ML041970435

License Amendment, Revised Surveillance Requirements in Technical Specifications 3.8.1 and 3.8.4 - AC and DC Sources

ML041970435
Person / Time
Site:	Wolf Creek
Issue date:	07/12/2004
From:	Donohew J NRC/NRR/DLPM/LPD4
To:	Muench R Wolf Creek
Donohew J N, NRR/DLPM,415-1307
Shared Package
ML041980406	List: ML041970435 ML041970583
References
TAC MB8763
Download: ML041970435 (24)

Text

July 12, 2004 Mr. Rick A. Muench President and Chief Executive Officer Wolf Creek Nuclear Operating Corporation Post Office Box 411 Burlington, KS 66839

SUBJECT:

WOLF CREEK GENERATING STATION - ISSUANCE OF AMENDMENT RE: TECHNICAL SPECIFICATIONS 3.8.1 AND 3.8.4 - AC AND DC SOURCES (TAC NO. MB8763)

Dear Mr. Muench:

The Commission has issued the enclosed Amendment No. 154 to Facility Operating License No. NPF-42 for the Wolf Creek Generating Station. The amendment consists of changes to the Technical Specifications (TS) in response to your application dated April 30, 2003 (WO 03-0009), as supplemented by letters dated December 18, 2003 (WO 03-0062), and April 13, 2004 (WO 04-0013).

The amendment revises several surveillance requirements (SRs) in TS 3.8.1 on alternating current sources for plant operation. The revised SRs have notes deleted or modified to adopt in part the staff-approved TSTF-283, Revision 3, which will allow these revised SRs to be performed, or partially performed, in reactor modes that previously were not allowed by the TS.

Although the proposed SRs 3.8.1.10, 3.8.1.13, and 3.8.1.14 are not consistent with the TSTF, they meet the intent of the TSTF. The proposed changes to SRs 3.8.4.7 and 3.8.4.8 for direct current sources were withdrawn in your letter dated April 13, 2004. The enclosed Notice of Partial Withdrawal of Application for Amendment to Facility Operating License has been forwarded to the Office of the Federal Register for publication.

A copy of our related Safety Evaluation is enclosed. The Notice of Issuance will be included in the Commission's next biweekly Federal Register notice.

Sincerely,

/RA/

Jack Donohew, Senior Project Manager, Section 2 Project Directorate IV Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket No. 50-482

Enclosures:

1. Amendment No. 154 to NPF-42

2. Safety Evaluation

3. Notice of Partial Withdrawal cc w/encls: See next page

Mr. Rick A. Muench July 12, 2004 President and Chief Executive Officer Wolf Creek Nuclear Operating Corporation Post Office Box 411 Burlington, KS 66839

SUBJECT:

WOLF CREEK GENERATING STATION - ISSUANCE OF AMENDMENT RE:

TECHNICAL SPECIFICATIONS 3.8.1 AND 3.8.4, AC AND DC SOURCES (TAC NO. MB8763)

Dear Mr. Muench:

The Commission has issued the enclosed Amendment No. 154 to Facility Operating License No. NPF-42 for the Wolf Creek Generating Station. The amendment consists of changes to the Technical Specifications (TS) in response to your application dated April 30, 2003 (WO 03-0009), as supplemented by letters dated December 18, 2003 (WO 03-0062), and April 13, 2004 (WO 04-0013).

The amendment revises several surveillance requirements (SRs) in TS 3.8.1 on alternating current sources for plant operation. The revised SRs have notes deleted or modified to adopt in part the staff-approved TSTF-283, Revision 3, which will allow these revised SRs to be performed, or partially performed, in reactor modes that previously were not allowed by the TS.

Although the proposed SRs 3.8.1.10, 3.8.1.13, and 3.8.1.14 are not consistent with the TSTF, they meet the intent of the TSTF. The proposed changes to SRs 3.8.4.7 and 3.8.4.8 for direct current sources were withdrawn in your letter dated April 13, 2004. The enclosed Notice of Partial Withdrawal of Application for Amendment to Facility Operating License has been forwarded to the Office of the Federal Register for publication.

A copy of our related Safety Evaluation is enclosed. The Notice of Issuance will be included in the Commissions next biweekly Federal Register notice.

Sincerely,

/RA/

Jack Donohew, Senior Project Manager, Section 2 Project Directorate IV Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket No. 50-482 DISTRIBUTION PUBLIC GHill (2)

Enclosures:

1. Amendment No. 154 to NPF-42 PDIV-2 Reading

2. Safety Evaluation RidsNrrDlpmPdiv(HBerkow)

3. Notice of Partial Withdrawal RidsNrrPMJDonohew RidsNrrLAEPeyton cc w/encls: See next page RidsOogRp RidsAcrsAcnwMailCenter RidsRegion4MailCenter (D. Graves)

• • See previous concurrence TBoyce

• EEIB memorandum dated 04/18/2004 TS: ML041970583 NRR-100 ACCESSION NO.: ML041970435 PKG: ML041980406 NRR-058 OFFICE PDIV-2/PM PDIV-2/LA EEIB-B/SC IROB-A/SC OGC PDIV-2/SC NAME JDonohew:mp EPeyton RJenkins* TBoyce** RHoefling SDembek DATE 7/9/04 7/9/04 04/18/2004 06/22/2004 7/8/04 7/9/04 DOCUMENT NAME: C:\ORPCheckout\FileNET\ML041970435.wpd OFFICIAL RECORD COPY

Wolf Creek Generating Station cc:

Jay Silberg, Esq. Site Vice President Shaw, Pittman, Potts & Trowbridge Wolf Creek Nuclear Operating Corporation 2300 N Street, NW P.O. Box 411 Washington, D.C. 20037 Burlington, KS 66839 Regional Administrator, Region IV Superintendent Licensing U.S. Nuclear Regulatory Commission Wolf Creek Nuclear Operating Corporation 611 Ryan Plaza Drive, Suite 400 P.O. Box 411 Arlington, TX 76011-7005 Burlington, KS 66839 Senior Resident Inspector U.S. Nuclear Regulatory Commission U.S. Nuclear Regulatory Commission Resident Inspectors Office P.O. Box 311 8201 NRC Road Burlington, KS 66839 Steedman, MO 65077-1032 Chief Engineer, Utilities Division Kansas Corporation Commission 1500 SW Arrowhead Road Topeka, KS 66604-4027 Office of the Governor State of Kansas Topeka, KS 66612 Attorney General 120 S.W. 10th Avenue, 2nd Floor Topeka, KS 66612-1597 County Clerk Coffey County Courthouse 110 South 6th Street Burlington, KS 66839 Vick L. Cooper, Chief Air Operating Permit and Compliance Section Kansas Department of Health and Environment Bureau of Air and Radiation 1000 SW Jackson, Suite 310 Topeka, KS 66612-1366

WOLF CREEK NUCLEAR OPERATING CORPORATION WOLF CREEK GENERATING STATION DOCKET NO. 50-482 AMENDMENT TO FACILITY OPERATING LICENSE Amendment No. 154 License No. NPF-42

1. The Nuclear Regulatory Commission (the Commission) has found that:

A. The application for amendment to the Wolf Creek Generating Station (the facility)

Facility Operating License No. NPF-42 filed by the Wolf Creek Nuclear Operating Corporation (the Corporation), dated April 30, 2003, as supplemented by letters dated December 18, 2003, and April 13, 2004, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commissions rules and regulations set forth in 10 CFR Chapter I; B. The facility will operate in conformity with the application, as amended, the provisions of the Act, and the rules and regulations of the Commission; C. There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commissions regulations; D. The issuance of this license amendment will not be inimical to the common defense and security or to the health and safety of the public; and E. The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commissions regulations and all applicable requirements have been satisfied.

2. Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment and Paragraph 2.C.(2) of Facility Operating License No. NPF-42 is hereby amended to read as follows:

2. Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 154, and the Environmental Protection Plan contained in Appendix B, both of which are attached hereto, are hereby incorporated in the license. The Corporation shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

3. The license amendment is effective as of its date of issuance and shall be implemented within 90 days of the date of issuance including the incorporation of the changes to the Technical Specification Bases for Technical Specification 3.8.1 as described in the licensees letters dated April 30 and December 18, 2003, and April 13, 2004.

FOR THE NUCLEAR REGULATORY COMMISSION

/RA/

Stephen Dembek, Chief, Section 2 Project Directorate IV Division of Licensing Project Management Office of Nuclear Reactor Regulation

Attachment:

Changes to the Technical Specifications Date of Issuance: July 12, 2004

ATTACHMENT TO LICENSE AMENDMENT NO. 154 FACILITY OPERATING LICENSE NO. NPF-42 DOCKET NO. 50-482 Replace the following pages of the Appendix A Technical Specifications with the attached pages. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change. The corresponding overleaf pages are provided to maintain document completeness.

REMOVE INSERT 3.8-8 3.8-8 3.8-9 3.8-9 3.8-10 3.8-10 3.8-11 3.8-11 3.8-12 3.8-12 3.8-13 3.8-13 3.8-14 3.8-14 3.8-15 3.8-15

SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 154 TO FACILITY OPERATING LICENSE NO. NPF-42 WOLF CREEK NUCLEAR OPERATING CORPORATION WOLF CREEK GENERATING STATION DOCKET NO. 50-482

1.0 INTRODUCTION

By application dated April 30, 2003, as supplemented by letters dated December 18, 2003, and April 13, 2004, Wolf Creek Nuclear Operating Corporation (the licensee) requested changes to the Technical Specifications (TSs, Appendix A to Facility Operating License No. NPF-42) for the Wolf Creek Generating Station (WCGS). The amendment, as originally submitted in the application, would revise TSs 3.8.1 and 3.8.4 on alternating current (AC) and direct current (DC) sources, respectively, for plant operation to allow surveillance testing during reactor modes which is currently not allowed. The revised surveillance requirements (SRs) would have notes deleted or modified to allow the SRs to be performed, or partially performed, in Modes 1 and 2, in some cases Modes 3 and 4, which are currently not allowed in the TSs. The purpose of the proposed amendment is to allow testing of the following AC and DC electrical sources in modes not currently allowed: the qualified circuits between the offsite transmission network and the onsite Class 1E electrical power distribution system, the emergency diesel generators (EDGs), and the DC electrical power subsystem.

The proposed changes to SRs 3.8.4.7 (battery service test) and 3.8.4.8 (battery discharge test),

for the DC electric power subsystems, were withdrawn by the licensee in its letter of April 13, 2004.

The proposed changes would do the following:

 Delete notes in SR 3.8.1.10 (EDG full-load rejection test), SR 3.8.1.13 (EDG protective-trip bypass test), and SR 3.8.1.14 (EDG endurance and margin test) to allow performing the required testing during Modes 1 and 2.

 Revise notes to remove restrictions in SR 3.8.1.11 (emergency bus and EDG loss-of-offsite-power (LOOP) test), SR 3.8.1.12 (EDG safety injection actuation signal test), SR 3.8.1.16 (EDG synchronizing test), SR 3.8.1.17 (EDG test mode change-over test), SR 3.8.1.18 (load block sequencing test), and SR 3.8.1.19 (emergency bus and EDG combined safety injection actuation signal and LOOP test), to allow performance or partial performance of the SRs during currently prohibited modes in order to re-establish operability following corrective maintenance, modifications, deficient or incomplete surveillance testing, and other operability concerns during plant operation.

These changes adopt in part the Nuclear Regulatory Commission-approved changes to the Standard Technical Specifications (STS) in Industry/Technical Specification Task Force (TSTF) 283, Revision 3 (TSTF-283) on eliminating mode restrictions on the performance of SRs in TS 3.8.1. The NRC has approved the TSTF for inclusion in the improved STS in NUREG-1431 for Westinghouse plants, and for consideration for being added to plant TSs. The intent of the TSTF is to allow testing of the EDGs and Class 1E batteries in modes not currently allowed in the TSs for the purpose of maintaining or reestablishing system or component operability (e.g.,

post maintenance testing), provided a safety assessment is made before the testing for operability.

As stated in the application, the above changes in TS 3.8.1 for the AC electric sources would provide the licensee with flexibility in outage scheduling and reduce outage critical path time since these EDG surveillance tests would no longer have to be performed during an outage. In addition, the changes will potentially allow the licensee to avoid a plant shutdown if corrective maintenance (planned or unplanned) performed during power operation results in the need to perform any of the above surveillances to demonstrate operability and to maximize its flexibility in responding to an event during shutdown when other engineered safety feature equipment may be out-of-service.

The licensees description of the proposed changes, technical analysis, and regulatory analysis in support of its proposed license amendment is given in Sections 2.0, 4.0 and 5.2, respectively, of the licensees application.

The licensee also provided responses to questions, addressed in Section 4.2 of this Safety Evaluation (SE), in an e-mail sent to the licensee (see ADAMS Accession No. ML040701115).

The questions were to have the licensee clarify information on operational restrictions in the licensees application and supplemental letter. The additional information provided in the e-mail and the supplemental letters dated December 18, 2003, and April 13, 2004, does not expand the scope of the application as noticed and does not change the NRC staffs original proposed no significant hazards consideration determination published in the Federal Register on July 22, 2003 (68 FR 43394).

2.0 REGULATORY REQUIREMENTS The proposed amendment involves the surveillance testing of the emergency buses and EDGs that currently are not allowed in Modes 1 and 2. The regulatory requirements involved are as follows:

General Design Criterion (GDC) 17, "Electric power systems," of Appendix A, "General Design Criteria for Nuclear Power Plants," to Title 10, Part 50, of the Code of Federal Regulations (CFR), requires, in part, that nuclear power plants have onsite and offsite electric power systems to permit the functioning of structures, systems, and components that are important to safety. The onsite system is required to have sufficient independence, redundancy, and testability to perform its safety function, assuming a single failure. The offsite power system is required to supply power from two physically independent circuits that are 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. In addition, this criterion requires provisions to minimize the probability of losing electric power from the remaining electric power supplies as a result of loss of power from the unit, the offsite transmission network, or the onsite power supplies.

GDC 18, "Inspection and testing of electric power systems," requires that electric power systems that are important to safety must be designed to permit appropriate periodic inspection and testing.

10 CFR 50.36(c)(3), "Technical Specifications," requires a licensees TSs to have SRs relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operations are within safety limits, and that the limiting conditions for operation (LCOs) will be met. The SRs may include mode restrictions based on the safety aspects of conducting the surveillances in excluded modes.

In Appendix 3A of the Wolf Creek Updated Safety Analysis Report (USAR), the licensee addresses how it conforms to NRC Regulatory Guides (RGs). RG 1.9, "Selection, Design, Qualification and Testing of Emergency Diesel Generator Units Used As Class 1E Onsite Electric Power Systems at Nuclear Power Plants," Revision 3, provides recommendations on the reactor modes during which the EDGs should be tested, which is the subject of the proposed amendment. However, the licensee is not committed to RG 1.9, Revision 3. Instead, the licensee is committed to RG 1.9, Revision 1, dated November 1978. The licensee states the following in the USAR:

The recommendations of this regulatory guide [i.e., RG 1.9, Revision 1] are met.

Refer to Section 8.1.4.3.

In USAR Section 8.1.4.3, the licensee provides design information for its EDGs and states that "The continuous rating of each diesel generator is greater than the sum of the conservative estimated loads needed to be supplied following any design basis event. Load requirements are listed in Figure 8.3-2." There are no statements concerning the reactor modes in which the EDGs are to be tested in USAR Section 8.1.4.3.

Because RG 1.9, Revision 1, does not have any recommendations related to testing the EDGs in Modes 1 and 2, the NRC staff reviewed the licensees commitment to RG 1.108, "Periodic Testing of Diesel Generator Units Used As Onsite Electric Power Systems at Nuclear Power Plants." For RG 1.108, Revision 1, dated August 1977, the licensee stated it met the recommendations of this RG as described in USAR Section 8.1.4.3 and the TSs. In USAR Section 8.1.4.3, the following is stated:

At least once per 18 months, during shutdown, the auto-connected loads to each diesel generator are verified not to exceed 6201 kW. This verification is performed as a prerequisite in the performance of Technical Specification Surveillance Requirement 3.8.1.14, to ensure this test does not require testing at above the continuous rating. [The underlining has been added.]

Therefore, if the proposed amendment is approved, the testing requirements in the TSs will be different from that stated in USAR Section 8.1.4.3 above for SR 3.8.1.14. If the amendment to SR 3.8.1.14 is approved, the resulting difference would be that the verification of the auto-connected loads to each EDG prior to conducting SR 3.8.1.14 would not always be performed "during shutdown," as stated in the USAR. After evaluating this inconsistency between the proposed amendment and the USAR, the NRC staff does not see the need for the licensee to revise Appendix 3A of the USAR prior to approval of the subject amendment because (1) the licensee states that it meets the recommendations on periodic testing of EDG in RG 1.108 as described in the TSs, and (2) RG 1.9, Revision 1 does not contain recommendations on the reactor modes that the EDGs should be tested. Changes to the design of the plant as described in the USAR that are approved by the NRC are required to be included in an update of the USAR on a schedule in accordance with 10 CFR 50.71(e).

3.0 BACKGROUND

The onsite power system for WCGS is provided with preferred power from the offsite system through two physically independent sources of power in accordance with GDC 17. With regard to the safety-related (Class 1E) power supply configuration, one preferred circuit from the switchyard supplies power to a multi-winding startup transformer, one winding of which feeds a 13.8/4.16-kV engineered safety feature (ESF) transformer. The second preferred (offsite) circuit supplies power from the switchyard to a second 13.8/4.16-kV ESF transformer. Each ESF transformer supplies power to an associated Class 1E 4.16-kV bus. For each safety-related bus normally fed by its associated ESF transformer, the capability exists for either bus to be supplied via the other preferred (offsite) source connection.

The onsite power system is generally divided into two load groups. Each load group consists of an arrangement of buses, transformers, switching equipment, and loads fed from a common power supply. Each load group is independently capable of safely bringing the plant to a cold shutdown condition, as the Class 1E electrical power distribution system is designed to satisfy the single-failure criterion.

The onsite standby power system includes Class 1E AC and DC power supply capability for equipment used to achieve and maintain a cold shutdown of the plant and to mitigate the consequences of a design basis accident. With regard to the Class 1E AC power, each of the two Class 1E load groups, at the 4.16-kV bus level, is capable of being powered from an independent EDG (one per load group) which functions to provide power in the event of a loss of the preferred (offsite) power source. Undervoltage relays are provided for each 4.16-kV bus to detect an undervoltage condition and automatically start the EDG in response to such a condition. The Class 1E DC system includes four separate 125-VDC battery supplies for Class 1E controls, instrumentation, power, and control inverters.

In the event of a loss-of-coolant accident (LOCA), LOOP, or both, the starting (or shedding and restarting) of Class 1E electrical loads is controlled by the load shedding emergency load sequencers (LSELS), one of which is provided for each 4.16-kV bus. In the event of a LOCA with preferred (offsite) power available to the 4.16-kV Class 1E bus(es), Class 1E loads are started in programmed time increments by the load sequencer(s). The associated EDG will be automatically started but not connected to the bus. However, in the event that preferred (offsite) power is lost, the load sequencer will function to shed selected loads and automatically start the associated standby EDG (via the EDG control circuitry). The load sequencer(s) will function to start the required Class 1E loads in programmed time increments.

4.0 TECHNICAL EVALUATION

To allow testing of AC electrical sources in TSs 3.8.1, in reactor modes not currently allowed, the licensee proposed the following changes to the TSs:

1. Delete the note stating surveillance shall not be performed in Modes 1 and 2 for SR 3.8.1.10 to verify each EDG at a power factor will not trip and voltage is maintained following a load rejection.

2. Revise Note 2 to allow performance of portions of SR 3.8.1.11, in Modes 1 and 2, to verify de-energization of emergency buses, load shedding from emergency buses, and EDG auto-starts from standby condition on an actual or simulated LOOP signal.

3. Revise Note 2 to allow performance of portions of SR 3.8.1.12, in Modes 1 and 2, to verify EDG auto-starts from standby condition on an actual or simulated safety injection signal (SIS).

4. Delete the note stating surveillance shall not be performed in Modes 1 and 2 for SR 3.8.1.13 to verify each EDGs automatic trips are bypassed on an actual or simulated loss-of-voltage signal on the emergency bus concurrent with an actual or simulated SIS.

5. Delete Note 2 (and renumber the remaining notes) stating surveillance shall not be performed in Modes 1 and 2 for SR 3.8.1.14 to verify each EDG operating for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

6. Revise note to allow performance of SR 3.8.1.16, in Modes 1 through 4, to verify each EDG synchronizes with offsite power source, transfers loads to offsite power source, and returns to ready-to-load operation.

7. Revise note to allow performance of portions of SR 3.8.1.17, in Modes 1 and 2, to verify, with an EDG operating in test mode and connected to its bus, an actual or simulated SIS overrides the test mode.

8. Revise note to allow performance of SR 3.8.1.18, in Modes 1 and 2, to verify interval between each sequenced load block for each LOCA and shutdown sequencer.

9. Revise Note 2 to allow performance of portions of SR 3.8.1.19, in Modes 1 and 2, to verify de-energization of emergency buses, load shedding from emergency buses, and EDG auto-starts from standby condition on an actual or simulated LOOP signal in conjunction with an actual or simulated SIS.

In revising or deleting the notes for the above SRs, the licensee is not changing either the frequency of conducting the SRs, the surveillance to be performed, or the performance criteria specified in the SRs. The only change is to the reactor modes that the surveillance may be performed.

For SRs 3.8.1.10, 3.8.1.13, and 3.8.1.14, the note that states "This Surveillance shall not be performed in MODE 1 or 2" would be deleted. Therefore, these SRs could be performed in any reactor mode including Modes 1 and 2.

For SRs 3.8.1.11, 3.8.1.12, 3.8.1.17 and 3.8.1.19, the notes would be revised such that the current note stating "This Surveillance shall not be performed in MODE 1 or 2" would be revised to state that "This Surveillance shall not normally be performed in MODE 1 or 2. However, portions of the Surveillance may be performed to re-establish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced." The changes to the current notes are underlined. Therefore, portions of these SRs to re-establish operability could be performed in Modes 1 and 2, but an assessment must be performed by the licensee before the SRs are performed.

For SR 3.8.1.16, the note would be revised such that the current note stating "This Surveillance shall not be performed in MODE 1, 2, 3, or 4" would be revised to state that "This Surveillance shall not normally be performed in MODE 1, 2, 3, or 4. However, this Surveillance may be performed to re-establish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced." The changes to the current notes are underlined. Therefore, the SR could be performed in Modes 1 through 4, but an assessment must be performed by the licensee before the SRs are performed.

For SR 3.8.1.18, the note would be revised such that the current note stating "This Surveillance shall not be performed in MODE 1 or 2" would be revised to state that "This Surveillance shall not normally be performed in MODE 1 or 2. However, this Surveillance may be performed to re-establish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced." The changes to the current notes are underlined. Therefore, the SR could be performed in Modes 1 and 2, but an assessment must be performed by the licensee before the SR is performed.

4.1 AC Sources Discussion The operability requirements for the onsite and offsite AC sources during plant operation in Modes 1, 2, 3, and 4 are specified in TS 3.8.1, AC sources - Operating. TS 3.8.1 includes SRs for monitoring the offsite sources and testing the EDGs. Currently, SRs 3.8.1.10 (full-load rejection test), 3.8.1.13 (protective-trip bypass test), and 3.8.1.14 (endurance and margin test) must be performed while the plant is in a shutdown condition (i.e., Mode 5 or 6). While in Mode 5 or 6, TS 3.8.2 requires that one of the two EDGs remain operable. The licensee stated that

the EDG being tested is typically not the EDG that is being maintained or credited as the operable EDG for satisfying TS 3.8.2.

The proposed changes would allow EDG testing to be performed during plant operation (i.e., in Modes 1, 2, 3, and 4) when both EDGs are required to be operable in accordance with TS 3.8.1. Therefore, the EDG under test would be required to be operable. Any condition associated with the testing that would not allow the EDG to be operable would require the licensee to declare the EDG inoperable and enter the required actions in TS 3.8.1 for an inoperable EDG.

4.1.1 SRs 3.8.1.10, 3.8.1.13, and 3.8.1.14 The proposed changes to SR 3.8.1.10 (EDG full-load rejection test), SR 3.8.1.13 (EDG protective-trip bypass test), and SR 3.8.1.14 (EDG endurance and margin test) would remove the reactor mode restrictions in the SRs that prohibit performing the testing in Modes 1 and 2.

The proposed changes are different from the changes to these SRs in TSTF-283 in that the TSTF changes would allow testing of the EDGs in Modes 1 and 2 only for reestablishing the operability of the EDGs. The licensees proposed changes would allow these SRs to be performed during Modes 1 and 2 to meet the surveillance frequency of once per 18 months, and thus need not be scheduled during refueling outages. The licensee stated in its application that it proposed the changes to SRs 3.8.1.10, 3.8.1.13, and 3.8.1.14 to "help reduce the complexity of coordinating work and testing activities during refueling outages and could potentially reduce outage critical path time" (i.e., reduce complexity by not performing these SRs in a refueling outage). The licensees proposed changes to these SRs, although not consistent with the TSTF, meet the intent of the TSTF to avoid a plant shutdown if maintenance of the EDGs were performed during power operation.

4.1.1.1 LOOP, LOCA, and LOOP/LOCA Discussion In reviewing the proposed changes to SRs 3.8.1.10, 3.8.1.13, and 3.8.1.14, the NRC staff considered postulated events associated with EDG start signals. There are three such events:

a LOOP, LOCA, and LOCA with a LOOP.

LOOP In the event of a LOOP occurring while an EDG is running and paralleled to offsite power for testing, the EDG would continue supplying power to the loads on the safety bus as well as to the offsite system if no separation of the offsite source occurred. In this case, the bus undervoltage relays might not immediately trip if the bus voltage is being adequately supported by the EDG. However, the licensee stated that because loading would exceed the EDGs capability, the EDG would be unable to match load and either the bus undervoltage relays would trip (after timing out) or the EDG overcurrent or underfrequency relays would trip. The former would cause the feeder breakers in the offsite source connection to trip (but not the EDG output breaker); whereas the latter would cause the EDG output breaker to trip open.

If the bus undervoltage relays (i.e., loss-of-power (LOP) diesel generator start instrumentation required by TS 3.3.5) tripped in response to an undervoltage condition (after the relays timed

out), the feeder breakers would trip to separate the offsite source. At the same time, the LOP signal would initiate the LSELS which in turn would cause all but the permanently connected bus loads to be shed. Sequenced loads would then be loaded onto the bus via the blackout sequencer. Since the EDG would already be running and connected, the EDG start signal from the LOP instruments would have no effect in that regard. At this point, the plant would respond as it would in response to a LOOP condition.

If the overcurrent or underfrequency relays tripped (i.e., before the degraded voltage relays tripped), the EDG output breaker would trip open. Immediately after the overcurrent or underfrequency relays opened the EDG output breaker, the resultant dead-bus condition would cause the LOP instrumentation to trip which would then trip the feeder breakers open to fully isolate the offsite system from the bus. The EDG output breaker would then re-close, reenergizing the bus. At this point, the plant would respond as it would in response to a LOOP condition.

The overcurrent or underfrequency trips are the features intended to open the EDG output breaker without lockout. However, there are several non-essential EDG trip functions enabled when the EDG is in the test mode, i.e., paralleled with the offsite source, which are bypassed when the EDG is in the emergency mode. In the event that one of these functions is caused to trip, the EDG output breaker will open and lock out. Depending on the type of trip, the EDG may also trip and lock out. If one of these EDG protective trips were to occur in response to a disturbance in the offsite power system, operator action can be taken to manually reset the lockout relay of the EDG under test so that the EDG can be restarted and loads properly sequenced.

For the above, the worst-case effect of having an EDG under test when a LOOP occurs is potentially delaying the plant response to the LOOP (by several minutes), as operator action may be needed to reset the EDG lockout relay. In general, the time response to a LOOP is not critical, as there is no concurrent accident condition and the affected bus can be restored well within the time needed to effect safe shutdown. In addition, the other train would not be affected by the EDG under test, therefore its response to a LOOP would not be affected.

LOCA For an SIS (i.e., a LOCA occurs) while an EDG is under test and paralleled to offsite power via the associated safety bus, the EDG response is as designed. In other words, the SIS overrides the test mode as follows: the LOCA signal will cause the EDG start circuitry to reset and trip the EDG output breaker. LSELS will initiate the LOCA sequence for required bus loads as the bus continues to be powered from the offsite source. The EDG will start and remain in a standby/ready-to-load condition. This sequence is in accordance with the design basis, and therefore, for this scenario there is no impact to the analyzed plant response to the LOCA. The override capability mentioned above is periodically verified by test pursuant to TS SR 3.8.1.17.

Furthermore, there is no impact to the other bus/EDG/load group since only the EDG under test is affected.

LOCA with a LOOP In the accident analyses of the WCGS USAR, a LOCA is postulated to occur concurrently with a LOOP (i.e., a LOCA with a LOOP, or a LOOP/LOCA) for the purposes of providing a bounding analysis that challenges ESF equipment. The response of an EDG to a LOOP and LOCA while the EDG is being tested is dependent on which (LOOP or LOCA) occurs first (or whether the two events occur simultaneously), as described further below.

If an EDG were under test, and a LOOP occurred simultaneously with a LOCA, the EDG output breaker would immediately open and the EDG start circuitry would be initiated (reset). Non-essential loads would be shed from the bus via LSELS and then the EDG output breaker would re-close onto the de-energized bus. Immediately after that, LSELS would sequence required loads onto the bus via the LOCA sequencer which, by design, takes precedence over the blackout sequencer.

For the case when the LOOP occurs just after a LOCA, the LOCA sequencer would still control bus loading. Initially, with offsite power still available, the LOCA signal would open the EDG output breaker while the EDG would continue to run (with its governor and voltage regulator reset). If a LOOP then occurred (i.e., after the SIS was reset), the LOP instrumentation would cause the EDG output breaker to close, and the blackout sequencer would then effect reloading the bus. This would cause a shedding and re-sequencing of loads (except for permanently connected loads such as the centrifugal charging pumps). The blackout sequencer would then allow the EDG to re-energize loads needed to maintain plant shutdown.

For the case where a LOOP occurs prior to a LOCA (with the EDG in a test mode), the following sequence could be expected to occur. Initially, when the LOOP occurs, the sequence would be as described previously for a LOOP-only condition. The degraded voltage, overcurrent, or underfrequency relays would actuate, or possibly one of the non-essential relays would actuate. Then, either of the aforementioned sequences would occur or begin to occur based on which of the noted trip functions occurred first (or in lieu of the other). The occurrence of a LOCA at this point would cause an SIS to be generated, but the subsequent response is dependent on which trip function was actuated in response to the LOOP.

(1) If the degraded voltage relays had effected a separation of the offsite source in response to the LOOP, the SIS would cause the LOCA sequencer to go into effect.

(2) If a non-essential relay had responded before the degraded voltage relays during the LOOP, an EDG lockout would be in effect. Although the non-essential trips are designed to be bypassed by an SIS, the SIS cannot reset a lockout that is already in effect. Operator action may be required to reset the lockout before the EDG is restarted in response to the LOOP-LOCA condition. The LOCA sequencer would then reload the bus with all required sequenced loads.

In summary, the licensee stated that the worst-case effect for some of the above scenarios is to delay but not preclude system responses to the SIS (i.e., a LOCA) for the affected bus.

Furthermore, the licensee noted that there would be no impact to the other bus since only the EDG under test is affected. For the worst-case effect of having an EDG under test when a

LOOP occurs is potentially delaying the plant response to the LOOP (by several minutes), the time response to a LOOP is not critical, as there is no concurrent accident condition and the affected bus can be restored well within the few minutes needed to effect safe shutdown.

Based on the discussion above, on the LOOP, LOCA, and LOCA with a LOOP, the NRC staff concludes that the EDG may be safely tested in Modes 1 and 2.

The following is the NRC staffs evaluation on the licensees proposed changes to SRs 3.8.1.10, 3.8.1.13, and 3.8.1.14.

4.1.1.2 SR 3.8.1.10 Performance of the full-load rejection test in accordance with SR 3.8.1.10 involves paralleling the EDG under test with the offsite power source while the offsite source is supplying the emergency bus, loading the EDG to the required load, and then opening the EDG output breaker. Opening the EDG output breaker separates the EDG from its associated emergency bus and allows the offsite circuit to continue to supply the bus. At WCGS, paralleling an EDG with the offsite source for testing does not render the EDG inoperable because a SIS will override the test mode to automatically return the EDG to a standby/ready-to-load condition.

This design feature of the EDGs does not adversely affect the capability of the EDG to respond to an SIS.

The concern associated with performing the full-load rejection test in Mode 1, 2, 3, or 4 as described in the TS Bases for SR 3.8.1.10, is that disconnecting the EDG while it is supplying power to the vital buses could cause undesirable electrical perturbations on the bus.

Additionally, the EDG being tested is susceptible to grid disturbances while it is paralleled to the offsite source, and is potentially more susceptible to tripping due to the extra protection trip relays that are cut in during the test. The EDG is paralleled with the offsite source for a limited period of time before tripping the EDG breaker.

In the event of a grid disturbance occurring while the EDG is paralleled to offsite power, protective relaying and instrumentation exists to mitigate the effects of such disturbances. With regard to plant loads connected to the associated safety bus and a grid disturbance involving a sustained low grid-voltage condition, the protection instrumentation required by TS 3.3.5, "Loss of Power Diesel Generator Start Instrumentation," would be available to respond to such a condition for protection of the plant loads. The LOP diesel generator start instrumentation is required for the ESF systems to function in any accident with a LOOP or degraded offsite power system. This instrumentation provides for the shedding and sequencing of safety-related loads in addition to sending a start signal to the EDGs. This instrumentation also provides for the protection of safety-related equipment against damage and the effects of inadvertent operation of overcurrent protection throughout its train. For this reason, the allowed outage time for multiple inoperable channels is restricted to that of the LSELS in LCOs 3.8.1 and 3.8.2 of the WCGS TSs.

The LCO for LOP diesel generator start instrumentation requires that four channels per 4.16 kV Class 1E system bus of both the loss-of-voltage and degraded voltage functions shall be operable in Modes 1, 2, 3, and 4 when the LOP diesel generator start instrumentation supports safety systems associated with the ESFAS. The LOP diesel generator start instrumentation

functions are required in Modes 1, 2, 3, and 4 because ESF systems are required to function in these modes. For the instance when one channel of the LOP diesel generator start instrumentation is inoperable, the inoperable channel is placed in trip within six hours. The trip logic would then be a one-out-of-three versus two-out-of-four, which is more conservative. If two or more channels of the LOP diesel generator start instrumentation are inoperable, the associated LSELS is declared inoperable immediately. This requires the EDG being tested to be declared inoperable.

In the licensees response dated December 18, 2003, to an NRC staff request for additional information, the licensee noted that for the case when the EDG not under test becomes inoperable while an EDG test is underway, the decision to abort the test would be based on existing plant conditions. TS 3.8.1, Condition E would be entered for two EDGs inoperable, with Required Action E.1 requiring restoring one EDG to operable status in 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. The testing remaining on one EDG and the cause of the failure on the opposite train EDG would result in determining the shortest time to restore one EDG to operable status. The above discussion provides an example of this process. In any case, TS 3.8.1, Condition E, adequately governs the situation.

Additionally, the licensee noted that the highest voltage level at which the degraded voltage relays may actuate, and not reset, is 91.5 percent of nominal and that the relays have a time delay of 119 +/-11 seconds before an actuation can occur. The licensee stated that this voltage level and time duration are not significantly approached during the load rejection test.

Furthermore, the licensees experience with this test has shown that the voltage perturbation seen on the bus during and just after the load rejection is within a 5 percent change, and, therefore, not significant.

4.1.1.3 SR 3.8.1.13 SR 3.8.1.13 requires verification that the non-emergency automatic protective trip functions for each EDG are bypassed on a loss-of-voltage signal concurrent with a SIS. The test procedure involves simulating trips for those functions that are automatically bypassed during an emergency start and verifying that the EDG output breaker does not trip. The use of jumpers and blocking devices is not required. The TS Bases for SR 3.8.1.13 currently notes that it is prohibited to perform this surveillance during Modes 1 and 2 since its performance requires removing a required EDG from service. The licensee stated that if this test were to be performed in either Modes 1 or 2 an appropriate overlap testing scheme would be used rather than having the EDG actually supplying the emergency bus in the emergency mode.

Therefore, the EDG under test will remain operable during this test. In addition, the other EDG will remain operable to supply its bus and all of its associated loads for safe shutdown of the facility in the event of an accident.

4.1.1.4 SR 3.8.1.14 Performance of the endurance and margin test in accordance with SR 3.8.1.14 involves synchronizing, paralleling and loading the EDG with the offsite source and then running it continuously at its full-load capability for not less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. In accordance with the WCGS TS, during the 24-hour run the EDG must be loaded and run at 110 percent of its continuous

duty rating for at least 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> if it has been determined that the auto-connected design loads have increased above the continuous duty rating of the EDG. As stated above, paralleling an EDG with the offsite source for testing does not render the EDG inoperable at WCGS. An SIS will override the test mode to automatically return the EDG to a standby/ready-to-load condition.

This design feature of the EDGs does not adversely affect the capability of the EDG to respond to an SIS. The concern with performing the 24-hour endurance test in Modes 1, 2, 3, or 4 (as described in the TS Bases for SR 3.8.1.14) is that while an EDG is paralleled to the offsite source, the EDG is not independent of disturbances on the offsite power system, and the associated safety bus and train of equipment are not independent of any potential interaction between the EDG and the offsite system. Additionally, the EDG is potentially more susceptible to tripping due to the extra protection trip relays that are cut in during testing. The licensee stated that the availability of the other EDG is maintained in a protected status during the performance of the subject surveillance. In the event of a grid disturbance occurring while the EDG is paralleled to offsite power, protective relaying and instrumentation will mitigate the effects of such disturbances (including the aforementioned LOP diesel generator start instrumentation). The licensee noted that if an EDG protective trip were to occur in response to a disturbance in the offsite power system, operator action can be taken to manually reset the lockout relay of the EDG under test (assuming that the condition which caused the trip was promptly cleared or isolated) so that the EDG can be restarted and loads properly sequenced, if required.

4.1.1.5 Conclusion Based on the above and the licensees commitments listed in Section 4.3 of this safety evaluation, the NRC staff concludes that it is safe for the licensee to test the EDGs in Modes 1 and 2 as proposed by the changes to SRs 3.8.1.10, 3.8.1.13, and 3.8.1.14.

4.1.2 SRs 3.8.1.11, 3.8.1.12, 3.8.1.16, 3.8.1.17, 3.8.1.18, and 3.8.1.19 The licensee proposed changes that would modify SR 3.8.1.11 (emergency bus and EDG LOOP test), SR 3.8.1.12 (EDG safety injection actuation signal test), SR 3.8.1.16 (EDG synchronizing test), SR 3.8.1.17 (EDG test mode change-over test), SR 3.8.1.18 (load block sequencing test), and SR 3.8.1.19 (emergency bus and EDG combined safety injection actuation signal and LOOP test) to allow the performance or partial performance of these surveillances during currently prohibited modes. This would be allowed in order to re-establish operability following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and other unanticipated operability concerns during plant operation. The proposed changes will permit testing in additional modes not currently allowed by the TSs and these surveillances can be physically conducted in the proposed additional modes. Because it is only the current requirements in TS 3.8.1 that prevent testing in the additional modes proposed in this amendment, there were no changes needed to the plant to conduct these SRs in the additional modes.

The proposed changes will revise a note in each affected SR to permit testing of an EDG or emergency bus "provided an assessment determines the safety of the plant is maintained or enhanced." The changes to these SRs are consistent with those given in TSTF-283. The

licensee stated that it will update the WCGS TS Bases to provide guidance relative to the safety assessment.

Because the testing of EDGs and emergency buses in SRs 3.8.1.11, 3.8.1.12, 3.8.17, and 3.8.1.19 are more complicated or intrusive than other SRs and would involve too great an impact or perturbation to the plant to be entirely performed during plant operation, the revised note for these SRs would permit a partial performance (i.e., portions of the surveillance or a partial surveillance) of the applicable SR to re-establish operability.

Because (1) the surveillances are not being changed by the proposed amendment and can be conducted in the modes proposed by the amendment, (2) the proposed notes require a safety assessment to be performed by the licensee before conducting the surveillances to ensure that plant safety is maintained or enhanced, and (3) the full or partial performance of the SR is to demonstrate operability of the EDGs, the NRC staff concludes that an unsafe condition should not exist when the licensee performs any of these SRs in reactor modes not currently allowed.

Allowing the licensee to make the determination that performance of these SRs in modes not currently allowed maintains or enhances the safety of the plant, is similar to the regulation 10 CFR 50.59 in which the licensee is allowed to make changes to the plant as described in the USAR if the changes meet the criteria given in the regulation. The criteria for this situation is that the licensee must determine that in conducting the SR the "safety of the plant is maintained or enhanced."

Based on the above, the NRC staff concludes that it is safe for the licensee to test the EDGs in Modes 1, 2, 3, and 4 as proposed by the changes to SRs 3.8.1.11, 3.8.1.12, 3.8.1.16, 3.8.1.17, 3.8.1.18, and 3.8.1.19 (for Modes 1 and 2) and to SR 3.8.1.16 (for Modes 3 and 4).

4.2 Licensee Commitment to Manage Risk In its application and supplemental letter dated December 18, 2003, which is the licensees response to the NRC staffs request for additional information dated September 25, 2003, the licensee described how it would manage the risk of testing the EDG in reactor modes not currently allowed by the TSs. To understand how the licensee would manage this risk, the NRC staff asked the licensee to clarify if its application and supplemental letter dated December 18, 2003, encompassed the following specific restrictions on testing the EDG in Modes 1 and 2 while the EDG is connected to the offsite power supply:

1. Weather conditions will be evaluated prior to testing the EDG in Modes 1 and 2 connected to the offsite power supply and the testing would not be conducted for severe weather watches or warnings.

2. The condition of the offsite power supply will be evaluated prior to testing the EDG in Modes 1 and 2 connected to the offsite power supply and testing would not be conducted if the offsite power supply is being challenged.

3. No discretionary switchyard maintenance, including the main, auxiliary, or startup transformers, will be allowed during testing of the EDG in Modes 1 and 2 connected to the offsite power supply.

4. No maintenance or testing that affects the reliability of the train not associated with the EDG being tested will be conducted during testing of the EDG in Modes 1 and 2 connected to the offsite power supply. If any testing or maintenance of the train must be performed at this time, then a 10 CFR 50.65(a)(4) evaluation will be performed prior to the EDG testing connected to the offsite power supply.

In the licensees email dated February 25, 2004 (ADAMS Accession No. ML040701115, dated March 10, 2004), the licensee stated that the restrictions listed above are encompassed by its discussion in its application and supplemental letter dated December 18, 2003.

In its letter dated April 13, 2004, the licensee stated that upon implementation of the amendment it would add information to the TS Bases for SR 3.8.1.14 that encompasses the statements made above. The NRC staff reviewed what would be added to the TS Bases for SR 3.8.1.14 and agrees that it encompasses the statements made above.

Based on the above evaluation, the NRC staff also concludes that the licensee's management of risk for testing the EDG in additional modes and the commitments given above are reasonable and sufficient for the amendment.

4.3 Conclusions The design of the onsite and offsite electric power systems for WCGS to permit the functioning of structures, systems, and components that are important to safety is not being changed by the proposed amendment. Further, the amendment does not change the testing of the EDG, only the modes in which the testing is conducted. Therefore, the plant continues to meet GDC 17.

The ability to inspect and test the safety-related electric power systems for Callaway, which must be designed to permit appropriate periodic inspection and testing, are not being changed by the amendment. Therefore, the plant continues to meet GDC 18.

For the reasons discussed in Sections 4.1 and 4.2 above, the NRC staff concludes that the proposed changes to SRs 3.8.1.10 through 3.8.1.14 and SRs 3.8.1.16 through 3.8.1.19, to allow testing the EDG in Modes 1 and 2 and for SR 3.8.1.16 in Modes 3 and 4, are acceptable.

Therefore, based on this, the NRC staff also concludes that the proposed changes to TS 3.8.1 meet 10 CFR 50.36(c)(3).

Based on the evaluation given above and because the proposed amendment meets GDC 17, GDC 18, and 10 CFR 50.36(c), the NRC staff concludes that the proposed amendment to SRs 3.8.1.10 through 3.8.14 and SRs 3.8.1.16 through 3.8.1.19 for AC power sources is acceptable.

4.4 Changes to the TS Bases The licensee presented the changes to the TS Bases for the proposed amendment in to its application and in the letters dated December 19, 2003, and April 14, 2004.

The NRC staff has reviewed the changes to the TS Bases for TS 3.8.1 and has no

disagreement with these changes. The TS Bases changes for TS 3.8.4 will not be made because the proposed changes to SRs 3.8.4.7 and 3.8.4.8 were withdrawn by the licensee.

5.0 STATE CONSULTATION

In accordance with the Commissions regulations, the Kansas State official was notified of the proposed issuance of the amendment. The State official had no comments.

6.0 ENVIRONMENTAL CONSIDERATION

The amendment changes surveillance requirements. The NRC staff has determined that the amendment involves no significant increase in the amounts, and no significant change in the types, of any effluents that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding that the amendment involves no significant hazards consideration and there has been no public comment on such finding (68 FR 34673). Accordingly, the amendment meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Pursuant to 10 CFR 51.22(b) no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the amendment.

7.0 CONCLUSION

The Commission has concluded, based on the considerations discussed above, that: (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 Commissions 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.

Principal Contributor: Matthew McConnell Date: July 12, 2004

7590-01-P UNITED STATES NUCLEAR REGULATORY COMMISSION WOLF CREEK NUCLEAR OPERATING CORPORATION DOCKET NO. 50-482 NOTICE OF PARTIAL WITHDRAWAL OF APPLICATION FOR AMENDMENT TO FACILITY OPERATING LICENSE The U.S. Nuclear Regulatory Commission (the Commission) has granted the request of Wolf Creek Nuclear Operating Corporation (the licensee) to partially withdraw its April 30, 2003, application for proposed amendment to Facility Operating License No. NPF-42 for the Wolf Creek Generating Station, Unit 1, located in Coffey County, Kansas.

The proposed amendment would modify several surveillance requirements (SRs) in Technical Specifications (TSs) 3.8.1 and 3.8.4 on alternating current and direct current sources, respectively, for plant operation. The revised SRs would have notes deleted or modified to allow the SRs to be performed, or partially performed, in reactor modes that are currently not allowed by the TSs. The current SRs are not allowed to be performed in Modes 1 and 2.

Several of the current SRs also cannot be performed in Modes 3 and 4.

The Commission had previously issued a Notice of Consideration of Issuance of Amendment published in the Federal Register on June 10, 2003 (68 FR 34673). However, by letter dated April 13, 2004, the licensee partially withdrew the proposed change in that it withdrew the proposed changes to TS 3.8.4.

For further details with respect to this action, see the application for amendment dated April 30, 2003, and the licensees letter dated April 13, 2004, which partially withdrew the application for license amendment. Documents may be examined, and/or copied for a fee, at the NRCs Public Document Room (PDR), located at One White Flint North, Public File Area O1

F21, 11555 Rockville Pike (first floor), Rockville, Maryland. Publicly available records will be accessible electronically from the Agencywide Documents Access and Management Systems (ADAMS) Public Electronic Reading Room on the internet at the NRC Web site, http://www.nrc.gov/reading-rm/adams/html. Persons who do not have access to ADAMS or who encounter problems in accessing the documents located in ADAMS, should contact the NRC PDR Reference staff by telephone at 1-800-397-4209, or 301-415-4737 or by email to pdr@nrc.gov.

Dated at Rockville, Maryland, this 12th day of July 2004.

FOR THE NUCLEAR REGULATORY COMMISSION

/RA/

Jack Donohew, Project Manager, Section 2 Project Directorate IV Division of Licensing Project Management Office of Nuclear Reactor Regulation