Text

Technical Specification Bases Changes
	ML042300557
Person / Time
Site:	Mcguire, McGuire
Issue date:	08/05/2004
From:	Gordon Peterson; Duke Energy Corp
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	Download: ML042300557 (50)
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fU Duke GARY R. PETERSON ObPowere Vice President McGuire Nuclear Station A Duke Energy Company Duke Power MGO1 VP / 12700 Hagers Ferry Road Huntersville, NC 28078-9340 704 875 5333 704 875 4809 fax grpeters @duke-energy. corn August 5, 2004 United States Nuclear Regulatory Commission ATTENTION: Document Control Desk Washington, DC 20555-0001

Subject:

Duke Energy Corporation McGuire Nuclear Station Units 1 and 2 Docket Nos. 50-369 and 50-370 Technical Specification Bases Changes Attached are revisions to McGuire Technical Specification (TS) Bases 3.8.1, "AC Sources - Operating" and TS Bases 3.9.5, "RHR and Coolant Circulation - High Water level."

These revisions were implemented in accordance with the TS Bases Control Program as described in TS 5.5.14.

TS Bases 3.8.1 was revised by enhancing the tables which show the allowable offsite power supply to essential bus breaker alignments.

TS Bases 3.9.5 was revised by adding a paragraph describing the additional controls in place when the upper internals are still installed in the reactor vessel.

Attachment 1 contains revised TS Bases 3.8.1 and TS Bases 3.9.5. Attachment 2 contains the revised TS and Bases List of Effective Sections.

Please contact Lee Hentz at 704-875-4187 if any questions arise.

Sincerely,

'i 14A4t& /7tg Gary R. Peterson Attachments www.duke-energy.com 1)0l

U.S. Nuclear Regulatory Commission August 5, 2004 Page 2 xc w/attachments:

W. D. Travers Regional Administrator, Region II U. S. Nuclear Regulatory Commission Atlanta Federal Center 61 Forsyth St., SW, Suite 23T85 Atlanta, GA 30303 J. J. Shea Project Manager U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation Mail Stop 0-8H12 Washington, D.C. 20555 J. B. Brady Senior Resident Inspector U. S. Nuclear Regulatory Commission McGuire Nuclear Station B. 0. Hall Section Chief N.C. Radiation Protection Section 1645 Mail Service Center Raleigh, NC 27699

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U. S. Nuclear Regulatory Commission August 5, 2004 Page 3 bcc w/attachments:

ELL (ECQ50)

B. Beaver (MGO1RC)

K. Crane (MGO1RC)

McGuire Master File 1.3.2.12

ATTACHMENT 1 REVISED TECHNICAL SPECIFICATION BASES 3.8.1 and 3.9.5

AC Sources-Operating B 3.8.1 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.1 AC Sources-Operating BASES BACKGROUND The unit Essential Auxiliary or Class 1E AC Electrical Power Distribution System AC sources consist of the offsite power sources (preferred power sources, normal and alternate(s)), and the onsite standby power sources (Train A and Train B diesel generators (DGs)). As required by 10 CFR 50, Appendix A, GDC 17 (Ref. 1), the design of the AC electrical power system provides independence and redundancy to ensure an available source of power to the Engineered Safety Feature (ESF) systems.

The onsite Class 1E AC Distribution System is divided into redundant load groups (trains) so that the loss of any one group does not prevent the minimum safety functions from being performed. Each train has connections to two preferred offsite power sources and a single DG.

Offsite power is supplied to the unit switchyard(s) from the transmission network by two transmission lines. From the switchyard(s), two electrically and physically separated circuits provide AC power, through step down station auxiliary transformers, to the 4.16 kV ESF buses. A detailed description of the offsite power network and the circuits to the Class 1E ESF buses is found in the UFSAR, Chapter 8 (Ref. 2).

A qualified offsite circuit consists of all breakers, transformers, switches, interrupting devices, cabling, and controls required to transmit power from the offsite transmission network to the onsite Class 1E ESF bus(es).

The offsite transmission systems normally supply their respective unit's onsite power supply requirements. However, in the event that one or both buslines of a unit become unavailable, or by operational desire, it is acceptable to supply that unit's offsite to onsite power requirements by aligning the affected 4160V bus of the opposite unit via the standby transformers, SATA and SATB in accordance with Regulatory Guides 1.6 and 1.81 (Ref. 12 and 13). In this alignment, each units offsite transmission system could simultaneously supply its own 41 60V buses and one (or both) of the buses of the other unit.

Although a single auxiliary transformer (1ATA, 1ATB, 2ATA, 2ATB) is sized to carry all of the auxiliary loads of its unit plus both trains of essential 41 60V loads of the opposite unit, the LCO would not be met in this alignment due to separation criteria.

McGuire Units 1 and 2 B 3.8.1 -1 Revision No. 56

AC Sources-Operating B 3.8.1 BASES BACKGROUND (continued)

Each unit's Train A and B 41 60V bus must be derived from separate offsite buslines. The first offsite power supply can be derived from any of the four buslines (1A, 1B, 2A, or 2B). The second offsite power supply must not derive its power from the same busline as the first.

Acceptable train and unit specific breaker alignment options are described below:

Unit I A Train

1. BL1 A-i ATA-1 TA-i ATC-1 ETA

2. BL1 B-1 ATBA-1 TA-1 ATC-1 ETA

3. BL1 A-1 ATA-1TC-SATA-1 ETA

4. BLI B-1 ATB-1TC-SATA-1 ETA

5. BL2A-2ATA-2TC-SATA-1 ETA

6. BL2B-2ATB-2TC-SATA-1 ETA Unit 1 B Train

1. BL1 B-1ATB-1TD-1ATD-1 ETB

2. BLIA-1ATA-1TD-1ATD-1 ETB

3. BLI B-1 ATB-1 TB-SATB-1 ETB

4. BL1 A-i ATA-1 TB-SATB-1 ETB

5. BL2B-2ATB-2TB-SATB-1 ETB

6. BL2A-2ATA-2TB-SATB-1 ETB Unit 2 A Train

1. BL2A-2ATA-2TA-2ATC-2ETA

2. BL2B-2ATB-2TA-2ATC-2ETA

3. BL2A-2ATA-2TC-SATA-2ETA

4. BL2B-2ATB-2TC-SATA-2ETA

5. BL1 A-1 ATA-1 TC-SATA-2ETA

6. BL1 B-1ATB-1TC-SATA-2ETA Unit 2 B Train

1. BL2B-2ATB-2TD-2ATD-2ETB

2. BL2A-2ATA-2TD-2ATD-2ETB

3. BL2B-2ATB-2TB-SATB-2ETB

4. BL2A-2ATA-2TB-SATB-2ETB

5. BL1 B-1ATB-ITB-SATB-2ETB

6. BLIA-1ATA-1TB-SATB-2ETB McGuire Units 1 and 2 B 3.8.1-2 Revision No. 56

AC Sources-Operating B 3.8.1 BASES BACKGROUND (continued)

Certain required unit loads are returned to service in a predetermined sequence in order to prevent overloading the transformer supplying offsite power to the onsite Class 1E Distribution System. Typically (via accelerated sequencing), within 1 minute after the initiating signal is received, all loads needed to recover the unit or maintain it in a safe condition are returned to service.

The onsite standby power source for each 4.16 kV ESF bus is a dedicated DG. DGs A and B are dedicated to ESF buses ETA and ETB, respectively.

A DG starts automatically on a safety injection (SI) signal (i.e., low pressurizer pressure or high containment pressure signals) or on an ESF bus degraded voltage or undervoltage signal (refer to LCO 3.3.5, "Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation"). After the DG has started, it will automatically tie to its respective bus after offsite power is tripped as a consequence of ESF bus undervoltage or degraded voltage, independent of or coincident with an SI signal. The DGs will also start and operate in the standby mode without tying to the ESF bus on an SI signal alone. Following the trip of offsite power, a sequencer strips loads from the ESF bus. When the DG is tied to the ESF bus, loads are then sequentially connected to its respective ESF bus by the automatic load sequencer. The sequencing logic controls the permissive and starting signals to motor breakers to prevent overloading the DG by automatic load application.

In the event of a loss of preferred power, the ESF electrical loads are automatically connected to the DGs in sufficient time to provide for safe reactor shutdown and to mitigate the consequences of a Design Basis Accident (DBA) such as a loss of coolant accident (LOCA).

Certain required unit loads are returned to service in a predetermined sequence in order to prevent overloading the DG in the process.

Typically (via accelerated sequencing), within 1 minute after the initiating signal is received, all loads needed to recover the unit or maintain it in a safe condition are returned to service.

Ratings for Train A and Train B DGs satisfy the requirements of Regulatory Guide 1.9 (Ref. 3). The continuous service rating of each DG Is 4000 kW with 10% overload permissible for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months in any 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months period. The ESF loads that are powered from the 4.16 kV ESF buses are listed in Reference 2.

APPLICABLE The initial conditions of DBA and transient analyses in the UFSAR, SAFETY ANALYSES Chapter 6 (Ref. 4) and Chapter 15 (Ref. 5), assume ESF systems are OPERABLE. The AC electrical power sources are designed to provide sufficient capacity, capability, redundancy, and reliability to ensure the availability of necessary power to ESF systems so that the fuel, Reactor McGuire Units 1 and 2 B 3.8.1-3 Revision No. 56

AC Sources-Operating B 3.8.1 BASES APPLICABLE SAFETY ANALYSES (continued)

Coolant System (RCS), and containment design limits are not exceeded.

These limits are discussed in more detail in the Bases for Section 3.2, Power Distribution Limits; Section 3.4, Reactor Coolant System (RCS);

and Section 3.6, Containment Systems.

The OPERABILITY of the AC electrical power sources is consistent with the initial assumptions of the Accident analyses and is based upon meeting the design basis of the unit. This results in maintaining at least one train of the onsite or offsite AC sources OPERABLE during Accident conditions in the event of:

a. An assumed loss of all offsite power or all onsite AC power; and

b. A worst case single failure.

The AC sources satisfy Criterion 3 of 10 CFR 50.36 (Ref. 6).

LCO Two qualified circuits between the offsite transmission network and the onsite Class 1E Electrical Power System and separate and independent DGs for each train ensure availability of the required power to shut down the reactor and maintain it in a safe shutdown condition after an anticipated operational occurrence (AOO) or a postulated DBA.

Qualified offsite circuits are those that are described in the UFSAR and are part of the licensing basis for the unit.

In addition, one required automatic load sequencer per train must be OPERABLE.

Each offsite circuit must be capable of maintaining rated frequency and voltage, and accepting required loads during an accident, while connected to the ESF buses.

The 4.16 kV essential system is divided into two completely redundant and independent trains designated A and B, each consisting of one 4.16 kV switchgear assembly, two 4.16 kV/600 V load centers, and associated loads.

Normally, each Class 1E 4.16 kV switchgear is powered from its associated non-Class 1E train of the 6.9 kV Normal Auxiliary Power System as discussed in 06.9 kV Normal Auxiliary Power System in Chapter 8 of the UFSAR (Ref. 2). Additionally, an alternate source of power to each 4.16 kV essential switchgear is provided from the 6.9 kV system via a separate and independent 6.914.16 kV transformer. Two transformers are shared between units and provide the capability-to supply an alternate source of power to each unit's 4.16 kV essential McGuire Units 1 and 2 B 3.8.1-4 Revision No. 56

AC Sources-Operating B 3.8.1 BASES LCO (continued) switchgear from either unit's 6.9 kV system. A key interlock scheme is provided to preclude the possibility of connecting the two units together at either the 6.9 or 4.16 kV level.

Each train of the 4.16 kV Essential Auxiliary Power System is also provided with a separate and independent emergency diesel generator.to supply the Class 1E loads required to safely shut down the unit following a design basis accident.

Each DG must be capable of starting, accelerating to rated speed and voltage, and connecting to its respective ESF bus on detection of bus undervoltage. This will be accomplished within 11 seconds. Each DG must also be capable of accepting required loads within the assumed loading sequence intervals, and continue to operate until offsite power can be restored to the ESF buses. These capabilities are required to be met from a variety of initial conditions such as DG in standby with the engine hot and DG in standby with the engine at ambient conditions.

Additional DG capabilities must be demonstrated to meet required Surveillance, e.g., capability of the DG to revert to standby status on an ECCS signal while operating in parallel test mode.

Proper sequencing of loads is a function of Sequencer OPERABILITY.

Proper load shedding is a function of DG OPERABILITY. Proper tripping of non-essential loads is a function of AC Bus OPERABILITY (Condition A of Technical Specification 3.8.9).

The AC sources in one train must be separate and independent (to the extent possible) of the AC sources in the other train. For the DGs, separation and independence are complete.

APPLICABILITY The AC sources and sequencers are required to be OPERABLE in MODES 1, 2, 3, and 4 to ensure that:

a. Acceptable fuel design limits and reactor coolant pressure boundary limits are not exceeded as a result of AOOs or abnormal transients; and

b. Adequate core cooling is provided and containment OPERABILITY and other vital functions are maintained in the event of a postulated DBA.

The AC power requirements for MODES 5 and 6 are covered in LCO 3.8.2, "AC Sources-Shutdown.'

McGuire Units 1 and 2 B 3.8.1-5 Revision No. 56

AC Sources-Operating B 3.8.1 BASES ACTIONS A.1 To ensure a highly r liablelp6e`i' source remains with one offsite circuit inoperable, it is necessary to verify the OPERABILITY of the remaining required offsite circuit on a more frequent basis. Since the Required Action only specifies "perform," a failure of SR 3.8.1.1 acceptance criteria does not result in a Required Action not met. However, if a second required circuit fails SR 3.8.1.1, the second offsite circuit is inoperable,.

and Condition C, for two offsite circuits inoperable, is entered.

A.2 Required Abtion A.2, which only applies if the train cannot be powered from an offsite source, is intended to provide assurance that an event coincident with a single failure of the associated DG will not result in a complete loss of safety function of critical redundant required features. These features are powered from the redundant AC electrical power train. This includes motor driven auxiliary feedwater pumps. The turbine driven auxiliary feedwater pump is required to be considered a redundant required feature, and, therefore, required to be determined OPERABLE by this Required Action. Three independent AFW pumps are required to ensure the availability of decay heat removal capability for all events accompanied by a loss of offsite power and a single failure. System design is such that the remaining OPERABLE motor driven auxiliary feedwater pump is not by itself capable of providing 100% of the auxiliary feedwater flow assumed in the safety analysis.

The Completion Time for Required Action A.2 is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero for beginning the allowed outage time 'clock." In this Required Action, the Completion Time only begins on discovery that both:

a. The train has no offsite power supplying its loads; and

b. A required feature on the other train is inoperable.

If at any time during the existence of Condition A (one offsite circuit inoperable) a redundant required feature subsequently becomes inoperable, this Completion Time begins to be tracked.

Discovering no offsite power to one train of the onsite Class 1E Electrical Power Distribution System coincident with one or more inoperable required support or supported features, or both, that are associated with the other train that has offsite power, results in starting the Completion Times for the Required Action. Twenty-four hours is acceptable because it minimizes risk while allowing time for restoration before subjecting the unit to transients associated with shutdown.

The remaining OPERABLE offsite circuit and DGs are adequate to supply electrical power to Train A and Train B of the onsite Class 1E Distribution McGuire Units 1 and 2 B 3.8.1-6 Revision No. 56

AC Sources-Operating B 3.8.1 BASES ACTIONS (continued)

System. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time takes into account the component OPERABILITY of the redundant counterpart to the inoperable required feature. Additionally, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.

A.3 According to Regulatory Guide 1.93 (Ref. 7), operation may continue in Condition A for a period that should not exceed 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . With one offsite circuit inoperable, the reliability of the offsite system is degraded, and the potential for a loss of offsite power is increased, with attendant potential for a challenge to the unit safety systems. In this Condition, however, the remaining OPERABLE offsite circuit and DGs are adequate to supply electrical power to the onsite Class 1E Distribution System.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.

The second Completion Time for Required Action A.3 establishes a limit on the maximum time allowed for any combination of required AC power sources to be inoperable during any single contiguous occurrence of failing to meet the LCO. If Condition A is entered while, for instance, a DG is inoperable and that DG is subsequently returned OPERABLE, the LCO may already have been not met for up to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . This could lead to a total of 144 hours0.00167 days 0.04 hours 2.380952e-4 weeks 5.4792e-5 months , since initial failure to meet the LCO, to restore the offsite circuit. At this time, a DG could again become inoperable, the circuit restored OPERABLE, and an additional 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months (for a total of 9 days) allowed prior to complete restoration of the LCO. The 6 day Completion Time provides a limit on the time allowed in a specified condition after discovery of failure to meet the LCO. This limit is considered reasonable for situations in which Conditions A and B are entered concurrently. The 'AND' connector between the 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and 6 day Completion Times means that both Completion Times apply simultaneously, and the more restrictive Completion Time must be met.

As in Required Action A.2, the Completion Time allows for an exception to the normal time zeros for beginning the allowed outage time "clock.0 This will result in establishing the "time zero" at the time that the LCO was initially not met, instead of at the time Condition A was entered.

McGuire Units 1 and 2 B 3.8.1-7 Revision No. 56

AC Sources-Operating B 3.8.1 BASES ACTIONS (continued) 8.1 To ensure a highly reliable power source remains with an inoperable DG, it is necessary to verify the availability of the offsite circuits on a more frequent basis. Since the Required Action only specifies perform," a failure of SR 3.8.1.1 acceptance criteria does not result in a Required Action being not met. However, if a circuit fails to pass SR 3.8.1.1, it is inoperable. Upon offsite circuit inoperability, additional Conditions and Required Actions must then be entered.

8.2 Required Action B.2 is intended to provide assurance that a loss of offsite power, during the period that a DG is inoperable, does not result in a complete loss of safety function of critical systems. These features are designed with redundant safety related trains. This includes motor driven auxiliary feedwater pumps. The turbine driven auxiliary feedwater pump is required to be considered a redundant required feature, and, therefore, required to be determined OPERABLE by this Required Action. Three independent AFW pumps are required to ensure the availability of decay heat removal capability for all events accompanied by a loss of offsite power and a single failure. System design is such that the remaining OPERABLE motor driven auxiliary feedwater pump is not by itself capable of providing 100% of the auxiliary feedwater flow assumed in the safety analysis. Redundant required feature failures consist of inoperable features associated with a train, redundant to the train that has an inoperable DG.

The Completion Time for Required Action B.2 is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time clock." In this Required Action, the Completion Time only begins on discovery that both:

a. An inoperable DG exists; and

b. A required feature on the other train (Train A or Train B) is inoperable.

If at any time during the existence of this Condition (one DG inoperable) a required feature subsequently becomes inoperable, this Completion Time would begin to be tracked.

Discovering one required DG inoperable coincident with one or more inoperable required support or supported features, or both, that are associated with the OPERABLE DG, results in starting the Completion McGuire Units 1 and 2 B 3.8.1-8 Revision No. 56

AC Sources-Operating B 3.8.1 BASES ACTIONS (continued Time for the Required Action. Four hours from the discovery of these events existing concurrently is Acceptable because it minimizes risk while allowing time for restoration before subjecting the unit to transients associated with shutdown.

In this Condition, the remaining OPERABLE DG and offsite circuits are..

adequate to supply electrical power to the onsite Class 1E Distribution System. Thus, on a component basis, single failure protection for the required feature's function may have been lost; however, function has not been lost. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time takes into account the OPERABILITY of the redundant counterpart to the inoperable required feature. Additionally, the 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.

B.3.1 and B.3.2 Required Action B.3.1 provides an allowance to avoid unnecessary testing of OPERABLE DG(s). If it can be determined that the cause of the inoperable DG does not exist on the OPERABLE DG, SR 3.8.1.2 does not have to be performed. If the cause of inoperability exists on other DG(s), the other DG(s) would be declared inoperable upon discovery and Condition E of LCO 3.8.1 would be entered. Once the failure is repaired, the common cause failure no longer exists, and Required Action B.3.1 is satisfied. If the cause of the initial inoperable DG cannot be confirmed not to exist on the remaining DG(s),

performance of SR 3.8.1.2 suffices to provide assurance of continued OPERABILITY of that DG.

In the event the inoperable DG is restored to OPERABLE status prior to completing either B.3.1 or B.3.2, the problem investigation process will continue to evaluate the common cause possibility. This continued evaluation, however, is no longer under the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months constraint imposed while in Condition B.

These Conditions are not required to be entered if the inoperability of the DG is due to an inoperable support system, an independently testable component, or preplanned testing or maintenance. If required, these Required Actions are to be completed regardless of when the inoperable DG is restored to OPERABLE status.

According to Generic Letter 84-15 (Ref. 8), 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is reasonable to confirm that the OPERABLE DG(s) is not affected by the same problem as the inoperable DG.

McGuire Units 1 and 2 B 3.8.1-9 Revision No. 56

AC Sources-Operating B 3.8.1 BASES ACTIONS (continued)

B.4 According to Regulatory Guide 1.93 (Ref. 7), operation may continue in Condition B for a period that should not exceed 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

In Condition B, the remaining OPERABLE DG and offsite circuits are adequate to supply electrical power to the onsite Class 1E Distribution System. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.

The second Completion Time for Required Action B.4 establishes a limit on the maximum time allowed for any combination of required AC power sources to be inoperable during any single contiguous occurrence of failing to meet the LCO. If Condition B is entered while, for instance, an offsite circuit is inoperable and that circuit is subsequently restored OPERABLE, the LCO may already have been not met for up to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

This could lead to a total of 144 hours0.00167 days 0.04 hours 2.380952e-4 weeks 5.4792e-5 months , since initial failure to meet the LCO, to restore the DG. At this time, an offsite circuit could again become inoperable, the DG restored OPERABLE, and an additional 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months (for a total of 9 days) allowed prior to complete restoration of the LCO. The 6 day Completion Time provides a limit on time allowed in a specified condition after discovery of failure to meet the LCO. This limit is considered reasonable for situations in which Conditions A and B are entered concurrently. The "AND" connector between the 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and 6 day Completion Times means that both Completion Times apply simultaneously, and the more restrictive Completion Time must be met.

As in Required Action B.2, the Completion Time allows for an exception to the normal "time zero for beginning the allowed time "clock." This will result in establishing the utime zero" at the time that the LCO was initially not met, instead of at the time Condition B was entered.

C.1 and C.2 Required Action C.1, which applies when two offsite circuits are inoperable, is intended to provide assurance that an event with a coincident single failure will not result in a complete loss of redundant required safety functions. The Completion Time for this failure of redundant required features is reduced to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months from that allowed for one train without offsite power (Required Action A.2). The rationale for the reduction to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is that Regulatory Guide 1.93 (Ref. 7) allows a Completion Time of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for two required offsite circuits inoperable, McGuire Units 1 and 2 B 3.8.1 -10 Revision No. 56

AC Sources-Operating B 3.8.1 BASES ACTIONS (continued) based upon the assumption that two complete safety trains are OPERABLE. When a concurrent redundant required feature failure exists, this assumption is not the case, and a shorter Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is appropriate. These features are powered from redundant AC safety trains. This includes motor driven auxiliary feedwater pumps.

Single train features, such as turbine driven auxiliary pumps, are not included in the list.

The Completion Time for Required Action C.1 is intended to allow the operat6r time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal 'time zeros for beginning the allowed outage time 'clock.m In this Required Action the Completion Time only begins on discovery that both:

a. All required offsite circuits are inoperable; and

b. A required feature is inoperable.

If at any time during the existence of Condition C (two offsite circuits inoperable) a required feature becomes inoperable, this Completion Time begins to be tracked.

According to Regulatory Guide 1.93 (Ref. 7), operation may continue in Condition C for a period that should not exceed 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . This level of degradation means that the offsite electrical power system does not have the capability to effect a safe shutdown and to mitigate the effects of an accident; however, the onsite AC sources have not been degraded. This level of degradation generally corresponds to a total loss of the immediately accessible offsite power sources.

Because of the normally high availability of the offsite sources, this level of degradation may appear to be more severe than other combinations of two AC sources inoperable that involve one or more DGs inoperable.

However, two factors tend to decrease the severity of this level of degradation:

a. The configuration of the redundant AC electrical power system that remains available is not susceptible to a single bus or switching failure; and

b. The time required to detect and restore an unavailable offsite power source is generally much less than that required to detect and restore an unavailable onsite AC source.

McGuire Units 1 and 2 B 3.8.1 -1 1 Revision No. 56

AC Sources-Operating B 3.8.1 BASES ACTIONS (continued)

With both of the required offsite circuits inoperable, sufficient onsite AC sources are available to maintain the unit in a safe shutdown condition in the event of a DBA or transient. In fact, a simultaneous loss of offsite AC sources, a LOCA, and a worst case single failure were postulated as a part of the design basis in the safety analysis. Thus, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time provides a period of time to effect restoration of one of the offsite circuits commensurate with the importance of maintaining an AC electrical power system capable of meeting its design criteria.

According to Reference 6, with the available offsite AC sources, two less than required by the LCO, operation may continue for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . If two offsite sources are restored within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , unrestricted operation may continue. If only one offsite source is restored within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , power operation continues in accordance with Condition A.

D.1 and D.2 Pursuant to LCO 3.0.6, the Distribution System ACTIONS would not be entered even if all AC sources to it were inoperable, resulting in de-energization. Therefore, the Required Actions of Condition D are modified by a Note to indicate that when Condition D is entered with no AC source to any train, the Conditions and Required Actions for LCO 3.8.9, TDistribution Systems-Operating,' must be immediately entered. This allows Condition D to provide requirements for the loss of one offsite circuit and one DG, without regard to whether a train is de-energized. LCO 3.8.9 provides the appropriate restrictions for a de-energized train.

According to Regulatory Guide 1.93 (Ref. 7), operation may continue in Condition D for a period that should not exceed 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

In Condition D, individual redundancy is lost in both the offsite electrical power system and the onsite AC electrical power system. Since power system redundancy is provided by two diverse sources of power, however, the reliability of the power systems in this Condition may appear higher than that in Condition C (loss of both required offsite circuits). This difference in reliability is offset by the susceptibility of this power system configuration to a single bus or switching failure. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.

McGuire Units 1 and 2 B 3.8.1-12 Revision No. 56

AC Sources-Operating BASES .* B3.8.1 BASES ACTIONS (continued)

E.1 With Train A and Train B DGs inoperable, there are no remaining standby AC sources. Thus, with an assumed loss of offsite electrical power, insufficient standby AC sources are available to power the minimum required ESF functions. Since the offsite electrical power system is the only source of AC power for this level of degradation, the risk associated with continued operation for a very short time could be less than that associated with an immediate controlled shutdown (the immediate shutdown could cause grid instability, which could result in a total loss of AC power). Since any inadvertent generator trip could also result in a total loss of offsite AC power, however, the time allowed for continued operation is severely restricted. The intent here is to avoid the risk associated with an immediate controlled shutdown and to minimize the risk associated with this level of degradation.

According to Reference 7, with both DGs inoperable, operation may continue for a period that should not exceed 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

F.1 The sequencer(s) is an essential support system to both the offsite circuit and the DG associated with a given ESF bus. Furthermore, the sequencer is on the primary success path for most major AC electrically powered safety systems powered from the associated ESF bus.

Therefore, loss of an ESF bus sequencer affects every major ESF system in the train. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Completion Time provides a period of time to correct the problem commensurate with the importance of maintaining sequencer OPERABILITY. This time period also ensures that the probability of an accident (requiring sequencer OPERABILITY) occurring during periods when the sequencer is inoperable is minimal.

G.1 and G.2 If the inoperable AC electric power sources cannot be restored to OPERABLE status within the required Completion Time, the unit must be brought to a MODE in which the LCO does not apply. To achieve this status, the unit must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging plant systems.

McGuire Units 1 and 2 B 3.8.1-1 3 Revision No. 56

AC Sources-Operating B 3.8.1 BASES ACTIONS (continued)

H.1 Condition H corresponds to a level of degradation in which all redundancy in the AC electrical power supplies has been lost. At this severely degraded level, any further losses in the AC electrical power system will cause a loss of function. Therefore, no additional time is justified for . .

continued operation. The unit is required by LCO 3.0.3 to commence a controlled shutdown.

SURVEILLANCE The AC sources are designed to permit inspection and testing of all REQUIREMENTS important areas and features, especially those that have a standby function, in accordance with 10 CFR 50, Appendix A, GDC 18 (Ref. 9).

Periodic component tests are supplemented by extensive functional tests during refueling outages (under simulated accident conditions). The SRs for demonstrating the OPERABILITY of the DGs are in accordance with the recommendations of Regulatory Guide 1.9 (Ref. 3) and Regulatory Guide 1.137 (Ref. 11), as addressed in the UFSAR.

Since the McGuire DG manufacturer, Nordberg, is no longer in business, McGuire engineering is the designer of record. Therefore, the term "manufacturers or vendors recommendations is taken to mean the recommendations as determined by McGuire engineering, with specific Nordberg input as it is available, that were intended for the DGs, taking into account the maintenance, operating history, and industry experience, when available.

Where the SRs discussed herein specify voltage and frequency tolerances, the following is applicable. The minimum steady state output voltage of 3740 V is 90% of the nominal 4160 V output voltage. This value allows for voltage drop to the terminals of 4000 V motors whose minimum operating voltage is specified as 90% or 3600 V. It also allows for voltage drops to motors and other equipment down through the 120 V level where minimum operating voltage is also usually specified as 90%

of name plate rating. The specified maximum steady state output voltage of 4580 V is equal to the maximum operating voltage specified for 4000 V motors. It ensures that for a lightly loaded distribution system, the voltage at the terminals of 4000 V motors is no more than the maximum rated operating voltages. The specified minimum and maximum frequencies of the DG are 58.8 Hz and 61.2 Hz, respectively. These values are equal to

+/- 2% of the 60 Hz nominal frequency and are derived from the recommendations given in Regulatory Guide 1.9 (Ref. 3).

McGuire Units 1 and 2 B 3.8.1 -14 ReVision No. 56

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.1 This SR ensures proper circuit continuity for the offsite AC electrical power supply to the onsite distribution network and availability of offsite AC electrical power. The breaker alignment verifies that each breaker is in its correct position to ensure that distribution buses and loads are connected to their preferred power source, and that appropriate independence of offsite circuits is maintained. The 7 day Frequency is adequate since breaker position is not likely to change without the operator being aware of it and because its status is displayed in the control room.

SR 3.8.1.2 and SR 3.8.1.7 These SRs help to ensure the availability of the standby electrical power supply to mitigate DBAs and transients and to maintain the unit in a safe shutdown condition.

To minimize the wear on moving parts that do not get lubricated when the engine is not running, these SRs are modified by a Note (Note 2 for SR 3.8.1.2) to indicate that all DG starts for these Suirveillances may be preceded by an engine prelube period and followed by a warmup period prior to loading.

For the purposes of SR 3.8.1.2 and SR 3.8.1.7 testing, the DGs are started from standby conditions using a manual start, loss of offsite power signal, safety injection signal, or loss of offsite power coincident with a safety injection signal. Standby conditions for a DG mean that the diesel engine coolant and oil are being continuously circulated and temperature is being maintained consistent with manufacturer recommendations.

In order to reduce stress and wear, the manufacturer recommends a modified start in which the DGs are gradually accelerated to synchronous speed prior to loading.. These start procedures are the intent of Note 3, which is only applicable when such modified start procedures are recommended by the manufacturer.

SR 3.8.1.7 requires that, at a 184 day Frequency, the DG starts from standby conditions and achieves required voltage and frequency within 11 seconds. The 11 second start requirement supports the assumptions of the design basis LOCA analysis in the UFSAR, Chapter 15 (Ref. 5).

McGuire Units 1 and 2 B 3.8.1-1 5 Revision No. 56

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

The 11 second start requirement is not applicable to SR 3.8.1.2 (see Note 3) when a modified start procedure as described above is used. If a modified start is not used, the 11 second start requirement of SR 3.8.1.7 applies.

Since SR 3.8.1.7 requires a 11 second start, it is more restrictive than.

SR 3.8.1.2, and it may be performed in lieu of SR 3.8.1.2. This is the intent of Note 1 of SR 3.8.1.2.

The normal 31 day Frequency for SR 3.8.1.2 and the 184 day Frequency for SR 3.8.1.7 are consistent with Regulatory Guide 1.9 (Ref. 3) Table 1.

These Frequencies provide adequate assurance of DG OPERABILITY, while minimizing degradation resulting from testing.

SR 3.8.1.3 This Surveillance verifies that the DGs are capable of synchronizing with the offsite electrical system and accepting loads greater than or equal to the equivalent of the maximum expected accident loads. A minimum run time of 60 minutes is required to stabilize engine temperatures, while minimizing the time that the DG is connected to the offsite source.

Although no power factor requirements are established by this SR, the DG is normally operated at a power factor between 0.8 lagging and 1.0.

The 0.8 value is the design rating of the machine, while the 1.0 is an operational limitation to ensure circulating currents are minimized. The load band is provided to avoid routine overloading of the DG. Routine overloading may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY.

The 31 day Frequency for this Surveillance is consistent with Regulatory Guide 1.9 (Ref. 3) Table 1.

This SR is modified by four Notes. Note 1 indicates that diesel engine runs for this Surveillance may include gradual loading, as recommended by the manufacturer, so that mechanical stress and wear on the diesel engine are minimized. Note 2 states that momentary transients, because of changing bus loads, do not invalidate this test. Similarly, momentary power factor transients above the limit do not invalidate the test. Note 3 indicates that this Surveillance should be conducted on only one DG at a time in order to avoid common cause failures that might result from offsite circuit or grid perturbations. Note 4 stipulates a prerequisite requirement for performance of this SR. A successful DG start must precede this test to credit satisfactory performance.

McGuire Units 1 and 2 B 3.8.1-1 6 Revision No. 56

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.4 This SR provides verification that the level of fuel oil in the day tank is at or above the level at which fuel oil is automatically added. The level is expressed as an equivalent volume in gallons, and is adequate for approximately 30 minutes of DG operation at full load.

The 31 day Frequency is adequate to assure that a sufficient supply of fuel oil is available, since low level alarms are provided and facility operators would be aware of any large uses of fuel oil during this period.

SR 3.8.1.5 Microbiological fouling is a major cause of fuel oil degradation. There are numerous bacteria that can grow in fuel oil and cause fouling, but all must have a water environment in order to survive. Removal of water from the fuel oil day tanks once every 31 days eliminates the necessary environment for bacterial survival. This is the most effective means of controlling microbiological fouling. In addition, it eliminates the potential for water entrainment in the fuel oil during DG operation. Water may come from any of several sources, including condensation, ground water, rain water, contaminated fuel oil, and breakdown of the fuel oil by bacteria. Frequent checking for and removal of accumulated water minimizes fouling and provides data regarding the watertight integrity of the fuel oil system. The Surveillance Frequencies are established by Regulatory Guide 1.137 (Ref. 11). This SR is for preventative maintenance. The presence of water does not necessarily represent failure of this SR, provided the accumulated water is removed during the performance of this Surveillance.

SR 3.8.1.6 This Surveillance demonstrates that each required fuel oil transfer pump operates and transfers fuel oil from its associated storage tank to its associated day tank. This is required to support continuous operation of standby power sources. This Surveillance provides assurance that the fuel oil transfer pump is OPERABLE, the fuel oil piping system is intact, the fuel delivery piping is not obstructed, and the controls and control systems for automatic fuel transfer systems are OPERABLE.

The design of fuel transfer systems is such that pumps operate automatically or may be started manually in order to maintain an adequate volume of fuel oil in the day tanks during or following DG testing. Therefore, a 31 day Frequency is appropriate.

McGuire Units 1 and 2 B 3.8.1-17 Revision No. 56

- - >AC~ Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.7 See SR 3.8.1.2.

SR 3.8.1.8 Transfer of each 4.16 kV ESF bus power supply from the normal offsite circuit to the alternate offsite circuit demonstrates the OPERABILITY of the alternate circuit distribution network to power the shutdown loads.

The 18' month Frequency of the Surveillance is based on engineering judgment, taking into consideration the unit conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths. Operating experience has shown that these components usually pass the SR when performed at the 18 month Frequency.

Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

This SR is modified by a Note. The reason for the Note is that, during operation with the reactor critical, performance of this SR could cause perturbations to the electrical distribution systems that could challenge continued steady state operation and, as a result, unit safety systems.

SR 3.8.1.9 Each DG is provided with an engine overspeed trip to prevent damage to the engine. Recovery from the transient caused by the loss of a large load could cause diesel engine overspeed, which, if excessive, might result in a trip of the engine. This Surveillance demonstrates the DG load response characteristics and capability to reject the largest single load without exceeding predetermined voltage and frequency and while maintaining a specified margin to the overspeed trip. For this unit, the single load for each DG and its kilowatt rating is as follows: Nuclear Service Water Pump which is a 576 kW motor. This Surveillance may be accomplished by:

a. Tripping the DG output breaker with the DG carrying greater than or equal to its associated single largest post-accident load while paralleled to offsite power, or while solely supplying the bus; or

b. Tripping its associated single largest post-accident load with the DG solely supplying the bus.

As required by Regulatory Guide 1.9 (Ref. 3), the load rejection test is acceptable if the increase in diesel speed does not exceed 75% of the McGuire Units 1 and 2 B 3.8.1 -18 Revision No. 56

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued) difference between synchronous speed and the overspeed trip setpoint, or 15% above synchronous speed, whichever is lower.

The time, voltage, and frequency tolerances specified in this SR are derived from Regulatory Guide 1.9 (Ref. 3) recommendations for response during load sequence intervals. The 3 seconds specified is equal to 60% of a typical 5 second load sequence interval associated with sequencing of the largest load. The voltage and frequency specified are consistent with the design range of the equipment powered by the DG.

SR 3.8.1.9.a corresponds to the maximum frequency excursion, while SR 3.8.1.9.b and SR 3.8.1.9.c are steady state voltage and frequency values to which the system must recover following load rejection. The 18 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3) Table 1.

This Surveillance is performed with the DG connected to its bus in parallel with offsite power supply. The DG is tested under maximum kVAR loading, which is defined as being as close to design basis conditions as practical subject to offsite power conditions. Design basis conditions have been calculated to be greater than 0.9 power factor. During DG testing, equipment ratings are not to be exceeded (i.e., without creating an overvoltage condition on the DG or 4 kV emergency buses, over-excitation in the generator, or overloading the DG emergency feeder while maintaining the power factor greater than or equal to 0.9).

This Surveillance should be conducted on only one DG at a time in order to avoid common cause failures that might result from offsite circuit or grid perturbations.

SR 3.8.1.10 This Surveillance demonstrates the DG capability to reject a full load without overspeed tripping or exceeding the predetermined voltage limits.

The DG full load rejection may occur because of a system fault or inadvertent breaker tripping. This Surveillance ensures proper engine generator load response under the simulated test conditions. This test simulates the loss of the total connected load that the DG experiences following a full load rejection and verifies that the DG does not trip upon loss of the load. These acceptance criteria provide for DG damage protection. While the DG is not expected to experience this transient during an event and continues to be available, this response ensures that the DG is not degraded for future application, including reconnection to the bus if the trip initiator can be corrected or isolated.

McGuire Units 1 and 2 B 3.8.1-1 9 Revision No. 56

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

Although not representative of the design basis inductive loading that the DG would experience,' a power factor of approximately unity (1.0) is used for testing. This power factor is chosen in accordance with manufacturer's recommendations to minimize DG overvoltage during testing.

The 18 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3) and is intended to be consistent with expected fuel cycle lengths.

This Surveillance should be conducted on only one DG at a time in order to avoid common cause failures that might result from offsite circuit or grid perturbations.

SR 3.8.1.11 As required by Regulatory Guide 1.9 (Ref. 3), paragraph 2.2.4, this Surveillance demonstrates the as designed operation of the standby power sources during loss of the offsite source. This test verifies the de-energization of the emergency buses, load shedding from the emergency buses and energization of the emergency buses and blackout loads from the DG. Tripping of non-essential loads is not verified in this test. It further demonstrates the capability of the DG to automatically achieve the required voltage and frequency within the specified time.

The DG autostart time of 11 seconds is derived from requirements of the accident analysis to respond to a design basis large break LOCA. The Surveillance should be continued for a minimum of 5 minutes in order to demonstrate that all starting transients have decayed and stability is achieved.

The requirement to verify the connection and power supply of the emergency bus and autoconnected loads is intended to satisfactorily show the relationship of these loads to the DG loading logic. In certain circumstances, many of these loads cannot actually be connected or loaded without undue hardship or potential for undesired operation. For instance, Emergency Core Cooling Systems (ECCS) injection valves are not desired to be stroked open, or high pressure injection systems are not capable of being operated at full flow, or residual heat removal (RHR) systems performing a decay heat removal function are not desired to be realigned to the ECCS mode of operation. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the DG systems to perform these functions is acceptable.

This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

McGuire Units 1 and 2 B 3.8.1-20 Revision No. 56

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

The Frequency of 18 months is consistent with the recommendations of Regulatory Guide 1.9 (Ref. 3) Table 1, takes into consideration unit conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.

This SR is modified by two Notes. The reason for Note 1 is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil continuously circulated and temperature maintained consistent with manufacturer recommendations. The reason for Note 2 is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.

SR 3.8.1.12 This Surveillance demonstrates that the DG automatically starts and achieves the required voltage and frequency within the specified time (11 seconds) from the design basis actuation signal (LOCA signal) and operates for 2 5 minutes. The 5 minute period provides sufficient time to demonstrate stability. SR 3.8.1.12.d ensures that the emergency bus remains energized from the offsite electrical power system on an ESF signal without loss of offsite power. This Surveillance also verified the tripping of non-essential loads. Tripping of non-essential loads is verified only once, either in this SR or in SR 3.8.1.19, since the same circuitry is tested in each SR.

The Frequency of 18 months is consistent with Regulatory Guide 1.9 (Ref. 3) Table 1 and takes into consideration unit conditions required to perform the Surveillance and is intended to be consistent with the expected fuel cycle lengths. Operating experience has shown that these components usually pass the SR when performed at the 18 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint. This SR is modified by a Note. The reason for the Note is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil continuously circulated and temperature maintained consistent with manufacturer recommendations.

SR 3.8.1.1 3 This Surveillance demonstrates that DG noncritical protective functions (e.g., high jacket water temperature) are bypassed on a loss of voltage McGuire Units 1 and 2 B 3.8.1-21 Revision No. 56

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued) signal concurrent with an -E actuation test signal, and critical protective functions (engine overspeed, generator differential current, low lube oil pressure, generator voltage-controlled overcurrent) trip the DG to avert substantial damage to the DG unit. The noncritical trips are bypassed during DBAs and provide an alarm on an abnormal engine condition.

This alarm provides the operator with sufficient time to react appropriately. The DG availability to mitigate the DBA is more critical than protecting the engine against minor problems that are not immediately detrimental to emergency operation of the DG.

The 18 month Frequency is consistent with Regulatory Guide 1.9 (Ref. 3)

Table 1, taking into consideration unit conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths. Operating experience has shown that these components usually pass the SR when performed at the 18 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

This SR is not normally performed in MODE 1 or 2, but it may be performed in conjunction with periodic preplanned preventative maintenance activity that causes the DG to be inoperable. This is acceptable provided that performance of the SR does not increase the time the DG would be inoperable for the preplanned preventative maintenance activity.

SR 3.8.1.14 Regulatory Guide 1.9 (Ref. 3), paragraph 2.2.9, requires demonstration once per 18 months that the DGs can start and run continuously at full load capability for an interval of not less than 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , 2 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months of which is at a load equivalent from 105% to 110% of the continuous duty rating and the remainder of the time at a load equivalent to the continuous duty rating of the DG. The DG starts for this Surveillance can be performed either from standby or hot conditions. The provisions for prelubricating and warmup, discussed in SR 3.8.1.2, and for gradual loading, discussed in SR 3.8.1.3, are applicable to this SR.

This Surveillance is performed with the DG connected to its bus in parallel with offsite power supply. The DG is tested under maximum kVAR loading, which is defined as being as close to design basis conditions as practical subject to offsite power conditions. Design basis conditions have been calculated to be greater than 0.9 power factor. During DG testing, equipment ratings are not to be exceeded (i.e., without creating an overvoltage condition on the DG or 4 kV emergency buses, over-excitation in the generator, or overloading the DG emergency feeder while maintaining the power factor greater than or equal to 0.9).

McGuire Units 1 and 2 B 3.8.1-22 Revision No. 56

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

The load band is provided to avoid routine overloading of the DG.

Routine overloading may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY.

The 18 month Frequency is consistent with the recommendations of Regulatory Guide 1.9 (Ref. 3) Table 1, takes into consideration unit conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.

This Surveillance is modified by two Notes. Note 1 states that momentary transients due to changing bus loads do not invalidate this test. Note 2 allows gradual loading of the DG in accordance with recommendation from the manufacturer.

This Surveillance should be conducted on only one DG at a time in order to avoid common cause failures that might result from offsite circuit or grid perturbations.

SR 3.8.1.15 This Surveillance demonstrates that the diesel engine can restart from a hot condition, such as subsequent to shutdown from normal Surveillances, and achieve the required voltage and frequency within 11 seconds. The 11 second time is derived from the requirements of the accident analysis to respond to a design basis large break LOCA. The 18 month Frequency is consistent with the recommendations of Regulatory Guide 1.9 (Ref. 3) Table 1.

This SR is modified by two Notes. Note 1 ensures that the test is performed with the diesel sufficiently hot. -The load band is provided to avoid routine overloading of the DG. Routine overloads may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY. The requirement that the diesel has operated for at least 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months at full load conditions prior to performance of this Surveillance is based on manufacturer recommendations for achieving hot conditions. Momentary transients due to changing bus loads do not invalidate this test. Note 2 allows all DG starts to be preceded by an engine prelube period to minimize wear and tear on the diesel during testing.

McGuire Units 1 and 2 B 3.8.1-23 Revision No. 56

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.16 As required by Regulatory Guide 1.9 (Ref. 3), paragraph 2.2.11, this Surveillance ensures that the manual synchronization and automatic load transfer from the DG to the offsite source can be made and the DG can be returned to standby operation when offsite power is restored. It also ensures that the autostart logic is reset to allow the DG to reload if a subsequent loss of offsite power occurs. The DG is considered to be in standby operation when the DG is at rated speed and voltage, the output breaker is open and can receive an autoclose signal on bus undervoltage, and the load sequence timers are reset.

The Frequency of 18 months is consistent with the recommendations of Regulatory Guide 1.9 (Ref. 3) Table 1, and takes into consideration unit conditions required to perform the Surveillance. This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.

SR 3.8.1.17 Demonstration of the test mode override ensures that the DG availability under accident conditions will not be compromised as the result of testing and the DG will automatically reset to standby operation if a LOCA actuation signal is received during operation in the test mode. Standby operation is defined as the DG running at rated speed and voltage with the DG output breaker open. These provisions for automatic switchover are required by Regulatory Guide 1.9 (Ref. 3), paragraph 2.2.13. The requirement to automatically energize the emergency loads with offsite power is essentially identical to that of SR 3.8.1.12. The intent in the requirement associated with SR 3.8.1.1 7.b is to show that the emergency loading was not affected by the DG operation in test mode. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the emergency loads to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

The 18 month Frequency is consistent with the recommendations of Regulatory Guide 1.9 (Ref. 3) Table 1, takes into consideration unit conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.

McGuire Units 1 and 2 B 3.8.1-24 Revision No. 56

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUI REMENTS (conti-u6d)-

This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.

SR 3.8.1.18.

Under accident and loss of offsite power conditions loads are sequentially connected to the bus by the automatic load sequencer. The sequencing logic c6ntrols the permissive and starting signals to motor breakers to prevent overloading of the DGs due to high motor starting currents. The load sequence time interval tolerance in Table 8-16 of Reference 2 ensures that sufficient time exists for the DG to restore frequency and voltage prior to applying the next load and that safety analysis assumptions regarding ESF equipment time delays are not violated.

Table 8-1 of Reference 2 provides a summary of the automatic loading of ESF buses. The sequencing times of Table 8-16 are committed and required for OPERABILITY. The typical 1 minute loading duration seen by the accelerated sequencing scheme is NOT required for OPERABILITY.

Operating experience has shown that these components usually pass the SR when performed at the 18 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

This takes into consideration unit conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.

SR 3.8.1.1 9 In the event of a DBA coincident with a loss of offsite power, the DGs are required to supply the necessary power to ESF systems so that the fuel, RCS, and containment design limits are not exceeded.

This Surveillance verifies the de-energization of the emergency buses, load shedding from the emergency buses, tripping of non-essential loads and energization of the emergency buses and ESF loads from the DG.

Tripping of non-essential loads is verified only once, either in this SR or in SR 3.8.1.12, since the same circuitry is tested in each SR. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the DG system to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

McGuire Units 1 and 2 B 3.8.1-25 Revision No. 56

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

The Frequency of 18 months is consistent with Regulatory Guide 1.9 (Ref. 3) Table 1.

This SR is modified by two Notes. The reason for Note 1 is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil continuously circulated and temperature maintained consistent with manufacturer recommendations for DGs. The reason for Note 2 is that the performance of the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.

SR 3.8.1.20 This Surveillance demonstrates that the DG starting independence has not been compromised. Also, this Surveillance demonstrates that each engine can achieve proper speed within the specified time when the DGs are started simultaneously.

The 10 year Frequency is consistent with the recommendations of Regulatory Guide 1.9 (Ref. 3) Table 1.

This SR is modified by a Note. The reason for the Note is to minimize wear on the DG during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil continuously circulated and temperature maintained consistent with manufacturer recommendations.

REFERENCES 1. 10 CFR 50, Appendix A, GDC 17.

2. UFSAR, Chapter 8.

3. Regulatory Guide 1.9, Rev. 3, July 1993.

4. UFSAR, Chapter 6.

5. UFSAR, Chapter 15.

6. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).

7. Regulatory Guide 1.93, Rev. 0, December 1974.

8. Generic Letter 84-15, "Proposed Staff Actions to Improve and Maintain Diesel Generator Reliability," July 2, 1984.

9. 10 CFR 50, Appendix A, GDC 18.

McGuire Units 1 and 2 B 3.8.1-26 Revision No. 56

AC Sources-Operating B 3.8.1 BASES

10. Regulatory Guide 1.137, Rev. 1, October 1979.

11. IEEE Standard 308-1971.

12. Regulatory Guide 1.6, Rev. 0, March 1971.

13. Regulatory Guide 1.8.1, Rev. 1, January 1975.

McGuire Units 1 and 2 B 3.8.147 Revision No. 56

RHR and Coolant Circulation-High Water Level B 3.9.5

. U.

B 3.9 REFUELING OPERATIONS B 3.9.5 Residual Heat Removal (RHR) and Coolant Circuiation-High Water Level BASES BACKGROUND The purpose of the RHR System in MODE 6 is to remove decay heat and sensible heat from the Reactor Coolant System (RCS), as required by GDC 34, to provide mixing of borated coolant and to prevent boron stratification (Ref. 1). Heat is removed from the RCS by circulating reactor coolant through the RHR heat exchanger(s), where the heat is transferred to the Component Cooling Water System. The coolant is then returned to the.RCS via the RCS cold leg(s). Operation of the RHR System for normal cooldown or decay heat removal is manually accomplished from the control room. The heat removal rate is adjusted by controlling the flow of reactor coolant and component cooling water through the RHR heat exchanger(s). Mixing of the reactor coolant is maintained by this continuous circulation of reactor coolant through the RHR System.

APPLICABLE If the reactor coolant temperature is not maintained below 2000F, I SAFETY ANALYSES boiling of the reactor coolant could result. This could lead to a loss of coolant in the reactor vessel. Additionally, boiling of the reactor coolant could lead to a reduction in boron concentration in the coolant due to boron plating out on components near the areas of the boiling activity.

The loss of reactor coolant and the reduction of boron concentration in the reactor coolant would eventually challenge the integrity of the fuel cladding, which is a fission product barrier. One train of the RHR System is required to be operational in MODE 6, with the water level 2 23 ft above the top of the reactor vessel flange, to prevent this challenge. The LCO does permit de-energizing the RHR pump for short durations, under the condition that the boron concentration is not diluted. This conditional de-energizing of the RHR pump does not result in a challenge to the fission product barrier.

The RHR System satisfies Criterion 4 of 10 CFR 50.36 (Ref. 2).

LCO Only one RHR loop is required for decay heat removal in MODE 6, with the water level 2 23 ft above the top of the reactor vessel flange. Only one RHR loop is required to be OPERABLE, because the volume of water above the reactor vessel flange provides backup decay heat removal capability. At least one RHR loop must be OPERABLE and in operation to provide:

McGuire Units 1 and 2 B 3.9.5-1 Revision No. 59

RHR and Coolant Circulation - High Water Level B 3.9.5 BASES LCO (continued)

a. Removal of decay heat;

b. Mixing of borated coolant to minimize the possibility of criticality; and

c. Indication of reactor coolant temperature.

An OPERABLE RHR loop includes an RHR pump, a heat exchanger, valves; piping, instruments, and controls to ensure an OPERABLE flow path and to determine the low end temperature. The flow path starts in one of the RCS hot legs and is returned to the RCS cold legs. The operability of the operating RHR train and.the supporting heat sink is dependent on the ability to maintain the desired RCS temperature.

The LCO is modified by a Note that allows the required operating RHR loop to be removed from service for up to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months per 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months period, provided no operations are permitted that would dilute the RCS boron concentration with coolant at boron concentrations less than required to meet the minimum boron concentration of LCO 3.9.1. Boron concentration reduction with coolant at boron concentrations less than required to assure minimum required RCS boron concentration is maintained is prohibited because uniform concentration distribution cannot be ensured without forced circulation. This permits operations such as core mapping or alterations in the vicinity of the reactor vessel hot leg nozzles and RCS to RHR isolation valve testing. During this 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months period, decay heat is removed by natural convection to the large mass of water in the refueling cavity.

The acceptability of the LCO and the LCO NOTE is based on preventing boiling in the core in the event of the loss of RHR cooling. However, it has been determined that when the upper internals are in place in the reactor vessel there is insufficient communication with the water above the core for adequate decay heat removal by natural circulation. As a result, boiling in the core could occur in a relatively short time if RHR cooling is lost. Therefore, during the short period of time that the upper internals are installed, administrative processes are implemented to reduce the risk of core boiling. The availability of additional cooling equipment, including equipment not required to be OPERABLE by the Technical Specifications, contributes to this risk reduction. The plant staff assesses these cooling sources to assure that the desired minimal level of risk is maintained. This is commonly referred to as defense-in-depth.

This strategy is consistent with NUMARC 91-06, "Guidelines for Industry Actions to Assess Shutdown Management.' (Ref.3)

McGuire Units 1 and 2 B 3.9.5-2 Revision No. 59

tt RHR and Coolant Circulation - High Water Level B 3.9.5 BASES APPLICABILITY One RHR loop must be OPERABLE and in operation in MODE 6, with the water level 2 23 ft above the top of the reactor vessel flange, to provide decay heat removal. The 23 ft water level was selected because it corresponds to the 23 ft requirement established for fuel movement in LCO 3.9.7, Refueling Cavity Water Level.' Requirements for the RHR System in other MODES are covered by LCOs in Section 3.4, Reactor Coolant System (RCS), and Section 3.5, Emergency Core Cooling Systems (ECCS). RHR loop requirements in MODE 6 with the water level < 23 ft are located in LCO 3.9.6, "Residual Heat Removal (RHR) and Coolant Circulation-Low Water Level."

ACTIONS RHR loop requirements are met by having one RHR loop OPERABLE and in operation, except as permitted in the Note to the LCO.

A.1 If RHR loop requirements are not met, there will be no forced circulation to provide mixing to establish uniform boron concentrations. Suspending positive reactivity additions that could result in failure to meet the minimum boron concentration limit is required to assure continued safe operation. Introduction of coolant inventory must be from sources that have a boron concentration greater than that which would be required in the RCS for minimum refueling boron concentration. This may result in an overall reduction in RCS boron concentration, but provides acceptable margin to maintaining subcritical operation.

A.2 If RHR loop requirements are not met, actions shall be taken immediately to suspend loading of irradiated fuel assemblies in the core. With no forced circulation cooling, decay heat removal from the core occurs by natural convection to the heat sink provided by the water above the core.

A minimum refueling water level of 23 ft above the reactor vessel flange provides an adequate available heat sink. Suspending any operation that would increase decay heat load, such as loading a fuel assembly, is a prudent action under this condition.

A.3 If RHR loop requirements are not met, actions shall be initiated and continued in order to satisfy RHR loop requirements. With the unit in MODE 6 and the refueling water level 2 23 ft above the top of the reactor vessel flange, corrective actions shall be initiated immediately.

McGuire Units 1 and 2 B 3.9.5-3 Revision No. 59

RHR and Coolant Circulation - High Water Level B 3.9.5 BASES ACTIONS (continued)

A.4 If RHR loop requirements are not met, all containment penetrations providing direct access from the containment atmosphere to the outside atmosphere must be closed within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . With the RHR loop requirements not met, the potential exists for the coolant to boil and release radioactive gas to the containment atmosphere. Closing contairiment penetrations that are open to the outside atmosphere ensures dose limits are not exceeded.

The Completion Time of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is reasonable, based on the low probability of the coolant boiling in that time.

SURVEILLANCE SR 3.9.5.1 REQUIREMENTS This Surveillance demonstrates that the RHR loop is in operation and circulating reactor coolant. The flow rate is determined by the flow rate necessary to provide sufficient decay heat removal capability and to prevent thermal and boron stratification in the core. The RCS temperature is determined to ensure the appropriate decay heat removal is maintained. The Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is sufficient, considering the flow, temperature, pump control, and alarm indications available to the operator in the control room for monitoring the RHR System.

REFERENCES 1. UFSAR, Section 5.5.7.

2. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).

3. NUMARC 91-06, -'Guidelines for Industry Actions to Assess Shutdown Management".

McGuire Units 1 and 2 B 3.9.5-4 Revision No. 59

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ATTACHMENT 2 REVISED TECHNICAL SPECIFICATION AND BASES LIST OF EFFECTIVE SECTIONS

McGuire Nuclear Station Technical Specifications List of Affected Pages / Sections Page Number Amendment Revision Date 184/166 9/30/98 ii 184/166 9/30/98 iii 184/166 9/30/98 iv 184/166 9/30/98 1.1-1 184/166 9/30/98 1.1-2 184/166 9/30/98 1.1-3 206/187 8/23/02 1.1-4 194/175 9/18/00 1.1-5 206/187 8/23/02 1.1-6 206/187 8/23/02 1.1-7 194/175 9/18/00 1.2-1 184/166 9/30/98 1.2-2 184/166 9/30/98 1.2-3 184/166 9/30/98 1.3-1 184/166 9/30/98 1.3-2 184/166 9/30/98 1.3-3 184/166 9/30/98 1.3-4 184/166 9/30/98 1.3-5 184/166 9/30/98 1.3-6 184/166 9/30/98 1.3-7 184/166 9/30/98 1.3-8 184/166 9/30/98 1.3-9 184/166 9/30/98 1.3-10 184/166 9/30/98 1.3-11 184/166 9/30/98 1.3-12 184/166 9/30/98 1.3-13 184/166 9/30/98 1.4-1 184/166 9/30/98 1.4-2 184/166 9/30/98 1.4-3 184/166 9/30/98 1.4-4 184/166 9/30/98 McGuire Units I and 2 Page I Revision 55

Page Number Amendment Revision Date 2.0-1 219/201 1/14/04 3.0-1 221/203 4/29/04 3.0-2 221/203 4/29/04 3.0-3 221/203 4/29/04 3.0-4 205/186 8/12/02 3.0-5 221/203 4/29/04 3.1.1-1 184/166 9/30/98 3.1.2-1 184/166 9/30/98 3.1.2-2 184/166 9/30/98 3.1.3-1 184/166 9/30/98 3.1.3-2 184/166 9/30/98 3.1.3-3 184/166 9/30/98 3.1.4-1 184/166 9/30/98 3.1.4-2 184/166 9/30/98 3.1.4-3 184/166 9/30/98 3.1.4-4 186/167 9/8/99 3.1.5-1 184/166 9/30/98 3.1.5-2 184/166 9/30/98 3.1.6-1 184/166 9/30/98 3.1.6-2 184/166 9/30/98 3.1.6-3 184/166 9/30/98 3.1.7-1 184/166 9/30/98 3.1.7-2 184/166 9/30/98 3.1.8-1 184/166 9/30/98 3.1.8-2 184/166 9/30/98 3.2.1-1 184/166 9/30/98 3.2.1-2 184/166 9/30/98 3.2.1-3 184/166 9/30/98 3.2.1-4 188/169 9/22/99 3.2.1-5 188/169 9/22/99 3.2.2-1 184/166 9/30/98 3.2.2-2 184/166 9/30/98 3.2.2-3 184/166 9/30/98 McGuire Units 1 and 2 Page 2 Revision 55

Page Number Amendment Revision Date 3.2.2-4 188/169 9/22/99 3.2.3-1 184/166 9/30/98 3.2.4-1 184/166 9/30/98 3.2.4-2 184/166 9/30/98 3.2.4-3 184/166 9/30/98 3.2.4-4 184/166 9/30/98 3.3.1-1 184/166 9/30/98 3.3.1-2 184/166 9/30/98 3.3.1-3 216/197 7/29/03 3.3.1-4 216/197 7/29/03 3.3.1-5 184/166 9/30/98 3.3.1-6 184/166 9/30/98 3.3.1-7 184/166 9/30/98 3.3.1-8 184/166 9/30/98 3.3.1-9 184/166 9/30/98 3.3.1-10 184/166 9/30/98 3.3.1-11 184/166 9/30/98 3.3.1-12 184/166 9/30/98 3.3.1-13 184/166 9/30/98 3.3.1-14 194/175 9/18/00 3.3.1 -15 222/204 6/21/04 3.3.1-16 194/175 9/18/00 3.3.1-17 194/175 9/18/00 3.3.1-18 219/201 1/14/04 3.3.1-19 219/201 1/14/04 3.3.1-20 184/166 9/30/98 3.3.2-1 184/166 9/30198 3.3.2-2 184/166 9/30/98 3.3.2-3 184/166 9/30/98 3.3.2-4 184/166 9/30/98 3.3.2-5 184/166 9/30/98 3.3.2-6 198/179 4/12/01 3.3.2-7 198/179 4/12/01 McGuire Units 1 and 2 Page 3 Revision 55

Page Number Amendment Revision Date 3.3.2-8 184/166 9/30/98 3.3.2-9 184/166 9/30/98 3.3.2-10 220/202 3/18/04 3.3.2-11 220/202 3/18/04 3.3.2-12 220/202 3/18/04 3.3.2-13 220/202 3/18/04 3.3.2-14 220/202 3/18/04 3.3.3-1 221/203 4/29/04 3.3.3-2 184/166 9/30/98 3.3.3-3 184/166 9/30/98 3.3.3-4 184/166 9/30/98 3.3.4-1 221/203 4/29/04 3.3.4-2 184/166 9/30/98 3.3.4-3 184/166 9/30/98 3.3.5-1 184/166 9/30/98 3.3.5-2 194/175 9/18/00 3.3.6-1 184/166 9/30/98 3.3.6-2 184/166 9/30/98 3.3.6-3 194/175 9/18/00 3.4.1-1 219/201 1/14/04 3.4.1-2 219/201 1/14/04 3.4.1-3 184/166 9/30/98 3.4.1-4 219/201 1/14/04 3.4.2-1 184/166 9/30/98 3.4.3-1 214/195 7/3/03 3.4.3-2 184/166 9/30/98 3.4.3-3 214/195 7/3/03 3.4.3-4 214/195 7/3/03 3.4.3-5 214/195 7/3/03 3.4.3-6 214/195 7/3/03 3.4.3-7 214/195 7/3/03 3.4.3-8 214/195 7/3/03 3.4.4-1 184/166 9/30/98 McGuire Units I and 2 Page 4 Revision 55

Page Number Amendment Revision Date 3.4.5-1 216/197 7/29/03 3.4.5-2 216/197 7/29/03 3.4.5-3 184/166 9/30/98 3.4.6-1 216/197 7/29/03 3.4.6-2 216/197 7/29/03 3.4.7-1 216/197 7/29/03 3.4.7-2 216/197 7/29/03 3.4.7-3 216/197 7/29/03 3.4.8-1 . 216/197 7/29/03 3.4.8-2 216/197 7/29/03 3.4.9-1 184/166 9/30/98 3.4.9-2 184/166 9/30/98 3.4.10-1 184/166 9/30/98 3.4.10-2 184/166 9/30/98 3.4-11-1 221/203 4/29/04 3.4.11-2 184/166 9/30/98 3.4-11-3 184/166 9/30/98 3.4.11-4 184/166 9/30/98 3.4.12-1 184/166 9/30/98 3.4.12-2 221/203 4/29/04 3.4.12-3 214/195 7/3/03 3.4.12-4 214/195 7/3/03 3.4.12-5 184/166 9/30/98 3.4.12-6 184/166 9/30/98 3.4.13-1 184/166 9/30/98 3.4.13-2 184/166 9/30/98 3.4.14-1 184/166 9/30/98 3.4.14-2 184/166 9/30/98 3.4.14-3 184/166 9/30/98 3.4.14-4 184/166 9/30/98 3.4.15-1 221/203 4/29/04 3.4.15-2 184/166 9/30/98 3.4.15-3 184/166 9/30/98 McGuire Units 1 and 2 Page 5 Rrevision 55

Page Number Amendment Revision Date 3.4.16-1 221/203 4/29/04 3.4.16-2 184/166 9/30/98 3.4.16-3 184/166 9/30/98 3.4.16-4 184/166 9/30/98 3.4.17-1 184/166 9/30/98 3.5.1-1 218/200 12/23/03 3.5.1-2 184/166 9/30/98 3.5.2-1 184/166 9/30/98 3.5.2-2 184/166 9/30/98 3.5.2-3 184/166 9/30/98 3.5.3-1 221/203 4/29/04 3.5.3-2 184/166 9/30/98 3.5.4-1 184/166 9/30/98 3.5.4-2 184/166 9130/98 3.5.5-1 184/166 9/30/98 3.5.5-2 184/166 9/30/98 3.6.1-1 207/188 9/4/02 3.6.1-2 207/188 9/4/02 3.6.2-1 184/166 9/30/98 3.6.2-2 184/166 9/30/98 3.6.2-3 184/166 9/30/98 3.6.2-4 184/166 9/30/98 3.6.2-5 207/188 9/4/02 3.6.3-1 184/166 9/30/98 3.6.3-2 184/166 9/30/98 3.6.3-3 184/166 9/30/98 3.6.3-4 184/166 9/30/98 3.6.3-5 184/166 9/30/98 3.6.3-6 207/188 9/4/02 3.6.3-7 207/188 9/4/02 3.6.4-1 184/166 9/30/98 3.6.5-1 184/166 9/30198 3.6.5-2 184/166 9/30198 McGuire Units 1 and 2 Page 6 Revision 55

Page Number Amendment Revision Date 3.6.6-1 184/166 9/30/98 3.6.6-2 184/166 9/30/98 3.6.7-1 221/203 4/29/04 3.6.7-2 184/166 9/30/98 3.6.8-1 221/203 4/29/04 3.6.8-2 184/166 9/30/98 3.6.9-1 184/166 9/30/98 3.6.9-2 184/166 9/30/98 3.6.10-1 184/166 9/30/98 3.6.10-2 184/166 9/30/98 3.6.11-1 184/166 9/30/98 3.6.11-2 184/166 9/30/98 3.6.12-1 184/166 9/30/98 3.6.12-2 217/199 9/29/03 3.6.12-3 217/199 9/29/03 3.6.13-1 184/166 9/30/98 3.6.13-2 184/166 9/30/98 3.6.13-3 184/166 9/30/98 3.6.14-1 184/166 9/30/98 3.6.14-2 184/166 9/30/98 3.6.14-3 184/166 9/30/98 3.6.15-1 184/166 9/30/98 3.6.15-2 184/166 9/30/98 3.6.16-1 212/193 5/8/03 3.6.16-2 212/193 5/8/03 3.7.1-1 184/166 9/30/98 3.7.1-2 184/166 9/30/98 3.7.1-3 184/166 9/30/98 3.7.2-1 184/166 9/30/98 3.7.2-2 184/166 9/30/98 3.7.3-1 184/166 9/30/98 3.7.3-2 184/166 9/30/98 3.7.4-1 221/203 4/29/04 McGuire Units 1 and 2 Page 7 Revision 55

i I I Page Number Amendment Revision Date 3.7.4-2 184/166 9/30/98 3.7.5-1 221/203 4/29/04 3.7.5-2 184/166 9/30/98 3.7.5-3 184/166 9/30/98 3.7.5-4 184/166 9/30/98 3.7.6-1 184/166 9/30/98 3.7.6-2 184/166 9/30/98 3.7.7-1 184/166 9/30/98 3.7.7-2 184/166 9/30/98 3.7.8-1 184/166 9/30/98 3.7.8-2 184/166 9/30/98 3.7.9-1 187/168 9/22/99 3.7.9-2 187/168 9/22/99 3.7.9-3 184/166 9/30/98 3.7.10-1 184/166 9/30/98 3.7.10-2 184/166 9/30/98 3.7.11-1 184/166 9/30/98 3.7.11-2 184/166 9/30/98 3.7.12-1 184/166 9/30/98 3.7.12-2 184/166 9/30/98 3.7.13-1 184/166 9/30/98 3.7.14-1 184/166 9/30/98 3.7.15-1 197/178 11/27/00 3.7.15-2 197/178 11/27/00 3.7.15-3 197/178 11/27/00 3.7.15-4 197/178 11/27/00 3.7.15-5 197/178 11/27/00 3.7.15-6 197/178 11/27/00 3.7.15-7 197/178 11/27/00 3.7.15-8 197/178 11/27/00 3.7.15-9 210/191 2/4/03 3.7.15-10 210/191 2/4/03 3.7.15-11 210/191 2/4/03 McGuire Units 1 and 2 Page 8 Revision 55

I Page Number Amendment Revision Date 3.7.15-12 197/178 11/27/00 3.7.15-13 197/178 11/27/00 3.7.15-14 197/178 11/27/00 3.7.15-15 197/178 11/27/00 3.7.15-16 210/191 2/4/03 3.7.15-17 210/191 2/4/03 3.7.15-18 210/191 2/4/03 3.7.15-19 210/191 2/4/03 3.7.15-20 197/178 11/27/00 3.7.15-21 197/178 11/27/00 3.7.16-1 184/166 9/30/98 3.8.1-1 221/203 4/29/04 3.8.1-2 184/166 9/30/98 3.8.1-3 184/166 9/30/98 3.8.1-4 184/166 9/30/98 3.8.1-5 184/166 9/30/98 3.8.1-6 184/166 9/30/98 3.8.1-7 184/166 9/30/98 3.8.1-8 192/173 3/15/00 3.8.1-9 184/166 9/30/98 3.8.1-10 184/166 9/30/98 3.8.1-11 192/173 3/15/00 3.8.1-12 184/166 9/30/98 3.8.1 -13 184/166 9/30/98 3.8.1-14 184/166 9/30/98 3.8.1-15 184/166 9/30/98 3.8.2-1 184/166 9/30/98 3.8.2-2 216/197 7/29/03 3.8.2-3 184/166 9/30/98 3.8.3-1 184/166 9/30/98 3.8.3-2 184/166 9/30/98 3.8.3-3 215/196 8/4/03 3.8.4-1 184/166 9/30/98 McGuire Units 1 and 2 Page 9 Revision 55

I, I-Page Number Amendment Revision Date 3.8.4-2 184/166 9/30/98 3.8.4-3 209/190 12/17/02 3.8.5-1 184/166 9/30/98 3.8.5-2 216/197 7/29/03 3.8.6-1 184/166 9/30/98 3.8.6-2 184/166 9/30/98 3.8.6-3 184/166 9/30/98 3.8.6-4 184/166 9/30/98 3.8.7-1 . 184/166 9/30/98 3.8.8-1 184/166 9/30/98 3.8.8-2 216/197 7/29/03 3.8.9-1 184/166 9/30/98 3.8.9-2 184/166 9/30/98 3.8.10-1 216/197 7/29/03 3.8.10-2 184/166 9/30/98 3.9.1-1 184/166 9/30/98 3.9.2-1 184/166 9/30/98 3.9.3-1 216/197 7/29/03 3.9.3-2 184/166 9/30/98 3.9.4-1 184/166 9/30/98 3.9.4-2 184/166 9/30/98 3.9.5-1 216/197 7/29/03 3.9.5-2 184/166 9/30/98 3.9.6-1 216/197 7/29/03 3.9.6-2 184/166 9/30/98 3.9.7-1 184/166 9/30/98 4.0.1 222/204 6/21/04 4.0.2 197/178 11/27/00 5.1-1 213/194 6/6/03 5.2-1 184/166 9/30/98 5.2-2 184/166 9/30/98 5.2-3 213/194 6/6/03 5.3-1 213/194 6/6/03 McGuire Units I and 2 Page 10 Revision 55

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Page Number Amendment Revision Date 5.4-1 184/166 9/30/98 5.5-1 212/193 5/8/03 5.5-2 212/193 5/8/03 5.5-3 184/166 9/30/98 5.5-4 184/166 9/30/98 5.5-5 190/171 12/21/99 5.5-6 184/166 9/30/98 5.5-7 184/166 9/30/98 5.5-8 184/166 9/30/98 5.5-9 184/166 9/30/98 5.5-10 184/166 9130/98 5.5-11 184/166 9/30/98 5.5-12 184/166 9/30/98 5.5-13 184/166 9/30/98 5.5-14 196/177 11/2/00 5.5-15 184/166 9/30/98 5.5-16 215/196 8/4/03 5.5-17 215/196 8/4/03 5.5-18 184/166 9/30/98 5.6-1 184/166 9/30/98 5.6-2 2191201 1/14/04 5.6-3 219/201 1/14/04 5.6-4 203/184 7/10/02 5.6-5 184/166 9/30/98 5.7-1 2131194 6/6/03 5.7-2 184/166 9/30/98 BASES (Revised per section)

Revision 0 9/30/98 ii Revision 0 9/30/98 iii Revision 0 9/30/98 B 2.1.1 Revision 51 1/14/04 McGuire Units 1 and 2 Page I I Revision 55

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Page Number Amendment Revision Date B 2.1.2 Revision 0 9/30/98 B3.0 Revision 57 4/29/04 B 3.1.1 Revision 0 9/30/98 B 3.1.2 Revision 10 9/22/00 B 3.1.3 Revision 10 9/22/00 B 3.1.4 Revision 0 9/30/98 B 3.1.5 Revision 19 1/10/02 B 3.1.6 Revision 0 9/30/98 B 3.1.7 . Revision 58 06/23/04 B 3.1.8 Revision 0 9/30/98 B 3.2.1 Revision 34 10/1/02 B 3.2.2 Revision 10 9/22/00 B 3.2.3 Revision 34 10/1/02 B 3.2.4 Revision 10 9/22/00 B 3.3.1 Revision 53 2/17/04 B 3.3.2 Revision 55 3/18/04 B 3.3.3 Revision 57 4/29/04 B 3.3.4 Revision 57 4/29/04 B 3.3.5 Revision 11 9/18/00 B 3.3.6 Revision 0 9/30/98 B 3.4.1 Revision 51 1/14/04 B 3.4.2 Revision 0 9/30/98 B 3.4.3 Revision 44 7/3/03 B 3.4.4 Revision 0 9/30/98 B 3.4.5 Revision 41 7/29/03 B 3.4.6 Revision 41 7/29/03 B 3.4.7 Revision 41 7/29/03 B 3.4.8 Revision 41 7/29/03 B 3.4.9 Revision 0 9/30/98 B 3.4.10 Revision 0 9/30/98 B 3.4.11 Revision 57 4/29/04 B 3.4.12 Revision 57 4/29/04 B 3.4.13 Revision 53 2/17/04 McGuire Units I and 2 Page 12 Revision 55

Page Number Amendment Revision Date B 3.4.14 Revision 0 9/30/98 B 3.4.15 Revision 57 4/29/04 B 3.4.16 Revision 57 4/29/04 B 3.4.17 Revision 0 9/30/98 B 3.5.1 Revision 48 12/23/03 B 3.5.2 Revision 45 8/20/03 B 3.5.3 Revision 57 4/29/04 B 3.5.4 Revision 0 9/30/98 B 3.5.5 . Revision 0 9/30/98 B 3.6.1 Revision 53 2/17/04 B 3.6.2 Revision 32 10/4/02 B 3.6.3 Revision 32 10/4/02 B 3.6.4 Revision 0 9/30/98 B 3.6.5 Revision 0 9/30/98 B 3.6.6 Revision 0 9/30/98 B 3.6.7 Revision 57 4/29/04 B 3.6.8 Revision 57 4/29/04 B 3.6.9 Revision 0 9/30/98 B 3.6.10 Revision 43 5/28/03 B 3.6.11 Revision 0 9/30/98 B 3.6.12 Revision 53 2/17/04 B 3.6.13 Revision 0 9/30/98 B 3.6.14 Revision 0 9/30/98 B 3.6.15 Revision 0 9/30/98 B 3.6.16 Revision 40 5/8/03 B 3.7.1 Revision 0 9/30/98 B 3.7.2 Revision 0 9/30/98 B 3.7.3 Revision 0 9/30/98 B 3.7.4 Revision 57 4/29/04 B 3.7.5 Revision 57 4/29/04 B 3.7.6 Revision 0 9/30/98 B 3.7.7 Revision 0 9/30/98 B 3.7.8 Revision 0 9/30/98 McGuire Units 1 and 2 Page 13 Revision 55

Page Number Amendment Revision Date B 3.7.9 Revision 43 5/28/03 B 3.7.10 Revision 0 9/30/98 B 3.7.11 Revision 39 3/19/03 B 3.7.12 Revision 28 5/17/02 B 3.7.13 Revision 0 9/30/98 B 3.7.14 Revision 52 1/7/04 B 3.7.15 Revision 52 1/7/04 B 3.7.16 Revision 0 9/30/98 B 3.8.1 . Revision 56 6/8/04 B 3.8.2 Revision 49 10/22/03 B 3.8.3 Revision 53 2/17/04 B 3.8.4 Revision 36 12/17/02 B 3.8.5 Revision 41 7/29/03 B 3.8.6 Revision 0 9/30/98 B 3.8.7 Revision 20 1/10/02 B 3.8.8 Revision 41 7/29/03 B 3.8.9 Revision 24 2/4/02 B 3.8.10 Revision 41 7/29/03 B 3.9.1 Revision 41 7/29/03 B 3.9.2 Revision 41 7/29/03 B 3.9.3 Revision 41 7/29/03 B 3.9.4 Revision 0 9/30/98 B 3.9.5 Revision 59 7/29/04 B 3.9.6 Revision 41 7/29/03 B 3.9.7 Revision 0 9/30/98 McGuire Units 1 and 2 Page 14 Revision 55

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