Text

Insp Repts 50-369/85-16 & 50-370/85-17 on 850421-0520. Violations Noted:Inadequate Measures,Procedures or Instructions Provided to Assume That Valve/Motor Installation Requirements Implemented
	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: IR 05000421/2005020; ML20133P700; ML20133P713;
References
	50-369-85-16, 50-370-85-17, NUDOCS 8508140435
	Download: ML20133P713 (13)
	v • d • e

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UNITED STATES

[DR Rf Cog"'o,

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NUCLEAR REGULATORY COMMISSION

O 'N /' REGloN li

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. 101 MARIETTA ST REET, N.W.

, ' t 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.- NPF-9 and NPF-17

Facility Name: McGuire 1 and 2

Inspection Conducted: ril 21 - May 20, 1985

Inspectors: , ,

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W. Orders, rTTor dentEngctor te Si ned

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Approved by: -( h

ugfi'C. Dance, Settion Chief

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Da'te S'igned

Reactor Projects Branch 2

Division of Reactor Projects

SUMMARY

j Scope: This routine, unannounced inspection entailed 284 inspector-hours on site

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in the areas of operations safety verification, surveillance testing, maintenance

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

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L. Weaver, Superintendent of Administration

B. Travis, Superintendent of Integrated Scheduling

E. McCraw, License and Compliance Engineer

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P. Pham, Assistant Operating Engineer

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

, violation 50-370/85-17-02. Details related to the apparent violation are

! 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,

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maintenance, chemistry, health physics, and performance personnel.

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 ,

technical specifications (TS). '

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

Auxiliary Buildings

I. 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,

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

! subsequently went critical at 6:09 a.m. on May 17, 1985, but the

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reactor reached criticality below the insertion limits and the unit was

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

j 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 0.02 hours 1.190476e-4 weeks 2.7396e-5 months from time of initial loss of i

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Operability, otherwise, be in at least Hot Standby within the next

six hours and in Cold Shutdown within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

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

l 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

difficult to stroke was replaced.

< An evaluation of this incident revealed the following sequence of events.

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.

1 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

! 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

1 (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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2SM-101. 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. 1

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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

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stipulated removal of the mechanical gag upon completion of 6005, was being

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 ,

water hammer occurred because the drain valves were not opened as required

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. ,

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

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drain valves. Further, maintenance personnel who removed the last remaining

i red tag were not observant enough to notice the remaining mechanical collar

! 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

Safety Tags, Lock-outs, and Delineation Tags. Step H. under implementation

I states that when a safety tag is removed, the supervisor who has operational

l responsibility for' the equipment to be tagged shall insure that the

i 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).

l 8. UHI Vent-Sightglass Rupture

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l On May 2, 1985 at 2:30 p.m., a Nuclear Equipment Operator was venting the

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.

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This example of failure to follow procedure in conjunction with the examples

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

i 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

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facility as specif <ed in Appendix A of Regulatory Guide 1.33. This in

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

i 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

1YC-40 Control Room Area Chilled Water Flow Control

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1YC-99 Control Room Area Chilled Water Flow

0 RN-10 Nuclear Service Water Supply B Shutoff

0 RN-12 Nuclear Service Water Supply A Shutoff

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O RN-4 Circ Water Supply B Shutoff

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

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2 NI-288 Reciprocating Charging Pump Recirc Isolation

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;

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.

.i 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:

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a. Maasures be established to assure that applicable regulatory

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 i

determining that important activities have been satisfactorily

accomplished.

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c. A program for inspection of these activities be established and

executed to verify conformance with the documented instructions,

procedures, and drawings for accompli:,hing the activity to assure

conformance.

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i 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

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PT/2/A/4206/02 NI Valve Stroke Timing Quarterly

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PT/2/A/4208/01A Containment Spray Pump 2A Perfor-

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mance Test

PT/2/A/4208/01B Containment Spray Pump 2B Perfor-

mance Test

PT/2/A/4252/01A Motor Driven Auxiliary Feedwater

l 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-

l 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

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Performance Test

PT/1/A/4208/02 Containment Spray Valve Stroke

Timing Test

12. Maintenance Observations

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The maintenance activities categorized below were analyzed and/or witnessed

lI 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.

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The selected activities witnessed were examined to ascertain that where

applicable, current written approved procedures were available and in use,

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that prerequisites were met, equipment restoration completed and maintenance

results were adequate.

The selected work requests / maintenance packages perused attested conformance

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. with applicable TS and procedural requirements and appeared to have received

the required administrative review.

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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

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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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ML20133P713

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