CPSES-200602078, License Amendment Request (LAR) 06-007, Revision to Technical Specification (TS) 3.8.1, AC Sources - Operating, Extension of Completion Times for Offsite Circuits

License Amendment Request (LAR)06-007, Revision to Technical Specification (TS) 3.8.1, AC Sources - Operating, Extension of Completion Times for Offsite Circuits

ML063100506
Person / Time
Site:	Comanche Peak
Issue date:	10/31/2000
From:	Madden F TXU Generation Co, LP, TXU Power
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
CPSES-200602078, TXX-06172
Download: ML063100506 (59)

Text

TXU Power TXU Power Mike Blevins Comanche Peak Steam Senior Vice President & Ref: 10CFR50.90 Electric Station Chief Nuclear Officer P. . Box 1002 (E01)

Glen Rose, TX 76043 Tel: 254 897 5209 Fax: 254 897 6652 mike.blevins@txu.com CPSES-200602078 Log # TXX-06172 File# 00236 October 31, 2006 U. S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555

SUBJECT:

COMANCHE PEAK STEAM ELECTRIC STATION (CPSES)

DOCKET NOS. 50-445 AND 50-446 LICENSE AMENDMENT REQUEST (LAR)06-007 REVISION TO TECHNICAL SPECIFICATION (TS) 3.8.1, "AC SOURCES - OPERATING," EXTENSION OF COMPLETION TIMES FOR OFFSITE CIRCUITS

Dear Sir or Madam:

Pursuant to IOCFR50.90, TXU Generation Company LP (TXU Power) hereby requests an amendment to the CPSES Unit I Operating License (NPF-87) and CPSES Unit 2 Operating License (NPF-89) by incorporating the attached changes into the CPSES Unit I and 2 Technical Specifications (TS). This change request applies to both units.

The proposed changes will revise TS 3.8.1 for "AC Sources - Operating" to extend the allowable Completion Time (CT) associated with restoration of an inoperable offsite circuit (i.e., Startup Transformer (ST)). The extended CT establishes a 30 day allowable out of service time when one ST is inoperable. The 30 day CT extension includes the normal 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> CT which is not risk informed, followed by a 27 day extension period based on a plant specific risk analysis performed to establish the overall out of service time. This change is needed to ensure the continued long term reliability of 345 kV and 138 kV offsite circuit STs which are common to both CPSES units. NRC approval of this request would allow sufficient time to perform maintenance on one ST while both units remain at power.

TXU Power's evaluation of the proposed changes includes traditional engineering analyses as well as a risk informed approach as set forth in the guidance of Regulatory Guide (RG) 1. 174, "An Approach for Using Probabilistic Risk Assessment In Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," and A member of the STARS (Strategic Teaming and Resource Sharing) Alliance Callaway Comanche

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TXX-06172 Page 2 of 3 RG 1.177, "An Approach for Plant-Specific, Risk-Informed Decisionmaking:

Technical Specifications."

The risk increase associated with this proposed CT extension is considered small according to the guidelines contained in RG 1.177. In addition, based on the risk graphs in RG 1. 174, the change in core damage probability and the change in large early release probability are not considered significant when ST maintenance is completed while both CPSES units remain at power. The requested CT extension for maintenance on the STs is supported by probabilistic evaluations presented in section 4.2 of Attachment 1.

The justification for these changes is based upon a risk-informed, deterministic evaluation consisting of three main elements: (1) the reliability and availability of offsite power via separate and physically independent offsite circuit startup transformers, (2) an assessment of risk that shows an acceptably small increase in risk (as indicated by Core Damage Frequency (CDF) and Large Early Release Frequency (LERF)), and (3) continued implementation of a Configuration Risk Management Program (CRMP). These elements provide the basis for the requested TS changes by providing a high degree of assurance of the capability to provide power to the safety related 6.9 kV AC Engineered Safety Features (ESF) buses during the extended CT. provides a detailed description of the proposed changes, a technical analysis of the proposed changes, TXU Power's determination that the proposed changes do not involve a significant hazard consideration, a regulatory analysis of the proposed changes and an environmental evaluation. Attachment 2 provides the affected TS pages marked-up to reflect the proposed changes. Attachment 3 provides proposed changes to the TS Bases for information only. These changes will be processed per CPSES site procedures. Attachment 4 provides retyped TS pages which incorporate the requested changes. Attachment 5 provides retyped TS Bases pages which incorporate the proposed changes.

TXU Power requests approval of the proposed License Amendment by September 1, 2007, to be implemented within 120 days. The plant does not require this amendment to allow continued safe full power operations although approval is required to support planned transformer maintenance in the fall of 2007.

In accordance with 10CFR50.91(b), TXU Power is providing the State of Texas with a copy of this proposed amendment.

This communication contains no new or revised commitments.

TXX-06172 Page 3 of 3 Should you have any questions, please contact Ms. Tamera J. Ervin at (254) 897-6902.

I state under penalty of perjury that the foregoing is true and correct.

Executed on October 31, 2006.

Sincerely, TXU Generation Company LP By: TXU Generation Management Company LLC Its General Partner Mike ins By: 72ln

/4iýodW. Madden Director, Oversight & Regulatory Affairs TJE Attachments 1. Description and Assessment

2. Markup of Technical Specifications Pages

3. Markup of Technical Specifications Bases Pages (for information)

4. Retyped Technical Specification Pages

5. Retyped Technical Specification Bases Pages (for information)

6. Comanche Peak Switchyards and Distribution Subsystem Figures (for information) c - B. S. Mallet, Region IV M. C. Thadani, NRR Resident Inspectors, CPSES Ms. Alice Rogers Environmental & Consumer Safety Section Texas Department of State Health Services 1100 West 49th Street Austin, Texas 78756-31 to TXX-006172 Page 1 of 37 ATTACHMENT I to TXX-06172 DESCRIPTION AND ASSESSMENT

Attachment I to TXX-006172 Page 2 of 37 LICENSEE'S EVALUATION

5.0 REGULATORY ANALYSIS

5.1 No Significant Hazards Consideration 5.2 Applicable Regulatory Requirements/Criteria

6.0 ENVIRONMENTAL CONSIDERATION

7.0 PRECEDENTS

8.0 REFERENCES

Attachment I to TXX-006172 Page 3 of 37

1.0 DESCRIPTION

By this letter, TXU Generation Company LP (TXU Power) requests a License amendment to the CPSES Unit I Operating License (NPF-87) and CPSES Unit 2 Operating License (NPF-89) by incorporating the attached changes into the CPSES Unit I and 2 Technical Specifications (TS).

The proposed changes will revise Technical Specification 3.8.1 for "AC Sources -

Operating" Required Action A.3 to extend the allowable Completion Time (CT) associated with restoration of an inoperable offsite source (i.e., startup transformer (ST)) from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 30 days. The proposed 30 day CT includes the normal 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> CT which is not risk informed, followed by a 27 day extension period based on a plant specific risk analysis performed to establish the overall out of service time.

The license amendment request also proposes to revise the second CT for Required Actions A.3 and B.4 from 6 days to 33 days to reflect the ST CT extension. The second CT establishes a limit on the maximum time allowed for any combination of required AC electrical sources to be inoperable during any single contiguous occurrence of failing to meet the Limiting Condition for Operation (LCO).

The requested changes are based upon CPSES plant specific risk-informed and deterministic evaluations performed in a manner consistent with the risk-informed approaches endorsed by Regulatory Guides 1.174 (Reference 8. 1) and 1.177 (Reference 8.2). The proposed changes would increase operational flexibility and provide additional allowances for performance of testing, repairs, and periodic maintenance while at power.

2.0 PROPOSED CHANGE

TXU Power's requested changes to Technical Specifications (TS) 3.8.1 are summarized below. The proposed changes to TS 3.8.1 are shown in Attachment 2.

On page 3.8-2 of TS 3.8.1 "AC Sources - Operating," the Completion Time (CT) for Required Action A.3 reads, "72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> AND 6 days from discovery of failure to meet LCO." The proposed change will revise the CT to read, "30 days AND 33 days from discovery of failure to meet LCO."

On Page 3.8-4 of TS 3.8. 1, the Required Action B.4 reads, "72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> AND 6 days from discover of failure to meet LCO." The proposed change will revise the CT to read, "72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> AND 33 days from discovery of failure to meet LCO."

For information only, this LAR includes markups in Attachment 3 indicating proposed associated changes to the Bases for TS 3.8. 1, "AC Sources - Operating."

Retyped TS pages and TS Bases pages which incorporate the proposed changes are provided in Attachments 4 and 5, respectively.

to TXX-006172 Page 4 of 37 In summary, the proposed changes will revise TS 3.8.1 for "AC Sources -

Operating" Required Action to extend the CT for an inoperable offsite circuit from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 30 days. Furthermore, the second CTs for Required Actions A.3 and B.4 will be revised to reflect the CT extension.

3.0 BACKGROUND

The Completion Time (CT) extension for the offsite circuit startup transformers (STs) is expected to be used for performing maintenance activities. In order to perform maintenance on either ST, XSTI or XST2, that would exceed the current CT of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, both CPSES units would be required to be in Cold Shutdown (Mode 5) simultaneously. This is due to the fact that each ST provides one of the two required offsite power sources to both Unit I and Unit 2 and both units are required to maintain two offsite power sources when in Modes 1-4. Based on experience with similar transformers, preventive maintenance could not be completed in the relatively short duration currently allowed by TS 3.8.1 Required Actions.

TXU Power does not anticipate planned outage schedules to include overlapping or simultaneous shutdowns of both units of sufficient duration to perform the recommended ST preventive maintenance. Given the importance of offsite power sources, it is prudent to maintain them in a reliable condition while minimizing their unavailability.

3.1 System Description The offsite AC power circuits for CPSES consist of two physically independent circuits from separate switchyards with startup transformers sized to simultaneously carry essential plant loads for both units. Two independent emergency diesel generators (DGs) per unit supply onsite AC power.

Reliability and Availability of the Offsite Power System The transmission lines of TXU Electric Delivery (ED) (also known as CPSES' Transmission and or Distribution Service Provider (TDSP))

comprise an integrated system with operations coordinated by the System Dispatcher so as to maintain system reliability. Transmission systems consist of 345 kilovolts (kV) lines for bulk supply and 138 kV and 69 kV lines to transmit power to load-serving substations. Generation sources connected to ED's transmission system include fossil fuel plants (lignite, gas/oil, and combustion turbines) and the CPSES nuclear plant. Direct ties to other utilities in Texas are maintained by the Electric Reliability Council of Texas (ERCOT), creating a highly reliable integrated system.

Attachment I to TXX-006172 Page 5 of 37 The CPSES output is connected to the 345 kV transmission system via the CPSES switchyard. Startup and shutdown power for the units is derived from the 138 kV and 345 kV systems. Separate connections to the 138 kV switchyard and the 345 kV switchyard provide independent and reliable offsite power sources to the Class I E systems for both units. The highly reliable network interconnections are made through five 345 kV and two 138 kV transmission lines as shown on the figures in Attachment 6.

Two physically independent and redundant sources of offsite power are available on an immediate basis for the safe shutdown of either unit. The preferred source to Unit I is the 345 kV offsite supply from the 345 kV switchyard via startup transformer (ST) XST2; the preferred source to Unit 2 is the 138 kV offsite supply from the 138 kV switchyard via ST XSTI. Each of the STs (XSTl and XST2) normally energizes its related 6.9 kV AC Class IE buses as a preferred source; i.e., XSTI normally energizes Unit 2 Class 1E buses and XST2 normally energizes Unit I Class I E buses.

The preferred power sources supply power to the Class I E buses during plant startup, normal operation, emergency shutdown, and upon a unit trip. This eliminates the need for automatic transfer of safety-related loads in the event of a unit trip.

Each ST has the capacity to supply the required Class 1E loads of both units during all modes of plant operation. In the event one ST (e.g., XSTI, a preferred source) becomes unavailable to its Class 1E buses, power is made available from the other ST (e.g., XST2, an alternate source) by an automatic transfer scheme. For the loss of a ST, the load transfer only takes place in the unit for which the transformer was the preferred source. If it becomes necessary to safely shutdown both units simultaneously, sharing of these offsite power sources between the two units has no effect on the station electrical system reliability because each transformer is capable of supplying the required safety-related loads of both units although the design criteria require consideration of a Design Basis Accident (DBA) on one unit only.

Reliability and Availability of the Onsite Standby Power System The standby AC power system is an independent, onsite, automatically starting system designed to furnish reliable and adequate power for Class I E loads to ensure safe plant shutdown and standby power when the preferred and the alternate offsite power sources are not available. Four independent diesel generator (DG) sets, two per unit, are provided.

Loads important to plant safety are divided into redundant divisions. Each division is provided with standby power from a dedicated DG. Each DG is directly connected to its dedicated bus. The DGs are physically and to TXX-006172 Page 6 of 37 electrically independent. With this arrangement, redundant components of all engineered safety feature (ESF) systems are supplied from a separate ESF bus so that no single failure can jeopardize the proper functioning of redundant ESF loads. Due to the redundancy of the units' ESF divisions and DGs, the loss of any one of the DGs will not prevent the safe shutdown of the unit.

The total standby power system, including DGs and electrical power distribution equipment, satisfies the single failure criterion.

A DG is automatically started by a safety injection signal or an under-voltage condition on the 6.9 kV ESF bus served by the DG. Upon loss of voltage on a 6.9 kV ESF bus due to a loss of offsite power (LOOP) with no safety injection signal present, under-voltage relays automatically start the DGs and close its output breaker. Sequential loading of the DG is automatically performed as a result of sequential loading of its dedicated bus.

The DG output breaker will close to its dedicated 6.9 kV Class I E bus automatically only if the other source feeder breakers to the bus are open.

When the DG output breaker is closed, no other source feeder breaker will close automatically. Design and procedural controls ensure that no means exist for connecting redundant buses with each other.

The design basis for the DGs is that the loss of one DG will not result in the inability to perform a safety function. With two DGs available per unit, the system is capable of perforiring its intended safety function with an assumed single failure of one DG.

Station Blackout (SBO)

Comanche Peak Station is able to withstand and recover from a SBO event of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> in accordance with the guidelines of RG 1. 155, "Station Blackout,"

dated August 1988 (Reference 8.4) as discussed in section 4.

FSAR References Related background in the CPSES FSAR (Reference 8.3) is found primarily in Section 1A(B) and Section 8. Compliance with NRC design criteria is described in detail in FSAR Section 8. 1, "INTRODUCTION," and in FSAR Appendix IA(B) "APPLICATION OF NRC REGULATORY GUIDES."

Onsite power systems are described in FSAR section 8.3 and Station Blackout is described in Appendix 8B of the FSAR.

3.2 Purpose of Amendment This proposed amendment request changes the CPSES TS to extend the required CT for restoration of an inoperable offsite circuit from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to

Attachment I to TXX-006172 Page 7 of 37 30 days. The proposed change is needed to ensure the continued long tern reliability of the offsite circuit STs. CPSES intends to use the proposed CT to perform conrective and preventive maintenance on the STs. 30 days has been requested to ensure the CT can be met even with emergent issues and to minimize the potential for a required shutdown of both units to Cold Shutdown conditions simultaneously. The proposed CT of 30 days is adequate to perform the proposed preventive maintenance requiring disassembly of the transformer and to perform post-maintenance and operability tests required to return the offsite circuit to operable status.

In order to perform maintenance on a ST., both CPSES units would need to be in the Cold Shutdown state simultaneously for an extended period of time.

This is due to the fact that each ST provides one of the two required offsite power sources to both Unit I and Unit 2 and both units are required to maintain two offsite power sources when in Modes 1-4. Based on experience with similar transformers, the preventive maintenance could not be completed in the relatively short duration currently allowed by TS 3.8.1 Required Actions. As will be discussed below, little preventive maintenance could be performed in such a short period of time.

TXU Power does not anticipate planned outage schedules to include overlapping or simultaneous shutdown of both units of sufficient duration to perform the recommended ST preventive maintenance. Given the importance of offsite power sources, it is prudent to maintain them in a reliable condition while minimizing their unavailability. ED has gained experience with similar type transformers installed in their transmission system and has identified the need to perform preventive maintenance on CPSES' offsite circuit STs. Additionally, ED has performed similar maintenance on other like transformers at CPSES within approximately 22 days and less. Moreover, ED has successfully performed the maintenance on similar transformers in the TXU ED transmission system.

XSTI and XST2 are forced oil and air (FOA), 58.33 MVA transformers, tapped at 138 kV/6.9 kV and 345 kV/6.9 kV, respectively. Routine preventive maintenance has been performed on these transformners approximately every three years. The routine preventive maintenance can be performed during power or shutdown operation of either unit. The routine preventive maintenance does not expose the transformer internals to outside air and typically requires approximately 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> to complete from the time the transformer is taken out of service until the time the safety related buses are restored to operable.

Any preventive maintenance that removes transformer oil could allow air and moisture to be admitted to the transformer internals, thus this type

Attachment I to TXX-006172 Page 8 of 37 maintenance is typically scheduled every ten years, or as determined necessary by gas analysis. Maintenance of this nature requires subsequent oil processing and consequently longer outage times to restore the transformer to operating conditions. The typical time to process transformer oil is 14 days.

Table I details the proposed preventive maintenance activities for the STs.

The activities listed in this table envelope the routine maintenance performed every three years. These activities add no additional length to the estimated duration of the transformer outage. The estimated hours for each set of activities assume that work is performed around the clock, 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> a day and 7 days a week, as applicable, with some exceptions. Twenty four hour coverage will be possible for all activities except for removing and regasketing coolers, pumps, and bushings, cleaning and inspecting the transformer, and bus work and diagnostic testing.

MAINTENANCE ACTIVITY ESTIMATED DURATION Remove transformer from service and danger tag 1/2 day Drain oil and calibrate instrumentation and relaying I day Remove and regasket coolers and pumps*

Replace and regasket bushings* 5 days Clean and inspect transformer*

Place transformer on vacuum for moisture removal Hot oil circulation and evacuate oil under vacuum 14 days Vacuum processing Process oil (Degassing) and oil fill Bus work and diagnostic testing* I day Trip test, deluge, and restore to power 1/2 day TOTAL 22 DAYS Table 1. Startup Transformer Maintenance Activity

• These activities should be performed during daylight hours only due to the high possibility of foreign material entering the ST when it is opened, the hazards to personnel and equipment safety, and the close proximity to transformer IST and other equipment.

The routine maintenance activities incorporated within the activities listed in Table I include:

• Relay and metering calibrations

• Instrumentation calibrations

• External cleaning and inspection

• Cleaning and inspection of affected breaker cubicle

• Cleaning and inspection of grounding resistor bank

Attachment I to TXX-006172 Page 9 of 37 In addition, the following provision will help to minimize the transformer outage time:

• Service and support equipment will be pre-staged

• Replacement parts will be pre-staged

• Experienced personnel will be available

• Pre-job briefs will be conducted with affected departments Therefore, TXU Power requests a CT of 30 days in order to provide time, with sufficient margin for unforeseen or unpredictable circumstances, to complete extensive pre-planned preventive or corrective transformer maintenance activities.

4.0 TECHNICAL ANALYSIS

The proposed changes have been evaluated to determine that current regulations and applicable requirements continue to be met, that adequate defense-in-depth and sufficient safety margins are maintained, and that any increases in core damage frequency (CDF) and large early release frequency (LERF) are small and consistent with the United States Nuclear Regulatory Commission (NRC) Safety Goal Policy Statement (Reference 8.5), and the acceptance criteria in Regulatory Guide (RG) 1.174, "An Approach for Using Probabilistic Risk Assessment In Risk-Informed Decisions On Plant-Specific Changes to the Licensing Basis," July 1998, (Reference 8.1) and RG 1. 177, "An Approach for Plant-Specific, Risk-Informed Decisionmnaking: Technical Specifications," August 1998 (Reference 8.2) are met.

The justification for the use of a 30 day Completion Time (CT) for the offsite sources is based upon a risk-informed deterministic evaluation consisting of three main elements: (1) the reliability and availability of offsite power via separate and physically independent offsite circuit startup transformers, (2) assessment of risk that shows an acceptable small increase in risk (as indicated by Core Damage Frequency (CDF) and Large Early Release Frequency (LERF)), and (3) continued implementation of a Configuration Risk Management Program (CRMP) when a Startup Transformer (ST) is removed from service. The CRMP is used to assess the risk impact due to taking a ST out of service (as it is similarly applied to other maintenance and testing work) and helps ensure that there is no significant increase in the risk of a severe accident while the transformer is out of service. These elements provide the bases for the proposed TS change by providing a high degree of assurance that power can be provided to the engineered safety feature (ESF) buses should a design basis accident (DBA) occur while the ST is out of service.

to TXX-006172 Page 10 of 37 4.1 Traditional Engineering Considerations Defense-in-depth The impacts of the proposed TS changes were evaluated and determined to be consistent with the defense-in-depth philosophy. The defense-in-depth philosophy in reactor design and operation results in multiple means to accomplish safety functions and prevent release of radioactive material.

The unavailability of one ST is already considered in the plant design and is allowed by the current Comanche Peak Steam Electric Station (CPSES) TS.

The increased outage time for a ST has no affect on the capability of each transformer to supply the required safety-related loads of both units if it becomes necessary to safely shut down both units simultaneously.

CPSES is designed and operated consistent with the defense-in-depth philosophy. The units have diverse power sources available (e.g., diesel generators (DGs) and STs) to cope with a loss of the preferred alternating current (AC) source (i.e., offsite power). The overall availability of the AC power sources to the ESF buses will not be reduced significantly as a result of increased on-line ST maintenance activities and the ST planned preventive maintenance will further insure the continued long tenri reliability of the transformers. It is therefore, acceptable, uinder certain controlled conditions, to extend the CT and perform on-line maintenance intended to maintain the reliability of the onsite emergency power systems.

Even with one ST out of service there are multiple means to accomplish safety functions and prevent release of radioactive material. The CPSES probabilistic risk assessment (PRA) (see section 4.2 below) evaluation confirms the results of the deterministic analysis, i.e., the adequacy of defense-in-depth and that protection of the public health and safety are ensured. System redundancy, independence, and diversity are maintained commensurate with the expected frequency and consequences of challenges to the system. As demonstrated in section 4.2 below, the risk increase associated with this proposed CT extension is considered small, according to the guidelines contained in RG 1.177. In addition, based on the risk graphs in RG 1.174, these values indicate that the change in CDF and LERF is not considered significant when maintenance on one ST is completed at power.

Implementation of the proposed changes will be done in a manner consistent with the defense-in-depth philosophy. Station procedures will ensure consideration of prevailing conditions, including other equipment out of service, and implementation of administrative controls to assure adequate defense-in-depth whenever a ST is out of service. No new potential common cause failure modes are introduced by these proposed changes and protection against common cause failure modes previously considered is not

Attachment I to TXX-006172 Page II of 37 compromised. Independence of physical barriers to radionuclide release is not affected by these proposed changes.

Adequate defenses against human errors are maintained. These proposed changes do not require any new operator response or introduce any new opportunities for human errors not previously considered. Qualified personnel will continue to perform ST maintenance activities whether they are performed on-line or during shutdown. The maintenance activities are not affected by this change with the exception that sufficient time will be available to perform the ST maintenance while both units remain on-line. No other new actions are necessary.

Station Blackout (SBO)

CPSES is able to withstand, and recover from., a SBO event of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> duration in accordance with the guidelines of RG 1.155, "Station Blackout," dated August 1988 (Reference 8.4). The 4-hour coping duration was determined by approved methods based on the redundancy and reliability of onsite emergency AC power sources, the expected frequency of loss of offsite power, and the probable time needed to restore offsite power.

Assumptions relevant to the proposed changes and used in the SBO analysis include:

1. One Unit at the CPSES site is assumed to be in a station blackout condition. The other unit is assumed to have one emergency DG available.

2. One emergency DG is capable of powering one train of those safety-related systems which are common to both Units 1 and 2.

3. Per NUMARC 87-00 (Reference 8.6), NRC Staff analysis reports the median AC power restoration time for all LOOP events to be about 1/2 hour, with offsite power restored in approximately 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> for 90 percent of all events.

4. As stated in NUMARC 87-00, since a number of failures must occur to result in a station blackout event, additional independent failures are of secondary importance.

5. Following the loss of all AC power, the reactor will shutdown automatically since the control rod drive mechanism rod drive motor generator sets will lose power.

The proposed changes are bounded by these assumptions. Therefore, the assumptions used in the SBO analysis are unaffected by this

Attachment I to TXX-006172 Page 12 of 37 proposed change. The results of the SBO analysis are also unaffected by this proposed change.

The impact of a SBO event on plant risk is discussed in section 4.2, "Evaluation of Risk Impact."

Onsite Power System Design Criteria Compliance with NRC design criteria is described in detail in FSAR Section 8. 1, "INTRODUCTION," and in FSAR Appendix IA(B)

"APPLICATION OF NRC REGULATORY GUIDES." Safety-related systems and components that require electrical power to perform their safety-related function are defined as Class 1E loads.

These proposed changes do not add or reclassify any safety-related systems or equipment; therefore, conformance with Safety Guide 6, dated March 10, 1971, titled "Independence Between Redundant Standby (Onsite) Power Sources and Between Their Distribution Systems," (Reference 8.7) as discussed in Appendix I A(B) of the FSAR is not affected by this change.

These proposed changes do not add any loads to the DGs; therefore, the selection of the capacity of the DGs for standby power systems and conformance to the applicable Sections of Safety Guide 9, dated March 10, 1971, titled "Selection of Diesel Generator Set Capacity for Standby Power Supplies," (Reference 8.8) are not affected by this change.

CPSES conformance with Regulatory Guide 1.81, Revision 1, dated January 1975, titled "Shared Emergency and Shutdown Electric Systems for Multi-unit Nuclear Power Plants," (Reference 8.9) is described in detail in Appendix I A(B) to the FSAR.

CPSES conformance with RG 1.93, Revision 0, dated December 1974, titled "Availability of Electric Power Sources," (Reference

8. 10) is described in Appendix IA(B) to the FSAR. The station currently conforms to RG 1.93, specifically the 72-hour CT and the proviso that the operating time limits are explicitly for corrective maintenance activities only. If the proposed changes are approved, the station will continue to conform to RG 1.93 with the exceptions that the CT for Required Actions associated with the restoration of an offsite AC circuit will be 30 days and the CT may be used for all ST maintenance.

CPSES commitments to conformance with other key design criteria applicable to onsite electrical systems are unaffected by these to TXX-006172 Page 13 of 37 proposed changes. These commitments include: RG 1.53, dated June 1973, titled, "Application of Single-Failure Criterion to Nuclear Power Plant Protection Systems," (Reference 8.11); RG 1.62, dated October, 1973, titled "Manual Initiation of Protective Actions,"

(Reference 8.12); and RG 1.75, Revision 1, dated January 1975, titled "Physical Independence of Electrical Systems" (Reference 8.13).

Application of the Configuration Risk Management Program Methodologies (Configuration Risk Management Program (CRMP))

associated with risk monitoring and contingency action planning currently exist at CPSES and provide an acceptable risk profile during periods of equipment inoperability. The CRMP will be applied throughout the duration of the extended outage per TS 5.5.18.

Plant procedures require management approval for entry into a limiting condition for operation (LCO) for planned maintenance activities that would exceed 50% of the required LCO CT. Thus if the planned ST maintenance activity requires greater than 50% of the requested CT, existing plant procedures would ensure specific management attention and heightened plant awareness in support of the planned activity.

Operator, maintenance, and management focus will be maximized by scheduling performance of this maintenance on-line when no other significant activities are taking place (as opposed to an outage, for example, where many competing tasks are occurring at the same time). The ST outage would be scheduled to ensure the availability of experienced manpower and technical support personnel, as well as to reduce the potential for distraction due to competing job demands.

Station procedure STA-604, "Configuration Risk Management and Work Scheduling" implements the requirements of TS 5.5.18, "Configuration Risk Management Program (CRMP)." Procedure STA-604, along with other station procedures, provides the administrative controls to ensure that equipment important to accident mitigation remains operable and available for the duration of a planned ST maintenance outage. For example, to minimize risk during a planned maintenance outage of a ST, maintenance and testing of the other unit ST would not be conducted. During the time that the ST is out of service, the only equipment that will be allowed to be unavailable for planned test and/or maintenance is the emergency DGs. The reason that the emergency DGs were excluded from the restriction on maintenance is due to the required monthly TS Surveillance Requirements 3.8.1.2 and 3.8.1.3. One of the four independent DG becomes unavailable each week for a short period of time due to the required surveillance test.

to TXX-006172 Page 14 of 37 The steam driven emergency feedwater pumps (one per unit and called the Turbine Driven Auxiliary Feedwater pumps) at CPSES are protected from elective maintenance activities since they are relied upon for mitigation of station blackout conditions when the electric motor-driven auxiliary feedwater pumps would be unavailable. Surveillance testing of any such "protected" equipment that might become due during the period that a ST is out of service would be performed prior to removing the ST from service.

Limiting testing in this way protects the availability of equipment during the ST maintenance window. This does not imply that surveillance testing requirements will not be performed on key equipment as required, but only that surveillance testing will be shifted as allowed by TS.

Routine testing and preventive maintenance activities are normally scheduled to be performed on a 12 week rotating basis. Work schedules can be adjusted to ensure that surveillance testing of equipment, identified as important to LOOP and SBO considerations, is demonstrated current prior to the start of the ST outage work window and will not be required for the duration of the planned ST outage. As mentioned above, normal test and maintenance activities for the DGs are allowed when the ST CT extension is exercised.

Risk management strategies and maintenance practices at CPSES ensure that extensive work planning is performed. Important aspects of this planning not already mentioned include pre-job briefs and consideration of overall station operating configuration which includes the effect of the planned activities on operation of the opposite unit.

When scheduling, to minimize grid loading and weather related impacts, the prospective schedule for any proposed on-line ST outage will be implemented during the time of the year when weather conditions at CPSES have historically not been severe or threatening to offsite power. Times of peak tornado and thunderstorm frequency or likelihood of winter ice storms will be avoided. In addition, times of optimum grid conditions outside the summer peak electric demands will be considered in selecting the on-line ST maintenance window. Other weather-related considerations include equipment protection, minimal job interruptions, and good worker conditions. Therefore, the CT extension will not be entered if weather conditions are not conducive to performance of on-line ST maintenance.

Station procedure STA-629, "Switchyard Control," is part of the Generation Interconnect Agreement for CPSES and defines responsibilities for the design, maintenance, control, and operation of the CPSES switchyards.

STA-629 establishes the necessary interfaces between CPSES and the transmission grid system operators. This procedure also provides guidance

Attachment I to TXX-006172 Page 15 of 37 for the timely exchange of necessary and pertinent information. This guidance has been summarized and is added to the procedure in the form of Attachments 8.F, "Communication Protocol," Attachment 8.G, "CPSES -

Plant Condition Communication Guideline," and is also supported by Attachment 8.H, "CPSES Offsite Power System Performance Characteristics," Attachment 8.1, "CPSES Generator and Transformer Performance Characteristics," and Attachment 8J, "Switchyard Work Description." STA-629 ensures (1) activities in the switchyards are closely monitored and controlled, (2) all switchyard maintenance is reviewed to ensure that the increase in probability of loss of offsite power is minimized, and (3) switchyard access is strictly controlled to minimize the potential for offsite power transients. Therefore, the ST extended CT will not be entered if switchyard and grid conditions are not conducive to perform on-line maintenance of the ST.

In sumnmary, CPSES has a robust design which retains desired design features such as defense-in-depth (i.e., the ability to mitigate design basis accidents when a ST is out of service). The risk-informed CT will be implemented consistent with the CRMP, STA-629, and other station procedures. When utilizing the 30 day CT, the requirements of the CRMP per TS 5.5.18 call for the consideration of other measures to mitigate consequences of an accident occurring while a ST is inoperable. Furthermore, the provisions of STA-629 will be applied when exercising the 30 day ST CT extension and are sufficient to maintain adequate defense-in-depth and existing safety margins.

The following administrative controls will be applicable upon entry into plant conditions which rely on the extended CT:

I. The Configuration Risk Management Program (CRMP) (TS 5.5.18) will be applied per 10CFR50.65(a)(4).

2. Weather conditions must be conducive to perform maintenance on the offsite circuits.

3. The offsite power supply and switchyard conditions mnust be conducive to perform maintenance on the offsite circuits.

4. Switchyard access will be monitored and controlled per procedures.

The license amendment request also proposes to revise the second CTs for Required Actions A.3, "Restore required offsite circuit to OPERABLE status" and B.4, "Restore DG to OPERABLE status" to reflect the ST proposed CT extension. The second CTs establish a limit on the maximum time allowed for any combination of required AC electrical sources to be inoperable during any single contiguous occurrence of failing to meet the Limiting Condition for Operation (LCO).

Attachment I to TXX-006172 Page 16of37 4.2 Evaluation of Risk Impact This section documents the probabilistic evaluation and is intended to supplement the deterministic engineering evaluations described in Section

4. 1. This analysis evaluates extending the ST CT from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 30 days to support maintenance activities on the STs. The probabilistic evaluations presented in the following sections support and justify the CT extension request for offsite circuit STs. The risk methods and analysis tasks employed are detailed in section 4.2.1, analysis results are presented in section 4.2.2, and are followed by a discussion on PRA quality in section 4.3.

4.2.1 Overall Methodology This section describes the CPSES PRA model for internal events and provides a description of the overall methodology that was used for the PRA analysis in support of this submittal. The features of the CPSES PRA model that were used in the analysis are also described.

Risk-informned changes to a nuclear power plant's licensing basis consist of both deterministic and probabilistic evaluations, as required by NRC Regulatory Guides 1.174 (Reference 8.1) and 1.177 (Reference 8.2). The values obtained in this evaluation are typical of normal maintenance conducted on site.

Data Review and Model Evaluation The scope of the existing PRA was reviewed to assure that it is adequate to evaluate this application. Two key areas were considered:

(1) review aspects of the PRA model related to 6.9 kV AC electrical power to ensure high quality standards for the submittal; and (2) review the reactor coolant pump (RCP) seal loss of coolant accident (LOCA) model to ensure integrity and completeness.

The 6.9 kV AC system fault tree models and reliability data for the ST were reviewed. This review included common cause failure parameters, unavailability parameters, failure rates, and level of detail of the system models. Similarly, the CPSES LOOP and SBO models were reviewed.

The review of the PRA model to ensure high quality standards is required for all risk-infonried submittals under RG 1. 174. The review of the RCP Seal LOCA model is required when the utility has not incorporated the Brookhaven RCP Seal LOCA model. For this submittal, TXU Power reviewed the ST reliability data, the LOOP and SBO sequences, and the RCP seal LOCA model using the Westinghouse Owners Group (WOG) certification guidelines. The key areas reviewed are summarized below.

to TXX-006172 Page 17 of 37 The 6.9 kV AC system fault tree models and reliability data for the ST were reviewed against the WOG review criteria.

Minor modifications to the models and enhancements to the documentation were needed to meet the PRA quality review criteria described later in this section.

It was confirmed that the existing RCP Seal LOCA model contains all of the failure modes identified in the United States Nuclear Regulatory Commission (USNRC)-approved Brookhaven RCP Seal LOCA model. The impact of using the Brookhaven Seal LOCA model was then examined as a sensitivity analysis. This sensitivity analysis showed a small increase (6.50E-08 for CDF and 1.70E-09 for LERF) in the baseline risk if the Brookhaven RCP Seal LOCA model is used. This sensitivity showed that the CPSES model compares very favorably with the Brookhaven model. Thus, the conclusions of this study remain unchanged and the proposed CT extension is supported.

PRA Model Modifications The CPSES PRA model (evaluated using the Electric Power Research Institute-Computer Aided Fault Tree AnalysisTM (EPRI-CAFTATM )

code) was used for quantification of various configurations required to support this submittal. During the evaluation process, the quantification runs were performed to calculate CDF and LERF values.

The CPSES PRA internal events model does not include contributions from internal fires, internal floods, seismic events and other external events. However, due to the common cause nature of these events and the fact that the increased CT only impacts risk contributions of independent component unavailabilities, inclusion of floods, fires and external events would not impact the conclusions of this evaluation.

While such contributions, if added, would make small contributions to the base CDF, the change in CDF or LERF due to the increased CT would be unaffected.

Analysis Assumptions The following assumptions were used in performing the analysis:

• The incremental CDF and LERIF are calculated by assuming the ST is in maintenance for the entire CT duration.

• The CPSES LOOP and RCP Seal LOCA model are the base

Attachment I to TXX-006172 Page 18 of 37 case. The existing RCP seal LOCA model contains all of the failure modes identified in the Brookhaven RCP Seal LOCA model.

Since work in the switchyard will be restricted, the frequency of the plant centered (PC) component of LOOP events was reduced. The reduction of the PC component was calculated using the EPRI Final Report, "Losses of Off-Site Power at U.S. Nuclear Power Plants-Through 2003," April 2004 (Reference 8.14)." Only incidents which were actual failure of equipment (not incidents due to operator error or maintenance activities) were used to calculate the PC frequency. This reduced the PC frequency from 1.03E-02 to 7.72E-03.

The impact of the proposed CT change was evaluated by quantifying the CPSES PRA internal events model.

During the time that a ST is out of service, the only PRA equipment that was allowed to be unavailable for planned test and or maintenance was an emergency DG.

Evaluation Criteria The guidance provided in RGs 1.174 and 1.177 (References 8.1 and 8.2, respectively) was used to determine the effect of the proposed CT extension. Thus, the following risk metrics were used to evaluate the risk impacts of extending the CT.

ACDF = The change in CDF with one ST out of service from the base CDF. This risk metric is used as suggested in RG 1. 174 to determine whether the proposed increase in CT has an acceptable risk.

ALERF = The change in LERF with one ST out of service from the base LERF. This risk metric is used as suggested in RG 1.174 to determine whether the proposed increase in CT has an acceptable risk.

The ACDF and ALERF are computed per the definitions from RG 1.174 (Reference 8.1). In terms of the parameters defined above, the definition of ACDF is as follows:

ACDF = [(CDFXAOOS

• 30/365) + (CDFX13ASE

• 335/365)] - CDFXBASE ALERF = [(LERFXAOOS

• 30/365) + (LEREFxIASE,

• 335/365)] -

LERFxBASE Note that in the above formula, the 30 days represents the time the plant will have a reduced plant centered effect and the time that a ST, XSTI or XST2, will be out of service. The 335 days represents the to TXX-006172 Page 19 of 37 time that the plant will be in a baseline configuration. The baseline configuration is either with all equipment available and normal test and maintenance allowed or all equipment available and no test or maintenance allowed. The factor of 365 days/year is merely a conversion factor to make the units for CT consistent with the units for CDF frequency.

Similarly, incremental conditional core damage probability (ICCDP) and incremental conditional large early release probability (ICLERP) are defined as follows:

ICCDP = The incremental conditional core damage probability with one ST out of service for a period equal to the proposed new CT.

This risk metric is used as suggested in RG 1. 177 to determine whether a proposed increase in CT has an acceptable risk impact.

ICLERP = The incremental conditional large early release probability with one ST out of service for a period equal to the proposed new CT.

RG 1.177 criteria are also applied to judge the significance of changes in this risk metric.

The incremental conditional core damage probability (ICCDP) and incremental conditional large early release probability (ICLERP) are computed per the definitions from RG 1. 177 (Reference 8.2). In terms of the parameters defined above, the definition of ICCDP is as follows:

ICCDPxA = (CDFXAOOS - CDFx13ASE)

• TcTr-ICCDPXA = (CDFXAOOS - CDFxI3ASE) * (30 days) * (365 days/year)-'

ICCDPXA = (CDFXAOOS - CDFxI3ASE)

• 8.22x 1-2/year where:

TcT= Completion Time Similarly, ICLERP is defined as follows:

ICLERPxA = (LERFXAOOS - LERFX13 ASE)

• 8.22x 10-2/year Note that in the above formula 365 days/year is merely a conversion factor to make the units for CT consistent with the units for CDF frequency. The ICCDP values are dimensionless incremental probabilities of a core damage event over a period of time equal to the extended CT.

Attachment I to TXX-006172 Page 20 of 37 4.2.2 Evaluation The CPSES PRA internal events model was used to evaluate the ST CT extension. All of the case runs were quantified using the EPRI CAFTA suite of computer programs and the updated CPSES internal events model.

• Baseline CDF for all components before and after the proposed CT.

• Baseline LERF for all components before and after the proposed CT.

• Conditional Core Damage Probability was evaluated for the proposed CT.

• Conditional Large Early Release Probability was evaluated for the proposed CT.

The incremental CDF and LERF were calculated while exercising the requested CT. The initial PRA analysis followed the steps listed below. Each step included calculation of the overall change in CDF and LERF as well as the incremental change in CDF and LERF, i.e.,

there were four risk numbers calculated for each step. The overall CDF and LERF are calculated using the formulas above. The incremental CDF and LERF were calculated by assuming one ST is in maintenance for the entire CT duration.

Evaluation of Startup Transformer Completion Time The proposed CT evaluated for the ST is 30 days. This evaluation was done using the methodology described above. The equations defined under section 4.2.1 were used for the evaluation cases described below.

In order to perform maintenance on either ST, XSTI or XST2, that would exceed the current CT of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, both CPSES units would be required to be in Cold Shutdown (Mode 5) simultaneously. This is due to the fact that each ST provides one of the two required offsite power sources to both Unit 1 and Unit 2 and both units are required to maintain two offsite power sources when in Modes 1-4.

If test and maintenance is restricted on all PRA components except the DGs, the increase in risk results in an additional CDF contribution of approximately 4.99E-07 and an additional LERF contribution of approximately 9.38E-9 per year for Unit 1. For Unit 2 the additional CDF contribution is 1.39E-07 per year and an additional LERF

Attachment I to TXX-006172 Page 21 of 37 contribution of approximately 7.24E- 10 per year. The Unit I at power ICCDP and ICLERP calculated values are 4.99E-07 and 9.38E-09, respectively. The Unit 2 at power ICCDP and ICLERP calculated values are 1.39E-07 and 7.24E-10, respectively.

The risk increase associated with this proposed CT extension is considered small, according to the guidelines contained in RG 1.177.

In addition, based on the risk graphs in RG 1.174, these values indicate that the change in CDF and LERF is not considered significant when one ST is removed from service for maintenance for 30 days while both units remain operating at power.

4.2.3 Sensitivity Studies In the past, TXU Power reviewed the LOOP using the WOG certification guidelines. The associated sensitivity studies performed at that time were conducted using a previous version of the model; however, the differences in model version are minor and do not affect conclusions. Results of the sensitivity study and its applicability to this evaluation are summarized below.

Sensitivity Cases The analysis for Case I was performed with XST1 out of service and XST2 supplying both Unit 1 and Unit 2 during power operation with the no test and maintenance model. It was assumed that XST1 would be out of service for 30 days with no change in XST2 failure rate.

Also, since work in the switchyard was going to be restricted, the frequency of the PC component of LOOP was reduced. The reduction of the PC component was calculated using the EPRI Final Report, "Losses of Off-Site Power at U.S. Nuclear Power Plants-Through 2003," (Reference 8.14). Only incidents which were actual failures of equipment (not incidents due to operator error or maintenance activities) were used to calculate the PC frequency. This reduced the PC frequency (basic event X3PCDATA) from 1.37E-02 to 7.72E-03.

The results of this analysis are shown in Table 2, "PRA Study Results."

The analysis for Case 2 assumed XSTI out of service and XST2 supplying both Unit I and Unit 2 at power with the test and maintenance model. No other changes in assumptions were made from Case 1. The results of this analysis are shown in Table 2.

The analysis for Case 3 assumed XST2 out of service and XSTI supplying both Unit 1 and Unit 2 at power with the test and

Attachment I to TXX-006172 Page 22 of 37 maintenance model. This case was used to quantify the risk metrics (CDF and LERF) for Unit 2 CDF. No other changes in assumptions were made from Case 1. The results of this analysis are shown in Table 2. This case was used to show that the difference in the risk metrics between Unit 1 and Unit 2 were very similar. Therefore the results for Unit I were considered to be valid for Unit 2.

The analysis for Case 4 assumed XSTI out of service and XST2 supplying both Unit I and Unit 2 at power with the test and maintenance model. No maintenance was allowed on any equipment except for the emergency DGs. This is consistent with the maintenance program in the plant. The reason that the emergency DGs were excluded from the restriction on maintenance is due to the required monthly surveillance. During the monthly surveillance, which is staggered (one emergency diesel generator is tested per week), the equipment becomes unavailable for a short period of time.

To be conservative, this maintenance unavailability was not removed from the model even though it is much longer than would normally be attributed to the identified required monthly surveillance testing.

The analysis for Case 5 was the same as Case 4 except that the results were for Unit 2. The Case 5 results are shown in Table 2.

The analysis for Case 6 assumed XSTI Out of service and XST2 supplying both Unit I and Unit 2 at power with the test and maintenance model. No maintenance was allowed on any equipment except for the emergency DGs. The failure probability for the weather centered events was reduced by 67 percent. The reason for reducing the weather centered event probability was that planned ST work would be scheduled during the time of the year when severe weather is not typical for this geographic location. This assumption is based on data from the National Severe Storms Laboratory which is part of the National Oceanic and Atmospheric Administration (NOAA). The Case 6 results are shown in Table 2. No other changes in assumptions were made from Case 1.

>~

Table 2. PRA Study Results CDwn w1 DESCRIPTION OF MEETS MEETS CD ASSUMPTIONS CDF LERF ACDF ALERF ICCDP ICLERP RG 1.174 RG 1.177 BASE NTM 6.58E-06 5.05E-07 - -

BASE TM 9.30E-06 6.3 1E-07 - -

Case 1: XSTI OOS NTM 1.22E-05 6.38E-07 4.6 1E-07 1.09E-08 4.61E-07 1.09E-08 YES YES Case 2: XSTI OOS TM I 1.84E-05 8.56E-07 7.47E-07 1.85E-08 7.47E-07 1.85E-08 YES NO Case 3:XST200S TM I 1.31E-05 7.37E-07 3.16E-07 8.74E-09 3.16E-07 8.74E-09 YES YES Case 4: XSTI OOS TM t RPC DGTM only 1.54E-05 7.45E-07 4.99E-07 9.38E-09 4.99E-07 9.38E-09 YES YES Case 5: XSTI OOS TM 2 RPC DGTM only 1.1OE-05 6.40E-07 1.39E-07 7.24E-10 1.39E-07 7.24E-10 YES YES Case 6: XST1 00S TM I RPC, RWC, DGTM only 1.41E-05 7.06E-07 3.91E-07 6.15E-09 3.91E-07 6.15E-09 YES YES NTM - NO TEST AND MAINTENANCE TM I - TEST AND MAINTENANCE Unit 1 TM 2 - TEST AND MAINTENANCE Unit 2 RPC - REDUCED PLANT CENTERED PROBABLILITY RWC - REDUCED WEATHER CENTERED PROBABILITY DGTM - DIESEL GENERATOR TEST AND MAINTENANCE OOS - OUT OF SERVICE RG 1.174 REQUIREMENTS - ACDF < IE-06 AND ALERF < 1E-07 RG 1.177 REQUIREMENTS - ICCDP < 5E-07 AND ICLERP < 5E-08 to TXX-006172 Page 24 of 37 4.2.4 Restriction on High Risk Configuration In addition to the administrative controls proposed by this license amendment, CPSES has existing administrative guidelines to avoid or reduce the potential for risk-significant configurations from either emergent or planned work. These guidelines control configuration risk by assessing the risk impact due to out of service equipment during all modes of operation to ensure that the plant is always operated within acceptable risk guidelines.

CPSES employs a conservative approach to performning maintenance during power operations. The weekly schedules are train/channel based and prohibit the scheduling of opposite train activities without additional review, approvals and/or administrative controls. The assessment process further minimizes risk by restricting the number and combination of systems/trains allowed to be simultaneously unavailable for scheduled work.

Unplanned or emergent work activities are factored into the plant's actual and projected condition, and the level of risk is re-evaluated. Based on the result of this re-evaluation, decisions are made concerning further actions required to achieve an acceptable level of risk. The unplanned or emergent work activities are also evaluated to determine the impact on other, already planned, activities and the affect the combinations would have on risk.

Risk Significant Components Given a Startup Transformer is out of Service The following components and/or systems become risk-significant when a ST is out of service. The list provides those components and/or systems whose unavailability simultaneous with an out of service ST would likely place the plant in a high-risk configuration, based upon quantitative and deterministic analysis. These are not necessarily in ranked order.

• Electric power - AC and DC power distribution, both trains

• The redundant ST

• All switchyard work

• Service water - both trains

• Emergency DGs

• Turbine Driven Auxiliary Feedwater Pump and the appropriate portions of the Auxiliary Feedwater System

Attachment I to TXX-006172 Page 25 of 37 4.2.5 Summary of Results and Conclusions of Risk Evaluation The probabilistic evaluations presented above support and justify the CT extension request for a ST.

If a ST is taken out of service for maintenance, it affects both units since transformer XSTI functions as a back-up to XST2 and XST2 functions as a back-up for XST I. The increase in risk results in an additional CDF contribution of approximately 4.990E-07 per year and an additional LERF contribution of approximately 9.38E-09 per year even without consideration for the reduced weather centered event probability (RWC).

The risk increase associated with this proposed CT extension is considered small, according to the guidelines contained in RG 1.177. Based on the risk graphs in RG 1.174, these values indicate that the change in core damage probability and large early release probability is not considered significant when either ST is out of service for planned or corrective maintenance for up to 30 days during continued power operation of both CPSES units.

4.3 PRA Quality The following milestones in the development of the CPSES PRA assure the analysis is sufficient to adequately provide risk insights in support of regulatory applications. The results of this history and the current evaluation for suitability in this application show that the CPSES PRA is appropriate for use in the CPSES Risk-Informed extension of CT for the STs.

PRA Model Update History To ensure a high-quality PRA and to provide quality control to the PRA process, two types of independent reviews were conducted during the development of the PRA model used to support the Individual Plant Examination (IPE) submittal. One was done internally by the TXU Power staff, and the other was done externally by outside PRA experts. In general, both reviews were applied to the entire examination process except when it was not possible due to the availability of resources or required skills. In those few cases, as a minimum, each task was reviewed thoroughly by either an internal or external independent reviewer.

Furthermore, a final independent review was performed after the IPE study was completed. A team of PRA experts was selected from the industry to independently review the entire IPE study and its supporting analyses.

The review team spent one week at the TXU Power offices where documents, procedures, and supporting calculations and analyses were available for use. The results of all independent review activities to TXX-006172 Page 26 of 37 performed by internal and external reviewers were well documented as part of the IPE documentation requirements.

As mentioned above, one of the main objectives of the original CPSES PRA development was to be able to utilize its results and insights toward the enhancement of plant safety through risk-based applications. With this objective in mind, the PPA elements were developed in detail and integrated in a manner sufficient to satisfy both the NRC Generic Letter 88-20 (Reference 8.15) requirements and to support future plant applications. In order to use the PRA for future plant applications, it was recognized that the PRA had to be of high quality, and that the assumptions within the PRA had to be supportable. In order to maintain the level of quality needed to support risk-informed applications, significant enhancements to the original IPE work have been incorporated.

The PRA model has been updated several times since the original IPE submittal. The current PRA model includes modeling enhancements that were identified as part of an overall model update, and insights gained when using the PRA model in support of several previous risk-informed initiatives. The first major updates to the PRA were performed in 1996 and 1997 when the original IPE model was revised to support a linked fault tree model. By revising the top logic (event tree/fault tree interface) to support a linked fault tree model, the effort required to requantify the PRA was reduced substantially. Subsequently, the usefulness of the PRA rose dramatically.

hi 1998, a large effort was undertaken to ensure the PRA system level models were done consistently, and that the models were symmetric between trains. The focus of this effort was to ensure consistency between the PRA system level models, including ensuring the newly developed system models were adequate to support upcoming risk informed activities. In addition, this update included reviewing plant-specific operational data in order to update component failure rates, initiating event frequencies, human error probabilities, and recovery probabilities. An initial update to the PRA model was completed in February 2000; however, additional modeling enhancements were identified when the PRA model was used to support risk-informed activities in the first and second quarters of 2000.

Further updates to the PRA model were accomplished in July 2001 and December 2005. The updated model, revision 3B, provides the basis for this submittal. The current PRA model includes the modeling updates performed to support each of the efforts mentioned above, and also includes modifying the models to include the enhancements identified during the risk-informed application process and other reviews. The

Attachment I to TXX-006172 Page 27 of 37 current model is the dual unit model which models the differences between the two units and provides logic, rather than point estimates, for opposite unit support systems.

In each of these efforts, there was a significant amount of work done to enhance the fault tree modeling, both at the system level and in the top logic. These enhancements include changes that:

• Updates the PRA model to reflect as-built changes since 1992.

• Updates the thermal-hydraulics analysis used to develop accident sequences, including using MAAP 4.0 versus MAAP 3.0 to evaluate the postulated scenarios.

Update component failure rates and unavailabilities with plant-specific data where available.

Update the initiating event frequencies with plant-specific data where available.

Update the model to reflect updated industry initiating events, in particular LOCA frequencies.

Update the model to reflect more systematic recovery analysis and application.

Revise the model structure to represent a linked fault tree for linked model quantification.

Integrate interfacing system loss of coolant accident (ISLOCA) sequences directly into the fault tree logic.

Update the latent human error analysis, including a detailed review and resulting reduction in human error probabilities.

• Update the dynamic and recovery analysis, including a detail review and resulting reduction in human error probabilities.

0 Update the model to reflect changes to RCP seal modeling, including crediting high temperature seal leak rates and treatment of small end leakage rates as covered by normal charging.

• Enhance the documentation and level of detail associated with the six systems not fully developed uinder the original [PE effort.

• Update the LOOP modeling to incorporate new methodology which included taking credit for rapid cooldown.

Current PRA Model The CPSES PRA model is controlled and archived on the CPSES LAN and is downloaded for maintenance and applications on business computers. The model can be readily manipulated to evaluate risk impact or individual system reliability due to modifications, procedure changes, or equipment status. The model is routinely updated to ensure plant changes (including modifications, procedure changes, etc.) are accurately reflected in the PRA.

Attachment I to TXX-006172 Page 28 of 37 Use of PRA for RI-IST Submittal In November 1995, CPSES submitted a request for an exemption from the requirements (testing frequency) of 10CFR50.55a(f)(4)(I) and (ii). This request is commonly referred to the Risk Informed In-Service Testing (RI-IST) submittal. Specifically, CPSES requested approval to utilize a risk-based in-service testing program to detenrine in-service test frequencies for valves and pumps that are identified as less safety significant, in lieu of testing those components per the frequencies specified by the American Society of Mechanical Engineers (ASME) code. As part of this effort the PRA model of record at that time was reviewed using the EPRI PRA Applications Guide and found to be suitable for a Risk-Informed In-Service Testing application. This review evaluated the questions posed in the EPRI PSA Applications Guide (Probabilistic Safety Assessment)

(Reference 8.21). These questions included problem definition, scope, figures of merit, analysis, decision criteria, initiating events, success criteria, event trees, system reliability models, parameter databases, dependent failure analysis, human reliability analysis, quantification, analysis of results, plant damage state classification, containment analysis, external events PRA hazards analysis, and shutdown PRA considerations.

In August 1998, the USNRC provided a Safety Evaluation Report to CPSES with respect to the RI-IST request, and approved the request (Reference 8.16). As part of their review of the RI-IST submittal, the NRC performed an in-depth review of the CPSES PRA model of record at that time, the original [PE and IPEEE submittals. The focus of the NRC's review was to establish that the CPSES PRA appropriately reflected the plant's design and actual operating conditions and practices, and that there was a suitable technical basis to support the PRA-related findings made to support the Safety Evaluation Report (SER).

To reach specific findings regarding the quality of the PRA, a focused-scope evaluation was performed that concentrated on elements of the PRA affected by the RI-IST application, and on the assumptions and elements of the PRA model which drive the results and conclusions. As a result of their in-depth evaluation, the USNRC found the quality of the Comanche Peak PRA acceptable for the 1998 RI-IST submittal. Since that time, the PRA has been updated and improved further, by means of an update process that incorporates review steps.

The CPSES PRA has been used in support of several other submittals to the USNRC including Risk-Informed Inservice Inspection program (Reference 8.17). Additionally, the CPSES PRA supported License Amendment Requests to (1) remove the mode restrictions on several

Attachment I to TXX-006172 Page 29 of 37 Technical Specification (TS) 3.8.1 surveillance requirements (Reference 8.18), (2) revise TS 3.8.1 to allow a one-time only change to extend the Action A.3 Completion Time (CT) for restoration of an inoperable offsite circuit from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 21 days (Reference 8.19), and (3) increase the allowed outage time for a centrifugal charging pump from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 7 days (Reference 8.20). The NRC has reviewed and approved these risk-informed submittals.

5.0 REGULATORY ANALYSIS

5.1 No Significant Hazards Consideration TXU Power has evaluated whether or not a significant hazards consideration is involved with the proposed amendment(s) by focusing on the three standards set forth in 10CFR50.92, "Issuance of amendment," as discussed below:

1. Do the proposed changes involve a significant increase in the probability or consequences of an accident previously evaluated?

Response: No The proposed Technical Specification (TS) Completion Time (CT) extension does not significantly increase the probability of occurrence of a previously evaluated accident because the startup transformers (STs) are not initiators of previously evaluated accidents involving a loss of offsite power. The proposed changes to the TS Required Actions CTs do not affect any of the assumptions used in the deterministic or the PSA analysis relative to loss of offsite power initiating event fiequency. Inplementation of the proposed changes does not result in a risk significant impact. The onsite AC power sources will remain highly reliable and the proposed changes will not result in a significant increase in the risk of plant operation. This is demonstrated by showing that the impact on plant safety as measured by the increase in core damage frequency (CDF) is less than I.OE-06 per year and the increase in large early release frequency (LERF) is less than I.OE-07 per year. In addition, for the CT changes, the incremental conditional core damage probabilities (ICCDP) and incremental conditional large early release probabilities (ICLERP) are less than 5.OE-07 and 5.OE-08, respectively. These changes meet the acceptance criteria in Regulatory Guides 1. 174 and 1. 177. Therefore, since the onsite AC power sources will continue to perforn their functions with high reliability as originally assumed and the increase in risk as measured by ACDF, ALERF, ICCDP, and ICLERP risk metrics is within the acceptance criteria of existing regulatory guidance, there will not be a significant increase in the consequences of any accidents.

Attachment I to TXX-006172 Page 30 of 37 The proposed changes do not adversely affect accident initiators or precursors nor alter the design assumptions, conditions, or configuration of the facility or the manner in which the plant is operated and maintained.

The proposed changes do not alter or prevent the ability of structures, systems, and components (SSCs) from performing their intended function to mitigate the consequences of an initiating event within the assumed acceptance limits. The proposed changes do not affect the source term, containment isolation, or radiological release assumptions used in evaluating the radiological consequences of an accident previously evaluated. The proposed changes are consistent with safety analysis assumptions and resultant consequences.

The proposed TS CT extension will continue to provide assurance that the sources of power to 6.9 kV AC buses perform their function when called upon. Extending the TS CT to 30 days does not affect the design of the STs, the operational characteristics of the STs, the interfaces between the STs and other plant systems, the function, or the reliability of the STs.

Thus, the STs will be capable of performing their accident mitigation functions and there is no impact to the radiological consequences of any accident analysis.

The Configuration Risk Management Program (CRMP) in TS 5.5.18 is an administrative program that assesses risk based on plant status. The risk informed CT will be implemented consistent with the CRMP and approved plant procedures. When utilizing the 30 day extension, requirements of the CRMP per TS 5.5.18 call for the consideration of other measures to mitigate the consequences of an accident occurring while a ST is inoperable. Furthermore, administrative controls will be applied when exercising the 30 day CT extension and are adequate to maintain defense-in-depth and sufficient safety margins.

Therefore, the proposed changes do not involve a significant increase in the probability or consequences of an accident previously evaluated.

2. Do the proposed changes create the possibility of a new or different kind of accident from any accident previously evaluated?

Response: No The proposed changes do not result in a change in the manner in which the electrical distribution subsystems provide plant protection. There is no design changes associated with the proposed changes. The changes to the CT do not change any existing accident scenarios, nor create any new or different accident scenarios.

to TXX-006172 Page 31 of 37 The changes do not involve a physical alteration of the plant (i.e., no new or different type of equipment will be installed) or a change in the methods governing normal plant operation. In addition, the changes do not impose any new or different requirements or eliminate any existing requirements.

The changes do not alter any of the assumptions made in the safety analysis. The changes to the CT do not affect the accident analysis directly; the CT is strictly tied to the PRA and the risk associated with the occurrence of a low-probability event during the limited time the component is unavailable.

3. Do the proposed changes involve a significant reduction in a margin of safety?

Response: No The proposed changes do not alter the manner in which safety limits, limiting safety system settings or limiting conditions for operation are determined. Neither the safety analyses nor the safety analysis acceptance criteria are impacted by these changes. The proposed changes will not result in plant operation in a configuration outside the current design basis.

The proposed activities only involve changes to certain TS CTs.

The proposed change does not involve a change to the plant design or operation and thus does not affect the design of the STs, the operation characteristics of the STs, the interfaces between the STs and other plant systems, or the function or reliability of the STs. Because the STs performance and reliability will continue to be ensured by the proposed TS change, the proposed changes do not result in a reduction in the margin of safety.

Therefore the proposed change does not involve a reduction in a margin of safety.

Based on the above evaluations, TXU Power concludes that the proposed amendment presents no significant hazards under the standards set forth in 10CFR50.92(c) and, accordingly, a finding of "no significant hazards consideration" is justified.

5.2 Applicable Regulatory Requirements/Criteria GDC 5 - Sharing of Structures, Systems, and Components, "Structures, systems, and components important to safety shall not be shared between nuclear power units unless it can be shown that such sharing will not significantly impair their ability to perform their safety functions including, in the event of an accident in one unit, an orderly shutdown and cooldown of the remaining unit." Therefore, the proposed license amendment has no impact on this regulatory requirement.

Attachment I to TXX-006172 Page 32 of 37 GDC 17 - Electric Power Systems, "An onsite electric power system and an offsite electric power system shall be provided to permit functioning of structures, systems, and components important to safety. The safety function for each system (assuming the other system is not functioning) shall be to provide sufficient capacity and capability to ensure that (1) specified acceptable fuel design limits and design conditions of the reactor coolant pressure boundary are not exceeded as a result of anticipated operational occurrences, and (2) the core is cooled and containment integrity and other vital functions are maintained in the event of postulated accidents.

The onsite electric power sources, including the batteries, and the onsite electrical distribution system, shall have sufficient independence, redundancy, and testability to perfonn their safety functions, assuming a single failure.

Electric power from the transmission network to the onsite electric distribution system shall be supplied by two physically independent circuits (not necessarily on separate rights of way) designed and located so as to minimize to the extent practical the likelihood of their simultaneous failure under operating and postulated accident and environmental conditions. A switchyard common to both circuits is acceptable. Each of these circuits shall be designed to be available in sufficient time following a loss of all onsite alternating current power supplies and the other offsite electrical power circuit, to ensure that specified acceptable fuel design limits and design conditions of the reactor coolant pressure boundary are not exceeded. One of these circuits shall be designed to be available within a few seconds following a loss of coolant accident to ensure that core cooling, containment integrity, and other vital safety functions are maintained.

Provisions shall be included to minimize the probability of losing electric power from any of the remaining supplies as a result of, or coincident with, the loss of power generated by the nuclear power unit, the loss of power from the transmission network, or the loss of power from the onsite electrical power supplies."

At CPSES, the safety-related systems are designed with sufficient capacity, independence, and redundancy to ensure performance of their safety functions assuming a single failure. The offsite electrical power system also provides independence and redundancy to ensure an available source of power to the safety-related loads. Upon loss of the preferred power source to any 6.9 kV Class I E bus, the alternate power source is automatically connected to the bus and the DG starts should the alternate source not return power to the Class IE buses. Loss of both offsite power sources to any 6.9 kV Class IE bus, although highly unlikely, results in the DG providing power to the Class lE bus. Two independent DGs and their distribution systems are provided for each unit to supply power to the redundant onsite alternating current (AC) Power System.

to TXX-006172 Page 33 of 37 Each DG and its distribution system is designed and installed'to provide a reliable source of redundant onsite-generated (standby) AC power and is capable of supplying the Class 1E loads connected to the Class I E bus which it serves.

Therefore, the proposed license amendment has no impact on this regulatory requirement.

GDC 18 - Inspection and Testing of Electric Power System, "Electric power systems important to safety shall be designed to penrit appropriate periodic inspection and testing of important areas and features, such as wiring, insulation, connections, and switchboards, to assess the continuity of the systems and the condition of their components. The systems shall be designed with a capability to test periodically (1) the operability and functional performance of the components of the systems, such as onsite power sources, relays, switches, and buses and (2) the operability of the systems as a whole and, under conditions as close to design as practical, the full operational sequence that brings the systems into operation, including operation of applicable portions of the protection system and the transfer of power among the nuclear power unit, the offsite power system, and the onsite power system." Therefore, this proposed license amendment has no impact on this regulatory requirement.

NRC Regulatory Guide 1.53, dated June 1973, titled "Applicability of Single-Failure Criterion to Nuclear Power Plant Protection Systems." The proposed license amendment has no impact on this regulatory requirement.

NRC regulatory Guide 1.62, dated October 1973, titled "Manual Initiation of Protective Actions." The proposed license amendment has no impact on this regulatory requirement.

NRC Regulatory Guide 1.75, Revision 1, dated January 1975, titled "Physical Independence of Electrical Systems." The proposed license amendment has no impact on this regulatory requirement.

NRC Regulatory Guide 1.81, Revision 1, dated January 1975, titled "Shared Emergency and Shutdown Electric Systems for Multi-unit Nuclear Power Plants."

The proposed license amendment has no impact on this regulatory requirement.

NRC Regulatory Guide 1.93, dated December 1974, titled "Availability of Electric Power Sources." The current CT associated with inoperable AC power source(s) are intended to minimize the time an operating plant is exposed to a reduction in the number of available AC power sources. NRC Regulatory Guide (RG) 1.93 (Reference 8.10) is referenced in the TS Bases for actions associated with TS 3.8.1. RG 1.93 provides operating restrictions (i.e., CT and maintenance limitations) that the NRC considers acceptable if the number of available AC power sources is one less than the LCO. RG 1.93 specifically states, "If the available a.c. power sources are one less than the LCO, power operation may continue for a period that should not exceed 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> if the system stability and

Attachment I to TXX-006172 Page 34 of 37 reserves are such that a subsequent single failure (including a trip of the unit's generator, but excluding an unrelated failure of the remaining offsite circuit if this degraded state was caused by the loss of an offsite source) would not cause total loss of offsite power." RG 1.93 additionally states, "The operating time limits delineated above are explicitly for corrective maintenance activities only."

Conformance with Regulatory Guide 1.93 is affected by these proposed changes.

The station currently conforms to the RG. If the proposed changes are approved, the station will continue to conform to RG 1.93 with the exception that the allowable Required Actions CT for restoration of a ST will be 30 days and the CT may be used for all ST maintenance.

NRC Regulatory Guide 1.155, "Station Blackout," dated August 1988. The proposed license amendment has no impact on this regulatory requirement.

NRC Regulatory Guide 1.174, "An Approach for Using Probabilistic Risk Assessment In Risk-Informed Decisions on Plant-Specific Changes to the Licensing Bases," dated July 1998. The proposed license amendment is consistent with this regulatory requirement.

NRC regulatory Guide 1.177, "An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications," dated August 1998. The proposed license amendment is consistent with this regulatory requiremnent.

NRC Safety Guide 6, dated March 10, 1971, titled "fridependence Between Redundant Standby (onsite) Power Sources and Between Their Distribution Systems." These proposed changes do not add or reclassify any safety-related systems or equipment; therefore, conformance with Safety Guide 6 (Reference 8.7) as discussed in Appendix I A(B) of the FSAR (Reference 8.3) is not affected by this change. Redundant parts within the AC and direct current (DC) systems are physically and electrically independent to the extent that a single event or single electrical fault can not cause a loss of power to both Class IE buses.

NRC Safety Guide 9 (Reference 8.8), dated March 10, 1971, titled "Selection of Diesel Generator Set Capacity for Standby Power Supplies." These proposed changes do not add any loads to the DGs; therefore, the selection of the capacity of the DGs for standby power systems and conformance to the applicable Sections of Safety Guide is not affected by this change.

The technical analysis performed by TXU Power in Section 4, "Technical Analysis," demonstrates the ability of the STs to perform their safety function.

The increased CT continues to comply with the above regulatory requirements with the exception of RG 1.93.

Safety analysis acceptance criteria in the FSAR continue to be met. The proposed changes do not affect any assumptions or inputs to the safety analysis (Reference 8.3).

Attachment I to TXX-006172 Page 35 of 37 In conclusion, based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.

6.0 ENVIRONMENTAL CONSIDERATION

TXU Power has determined that the proposed amendment would change requirements with respect to the installation or use of a facility component located within the restricted area, as defined in IOCFR20, or would change an inspection or surveillance requirement.

TXU Power has evaluated the proposed changes and has detennined that the changes do not involve (1) a significant hazards consideration, (2) a significant change in the types or significant increase in the amounts of any effluent that may be released offsite, or (3) a significant increase in individual or cumulative occupational radiation exposure.

Accordingly, the proposed changes meet the eligibility criterion for categorical exclusion set forth in IOCFR51.22(c)(9). Therefore, pursuant to IOCFR51.22(b), an environmental assessment of the proposed change is not required.

7.0 PRECEDENTS 7.1 By letter dated April 28, 2000 (Reference 8.22), the NRC issued Amendment No.

206 to Facility Operating License No. DPR-51 and Amendment No. 215 to facility Operating License No. NPF-6 for Arkansas Nuclear One (ANO), Units I and 2, respectively. The amendment provided a 30-day allowed outage time for offsite startup transformer No. 2 which is shared by both units. The 30-day completion time will be used not more than once in any 10-year period for the purpose of performing preventive maintenance to increase the reliability of the transformer. Although similar, the proposed CPSES amendment requests a CT of 30 days, based on PRA, and will not be limited to once in any 10-year period.

7.2 A similar license amendment was issued to Oyster Creek Generating Station (Reference 8.23), to delete the 30 day unavailability period restriction for occurrence of the specified 7 day allowed outage durations for the startup transformers. During the allowed outage time of 7 days, the redundant Oyster Creek startup transformer is required to be operable. This license amendment is similar to the proposed CPSES license amendment with the exception that the proposed allowed outage time will be 30 days.

7.3 The CPSES PRA has been used in support of several submittals to the NRC including Risk-Informed Inservice Testing program (Reference 8.16) and Risk-Informed tnservice Inspection program (Reference 8.17). Additionally, the NRC has reviewed and approved CPSES PRA supported License Amendment Requests to (1) remove the mode restrictions on several Technical Specification (TS) 3.8.1

Attachment I to TXX-006172 Page 36 of 37 surveillance requirements via amendment 124 (Reference 8.18), (2) revise TS 3.8.1 to allow a one-time only change to extend the Action A.3 Completion Time (CT) for restoration of an inoperable offsite circuit from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 21 days via amendment number 88 (Reference 8.19), and (3) increase the allowed outage time for a centrifugal charging pump from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 7 days via amendment numbers 62 and 48 (Reference 8.20).

8.0 REFERENCES

8.1 NRC Regulatory Guide 1.174, "An Approach for Using Probabilistic Risk Assessment In Risk-Informed Decisions On Plant-Specific Changes to the Licensing Basis," July 1998.

8.2 NRC Regulatory Guide 1.177, "An Approach for Plant-Specific, Risk-hiformed Decisionmaking: Technical Specifications," August 1998.

8.3 Comanche Peak Steam Electric Station Final Safety Analysis Report, Docket Nos.

50-445 and 50-446.

8.4 NRC Regulatory Guide 1.155, "Station Blackout," August 1988.

8.5 NRC Probabilistic Risk Assessment (PRA) Policy Statement, "Use of Probabilistic Risk Assessment Methods in Nuclear Activities: Final Policy Statement," Federal Register, Volume 60, p.42622, August 16, 1995.

8.6 NUMARC 87-00, "Guidelines and Technical Bases for NUMARC Initiatives Addressing Station Blackout at Light Water Reactors," Rev. 1, August 1991.

8.7 NRC Safety Guide 6, "Independence Between Redundant Standby (Onsite) Power Sources and Between Their Distribution Systems," March 10, 1971.

8.8 NRC Safety Guide 9, "Selection of Diesel Generator Set Capacity for Standby Power Supplies," March 10, 1971.

8.9 NRC Regulatory Guide 1.81, Revision 1, "Shared Emergency and Shutdown Electric Systems for Multi-unit Nuclear Power Plants," January 1975.

8.10 NRC Regulatory Guide (RG) 1.93, "Availability of Electric Power Sources,"

December 1974.

8.11 NRC Regulatory Guide 1.53, "Applicability of Single-Failure Criterion to Nuclear Power Plant Protection Systems," June 1973.

8.12 NRC Regulatory Guide 1.62, "Manual Initiation of Protective Actions," October 1973.

8.13 NRC Regulatory Guide 1.75, Revision I, "Physical Independence of Electrical Systems," January 1975.

8.14 EPRI Final Report, "Losses of Off-Site Power at U.S. Nuclear Power Plants-Through 2003," April 2004.

8.15 Generic Letter 88-20, Supplement No. 1, "Initiation of the Individual Plant Examination for Severe Accident Vulnerabilities- 10 CFR 50.54(0," August, 29, 1989.

8.16 Letter to C. Lance Terry (TU Electric) from John H. Hannon (USNRC) dated August 14, 1998, "Approval of Risk-Informed Inservice Testing (RI-IST)

Program for Comanche Peak Steam Electric Station, Units I and 2 (TAC Nos.

M94165, M94166, MA1972, and MA1973)."

to TXX-006172 Page 37 of 37 8.17 Letter to C. Lance Terry (TXU Electric) from Robert A. Gramm (USNRC) dated September 28, 2001, "Comanche Peak Steam Electric Station (CPSES), Units I and 2 - Approval of Relief Request for Application of Risk-Informed inservice Inspection Program for American Society of Mechanical Engineers Boiler and Pressure Vessel Code Class I and 2 Piping (TAC Nos. MB1201 and MB1202)."

8.18 Letter to M. R. Blevins (TXU Power) from Mohan C. Thadani (USNRC) dated March 15, 2006, amendment number 124, "Comanche Peak Steam Electric Station (CPSES), Units 1 and 2 - Issuance of Amendments Re: Technical Specification 3.8.1, "AC Sources- Operating," Mode Restrictions on Emergency Diesel Generator Surveillance (TAC Nos. MC4912 and MC4913)."

8.19 Letter to C. Lance Terry (TXU Electric) from David H. Jaffe (USNRC) dated October 9, 2001, amendment no. 88, "Comanche Peak Steam Electric Station (CPSES), Units 1 and 2 - Issuance of Amendments Re: Extended Outage Time for Off-site Power - Single Occurrence (TAC Nos. MB 1823 and MB 1824)."

8.20 Letter to C. Lance Terry (TU Electric) from Timothy J. Polich (USNRC) dated December 29, 1998, "Comanche Peak Steam Electric Station, Units I and 2 -

Amendment Nos. 62 and 48 to Facility Operating License Nos. NPF-87 and NPF-89 (TAC Nos. M97809 and M97810)."

8.21 EPRI-TR-10536, "PSA Applications Guide," August 1995.

8.22 Letter from M. Christopher Nolan (NRC) to Craig G. Anderson (Entergy Operations, Inc.) dated April 28, 2000, "Arkansas Nuclear One, Units I and 2 -

Issuance of Amendments Re: Startup Transformer No. 2 Allowed Outage Time for Preventative Maintenance (TAC Nos. MA7184 and MA7185)."

8.23 Letter from Peter S. Tam (NRC) to John L Skolds (AmerGen Energy Company) dated November 23, 2003, "Oyster Creek Nuclear Generating Station - Issuance of Amendment Re: Startup Transformer and Emergency Diesel Generator Unavailability Periods (TAC No. MB9144)."

to TXX-06172 Page 1 of 5 ATTACHMENT 2 to TXX-06172 PROPOSED TECHNICAL SPECIFICATION CHANGES (MARK-UP)

Pages 3.8-1 3.8-2 3.8-3 3.8-4 to TXX-06172 Page 2 of 5 I For Information Only JAC Sources - Operating 3.8.1 3.8 ELECTRICAL POWER SYSTEMS 3.8.1 AC Sources -Operating LCO 3.8.1 The following AC electrical sources shall be OPERABLE:

a. Two qualified circuits between the offsite transmission network and the onsite Class 1E AC Electrical Power Distribution System;

b. Two diesel generators (DGs) capable of supplying the onsite Class 1E power distribution subsystem(s); and

c. Automatic load sequencers for Train A and Train B.

APPLICABILITY: MODES 1, 2, 3, and 4

-.-------------- ......--------------------- NOTE ---------.....................----------

One DG may be synchronized with the offsite power source under administrative controls for the purpose of surveillance testing.

COMANCHE PEAK - UNITS 1 AND 2 3.8-1 Amendment No. 64,124 to TXX-06172 AC Sources - Operating Page 3 of 5 3.8.1 ACTIONS

---

NOTE ---.............................................----- -

LCO 3.0.4.b is not applicable to DGs.

CONDITION REQUIRED ACTION COMPLETION TIME A. One required offsite circuit A.1 Perform SR 3.8.1.1 for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> inoperable. required OPERABLE offsite circuit. AND Once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter AND

.............. NOTE -----------------

In MODES 1, 2 and 3, the TDAFW pump is considered a required redundant feature.

A.2 Declare required 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> from feature(s) with no offsite discovery of no power available offsite power to one inoperable when its train concurrent with redundant required inoperability of feature(s) is inoperable. redundant required feature(s)

AND A.3 Restore required offsite circuit to OPERABLE status.

3, AND

'bays from discovery of failure to meet LCO (continued)

COMANCHE PEAK - UNITS 1 AND 2 3.8-2 Amendment No. 4-99,+24-to TXX-06172 AC Sources- Operating Page 4 of 5 For Information Only 3.8.1 ACTIONS (continued)

CONDITION I REQIRE ACINCMPLETION TIME IREQUIRED ACTION B. One DG inoperable. B.1 Perform SR 3.8.1.1 for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> the required offsite circuit(s). AND Once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter AND

---

------------- NOTE -------

In MODES 1, 2 and 3, the TDAFW pump is considered a required redundant feature.

B.2 Declare required 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> from feature(s) supported by discovery of the inoperable DG Condition B inoperable when its concurrent with required redundant inoperability of feature(s) is inoperable. redundant required feature(s)

AND B.3.1 Determine OPERABLE 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> DG(s) is not inoperable due to common cause failure.

OR

- -- ---------- NOTE------

The SR need not be performed if the DG is already operating and loaded.

B.3.2 Perform SR 3.8.1.2 for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> OPERABLE DG(s).

(continued)

COMANCHE PEAK - UNITS 1 AND 2 3.8-3 Amendment No. 64 to TXX-06172 AC Sources - Operating Page 5 of 5 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) AND 8.4 Restore DG to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> OPERABLE status.

AND

.{la ys from discoverP failure to meet LCO -- E C. Two required offsite circuits ------------ NOTE------

inoperable. In MODES 1, 2 and 3, the TDAFW pump is considered a required redundant feature.

C.1 Declare required 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> from feature(s) inoperable discovery of when its redundant Condition C required feature(s) is concurrent with inoperable. inoperability of redundant required features AND C.2 Restore one required 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> offsite circuit to OPERABLE status.

(continued)

COMANCHE PEAK - UNITS 1 AND 2 3.8-4 Amendment No. to TXX-06172 Page I of 4 ATTACHMENT 3 to TXX-06172 PROPOSED TECHNICAL SPECIFICATIONS BASES CHANGES (Markup For Information Only)

Pages B 3.8-7 B 3.8-10 INSERTS

Attachment 3 to TXX-06172 AC Sources-- Operating Page 2 of 4 B 3.8.1 BASES ACTIONS A.3 (continued) pcotent Rec to th ty system.6 In this Condition, /

I 30dayI

]

Te7 option Time thaksihou aount 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.

IINSERT B 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

-iinstance, a DG is inoperable and that DG is subsequently returned 2s OPERBLE theLCOmay ready havee been not met for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

Thscould lead oa total ousince initial failure to meet the LCOG, to restore the offsite circuit. At this time, a DG could again become inoperable e on

-- C(for a total oheys) allowed prior to complete restoration of the LCO. L_

I spncified condition after discovery of failure Khconsidered reasonable for situations in whichto Conditions entered concurrently.

,.ay Completion TimesThemeans "AND"that connector meet the LCO. This limit is between t._._*

both Completion A and B are Times apply - 30day 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 zero" for beginning the allowed outage time "clock."

This will result in establishing the 'time zero" at the time that the LCi was initially not met, instead of at the time Condition A was enteredw, (continued)

COMANCHE PEAK - UNITS 1 AND 2 B 3.8-7 Revision 46 to TXX-06172 AC Sources- Operating Page 3 of 4 B 3.8.1 BASES ACTIONS (continued) Acodn t euatory Guide19 Rf ) prto a otnei

/Condition B for a period that should not exceed 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

INERT C h>---

In Condition B, the remaining OPERABLE DG and offsite circuits are Sadequate.,)3~l elcrca oe to the onst las1E Distribution S te.he 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> 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 m failing to meet the LCO. If Condition B is entered while, for instance, an 30 days offsite circuit is inoperable and that circuit is subsequently restored 33 days OPERABLE, the LCO may already h ye been not met for up to.

This could lead to a total ur since initial failure to meetthe LCO, to restore the DG. Althis time, an offsite circuit could again bec me noperale,,.he DG restored OPERABLE, and an additional or a total 6days) allowed prior to complete restoration of the LCO. he OdayCompletion Time provides a limit on time allowed in a specified F7-13]4condition after discovery of failure to meet the LCO. This limit is 33Jjconsidered reasonable for situations in which Conditions A and B are entered concurrently. The "AND" connector between the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and

@day Completion Times means that both Completion Times apply r imultaneously, 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 "time 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 <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> from that allowed for (continued)

COMANCHE PEAK - UNITS 1 AND 2 B 3.8-10 Amendment No. 64 to TXX-06172 Page 4 of 4 INSERTS INSERT A In Condition A, the remaining OPERABLE offsite circuit and DGs are adequate to supply electrical power to the onsite Class 1E Distribution System. With an offsite circuit inoperable, the inoperable offsite circuit must be restored to OPERABLE status within the applicable, specified Completion Time.

INSERT B The 30 day Completion Time includes the normal 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> allowable out of service time which is not risk informed, followed by a 27 day extension period based on a plant specific risk analysis performed to establish the overall out of service time.

The following administrative controls will be applicable upon entry into plant conditions which rely on the extended CT.

1. The Configuration Risk Management Program (CRMP) (TS 5.5.18) will be applied per 10CFR50.65(a)(4).

2. Weather conditions must be conducive to perform maintenance on the offsite circuits.

3. The offsite power supply and switchyard conditions must be conducive to perform maintenance on the offsite circuits.

4. Switchyard access must be monitored and controlled per procedures.

INSERT C In Condition B, the remaining OPERABLE DG and offsite circuits are adequate to supply electrical power to the onsite Class 1E Distribution System. With a DG inoperable, the inoperable DG must be restored to OPERABLE status within the applicable, specified Completion Time.

to TXX-06172 Page 1 of3 ATTACHMENT 4 to TXX-06172 RETYPED TECHNICAL SPECIFICATION PAGES Pages 3.8-2 3.8-4 to TXX-06172 AC Sources - Operating Page 2 of 3 3.8.1 ACTIONS

-NOTE ------------------------------------------

LCO 3.0.4.b is not applicable to DGs.

CONDITION REQUIRED ACTION COMPLETION TIME A. One required offsite circuit A.1 Perform SR 3.8.1.1 for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> inoperable, required OPERABLE offsite circuit. AND Once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter AND

...............-NOTE --------

In MODES 1, 2 and 3, the TDAFW pump is considered a required redundant feature.

A.2 Declare required 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> from feature(s) with no offsite discovery of no power available offsite power to one inoperable when its train concurrent with redundant required inoperability of feature(s) is inoperable, redundant required feature(s)

AND A.3 Restore required offsite 30 days circuit to OPERABLE status. AND 33 days from discovery of failure to meet LCO (continued)

COMANCHE PEAK - UNITS 1 AND 2 3.8-2 Amendment No. 4-99,4-24, to TXX-06172 AC Sources- Operating Page 3 of 3 3.8.1 CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) AND B.4 Restore DG to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> OPERABLE status.

AND 33 days from discovery of failure to meet LCO C. Two required offsite circuits .NOTE------

inoperable. In MODES 1, 2 and 3, the TDAFW pump is considered a required redundant feature.

C.1 Declare required 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> from feature(s) inoperable discovery of when its redundant Condition C required feature(s) is concurrent with inoperable. inoperability of redundant required features AND 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> C.2 Restore one required offsite circuit to OPERABLE status.

(continued)

COMANCHE PEAK - UNITS I AND 2 3.8-4 Amendment No. 64, to TXX-06172 Page 1 of 3 ATTACHMENT 5 to TXX-06172 RETYPED TECHNICAL SPECIFICATION BASES PAGES Pages B 3.8-7 B 3.8-10 to TXX-06172 AC Sources - Operating Page 2 of 3 B 3.8.1 BASES ACTIONS (continued)

A.3 In Condition A, the remaining OPERABLE offsite circuit and DGs are adequate to supply electrical power to the onsite Class 1 E Distribution System. With an offsite circuit inoperable, the inoperable offsite circuit must be restored to OPERABLE status within the applicable, specified Completion Time.

The 30 day 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 30 day Completion Time includes the normal 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> allowable out of service time which is not risk informed, followed by a 27 day extension period based on a plant specific risk analysis performed to establish the overall out of service time.

The following administrative controls will be applicable upon entry into plant condtions which rely on the extended CT.

1. The Configuration Risk Management Program (CRMP) (TS 5.5.18) will be applied per 10CFR50.65(a)(4).

2. Weather conditions must be conducive to perform maintenance on the offsite circuits.

3. The offsite power supply and switchyard conditions must be conducive to perform maintenance on the offsite circuits.

4. Switchyard access must be monitored and controlled per procedures.

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 <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

This could lead to a total of 33 days, 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 <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or a total of 36 days) allowed prior to complete restoration of the LCO.

he 33 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 30 day and 33 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 zero" for beginning the allowed outage time "clock."

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.

(continued)

COMANCHE PEAK - UNITS 1 AND 2 B 3.8-7 Revision to TXX-06172 AC Sources - Operating Page 3 of 3 B 3.8.1 BASES ACTIONS B.4 (continued)

In Condition B, the remaining OPERABLE DG and offsite circuits are adequate to supply electrical power to the onsite Class 1E Distribution System. With a DG inoperable, the inoperable DG must be restored to OPERABLE status within the applicable, specified Completion Time.

The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> 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 30 days.

This could lead to a total of 33 days, 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 30 days (for a total of 63 days) allowed prior to complete restoration of the LCO. The 33 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 <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and 33 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 "time 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 <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> from that allowed for (continued)

COMANCHE PEAK - UNITS 1 AND 2 B 3.8-10 Revision to TXX-06172 Page 1 of 4 ATTACHMENT 6 to TXX-06172 CPSES SWITCHYARDS and DISTRIBUTION SUBSYSTEM FIGURES (For Information Only) to TXX-06172 Page 2 of 4 OFFSITE POWER SYSTEM 138kv Switchyard I 345kv Switchyard Startup Transformer XST2 Unit 2 Startup Transformer XST1 ' T

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'1 STATION CV1SPARE SAINSTART-UPl TRANSFORMER SERVICE TRANSFORMER UNIT I XSTZI2 1STT TRANSFORMER 8TA2 UNIT2 345KV AUXILIARY CPX-EPTRST-03 oAUXILIARY ->,y- STATION 1ST CPX-EPTRST-02 T TRANSFORMER CP1-EPTRST-01 I TRANSFORMER SERVICE IUT lEA1, 1EA2 2UT TRANSFORMER CPI-EPTRUT-01lI 2EAI, 2EA2 CP2-EPTRUT-01 2ST CP2 EPTRST-Ol NN F6.UKV A 6S KV R O 68 KV UNIT 1 LN1NON-SAFEGUARDS BUSES SAFEGUARDSBUSES G UNIT 2 NON-SAFEGUARDS BUSES ELECTRIC POWER SYSTEM HIGH VOLTAGE SWITCHYARDS SIMPLIFIED SCHEMATIC SHEET 1 OF 2 to TXX-06172 Page 4 of 4 PLANTSUPPORT POWER SYSTEM PLANTSUPPORT POWER SYSTEM lTRANSFORMER 1 DECORDOVA 70 TASOMR1STEPHENVILLE 022 WEST BUS 70197 7020 N 7030 N 7021 7S31 72 138 KV SWITCHYARD 7041 7051 PLANTSUPPORT 7040 NC 7050 [NC POWER SYSTEM TRANSFORMER2 1 7030 7G49 PLANTSUPPORT 7052 EASTBUS POWERSYSTEM

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