Type

A tests have been successful and have

demonstrated a good containment

performance. Thus, the Type A test

results only confirm the results of the

Type B and C test results. The NRC staff

has noted that the licensee has a good

record of ensuring a leak-tight

containment. Since the first failure, all

Type A tests have passed with

significant margin and the licensee has

noted that the results of the Type A

testing have been confirmatory of the

Type B and C tests which will continue

to be performed.

The NRC staff has also made use of

the information in a draft staff report,

NUREG–1493, which provides the

technical justification for the present

appendix J rulemaking effort which also

includes a 10-year test interval for Type

A tests. The integrated leakage rate test,

or Type A test, measures overall

containment leakage. However,

operating experience with all types of

containments used in this country

demonstrates that essentially all

containment leakage can be detected by

local leakage rate test (Type B and C).

According to results given in NUREG–

1493, out of 180 ILRT reports covering

110 individual reactors and

approximately 770 years of operating

history, only 5 ILRT failures were found

which local leakage rate testing could

not detect. This is 3 percent of all

failures. This study agrees well with

previous NRC staff studies which show

that Type B and C testing can detect a

very large percentage of containment

leaks. The CC–2 experience has also

been consistent with these results as

previously noted.

The Nuclear Management and

Resources Council (NUMARC), now the

Nuclear Energy Institute (NEI), collected

and provided the NRC staff with

summaries of data to assist in the

appendix J rulemaking effort. NUMARC

collected results of 144 ILRTs from 33

units; 23 ILRTs exceeded 1.0La. Of

these, only nine were not due to Type

B or C leakage penalties. The NEI data

also added another perspective. The NEI

data show that in about one-third of the

cases exceeding allowage leakage, the

as-found leakage was less than 2La; in

one case the leakage was found to be

approximately 2La; in one case the asfound leakage was less than 3La; one

case approached 10La; and in one case

the leakage was found to be

approximately 21La. For about half of

the failed ILRTs the as-found leakage

was not quantified. These data show

that, for those ILRTs for which the

leakage was quantified, the leakage

values are small in comparison to the

leakage value at which the risk to the

public starts to increase over the value

of risk corresponding to La

(approximately 200La, as discussed in

NUREG–1493). Therefore, based on

these considerations, it is unlikely that

an extension of one cycle for the

performance of the appendix J, Type A

test at CC–2 would result in significant

degradation of the overall containment

integrity. As a result, the application of

the regulation of these particular

circumstances is not necessary to

achieve the underlying purpose of the

rule.

Based on generic and plant specific

data, the NRC staff finds the basis for

the licensee’s proposed exemption to

allow a one-time exemption to permit a

schedular extension for CC–2 of one

cycle (24 months) for the performance of

the appendix J, Type A test, and to

permit the third Type A test to be

performed during the spring 1999

refueling which extends the second 10-

year service period to 12 years to be

acceptable. As a condition for granting

this exemption, the licensee will

perform visual containment inspections.

Pursuant to 10 CFR 51.32, the

Commission has determined that

granting this Exemption will not have a

significant impact on the environment

(60 FR 14979).

This Exemption is effective upon

issuance and shall expire at the

completion of the 1997 refueling outage.

Dated at Rockville, Maryland, this 3rd day

of April 1995.

For the Nuclear Regulatory Commission.

Steven A. Varga,

Director, Division of Reactor Projects—I/II,

Office of Nuclear Reactor Regulation.

[FR Doc. 95–8707 Filed 4–7–95; 8:45 am]

BILLING CODE 7590–01–M

[Docket Nos. 50–275 and 50–323]

Pacific Gas & Electric Co., Diablo

Canyon Nuclear Power Plant, Unit Nos.

1 and 2; Environmental Assessment

and Finding of No Significant Impact

The U.S. Nuclear Regulatory

Commission (the Commission) is

considering issuance of exemptions

from Facility Operating License Nos.

DPR–80 and DPR–82, issued to Pacific

Gas and Electric Company (the licensee)

for operation of Diablo Canyon Nuclear

Nuclear Power Plant, Unit Nos. 1 and 2,

located in San Luis Obispo County,

California.

Environmental Assessment

Identification of the Proposed Action

The proposed action would grant

relief from the requirement in Section

III.D.1.(a) of Appendix J to 10 CFR Part

50 that the third Type A test in a 10-year

service period be conducted when the

plant is shut down for the 10-year plant

inservice inspections and allows the

licensee to perform the three Type A

tests at approximately equal intervals

within each 10-year service period.

The proposed action is in accordance

with the licensee’s application for

exemption dated February 16, 1994.

The Need for the Proposed Action

The proposed action is needed so that

the licensee, given the 18-month fuel

cycles at Diablo Canyon, is not required

to perform a fourth Type A test in order

to meet the Appendix J requirement and

the Diablo Canyon Technical

Specification requirement that Type A

tests be conducted at 40 months plus or