ML20133P713
| ML20133P713 | |
| Person / Time | |
|---|---|
| Site: | McGuire, Mcguire  |
| Issue date: | 07/18/1985 |
| From: | Dance H, William Orders, Pierson R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20133P702 | List: |
| References | |
| 50-369-85-16, 50-370-85-17, NUDOCS 8508140435 | |
| Download: ML20133P713 (13) | |
See also: IR 05000369/1985016
Text
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[DR Rf Cog"'o,
UNITED STATES
NUCLEAR REGULATORY COMMISSION
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101 MARIETTA ST REET, N.W.
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ATL ANT A, GEORGI A 30373
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Report Nos.:
50-369/85-16 and 50-370/85-17
Licensee:
Duke Power Company
422 South Church Street
Charlotte, NC 28242
Docket Nos.:
50-369 and 50-370
License Nos.-
Facility Name: McGuire 1 and 2
Inspection Conducted:
ril 21 - May 20, 1985
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Inspectors:
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Approved by:
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ugfi'C. Dance, Settion Chief
Da'te S'igned
Reactor Projects Branch 2
Division of Reactor Projects
SUMMARY
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Scope: This routine, unannounced inspection entailed 284 inspector-hours on site
in the areas of operations safety verification, surveillance testing, maintenance
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activities and refueling activities.
Results: Of the areas inspected, no violations or deviations were identified in
the areas of surveillance testing, maintenance activities or refueling
activities; two apparent violations were found in the area of operations safety
verification.
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REPORT DETAILS
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1.
Persons Contacted
Licensee Employees
- T. McConnell, Plant Manager
G. Gage, Superintendent of Operations
D. Rains, Superintendent of Maintenance
- B. Hamilton, Superintendent of Technical Services
- L. Weaver, Superintendent of Administration
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- B. Travis, Superintendent of Integrated Scheduling
- E. McCraw, License and Compliance Engineer
- P. Pham, Assistant Operating Engineer
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Other licensee employees contacted included construction craftsmen,
engineers, technicians, operators, mechanics, security force members, and
office personnel.
- Attended exit interview
2.
Exit Interview
The inspection scope and findings were summarized on May 31, 1985, with
those persons indicated in paragraph 1 above.
The licensee acknowledged
understanding of the issues discussed and offered no substantive related
discussion.
The licensee did not identify as proprietary any of the
materials provided to or reviewed by the inspectors during this inspection.
3.
Licensee Action on Previous Enforcement Matters
This subject was not addressed in the inspection.
4.
Unresolved Items *
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Unresolved items 50-370/85-15-01 was reviewed resulting in an apparent
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violation 50-370/85-17-02. Details related to the apparent violation are
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delineated in paragraph 10.
5.
Plant Operations
The inspection staff reviewed plant operations during the report period,
April 21 through May 20, 1985, to verify conformance with applicable
regulatory requirements. Control room logs, shift supervisors logs, shift
- An Unresolved Item is a matter about which more information is required to
determine whether it is acceptable or may involve a violation or deviation.
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turnover records and equipment removal and restoration records were
routinely perused.
Interviews were conducted with plant operations,
maintenance, chemistry, health physics, and performance personnel.
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Activities within the control rooms were monitored during shifts and at
shift changes.
Actions and/or activities observed were conducted as
prescribed in applicable station administrative directives.
The complement
of licensed personnel on each shift met or exceeded the minimum required by
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technical specifications (TS).
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Plant tours were taken during the reporting period on a systematic basis.
The areas toured included but were not limited to the following:
Turbine Buildings
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Auxiliary Buildings
Unit 1 and 2, Electrical Equipment Rooms
Units 1 and 2, Cable Spreading Rooms
Station Yard Zone within the protected area
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Unit 2 Reactor Building
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During the plant tours, ongoing activities, housekeeping, security,
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equipment status and radiation control practices were observed.
a.
Unit 1 Operations
McGuire Unit 1 began the reporting period in Mode 4 having just cooled
down in preparation for a refueling outage. The unit entered Mode 5 at
9:47 p.m. that evening and remained in Mode 5 until 11:35 p.m.
on
May 2, 1985, when the head was detensioned and the unit entered Mode 6.
At 4:05 p.m. on May 6,1985, unlatching control rods was commenced.
Fuel unloading commenced on May 8,1985. The last fuel assembly was
removed from the core at 9:41 a.m. on Saturday, May 11, 1985. The unit
remained in a defueled condition through May 19, 1985, when the unit
entered Mode 6.
Core load commenced at 3:12 p.m. on the 19th and the
unit remained in Mode 6 throughout the reporting period.
b.
Unit 2 Operations
McGuire Unit 2 began the reporting period at the end of a refueling
outage in Mode 5.
The unit entered Mode 4 at 6:24 a.m. on April 27,
1985. During the subsequent heatup and pressurization a water hammer
occurred in the "C" main steam line following the opening of 2SM-10
("C" main steam line isolation valve bypass valve) while main steam
drains were left closed.
This event is discussed in detail in
paragraph 7.
Following a determination of system seismic accept-
ability, unit start-up was continued.
The unit entered Mode 3 on
April 30, 1985 at 11:16 a.m., entered Mode 2 at 6:00 a.m. the following
morning and went critical at 11:50 a.m. on May 7, 1985. The unit then
entered Mode 1 at 6:17 a.m. on May 8th. During the process of swapping
from auxiliary steam to main steam as the supply for the main feed
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pump, the "A" main feed pump was lost and at 6:47 a.m. the reactor was
manually tripped from 7% power.
All systems responded normally following the reactor trip and recovery
was initiated.
The unit was restarted and was placed on line at 4:55
p.m. that afternoon.
Following the necessary post refueling testing
the unit's power was increased and the unit reached 100% power at 11:00
p.m. on May 12, 1985.
The unit was maintained at this power until
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ilay 16, 1985, when the unit was manually tripped following a loss of
generttor hydrogen. Following a determination that the main electrical
generator was not damaged, unit recovery was initiated.
The unit
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subsequently went critical at 6:09 a.m.
on May 17, 1985, but the
reactor reached criticality below the insertion limits and the unit was
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shutdown.
The unit was then restarted and reached criticality at
11:48 a.m.
This incident is discussed in detail in Report Nos.
50-369/85-20 and 50-370/85-21. Following recovery, power was increased
,
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to 100% and maintained at 100% throughout the reporting period.
6.
Missing Spacers on Battery EVCC
On May 1,1985, during a routine tour of the auxiliary building, the Resident
Inspector Staff determined that Vital DC Power Supply Battery EVCC was
missing approximately 10 plastic cell support spacers between the individual
cells.
Subsequent licensee evaluation did not determine when or for what purpose
these spacers were removed.
Procedure IP/0/A/3061/07, Vital Battery and
Terminal Post Inspection, was last performed on battery EVCC under Work Request 040053 on February 26, 1985.
During the performance of this
procedure a visual inspection of the battery rack and battery cells was
performed.
Included on the checklist is a block for spacing.
This block
was checked " SAT".
No discrepancies were noted during this inspection. As
such one can only conclude that the spacers were for some reason removed
between February 26, 1985 and May 1,
1985.
As noted however, no work
request could be found which authorized removal of these plastic cell
spacers.
Since these spacers are required by Duke Power Design Engineering Drawing
MCM 1356.01-001-001, the battery is unable to meet its structural design
criteria with the spacers missing.
Consequently, the battery was inoperable
for the time period February 26, 1985 through May 2, 1985, the date the
spacers which were missing were replaced.
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TS 3.8.2.1 requires that EVCC shall be OPERABLE and energized in Modes 1, 2,
3, and 4.
TS 3.8.2.1 ACTION statement b. states that:
With one 126-volt D.C. battery and/or its normal and standby chargers
inoperable or not energized, either:
1.
Restore the inoperable battery and/or charger to OPERABLE and
energized status within two hours or be in at least Hot Standby
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within the next six and in Cold Shutdown within the following 30
hours, or
2.
Energize the associated bus with an Operable battery bank via
Operable tie breakers within two hours; operation may then
continue for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> from time of initial loss of
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Operability, otherwise, be in at least Hot Standby within the next
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six hours and in Cold Shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
During the time period between February 26, 1985 and May 2, 1985, Unit I was
operated at power from February 26 until April 19 essentially unencumbered.
Unit 2, in its first refueling outage was in Mode 5 and 6 or in a "No Mode"
condition during this time.
Operating Unit 1 in Modes 1 through 4 during
the time that DC battery EVCC was inoperable due to missing plastic cell
spacers constitutes a violation of the requirements of TS 3.8.2.1.
In as much as this event is similar in nature to events detailed in report
50-369/85-10 and 50-370/85-11 which is yet to be issued and which entails
apparent enforcement issues, and in keeping with current NRC enforcement
policy which allows licensees to respond to previous examples of
noncompliance before issuing yet another Violation, a Notice of Violation
will not be issued in this instance.
7.
Water Hammer in "C" Main Steam Line
On April 20, 1985, startup was in progress on Unit 2 following a refueling
outage.
The main steam isolation valves were open for heatup of the
secondary system.
Step 3.2.25 of OP/2/A/6100/01 (Controlling Procedure for
Unit Startup) which requires the opening of steam line drains 2SM-83,
2SM-89, 2SM-95 and 2SM-101 had been performed but Control Room Operators had
noted that they did not receive an open indication for these valves.
This
discrepancy was turned over to the relieving shift.
Due to unrelated problems the unit startup was delayed and the valves were
not evaluated during the day shift. When the night shift was relieved the
steam drain valves were not included in the turnover.
A performance
technician then requested permission to perform PT/2/A/4255/03 SM (Main
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Steam) Valve Stroke Timing Shutdown and was granted permission.
This
performance test requires the cycling and timing of Main Steam Isolation
Valves; 2SM1AB, 2SM3AB, 2SMSAB, 2SM7AB and main steam bypass valves; 2SM9AB,
2SM10AB, 2SM11AB and 2SM12AB.
This performance test requires that the
initial valve position for testing be OPEN. The main steam bypass valves
were then opened. The main steam bypass valves and the main steam isolation
valves were then cycled closed and remain closed for approximately two
hours.
At approximately 2 o' clock in the morning on April 29, 1985, the main steam
bypass valves were opened. Approximately 20 minutes later a water hammer
occurred on the "C" main steam line.
The main steam bypass valves were
immediately shut.
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A system walkdown was performed to evaluate potential damage. No hanger
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damage or mechanical damage was noted, one snubber, 2MR-SM-75, which vas
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difficult to stroke was replaced.
An evaluation of this incident revealed the following sequence of events.
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On January 30, 1985 OP/0/A/6100/09 Removal and Restoration (R&R) of Station
Equipment (5866) was issued to perform an inspection of the main turbine.
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Main steam line drain valves 2SM-89, 2SM-83, 2SM-101 and 2SM-95 were gagged
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closed. These valves have an internal gag mechanism which was utilized to
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perform this gagging operation. In addition the valves were red tagged in
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accordance with R&R procedures. On February 12, 1985, another R&R procedure
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(6005) was performed to isolate these valves. This job was to inspect and
weld baffle plates on the Unit 2 hotwell. The valves were jacked closed and
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a mechanical gag was placed on each valve; 2SM-83, 2SM-89, 2SM-95 and
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A work request was issued WR123182, to implement placing these
collars on the valves and to subsequently remove these collars. Another red
tag was hung on the valves in accordance with R&R procedures.
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Upon completion of the Inspecting and Welding of Baffle Plates on the Unit 2
hotwell, R&R 6005 was closed. The technician removed one red tag from each
valve but did not remove the mechanical gag because he thought it was
required for the other red tag.
Meanwhile work request 123182, which
stipulated removal of the mechanical gag upon completion of 6005, was being
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held in Planning awaiting notification that the red tags needed removal and
the mechanical gag removed.
Later when Inspection of the Main Turbine
(5866) was completed a technician removed the remaining red tag and the
internal gag mechanism. He did not notice the installed collar providing a
mechanical gag. As such the valves were turned back to Operations with a
mechanical gag installed. As a result the valves did not open when Step
3.2.25 of OP/2/A/6100/01 was performed as discussed earlier.
The resulting
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water hammer occurred because the drain valves were not opened as required
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by the startup procedure.
The above scenario suggests several potential problems.
R&R procedures as
implemented were inadequate to ensure removal of the mechanical collar gags.
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Operation personnel involved did not adequately assess their lack of an
"0 PEN" indication on the main steam drain . valves during the startup
procedure, and the shift turncver was inadequate in that the relieving night
shift was not adequately informed about the status of the main steam line
drain valves. Further, maintenance personnel who removed the last remaining
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red tag were not observant enough to notice the remaining mechanical collar
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gag, and as a result the valves were turned over to operations, inoperable
with an outstanding work request and a mechanical gag installed.
Nonetheless, the underlying reason for the failure to remove the gags
remains the inadequate implementation of Station Directive 3.1.19 covering
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Safety Tags, Lock-outs, and Delineation Tags. Step H. under implementation
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states that when a safety tag is removed, the supervisor who has operational
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responsibility for' the equipment to be tagged shall insure that the
operating device to which it is attached is returned to its normal operating
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state as determined from the applicable written procedure or is placed in
some other state as may be required.
This was not done.
TS 6.8.1 states that written procedures shall be established, implemented,
and maintained covering the activities referenced in Appendix A of
Regulatory Guide 1.33, Revision 2, February 1978. This Regulatory Guide in
Appendix A, Part 1, Administrative Procedures, Step C.
Equipment Control
(e.g.,
locking and tagging) implicitly states that procedures will be
utilized to control removal of safety tags. Station Directive 3.1.19 which
implements this requirement of Regulatory Guide 1.33 was inadequately
implemented in that Safety Tags (Red Tags) were removed from main steam
drain valves 2SM-83,2SM-89, 2SM-95 and 2SM-101 contrary to Station Directive
3.1.19 without insuring that the operating device to which the tags were
attached was returned to its normal operating state. This constitutes a
violation of the requirements of TS 6.8.1., and collectively with the issues
discussed in paragraphs 8 and 9 constitutes a Violation. (370/85-17-01).
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8.
UHI Vent-Sightglass Rupture
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On May 2, 1985 at 2:30
p.m., a Nuclear Equipment Operator was venting the
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Upper Head Injection system pursuant to Enclosure 4.1 to operating procedure
OP-2-A-6200/10 Upper Head Injection, when he opened valve 2NI-340, instead
of valve 2NI-297. This placed reactor coolant system pressure on the vent
line discharge sightglass downstream.
The sightglass ruptured and the
diaphragm of valve 2NC-215 which is downstream of the sightglass was
ruptured as well.
Valve 2NI-340 did not have a valve tag affixed.
The
operator noticed however that written on some duct work nearby was the
number 297. He inappropriately assumed that valve 2NI-340 was 2NI-297 and
opened it.
Another operator assisting in the process detected that the
sightglass had blown and informed his counterpart.
The valve was then
reclosed and the incident was terminated.
Subsequent evaluation revealed that 2NC215, had been locked open when the
incident occurred as was its required position.
The above event constitutes a violation of TS 6.8.1 which requires that
currently written approved procedures be followed covering the Emergency
Core Cooling System as specified in Appendix A of Regulatory Guide 1.33.
This example of failure to follow procedure in conjunction with the examples
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detailed in Paragraphs 7 and 9 constitutes a violation (370/85-17-01).
9.
Containment Cleanliness
On April 24, 1985, during a routine inspection of Unit 2 containment loose
debri s , trash, clothing and plastic was observed which during accident
conditions could be transported to the containment sump causing a
restriction.
Procedure number OP/2/A/6100/01, the Controlling Procedure for Unit Startup,
was subsequently reviewed to determine if the requirements set forth therein
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concerning containment cleanliness had been completed.
Step 39 of
OP/2/A/6100/01 requires that Enclosure 13.1 of PT/2/A/4600/08 (Precri-
ticality Surveillance Requirements for Unit Startup) be completed if unit
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startup is from Mode 5 or 6.
PT/2/A/4600/08 Part A item 1 specifically
requires that containment cleanliness be verified by visual inspection:
that no loose debris is present in the containment.
The inspectors brought this situation to the attention of plant management
on April 26, 1985. A subsequent inspection of Unit 2 containment was then
conducted by Operations and a list of remaining items to be performed /
removed prior to Unit 2 startup was prepared.
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In as much as the procedure step had been signed off on April 20, 1985, but
the requirement of that step, to remove all loose debris, trash, clothing
and plastic from the containment which during accident conditions could be
transported to the containment sump causing a restriction had not been
performed, the abose event constitutes a failure to follow procedure.
The above event ccastitutes a violation of T.S. 6.8.1 which requires that
current written approved procedures be employed covering the startup of a
facility as specif <ed in Appendix A of Regulatory Guide 1.33.
This in
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conjunction with t> e examples detailed in Paragraphs 7 and 8 constitutes a
Violation.
(370/85-17-01)
10. Thermal Overloac Protection Design
In Report 50-369/85-14 it was identified that on April 3, 1985, at 3:05 p.m.
while performing Performance Test PT/2/4200/09A ESF Train A, the licensee
found that shorting bars which were to have been installed on the breaker of
the operator of ,alve 2NI-9A had not been installed. The shorting bars were
to bypass the thermal overload protection of the breaker to assure valve
operation during an accident situation. At that time the issue was under
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review and maintained as an Unresolved Item pending completion of that
analysis. (370/85-15-01)
Further analysis by the resident inspection staff and the licensee revealed
that a number of valves on both units had not been installed per design
specification;
Those valves are:
Valve Number
Function
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INV-94
Reactor Coolant Seal Return Containment Isolation
INV-842
Standby Makeup Pump Inlet Isolation
INV-849
Standby Makeup Pump Outlet Containment Isolation
Control Room Area Chilled Water Flow Control
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Control Room Area Chilled Water Flow
0 RN-10
Nuclear Service Water Supply B Shutoff
0 RN-12
Nuclear Service Water Supply A Shutoff
O RN-4
Circ Water Supply B Shutoff
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0 RN-147
Circ Water Discharge A Isolation
0 RN-283
Circ Water Discharge B Isolation
0 RN-301
Containment Ventilation System Isolation
2 NI-9
Safety Injection Discharge Isolation
2 NI-288
Reciprocating Charging Pump Recirc Isolation
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2 NI-358
Safety Injection Pump 2A to Upper Head Injection
2 NI-430
Accumulator 2A Vent to NC 34
2 NI-88
Accumulator 2D Discharge Isolation
2 NC-33
Pressurizer PORV Isolation
2 NC-31
Pressurizer PORV Isolation
2 NC-35
Pressurizer PORV Isolation
2 RN-174
Diesel Generator 2B Heat Exchange Flow Control
Valve
Subsequent to determining that the above listed valves were technically
inoperable due to their having not been tested and/or evaluated in their
" degraded" state, the licensee performed the necessary modifications to
bring the components into compliance with the applicable design specifi-
cation (MCS 1390.01-00-0077) which not only required that the shorting bars
be installed but that the control contact actuated by the overload heaters
be jumpered.
Regulatory Guide 1.106, November 1975, Thermal Overload Protection For
Electric Motors On Motor-Operated Valves,
as
revised
in
Revision 1,
March 1977 offered acceptable methods for complying with the germain
criterion in Appendices A and B of 10 CFR 50 with regard to the application
of thermal overload protection devices for electric motors on motor-operated
valves to ensure that thermal overload protection devices will not prevent
the valve / motor from performing its intended safety-related function.
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The design specification under which Unit I safety related valves / motors
were installed (MCS 1390.01-00-0077) specified that shorting bars which
explore the overload heaters be installed and the corresponding control
contact be jumpered with the appropriate modifications installed ". . . safety
related motor operated valve start as are equipped with thermal overload
devices which are connected to alarm only."
(FSAR, Section 8.3.1.1.6)
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During McGuire Unit 2 construction the specification was modified to allow
the re-installation of the protection circuitry during construction;
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however, the protection circuitry was to have been removed prior to Unit 2
fuel load.
According to the licensee the Unit 1 valves and the shared valves (the ones
with an "0"
prefix) detailed in the table above were installed or modified
subsequent to the specification being revised and were not properly
modified.
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Succinctly stated, the measures established and/or complemented at McGuire
to ensure that the applicable regulatory requirements and design basis, as
defined in 10 CFR 50.2, and as specified in the license as they pertain to
the design control of structures, systems and components were inadequate.
More specifically; 10 CFR 50, Appendix B, Criterion III, Design Control
Criterion V,
Instructions, Procedures, and Drawings and Criterion
X,
Inspection, require that:
a.
Maasures be established to assure that applicable regulatory
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requirements and the design basis for safety-related structures,
s'ystems, and components are correctly translated into specifications,
drawings, procedures, and instructions. These measures shall include
provisions to assure that appropriate quality standards are specified
and included in design documents and that deviations from such
standards are controlled.
b.
Those specifications, drawings procedures and instructions be of a
type appropriate to the circumstances and that the associated
activities be accomplished in accordance with these instructions,
procedures, or drawings.
Instructions, procedures, or drawings shall
include appropriate quantitative or qualitative acceptance criteria for
determining that important activities have been satisfactorily
accomplished.
c.
A program for inspection of these activities be established and
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executed to verify conformance with the documented instructions,
procedures, and drawings for accompli:,hing the activity to assure
conformance.
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Contrary to those requirements:
(1) There were no specific procedures, or instructions generated to assure
that all requirements of design specification MCS 1390.01-00-0077 were
implemented.
(2) The
inspection
program to verify conformance with regulatory
requirements was inadequate, in that it did not detect that there were
no procedures for the activity in question, nor did the program detect
the inadequate installations.
(3) The measures established to control components which do not conform to
requirements to prevent their use was inadequate, resulting in the
delineated components' employment.
The above constitutes a Violation (369/85-16-01, 370/85-17-02).
11.
Surveillance Testing
The surveillance tests categorized below were analyzed and/or witnessed by
the inspector to ascertain procedural and performance adequacy.
The completed test procedures examined were analyzed for embodiment of the
necessary test prerequisites,
preparations,
instructions, acceptance
criteria, and sufficiency of technical content.
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The selected tests witnessed were examined to ascertain that current written
approved procedures were available and in use, that test equipment in use
was calibrated, that test prerequisites were met, system restoration
completed and test results were adequate.
The selected procedures perused attested conformance with applicable TS and
procedural requirements, they appeared to have received the required
administrative review and they apparently were performed within the
,
surveillance frequency specified.
Procedure Number
Procedure Title
PT/2/A/4206/02
NI Valve Stroke Timing Quarterly
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PT/2/A/4208/01A
Containment Spray Pump 2A Perfor-
mance Test
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PT/2/A/4208/01B
Containment Spray Pump 2B Perfor-
mance Test
PT/2/A/4252/01A
Motor Driven Auxiliary Feedwater
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Pump 2A Performance Test
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PT/2/A/4252/018
Motor Driven Auxiliary Feedwater
Pump 28 Performance Test
PT/2/A/4200/28
Slave Relay Test
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PT/2/A/4601/04
Protection System Channel 4 Func-
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tional Test
PT/2/A/4200/09A
ESF Actuation Test
PT/2/A/4601/02
Protection
System
Channel 2
Functional Test
l
PT/1/A/4350/17B
D/G 1B Fuel Oil
Transfer Pump
Performance Test
,
PT/1/A/4208/02
Containment
Spray
Valve
Stroke
Timing Test
12. Maintenance Observations
1
lI
The maintenance activities categorized below were analyzed and/or witnessed
by the resident inspection staff to ascertain procedural and performance
!
adequacy.
The completed procedures examined were analyzed for embodiment of the
necessary prerequisites, preparation, instruction, acceptance criteria and
sufficiency of technical detail.
'
The selected activities witnessed were examined to ascertain that where
applicable, current written approved procedures were available and in use,
that prerequisites were met, equipment restoration completed and maintenance
'
results were adequate.
The selected work requests / maintenance packages perused attested conformance
.
with applicable TS and procedural requirements and appeared to have received
'
the required administrative review.
i
Work Request
Equipment
123674
1A D/G Inspect Fuel Injectors
86058
Interim Calibration of Excores
93484
Rebuild CF Pump Pedestals
65481
Replace Styrofoam Spacers on Battery EVCC
123182
Place Collars on Main Steam Drain Valves
040053
Perform IP/0/A/3061/07 on Battery EVCC
i
!
!
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_
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_
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1
1
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12
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13. Open Items Review
The following items, entailing in part licensee event reports, violations,
inspector followup items and unresolved items were reviewed in order to
r
determine the adequacy of corrective actions, the implications as they
pertain to safety of operations, the applicable reporting requirements, and
licensee review of the event.
Based upon the results of this review, the items are herewith closed.
Unit 1, Docket 50-369, LER 85-03
LER 85-04
Unit 2, Docket 50-370, LER 85-07
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