Text

NRR E-mail Capture - ME8251 - Duane Arnold - Preparations for Potential Bravo Diesel Generator LCO Extension TS 3.8.1
	ML12107A153
Person / Time
Site:	Duane Arnold
Issue date:	04/13/2012
From:	Feintuch K; Division of Operating Reactor Licensing
To:	Feintuch K; Division of Operating Reactor Licensing
References
	TAC ME8251
	Download: ML12107A153 (78)
	v • d • e

NRR-PMDAPEm Resource From: Feintuch, Karl Sent: Friday, April 13, 2012 2:38 PM To: Feintuch, Karl

Subject:

ME8251 - Duane Arnold - preparations for potential Bravo Diesel Generator LCO Extension Re: TS 3.8.1 Attachments: TSCR-134 (NG-12-0145); Emergency TS Change on DG B.DOC; TSCR-134 (NG-12-0145);

Emergency TS Change on DG B.DOC; BTP 8-8 ML113640138.pdf The activities associated with this issue scroll from the bottom up. This information will be placed in ADAMS and used to close TAC ME8251 in TRIM.

As background for this issue, see a comparable activity associated with TAC1404 pertaining to the Fitzpatrick plant in June 2009 and see Branch Technical Position BTP 8-8 (attached).

========== final update 2012-04-13-1410 ET =======

There has been no further activity on this issue. The content below will be placed in ADAMS as a record and used to close TAC ME8251.

Karl Feintuch PM for Duane Arnold 301-415-3079

========== update 2012-03-26-1030 ET =======

1 - There has been no further activity associated with TAC ME8251. As noted below, ME8251 should accept charges for the period of interest March 21-26, 2012. Please contact me if you experience a problem entering the charge number on your time sheets.

2 - For this update I deleted addressees external to the NRC: DAEC staff Steve Catron and Thomas Byrne.

3 - I still intend to close the TAC using an update to this record. My review of content thus far is that it is public and non-sensitive: All attached items are clearly labeled as drafts, are not labeled for sensitivity, have open space and editorial comments indicating needs for further writing, and no decisions were made on the action(s) then contemplated by the licensee.

Karl Feintuch PM for Duane Arnold 301-415-3079

========== update 2012-03-26-1448 ET =======

Duane Arnold exited the LCO at 0530 CT on 3/25/2012. A TAC has been issued to assemble costs for this effort:

ME8251, DUANE ARNOLD - Bravo Diesel Generator LCO Extension Re: TS 3.8.1 Action B.5 The estimated start date has been moved back to 3/20/2012 to accept time charges for 3/22-23/2012, as needed for amended time sheets. I will leave the TAC open for approx 1-2 weeks and close it with one of these updates.

========== update 2012-03-25-0844 ET =======

Event is over: Duane Arnold has exited LCO. I will get details later.

(I applied for a pre-application review TAC yesterday, backdated to Thursday. You can try it when I distribute the information. I will close it with one of these updates - kdf)

message from Steve Catron NextEra Licensing Sat 3/24/2012 8:23AM ET --------

1

From: Catron, Steve [1]

Sent: Sunday, March 25, 2012 8:23 AM To: Feintuch, Karl Cc: Byrne, Thomas

Subject:

Re: DAEC B SBDG Status 0900 Update Operability run completed and LCO exited.

Sent from my iPad

Feintuch enquiry --------------

On Mar 25, 2012, at 6:55 AM, "Feintuch, Karl" <Karl.Feintuch@nrc.gov> wrote:

Any updates for me to distribute?

3/24/2012 status --------------

Nothing new at 5 PM ET. I just tuned up the figures in case of the need to later reference them.

catch up message: attendees at 3/23/2012 conference call ------------

From: Feintuch, Karl Sent: Sunday, March 25, 2012 1:29 AM To: Feintuch, Karl; 'Byrne, Thomas'

Subject:

RE: DAEC Personnel on the 10AM DG Phone Call, NRC participants with spelling correction Spelling correction:

Sergiu Basturescu, EEEB From: Feintuch, Karl Sent: Sunday, March 25, 2012 1:25 AM To: 'Byrne, Thomas' Cc: Feintuch, Karl

Subject:

RE: DAEC Personnel on the 10AM DG Phone Call, NRC participants NRC Personnel Karl Feintuch, LPL3-1 Shawn Williams, LPL3-1 Jim Andersen, EEEB Bob Wolfgang, EPTB Gurjendra Bedi, EPTB Sergiu Basturesau, EEEB Roy Mathew, EEEB Matthew McConnell, EEEB Gerald Waig, STSB Terry Beltz, LPL3-1 Lucas Haeg, Region 3, SRI Rob Murray, Region 3, RI Mark Ring, Region 3, BC From: Byrne, Thomas [2]

Sent: Friday, March 23, 2012 11:07 AM To: Feintuch, Karl

Subject:

DAEC Personnel on the 10AM DG Phone Call Tom Byrne Steve Catron Bob Murrell Jim Connolly Anil Julka Dan Tomaszewski Thomas R. Byrne 2

Thomas.Byrne@nexteraenergy.com Senior Licensing Engineer Duane Arnold Energy Center (319) 851-7929

end conference call attendees ----------------

Added Figure Numbers to differentiate early draft of application from later draft - kdf 3/24/2012 1605 ET

========== update 2012-03-24-1533 ET =======

Repairs are going well and ahead of schedule two relevant messages follow.

Yellow highlight below was added by me - kdf.

message from Steve Catron NextEra Licensing Sat 3/24/2012 10:06 AM --------

Flex gear was installed over night and blower is on the engine. In process of bolting and then will begin warming the oil and jacket coolant for the maintenance run.

First installation last night indicated the need to remove a small amount of material from inner bore of gear. All clearances are now in spec.

Anticipate maintenance run this afternoon and operability test tonight, so that we expect to exit the LCO ahead of expiration.

Sent from my iPad Begin forwarded message:

Subject:

DAEC B SBDG Status 0900 Update Reassembly of the blower is in progress timeline currently is:

Torquing and lockwiring completed at 1100

Lube oil start warming to start at 1200 (6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months duration)

Clear remaining tags at 1500

Maintenance Run at 1800 to be completed at 2100.

Operability Run completed at 3/25 0300.

end Catron message --------

message from Luke Haeg Senior Resident Inspector Sat 3/24/2012 1:02 PM -----

1200 CST update for Saturday, March 24 I just talked with the licensee - they have re-assembled the flex gear and are in the process of re-assembling the blower. The maintenance run is expected to occur within the next few hours, and the operability test to exit the LCO is slated for 9pm CST tonight. Yesterday, the licensee discovered that the flex gear outer ring gear clearance to the hub was less than the specification and performed polishing of the ring gear to re-establish the clearance. Assuming that the maintenance and operability runs are successful, an emergency TS amendment is very unlikely at this point. Based on the prior several days, there is no indication that the B EDG testing activities would not be successful today. The RI or myself will be observing the operability test tonight and we'll go through the normal channels if any issues arise.

Please call with any questions.

-Luke Haeg, SRI 219-448-3161

end Haeg message --------

========== update 2012-03-23-1815 ET =======

We got a break: Licensee is making progress toward exiting the LCO before its expiration. Licensee provided an advanced draft, which will not be reactivated unless the repair path is challenged. It appears unlikely that you will need to work on this further this weekend.

Details follow:

A - The Repair Path is now the strongest of the three paths:

3

Timeline and planned phases -

Friday (today, 3/23/2012, 1800 ET*) - Fairbanks-Morse is continuing maintenance and surface refinishing: no show-stopper conditions are apparent

ET or CT will not be further specified because the times are approximate

Friday (est 2000) - system in reassembly

Saturday (est 2000) - Maintenance run of D-Gen (est 4 hours0.167 days 0.0238 weeks 0.00548 months )

Sunday (est 0600) - Operability Surveillance Test (est 3-4 hours0.167 days 0.0238 weeks 0.00548 months )

Sunday (est 1200) - Operability Test is passed: Exit LCO

Monday (0230 CT) - LCO would have expired, but licensee had already exited LCO B - The Emergency Amendment Path is placed on hold as an advanced draft.

The draft has been sent to PM Feintuch for circulation to internal stakeholders. The amendment path will only be reactivated if the repair path falters.

C - Forced Shutdown Path Prep for forced shutdown continues but will only implement if paths A and B falter D (actually a background path currently in monitoring mode) - NOED watch NOED SME Zoulis has been placed on distribution of information to watch the evolution toward success (Paths A or B). If we fixate (develop tunnel vision) on A or B and time to accomplish a NOED erodes, Zoulis will so advise. Licensee is aware of this contingency monitoring. It is not likely, but neither is it being dismissed.

advanced draft of amendment application now on hold -----------------------

Karl:

Attached is the latest DRAFT of the Emergency TS Change Request for the "B" DG for DAEC. Note that it still has some holes in it, but is more complete than the previous version we sent you this morning. This is for your information should we need to resurrect this submittal in the near future. Thanks for your help!

Tom Thomas R. Byrne Thomas.Byrne@nexteraenergy.com Senior Licensing Engineer Duane Arnold Energy Center (319) 851-7929 Figure 1.2 - Later draft as of 3/23/2012 1815 ET

========== update 2012-03-23-0945 ET =======

Fri 3/23/2012 9:39 AM attached is a draft of our request for emergency TS change to allow extending the EDG LCO. Please note that this document has not been subject to Onsite Review Group and is still missing detailed PRA results. However, it does provide an indication of where we are headed.

Steve Catron DAEC Licensing Manager steve.catron@nexteraenergy.com (319) 851-7234 business (319) 210-5478 mobile Figure 1.1 - Early draft as of 3/23/2012 0945 ET

========== update 2012-03-23-0922 ET =======

4

Based on call from Byrne this morning I alerted Andersen via call to McConnell that agenda is bravo Diesel Generator re: Fairbanks-Morse recommendation and extension of LCO. (Call is NOT about the batteries. That application is coming under routine circumstances.)

Bridge Line information for 9AM CT (10AM ET) call:

(305) 552-3000 PIN # 8517929 New invitees are:

Mark Ring, R-3 Luke Haeg, SRI Rob Murray, RI Shawn Williams, LPL3-1 BC Rob Elliott, STSB, BC Bob Wolfgang, EPTB Assembly point at HQ, except for call-ins is Jim Andersens office O-12H01)

========== original message =========

As described to McConnell and Andersen in email from Feintuch of Thu 3/22/2012 8:16 PM.

5

Hearing Identifier: NRR_PMDA Email Number: 332 Mail Envelope Properties (26E42474DB238C408C94990815A02F0968BBBAE617)

Subject:

ME8251 - Duane Arnold - preparations for potential Bravo Diesel Generator LCO Extension Re: TS 3.8.1 Sent Date: 4/13/2012 2:37:48 PM Received Date: 4/13/2012 2:37:51 PM From: Feintuch, Karl Created By: Karl.Feintuch@nrc.gov Recipients:

"Feintuch, Karl" <Karl.Feintuch@nrc.gov>

Tracking Status: None Post Office: HQCLSTR01.nrc.gov Files Size Date & Time MESSAGE 10906 4/13/2012 2:37:51 PM TSCR-134 (NG-12-0145); Emergency TS Change on DG B.DOC 643650 TSCR-134 (NG-12-0145); Emergency TS Change on DG B.DOC 683074 BTP 8-8 ML113640138.pdf 127034 Options Priority: Standard Return Notification: No Reply Requested: No Sensitivity: Normal Expiration Date:

Recipients Received:

March 23, 2012 NG-12-0145 10 CFR 50.90 10 CFR 50.91(a)(5)

U.S. Nuclear Regulatory Commission Attn: Document Control Desk 11555 Rockville Pike Rockville, MD 20852 Duane Arnold Energy Center Docket No. 50-331 Renewed Op. License No. DPR-49 Technical Specification Change Request (TSCR-134) - Emergency License Amendment Request for One-Time Allowance to Allow Continued Operation with the B Diesel Generator Inoperable Affected Technical Specification: Section 3.8.1 Pursuant to 10 CFR 50.90 and 10 CFR 50.91(a)(5), NextEra Energy Duane Arnold, LLC (hereafter NextEra Energy Duane Arnold) hereby requests revision to the Technical Specifications (TS) for the Duane Arnold Energy Center (DAEC) on an emergency basis. With the plant operating in MODE 1 at 100% Rated Thermal Power, additional time is requested to repair and test the B diesel generator (DG) before a plant shutdown will be required.

The events leading to NextEra Energy Duane Arnolds request began when the B DG was declared inoperable at 0230 hours9.583 days 1.369 weeks 0.315 months on March 19, 2012, for preplanned maintenance. During the maintenance activities to inspect the flex drive gear, no movement was found to be present in the gear. The necessary parts are on hand, however flex drive gear repairs, along with subsequent restoration of the B DG to OPERABLE status will result in exceeding the 7 day Completion Time of TS 3.8.1, Required Action B.5. The current 7 day Completion Time for the B DG expires at 0230 on March 26, 2012. This request also corrects a simple typographical error in the Completion Time for Required Action B.5 for clarity.

NextEra Energy Duane Arnold requests to be allowed to permits additional time to complete repairs to the B DG flex drive gear and restore B DG before a plant shutdown is required. An additional 7 days beyond that currently provided in TS 3.8.1, Required Action B.5 is requested to restore the B DG to OPERABLE status such that entry into MODE 3 would not be required until 0230 hours9.583 days 1.369 weeks 0.315 months on April 2, 2012. The

Document Control Desk NG-12-0145 Page 2 requested additional time for restoring the B DG had been evaluated and shown to involve (???no or small increase) in quantitative risk, ???offset by qualitative considerations. In addition, it has been determined that there is no net increase in radiological risk.

NextEra Duane Arnold requests approval of this emergency License Amendment Request on an emergency basis by March 25, 2012. A list of regulatory commitments made in this letter is provided in Exhibit D.

If you have any questions or require additional information, please contact Steve Catron (319) 851-7234.

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

Executed on March 23, 2012.

Peter Wells Vice President, Duane Arnold Energy Center NextEra Energy Duane Arnold, LLC Exhibits: A) EVALUATION OF PROPOSED CHANGE B) PROPOSED TECHNICAL SPECIFICATION CHANGES (MARK-UP)

C) PROPOSED TECHNICAL SPECIFICATION PAGES (RE-TYPED)

D) LIST OF COMMITMENTS E) EXPLANATION OF THE EXIGENCY AND WHY THE SITUATION COULD NOT HAVE BEEN AVOIDED cc: S. Rasmusson (State of Iowa)

NG-12-0145 Exhibit A Page 1 of 18 EXHIBIT A EVALUATION OF PROPOSED CHANGE

Subject:

Technical Specification Change Request (TSCR -134) - Emergency License Amendment Request for One-Time Allowance to Allow Continued Operation with the B Diesel Generator Inoperable

1. DESCRIPTION

2. PROPOSED CHANGE

3. BACKGROUND

4. TECHNICAL ANALYSIS

5. REGULATORY SAFETY ANALYSIS 5.1 No Significant Hazards Consideration 5.2 Applicable Regulatory Requirements/Criteria

6. ENVIRONMENTAL CONSIDERATION

7. PRECEDENT

8. REFERENCES

NG-12-0145 Exhibit A Page 2 of 18 Technical Specification Change Request (TSCR -134) - Emergency License Amendment Request for One-Time Allowance to Allow Continued Operation with the B Diesel Generator Inoperable

1.0 DESCRIPTION

NextEra Energy Duane Arnold requests on an emergency basis to be allowed to permit non-compliance with LCO 3.8.1, i.e., to permit additional time to complete repairs to the B Diesel Generator (DG) flex drive gear and restore B DG before a plant shutdown is required. An additional 7 days beyond that currently provided in TS 3.8.1, Required Action B.5 is requested to restore the B DG to OPERABLE status such that entry into MODE 3 would not be required until 0230 hours9.583 days 1.369 weeks 0.315 months on April 2, 2012. The current 7 day Completion Time for the B DG expires at 0230 on March 26, 2012. This request also corrects a simple typographical error in the Completion Time for Required Action B.5 (except instead of expect) for clarity.

The events leading to NextEra Energy Duane Arnolds request began when the B DG was declared inoperable at 0230 hours9.583 days 1.369 weeks 0.315 months on March 19, 2012, for planned maintenance. During the maintenance activities to inspect the flex drive gear, no movement was found to be present in the gear. The necessary parts are on hand, however flex drive gear repairs, along with subsequent restoration of the B DG to OPERABLE status will result in exceeding the 7 day Completion Time of TS 3.8.1, Required Action B.5.

NextEra Duane Arnold requests approval of this emergency License Amendment Request on an emergency basis by March 25, 2012.

2.0 PROPOSED CHANGE

The proposed change will insert a note related to the Completion Times of Condition B.5 of TS 3.8.1 that specifies the following:

The Completion Time for Required Action B.5 may be extended beyond the 7 days and up to 8 days from discovery of failure to meet the LCO except for Condition A up to a total of 14 days to enable repairs to the B DG flex gear. This allowance is only applicable to the B DG for the period from March 19, 2012 0230 hours9.583 days 1.369 weeks 0.315 months through April 2, 2012 0230 hours9.583 days 1.369 weeks 0.315 months .

This note will allow an extension of 7 days to the current 7 day Completion Time of TS 3.8.1, Required Action B.5 to enable repairs to the B DG flex gear, subject to the conditions specified by the note. This request also corrects a simple typographical error in the Completion Time for Required Action B.5.

NG-12-0145 Exhibit A Page 3 of 18

3.0 BACKGROUND

The events leading to NextEra Energy Duane Arnolds request began when the B DG was declared inoperable at 0230 hours9.583 days 1.369 weeks 0.315 months on March 19, 2012, for planned maintenance. During the maintenance activities to inspect the flex drive gear, no movement was found to be present in the gear. The necessary parts are on hand, however flex drive gear repairs, along with subsequent restoration of the B DG to OPERABLE status will result in exceeding the 7 day Completion Time of TS 3.8.1, Required Action B.5. The 7 day Completion Time for the B DG expires at 0230 on March 26, 2012.

The onsite standby power source for 4.16 kV essential buses 1A3 and 1A4 consists of two DGs. DGs 1G-31 and 1G-21 are dedicated to essential buses 1A3 and 1A4, respectively. A DG starts automatically on a Loss of Coolant Accident (LOCA) signal (i.e., low reactor water level signal or high drywell pressure signal) or on an essential bus degraded voltage or undervoltage signal.

After the DG has started, it automatically ties to its respective bus after offsite power is tripped as a consequence of essential bus undervoltage or degraded voltage, independent of or coincident with a LOCA signal. The DGs also start and operate in the standby mode without tying to the essential bus on a LOCA signal alone. Following the trip of offsite power, non emergency loads powered from essential buses are load shed. When the DG is tied to the essential bus, loads are then sequentially connected to its respective essential bus. The sequencing logic controls the permissive and starting signals to motor breakers to prevent overloading the DG.

Scavenging air is supplied to each engine through the combination of an engine driven positive displacement, lobe-type blower and two exhaust driven turbo-chargers. During engine start and low load conditions, the blower provides scavenging air to the engine. The scavenging air blower draws air from the Diesel Generator Room through an air intake filter-silencer and discharges it to the engine through two turbo-chargers and air coolers. As engine load is increased, the turbo-charger demand will overrun the blower supply. An intake check valve, located on the common header between the scavenging air blower and the turbo-chargers, will open progressively and admit air directly to the turbo-chargers through a second air intake filter-silencer. When the diesel is fully loaded, the scavenging air blower is virtually unloaded; the scavenging air is being supplied by the turbo-chargers. Please refer to the figure below for more detail:

NG-12-0145 Exhibit A Page 4 of 18 The blower flexible drive gear is mounted on the end of the upper crankshaft. It consists of a radially grooved drive hub which is keyed to the crankshaft. Leaf spring packs fitted in radial groove extend into a channel in the blower drive gear.

Pins through the gear on either side of the spring packs complete the drive. The intent of the flex gear is to transmit torque between the upper drive shaft through the springs to the gears to absorb torsional vibration and to minimize shock loading between the gear teeth. Please refer to the figure below for more detail:

NG-12-0145 Exhibit A Page 5 of 18 Based on information supplied by the Fairbanks Morse vendor, the two potential causes for the flex gear not to perform its design function are:

1. Failure of the leaf springs -this could be a portion of a broken leaf (or several) that have lodged between the drive lugs of the hub and gear causing the locked condition; or

2. Failure of the chrome plating on the OD of the hub causing a galled spot by accumulating metal debris between the gear and hub causing the locked condition.

The failure of the flex gear to perform its design function will manifest in the following ways:

NG-12-0145 Exhibit A Page 6 of 18

1. Abnormal gear wear

2. Gear teeth damage or breakage Leaf springs were replaced in 1984 with the replacement/ rebuild of the blower.

No indication exist that the flexibility of the gear has been checked in the past.

This check is not included in the site procedure or owners group recommendations.

A review of the site maintenance procedure, GENERA-F010, and the Fairbanks Morse vendor manual found no requirement to perform the flexibility check, of the flex gear and no acceptance criteria for this check. A review of the Fairbanks Morse Owners Group (FMOG) maintenance procedure which includes the maintenance that is recommended to be performed on Fairbanks Morse diesel generators and approved by the OEM also does not include this test or give any acceptance criteria.

Inspection of the flex and blower gear was performed in March 2012. The gear mesh, gear wear, lobe timing, blower timing gear backlash and blower drive flexible drive gear pinion backlash was inspected for evidence that that would be an indications of an issue with the flex drive gear assembly. No evidence of an issue with the flexible drive other then the inability to flex the gear was identified by this work order. No abnormal gear wear, gear teeth damage or fretting was identified. Below are the acceptance criteria along with the as found readings for this work order and the two previous inspections.

Component Acceptance Criteria 2008 2010 2012 Blower 0.002 to 0.004 in Not taken, Not taken, 0.025 in Timing Gear gear wear gear wear (backlash) is normal is normal Blower 0.002 to 0.008 in Not taken, Not taken, 0.007 in Drive - gear wear gear wear Flexible is normal is normal drive gear to pinion (backlash)

Lobe Timing Inlet: 0.058 (+/-0.005) 0.056 0.059 0.058 Outlet: 0.041 (+/-0.005) 0.038 0.040 0.038 Gear wear Normal/Abnormal Normal Normal Normal Blower Flex None specified by the Not taken Not taken 0.0 gear OEM The potential failure mode as described by Fairbanks Morse is tooth damage -

either chipped teeth or tooth breakage. The surface of the teeth appears in new condition with no visible signs of wear or uneven contact. Therefore, an

NG-12-0145 Exhibit A Page 7 of 18 evaluation was performed to estimate the bending stress to determine if tooth breakage is a credible failure mode with the current condition of the flex gear.

To bound the evaluation the blowers maximum horse power demand of 250 Hp was utilized along with conservative 300Bhn hardness for the gears. The conclusion of this evaluation was that the approximate bending stress based on the conservative assumptions and the vendors verbal information is 3,560 psi.

While the allowable bending stress on a 300 Bhn gear material is 36,000 psi.

Therefore, both the flex gear and pinion gear are very lightly loaded even with this issue.

Fairbanks Morse has recommended that the flex gear be inspected and replaced as necessary. This repair activity is anticipated to take XX days due toMORE HERE..

Common Cause argument

4.0 TECHNICAL ANALYSIS

LATER - FROM PRA Quality of PRA TS Amendment 280, dated February 24, 2012, (Reference 1, ML120110282) stated the following regarding the quality of the DAEC PRA:

The quality of the DAEC PRA must be compatible with the safety implications of the proposed TS change and the role the PRA plays in justifying the change.

That is, the more the potential change in risk or the greater the uncertainty in that risk from the requested TS change, or both, the more rigor that must go into ensuring the quality of the PRA.

RG 1.200 is NRC's developed regulatory guidance for assessing the technical adequacy of a PRA. Revision 2 to RG 1.200 endorses (with comments and qualifications) the use of the American Society of Mechanical Engineers (ASME)

I American Nuclear Society (ANS) RA-Sa-2009, "Addenda to ASME/ANS RA-S-2008 Standard for Level1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications," NEI 00-02, "Probabilistic Risk Assessment Peer Review Process Guidelines," and NEI 05-04, "Process for Performing Follow-on PRA Peer Reviews Using the ASME PRA Standard.

Revision 1 to RG 1.200 had endorsed the internal events PRA standard ASME RA-Sb-2005, "Addenda to ASME RA-S-2002 Standard for Probabilistic Risk

NG-12-0145 Exhibit A Page 8 of 18 Assessment for Nuclear Power Plant Applications." For the internal events PRA, there are no significant technical differences in the standard requirements and, therefore, assessments using the previously endorsed internal events standard are acceptable.

The licensee has performed an assessment of the PRA models used to support the SFCP using the guidance of RG 1.200, Revisions 1 and 2, to assure that the PRA models are capable of determining the change in risk due to changes to surveillance frequencies of SSCs, using plant specific data and models.

Capability Category II of the standard is required by NEI 04-10 for the internal events PRA, and any identified deficiencies to those requirements are assessed further to determine any impacts to proposed decreases to surveillance frequencies, including the use of sensitivity studies where appropriate.

The Boiling Water Reactor Owner's Group performed a peer review of the DAEC internal events PRA model in December 2007, using the NEI 05-04 PRA peer review process and the ASME PRA Standard ASME RA-Sb-2005, along with the clarifications provided in Regulatory Guide 1.200, Revision 1. The DAEC PRA peer review was a full-scope review of all the technical elements of the internal events, at-power PRA. Also in December 2007, the licensee completed a gap analysis against the ASME PRA Standard RA-Sb-2005 and RG 1.200, Revision 1, to identify potential gaps to Capability Category II of the Standard. The licensee provided open gap items for their Internal Events PRA model, Revision 5C, for NRC staff review, in the license amendment request (LAR) submittal

[Reference 2 (ML110550570)].

Subsequently, on June 30, 2011, the licensee completed a DAEC Internal Events PRA model update to Revision 6, to be used for the TSTF-425 application. To support this model update, a focused peer review was completed in March 2011.

The focused peer review utilized the ASME/ANS RA-Sa-2009 standard and RG 1.200, Revision 2. The scope of the review included those open gap items provided in the LAR submittal, as well as the additional gap items from the 2007 full scope peer review. The focused peer review included a review of new methods implemented in the model upgrade.

The licensee provided the results of the focused peer review to the NRC staff in its letters dated April 20, and August 15, 2011. As a result of the focused peer review, many of the open gap items identified in the LAR submittal were closed.

The focused peer review team found twelve (12) open gap items that were assessed as not meeting Capability Category II per the ASME/ANS RA-Sa-2009 standard, five of which the licensee addressed and closed after the focused peer review. To assess the technical adequacy of the DAEC Internal Events PRA model for TSTF-425 application, the NRC staff reviewed the remaining seven open gap items for the Revision 6 model to ensure the deficiency, in not meeting Capability Category II, may be addressed and dispositioned for each surveillance frequency per the NEI 04-10 methodology.

NG-12-0145 Exhibit A Page 9 of 18 The following is the NRC staff's evaluation of the seven remaining open gap items identified for the Revision 6 model.

IE-83-01A: SR IE-83 provides requirements for grouping of initiating events. The staff's review finds that loss of bus 1A1, 1A2, 1A3, and 1A4 initiators need to be evaluated separately from the turbine trip initiator. This conclusion is based on a sensitivity study and insights obtained in response to requests for additional information. The licensee's sensitivity analysis, performed with the Internal Events PRA model, found the loss of these bus initiators to be a very small contributor to core damage frequency. However, uncertainties need to be fully considered in surveillance test interval evaluations in accordance with NEI 04-10.

For these loss-of-bus initiators, uncertainties include the potential of fire resulting, for example, from an electrical fault, with possible event complications other than those assumed in the Internal Events PRA model, as well as the potential of human error resulting in a loss-of-bus initiating event during maintenance or testing. These uncertainties can be considered qualitatively or quantitatively. NEI 04-10 guidance can be used to address this open gap item. Therefore, the NRC staff agrees that this deficiency may be addressed and dispositioned for each surveillance frequency evaluation per the NEI 04-10 methodology.

Based on the licensee's assessment using the applicable PRA standard and RG 1.200, the level of PRA quality, combined with the proposed evaluation and disposition of gaps, is sufficient to support the evaluation of changes proposed to surveillance frequencies within the SFCP, and is consistent with Regulatory Position 2.3.1 of RG 1.177.

3.1.4.2 Scope of the PRA The licensee is required to evaluate each proposed change to a relocated surveillance frequency using the guidance contained in NEI 04-10 to determine its potential impact on risk, due to impacts from internal events, fires, seismic, other external events, and from shutdown conditions. Consideration is made of both COF and LERF metrics. In cases where a PRA of sufficient scope or where quantitative risk models were unavailable, the licensee uses bounding analyses, or other conservative quantitative evaluations. A qualitative screening analysis may be used when the surveillance frequency impact on plant risk is shown to be negligible or zero.

The licensee uses a full-scope PRA model for evaluation of at-power internal events, fires, and seismic events. Since a PRA has not been developed for shutdown conditions, the licensee utilizes guidance provided in NUMARC 91-06, "Guidelines for Industry Actions to Assess Shutdown Management." The licensee has analyzed high winds, floods, and other external hazards events against the 1975 Standard Review Plan criteria, and will use insights from this evaluation to analyze these hazards.

NG-12-0145 Exhibit A Page 10 of 18 Based on the above, the NRC staff concludes that the licensee's evaluation methodology is sufficient to ensure the scope of the risk contribution of each surveillance frequency change is properly identified for evaluation, and is consistent with Regulatory Position 2.3.2 of RG 1.177.

PRA Modeling The licensee will determine whether the SSCs affected by a proposed change to a surveillance frequency are modeled in the PRA. Where the SSC is directly or implicitly modeled, a quantitative evaluation of the risk impact may be carried out.

The methodology adjusts the failure probability of the impacted SSCs, including any impacted common cause failure modes, based on the proposed change to the surveillance frequency. Where the SSC is not modeled in the PRA, bounding analyses are performed to characterize the impact of the proposed change to the surveillance frequency. Potential impacts on the risk analyses due to screening criteria and truncation levels are addressed by the requirements for PRA technical adequacy consistent with guidance contained in RG 1.200, and by sensitivity studies identified in NEI 04-10.

The licensee will perform quantitative evaluations of the impact of selected testing strategy (i.e., staggered testing or sequential testing) consistent with the guidance of NUREG/CR-6141 and NUREG/CR-5497, as discussed in NEI 04-10.

Thus, through the application of NEI 04-10, the NRC staff concludes that the DAEC PRA modeling is sufficient to ensure an acceptable evaluation of risk for the proposed changes in surveillance frequency, and is consistent with Regulatory Position 2.3.3 of RG 1.177.

Assumptions for Time-Related Failure Contributions For SSCs that are normally in a standby mode, the on-demand failure probability of SSCs modeled in typical PRAs may include a standby time-related contribution and cyclic demand related contribution. NEI 04-10 criteria adjust the time-related failure contribution of SSCs affected by the proposed change to surveillance frequency. This is consistent with RG 1.177, Section 2.3.3, which permits separation of the failure rate contributions into demand and standby for evaluation of surveillance requirements. If the available data do not support distinguishing between the standby time-related failures and cyclic demand failures, then the change to surveillance frequency is assumed to impact the total failure probability of the SSC, including both standby and cyclic demand contributions. The licensee informed the NRC staff that they do not explicitly include a separate standby time-related contribution. As such, the licensee will assume that changes to the surveillance frequency impact the total failure probability of the SSC consistent with NEI 04-10 guidance. The SSC failure rate (per unit time) is assumed to be unaffected by the change in test frequency, and

NG-12-0145 Exhibit A Page 11 of 18 will be confirmed by the required monitoring and feedback implemented after the change in surveillance frequency is implemented. Selecting the testing strategy, such as staggered testing, is important in providing monitoring and feedback on performance for surveillance testing intervals and, as noted previously, the licensee will perform quantitative evaluations of the impact of the testing strategy as discussed in NEI 04-10. In addition, the process requires consideration of qualitative sources of information with regards to potential impacts of test frequency on SSC performance, including industry and plant-specific operating experience, vendor recommendations, industry standards, and code-specified test intervals. Thus the process is not reliant upon risk analyses as the sole basis for the proposed changes.

The potential beneficial risk impacts of reduced surveillance frequency, including reduced downtime, lesser potential for restoration errors, reduction of potential for test-caused transients, and reduced test-caused wear of equipment, are identified qualitatively, but are conservatively not required to be quantitatively assessed. Thus, through the application of NEI 04-10, the licensee has employed reasonable assumptions with regard to extensions of surveillance test intervals, and is consistent with Regulatory Position 2.3.4 of RG 1.177.

Sensitivity and Uncertainty Analyses NEI 04-10 requires sensitivity studies to assess the impact of uncertainties from key assumptions of the PRA, uncertainty in the failure probabilities of the affected SSCs, impact to the frequency of initiating events, and of any identified deviations from Capability Category II of the PRA standard. Where the sensitivity analyses identify a potential impact on the proposed change, revised surveillance frequencies are considered, along with any qualitative considerations that may bear on the results of such sensitivity studies. Required monitoring and feedback of SSC performance once the revised surveillance frequencies are implemented will also be performed. Thus, through the application of NEI 04-10, the licensee has appropriately considered the possible impact of PRA model uncertainty and sensitivity to key assumptions and model limitations, and is consistent with Regulatory Position 2.3.5 of RG 1.177.

Acceptance Guidelines The licensee will quantitatively evaluate the change in total risk (including internal and external events contributions) in terms of CDF and LERF for both the individual risk impact of a proposed change in surveillance frequency and the cumulative impact from all individual changes to surveillance frequencies using the guidance contained in NRC-approved NEI 04-10 in accordance with the TS SFCP. Each individual change to surveillance frequency must show a risk impact below 1E-6 per year for change to CDF, and below 1E-7 per year for change to LERF. These are consistent with the limits of RG 1.174 for very small changes in risk. Where the RG 1.174 limits are not met, the process either considers revised

NG-12-0145 Exhibit A Page 12 of 18 surveillance frequencies which are consistent with RG 1.174 or the process terminates without permitting the proposed changes. Where quantitative results are unavailable to permit comparison to acceptance guidelines, appropriate qualitative analyses are required to demonstrate that the associated risk impact of a proposed change to surveillance frequency is negligible or zero. Otherwise, bounding quantitative analyses are required which demonstrate the risk impact is at least one order of magnitude lower than the RG 1.174 acceptance guidelines for very small changes in risk. In addition to assessing each individual SSC surveillance frequency change, the cumulative impact of all changes must result in a risk impact below 1 E-5 per year for change to CDF, and below 1 E-6 per year for change to LERF, and the total CDF and total LERF must be reasonably shown to be less than 1 E-4 per year and 1 E-5 per year, respectively. These are consistent with the limits of RG 1 .174 for acceptable changes in risk, as referenced by RG 1.177 for changes to surveillance frequencies. The NRC staff interprets this assessment of cumulative risk as a requirement to calculate the change in risk from a baseline model utilizing failure probabilities based on the surveillance frequencies prior to implementation of the SFCP, compared to a revised model with failure probabilities based on changed surveillance frequencies. The NRC staff further notes that the licensee includes a provision to exclude the contribution to cumulative risk from individual changes to surveillance frequencies associated with insignificant risk increases (less than 5E-8 CDF and 5E-9 LERF) once the baseline PRA models are updated to include the effects of the revised surveillance frequencies.

The quantitative acceptance guidance of RG 1.174 is supplemented by qualitative information to evaluate the proposed changes to surveillance frequencies, including industry and plant-specific operating experience, vendor recommendations, industry standards, the results of sensitivity studies, and SSC performance data and test history.

The final acceptability of the proposed change is based on all of these considerations and not solely on the PRA results compared to numerical acceptance guidelines. Post implementation performance monitoring and feedback are also required to assure continued reliability of the components.

The NRC staff concludes that the licensee's application of NEI 04-10 provides reasonable acceptance guidelines and methods for evaluating the risk increase of proposed changes to surveillance frequencies, consistent with Regulatory Position 2.4 of RG 1.177.

Based on the above, the NRC staff concludes that the proposed methodology satisfies the fourth key safety principle of RG 1.177 by assuring that any increase in risk is small and consistent with the intent of the Commission's Safety Goal Policy Statement.

The Impact of the Proposed Change Should Be Monitored Using Performance Measurement Strategies

NG-12-0145 Exhibit A Page 13 of 18 The licensee's adoption of TSTF-425 requires application of NEI 04-10 in the SFCP. NEI 04-10 requires performance monitoring of SSCs whose surveillance frequency has been revised as part of a feedback process to assure that the change in test frequency has not resulted in degradation of equipment performance and operational safety. The monitoring and feedback includes consideration of maintenance rule monitoring of equipment performance. In the event of degradation of SSC performance, the surveillance frequency will be reassessed in accordance with the methodology, in addition to any corrective actions which may apply as part of the maintenance rule requirements. The performance monitoring and feedback specified in NEI 04-10 is sufficient to reasonably assure acceptable SSC performance and is consistent with Regulatory Position 3.2 of RG 1.177.

Based on the above, the NRC staff concludes that the fifth key safety principle of RG 1.177 is satisfied.

5.0 REGULATORY ANALYSIS

5.1 No Significant Hazards Consideration According to 10 CFR 50.92, Issuance of amendment, paragraph (c), a proposed amendment to an operating license involves no significant hazards consideration if operation of the facility in accordance with the proposed amendment would not:

1. Involve a significant increase in the probability or consequence of an accident previously evaluated; or

2. Create the possibility of a new or different kind of accident from any accident previously evaluated; or

3. Involve a significant reduction in margin of safety.

NextEra Energy Duane Arnold has evaluated the proposed change to the TS using the criteria in 10 CFR 50.92, and has determined that the proposed change does not involve a significant hazards consideration. The following information is provided to support a finding of no significant hazards consideration.

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

No. Reactor protection system performance will remain within the bounds of the previously performed accident analyses and will continue to function in a manner consistent with the plant design basis. The additional allowed time does not result in a condition where the design, material, and construction standards that were applicable prior to the change are altered. The proposed change will not modify any system interface. The proposed change will not affect the probability of any event initiators.

NG-12-0145 Exhibit A Page 14 of 18 There will be no change to the normal plant operating parameters or accident mitigation performance. The proposed change will not alter any assumptions or change any mitigation action in the radiological consequence evaluations in the UFSAR.

Implementation of the proposed change will minimize risk impact. The proposed one-time only change to the TS 3.8.1 Required Action B.5 Completion Time does not, of itself, increase the probability of any accident previously evaluated. The proposed change represents.ICLERP and ICCDP data here The proposed change does not adversely affect accident initiators or precursors nor alter the design assumptions or the manner in which the plant is normally operated and maintained. The proposed change does not affect source term, containment isolation, or radiological release assumptions used in evaluating the radiological consequences of an accident previously evaluated. The proposed change is consistent with safety analysis assumptions, which apply when the plant is operating in compliance with LCO requirements.

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

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

No. The proposed change does not result in a change in the manner in which the electrical distribution systems provide plant protection. The change does not alter assumptions made in the safety analysis. The one-time extension of the Completion Time does not change any existing accident scenarios, nor create any new or different accident scenarios. The proposed change is consistent with the safety analysis assumptions and current plant operating practice.

Therefore, the proposed request does not create a new or different kind of accident from any accident previously evaluated.

3. Does the proposed change involve a significant reduction in a margin of safety?

No. Based upon the availability of redundant systems, the mitigating actions that have been taken and the low probability of an accident, NextEra Energy Duane Arnold concludes that the reduction in availability of the B EDG does not result in a significant reduction in the margin of safety. The margin of safety is related to the confidence in the ability of the fission product barriers to perform their design functions during and following an accident situation. These barriers include the fuel cladding, the reactor coolant system, and the containment system. The performance of the fuel cladding, containment and the reactor coolant system will not be significantly impacted by the proposed change.

NG-12-0145 Exhibit A Page 15 of 18 Therefore the proposed change does not involve a significant reduction on the margin of safety.

Based upon the above, NextEra Energy Duane Arnold concludes that the proposed amendment presents no significant hazards consideration under the standards set forth in 10 CFR 50.92 (c), and accordingly a finding of no significant hazards consideration is justified.

In conclusion, based on the considerations discussed above, (1) there is a 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 US NRCs 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.

CONCLUSION Based on the preceding 10 CFR 50.92 evaluation, NextEra Energy Duane Arnold concludes that the proposed amendment presents no significant hazards consideration under the standards set forth in 10 CFR 50.92(c), and, accordingly, a finding of no significant hazards consideration is justified.

5.2 Applicable Regulatory Requirements/Criteria By letter dated March 23, 2012, NextEra Energy Duane Arnold, LLC has submitted a request for revision of the Technical Specifications for the Duane Arnold Energy Center (DAEC). The proposed amendment allows permits additional time to complete repairs to the B DG flex gear and restore the B DG before a plant shutdown was required. An additional 7 days beyond that currently provided in TS 3.8.1, Required Action B.5 is requested to restore the B DG to OPERABLE status such that entry into MODE 3 would not be required until 0230 hours9.583 days 1.369 weeks 0.315 months on April 2, 2012. The current 7 day Completion Time for the B DG expires at 0230 on March 26, 2012. . This request also corrects a simple typographical error in the Completion Time for Required Action B.5.

Evaluation:

The proposed change is consistent with the current regulations and thus, an exemption pursuant to 10 CFR 50.12 is not required. The current regulations (e.g., §50.36) do not dictate the specific actions to be taken when a DG is inoperable; only that Limiting Conditions for Operability (LCO) are included in the TS that are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When a limiting condition for operation of a nuclear reactor is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the technical specifications until the condition can be met. {emphasis added} The proposed extension for the B DG

NG-12-0145 Exhibit A Page 16 of 18 Completion Time continues to demonstrate these CFR requirements, as the Required Action for the B DG will continue to provide the necessary remedial actions until the LCO is again met.

The DAEC Construction Permit was issued in 1970, prior to the issuance of 10 CFR 50, Appendix A, General Design Criteria (GDC), and thus, the DAEC was not specifically licensed to the GDC (Ref. SECY-92-223). The following describes the DAEC UFSAR commitment to the GDCs pertinent to this application and the impact of the requested change on those commitments.

GDC 17 deals with the design of the Electrical Power Systems for the unit, both offsite and onsite power systems. The proposed change does not affect the design of the onsite or offsite power systems, thus GDC 17 is not impacted by this change.

GDC 18 deals with testing of Electric Power Systems for the unit, both offsite and onsite power systems. The proposed change also does not involve onsite or offsite power circuit testing, which is covered by GDC 18. No other changes in the design, operation or testing of the offsite power circuits are being proposed.

GDCs 37, 40, 43 and 46, all contain provisions for testing of key safety systems (other than the Electrical Power Systems), including the performance of the full operational sequence that brings the systems into operation, including the transfer between normal and emergency power sources. The proposed extension for the B DG Completion Time does not impact this capability, as the normal onsite and offsite power circuit Surveillances, along with the various system simulated automatic actuation Surveillances, will continue to demonstrate that these GDCs are met.

Safety Guide 6 (i.e., original revision of Regulatory Guide 1.6) deals with the electrical independence of each division of the electrical distribution system. The proposed extension for the B DG Completion Time will not impact the design of the electrical distribution system, nor the associated interlocks between the onsite and offsite electrical distribution systems. Thus, the proposed change does not impact the DAECs ability to meet Safety Guide 6, as described in UFSAR Section 1.8.6.

6.0 ENVIRONMENTAL CONSIDERATION

10 CFR Section 51.22(c)(9) identifies certain licensing and regulatory actions which are eligible for categorical exclusion from the requirement to perform an environmental assessment. A proposed amendment to an operating license for a facility requires no environmental assessment if operation of the facility in accordance with the proposed amendment would not: (1) involve a significant hazards consideration; (2) result in a significant change in the types or significant

NG-12-0145 Exhibit A Page 17 of 18 increase in the amounts of any effluents that may be released offsite; and (3) result in a significant increase in individual or cumulative occupational radiation exposure. NextEra Energy Duane Arnold has reviewed this request and determined that the proposed amendment meets the eligibility criteria for categorical exclusion set forth in 10 CFR Section 51.22(c)(9). Pursuant to 10 CFR Section 51.22(b), no environmental impact statement or environmental assessment needs to be prepared in connection with the issuance of the amendment. The basis for this determination follows.

Basis The change meets the eligibility criteria for categorical exclusion set forth in 10 CFR Section 51.22(c)(9) for the following reasons:

1. As demonstrated in the 10 CFR 50.92 evaluation included in this exhibit, the proposed amendment does not involve a significant hazards consideration.

2. The proposed changes do not result in an increase in power level, do not increase the production, nor alter the flow path or method of disposal of radioactive waste or byproducts. There is no significant change in the types or significant increase in the amounts of any effluents that may be released offsite.

3. The proposed changes do not result in changes in the level of control or methodology used for processing of radioactive effluents or handling of solid radioactive waste nor will the proposal result in any change in the normal radiation levels within the plant. There is no significant increase in individual or cumulative occupational radiation exposure.

7.0 PRECEDENT

1. NRC Approval of the McGuire Unit 1 license amendment request of June 7, 2007 (ML071700272) requesting a one limited duration exception from the Completion Time for the Unit 1 A Emergency Diesel Generator (EDG) Amendment 241 dated June 8, 2007 and the conclusions of the associated NRC Safety Evaluation Report (ML071570599).

2. NRC approval of the D. C. Cook Nuclear Plant, Unit 2 license amendment request of December 9, 2003 (ML033460380) requesting a one-time limited duration exception from the allowed outage time (AOT) for the Unit 2AB EDG, Amendment 264, dated December 10, 2003, and the conclusions of the associated NRC Safety Evaluation Report (ML04260015).

3. NRC approval of the Browns Ferry Nuclear Plant, Unit 3 license amendment request of April 6, 2007 (ML071010092requesting a one-time limited duration exception from the allowed outage time (AOT) for the Unit 3D EDG, Amendment

NG-12-0145 Exhibit A Page 18 of 18 257, dated April 6, 2007, and the conclusions of the associated NRC Safety Evaluation (ML071070289).

8.0 REFERENCES

1. Letter from Terry A. Beltz (USNRC) to Peter Wells (NextEra Energy Duane Arnold), Duane Arnold Energy Center - Issuance of Amendment Re: Adoption of Technical Specifications Task Force Traveler (TSTF-425) to Relocate Specifica Surveillance Frequencies to a Licensee-Controlled Program (TAC No. ME5744), dated February 24, 2012 (ML120110282)

2. Letter from Christopher R. Costanzo (NextEra Energy Duane Arnold) to USNRC (Document Control Desk), License Amendment Request (TSCR-120): Application for Technical Specification Change Regarding Risk-Informed Justification for the Relocation of Specific Surveillance Frequency Requirements to a Licensee Controlled Program (TSTF-425, Rev. 3, dated February 23, 2011 (ML110550570)

NG-12-0145 Exhibit B EXHIBIT B PROPOSED TECHNICAL SPECIFICATION AND BASES CHANGES (MARK-UP) 2 Pages Follow

AC Sources Operating 3.8.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) B.3 Determine OPERABLE 24 hours1 days 0.143 weeks 0.0329 months DG is not inoperable due to common cause failure.

AND

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

Not required to be performed when the cause of the inoperable DG is pre-planned, preventive maintenance and testing.

B.4 Perform SR 3.8.1.2 for Once per 72 OPERABLE DG. hours AND B.5 Restore DG to 7 days*

OPERABLE status.

AND 8 days from discovery of failure to meet LCO except expect for Condition A*

C. Two offsite circuits C.1 Declare required 12 hours0.5 days 0.0714 weeks 0.0164 months from inoperable. feature(s) inoperable discovery of Condition when the redundant C concurrent with required feature(s) are inoperability of inoperable. redundant required feature(s)

AND (continued)

NOTE: The Completion Time for Required Action B.5 may be extended beyond the 7 days and up to 8 days from discovery of failure to meet the LCO except for Condition A up to a total of 14 days to enable repairs to the B DG flex gear. This allowance is only applicable to the B DG for the period from March 19, 2012 0230 hours9.583 days 1.369 weeks 0.315 months through April 2, 2012 0230 hours9.583 days 1.369 weeks 0.315 months .

DAEC 3.8-3 TSCR-134

BASES ACTIONS B.5 (continued)

The second Completion Time for Required Action B.5 establishes a limit based on the maximum time allowed for the combination of one DG and two offsite AC power sources to be inoperable during any single contiguous occurrence of failing to met the LCO except for Action A. If Condition B is entered while, for instance, two offsite circuits are inoperable and one circuit is subsequently restored OPERABLE, the LCO may already have been not met for up to 24 hours1 days 0.143 weeks 0.0329 months . This situation could lead to a total of 8 days, since initial failure of the LCO (except for Condition A), to restore the DG. At this time, the second offsite circuit could again become inoperable, the DG restored OPERABLE, and an additional 24 hours1 days 0.143 weeks 0.0329 months (for a total of 9 days) allowed prior to complete restoration of the LCO (except for Condition A). The 8 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 B and C are entered concurrently, and when corrective actions are completed prior to completing the shutdown required by LCO 3.0.3 (which is required to be entered by Action F). The AND connector between the 7 day and 8 day Completion Times means that both Completion Times apply simultaneously, and the more restrictive must be met.

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

An Amendment was approved that provides a Note allowing the Completion Time for Required Action B.5 may be extended up to 14 days from discovery of failure to meet the LCO to enable repairs to the B DG flex gear. This allowance is only applicable to the B DG for the period from March 19, 2012 0230 hours9.583 days 1.369 weeks 0.315 months through April 2, 2012 0230 hours9.583 days 1.369 weeks 0.315 months . This will allow continued operation during repairs to the B DG flex gear.

(continued)

DAEC B 3.8-10 TSCR-134

NG-12-0145 Exhibit C EXHIBIT C PROPOSED TECHNICAL SPECIFICATION PAGE (RE-TYPED) 1 Page Follows

AC Sources Operating 3.8.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) B.3 Determine OPERABLE 24 hours1 days 0.143 weeks 0.0329 months DG is not inoperable due to common cause failure.

AND

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

Not required to be performed when the cause of the inoperable DG is pre-planned, preventive maintenance and testing.

B.4 Perform SR 3.8.1.2 for Once per 72 OPERABLE DG. hours AND B.5 Restore DG to 7 days*

OPERABLE status.

AND 8 days from discovery of failure to meet LCO except for Condition A*

C. Two offsite circuits C.1 Declare required 12 hours0.5 days 0.0714 weeks 0.0164 months from inoperable. feature(s) inoperable discovery of Condition when the redundant C concurrent with required feature(s) are inoperability of inoperable. redundant required feature(s)

AND (continued)

NOTE: The Completion Time for Required Action B.5 may be extended beyond the 7 days and up to 8 days from discovery of failure to meet the LCO except for Condition A up to a total of 14 days to enable repairs to the B DG flex gear. This allowance is only applicable to the B DG for the period from March 19, 2012 0230 hours9.583 days 1.369 weeks 0.315 months through April 2, 2012 0230 hours9.583 days 1.369 weeks 0.315 months .

DAEC 3.8-3 Amendment No.

NG-12-0145 Exhibit D Page 1 of 2 EXHIBIT D LIST OF COMMITMENTS

NG-12-0145 Exhibit D Page 2 of 2 LIST OF COMMITMENTS The following contingency actions will be instituted at the DAEC during the applicability of this license amendment:

All maintenance on the A DG during the time period of this extension will be suspended. The A DG will be guarded.

Anytime notified switchyard contingency voltage is low or forecasted to be low, DAEC will suspend any maintenance with elevated risk.

Fire watches??????

Switchyard guarded???

MORE???

NG-12-0145 Exhibit E Page 1 of 2 EXHIBIT E EXPLANATION OF THE WHY THE EMERGENCY SITUATION OCCURRED AND WHY THE SITUATION COULD NOT HAVE BEEN AVOIDED

NG-08-0500 Exhibit E Page 2 of 2 EXPLANATION OF THE WHY THE EMERGENCY SITUATION OCCURRED AND WHY THE SITUATION COULD NOT HAVE BEEN AVOIDED The events leading to NextEra Energy Duane Arnolds request began when the B DG was declared inoperable at 0230 hours9.583 days 1.369 weeks 0.315 months on March 19, 2012, for preplanned maintenance. During the maintenance activities to inspect the flex drive gear, no movement was found to be present in the gear. The necessary parts are on hand, however flex drive gear repairs, along with subsequent restoration of the B DG to OPERABLE status will result in exceeding the 7 day Completion Time of TS 3.8.1, Required Action B.5.

Upon visual review of the assembly by the Fairbanks Morse Technical Representatives on site, and the observations that indicate no abnormal condition other than the gear being locked up on the flex drive hub. This would indicate a possible first stage failure that can be either of two causes.

1) Failure of the leaf springs - this could be a portion of a broken leaf (or several) that have lodged between the drive lugs of the hub and gear causing the locked condition; or

2) Failure of the chrome plating on the OD of the hub causing a "galled" spot by accumulating metal debris between the gear and hub causing the locked condition.

Either of these conditions are the precursor of a more drastic failure that could (and have been known to) lead to a catastrophic engine failure during loaded operation. This type of major failure has been known to extend to destruction and removal of the gear teeth on both gears, bending the blower drive shaft, causing contact of the blower rotors and dispersal of aluminum particles and debris from the rotors into the air receiver and onto the liners and piston rings entailing a complete rebuild of the engine.

The official recommendation of Fairbanks Morse is to repair the relatively minor condition of the locked drive gear before any major failures occur. This can be accomplished by removal of the blower and disassembly and repair of the gear in place.

More needed here.

BLIND CARBON COPY LIST FOR NG-12-0145 March 22, 2012 D. Curtland CTS Project IRMS CNRB GDS Associates, Inc. CIPCO (w/o)

ORG (S. Hamed) Cornbelt (w/o)

S. Catron B. Lawrence Mark Lingenfelter

Subject:

Technical Specification Change Request (TSCR -134) - Emergency License Amendment Request for One-Time Allowance to Allow Continued Operation with the B Diesel Generator Inoperable

March 23, 2012 NG-12-0145 10 CFR 50.90 10 CFR 50.91(a)(5)

U.S. Nuclear Regulatory Commission Attn: Document Control Desk 11555 Rockville Pike Rockville, MD 20852 Duane Arnold Energy Center Docket No. 50-331 Renewed Op. License No. DPR-49 Technical Specification Change Request (TSCR-134) - Emergency License Amendment Request for One-Time Allowance to Allow Continued Operation with the B Diesel Generator Inoperable Affected Technical Specification: Section 3.8.1 Pursuant to 10 CFR 50.90 and 10 CFR 50.91(a)(5), NextEra Energy Duane Arnold, LLC (hereafter NextEra Energy Duane Arnold) hereby requests a one-time amendment to the Technical Specifications (TS) for the Duane Arnold Energy Center (DAEC) on an emergency basis. With the plant operating in MODE 1 at 100% Rated Thermal Power, additional time is requested to repair and test the B diesel generator (DG) before a plant shutdown will be required.

The B DG was declared inoperable at 0230 hours9.583 days 1.369 weeks 0.315 months on March 19, 2012, for preplanned maintenance. During the maintenance activities to inspect the flex drive gear, no movement was found to be present in the gear. The necessary parts are on hand; however flex drive gear repairs, along with subsequent restoration of the B DG to OPERABLE status will result in exceeding the 7 day Completion Time of TS 3.8.1, Required Action B.5. The current 7 day Completion Time for the B DG expires at 0230 on March 26, 2012. This request also corrects a simple typographical error in the Completion Time for Required Action B.5 for clarity.

NextEra Energy Duane Arnold requests to be allowed additional time to complete repairs to the B DG flex drive gear and restore B DG before a plant shutdown is required. An additional 2 days beyond that currently provided in TS 3.8.1, Required Action B.5 is requested to restore the B DG to OPERABLE status such that entry into MODE 3 would not be required until 0230 hours9.583 days 1.369 weeks 0.315 months on March 28, 2012. The requested

Document Control Desk NG-12-0145 Page 2 additional time for restoring the B DG had been evaluated and shown to involve a small increase in quantitative risk, offset by qualitative considerations.

NextEra Duane Arnold requests approval of this emergency License Amendment Request on an emergency basis by March 25, 2012. A list of regulatory commitments made in this letter is provided in Exhibit D.

If you have any questions or require additional information, please contact Steve Catron (319) 851-7234.

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

Executed on March 23, 2012.

Peter Wells Vice President, Duane Arnold Energy Center NextEra Energy Duane Arnold, LLC Exhibits: A) EVALUATION OF PROPOSED CHANGE B) PROPOSED TECHNICAL SPECIFICATION AND BASES CHANGES (MARK-UP)

C) PROPOSED TECHNICAL SPECIFICATION PAGE (RE-TYPED)

D) LIST OF COMMITMENTS E) EXPLANATION OF THE WHY THE EMERGENCY SITUATION OCCURRED AND WHY THE SITUATION COULD NOT HAVE BEEN AVOIDED cc: S. Rasmusson (State of Iowa)

NG-12-0145 Exhibit A Page 1 of 21 EXHIBIT A EVALUATION OF PROPOSED CHANGE

Subject:

Technical Specification Change Request (TSCR-134) - Emergency License Amendment Request for One-Time Allowance to Allow Continued Operation with the B Diesel Generator Inoperable

1. DESCRIPTION

2. PROPOSED CHANGE

3. BACKGROUND

4. TECHNICAL ANALYSIS

5. REGULATORY SAFETY ANALYSIS 5.1 No Significant Hazards Consideration 5.2 Applicable Regulatory Requirements/Criteria

6. ENVIRONMENTAL CONSIDERATION

7. PRECEDENT

8. REFERENCES

NG-12-0145 Exhibit A Page 2 of 21 Technical Specification Change Request (TSCR-134) - Emergency License Amendment Request for One-Time Allowance to Allow Continued Operation with the B Diesel Generator Inoperable

1.0 DESCRIPTION

NextEra Energy Duane Arnold requests a one-time amendment the Technical Specifications (TS) on an emergency basis to be allowed to permit non-compliance with LCO 3.8.1, i.e., to permit additional time to complete repairs to the B Diesel Generator (DG) flex drive gear and restore B DG before a plant shutdown is required. An additional 2 days beyond that currently provided in TS 3.8.1, Required Action B.5 is requested to restore the B DG to OPERABLE status such that entry into MODE 3 would not be required until 0230 hours9.583 days 1.369 weeks 0.315 months on March 28, 2012. The current 7 day Completion Time for the B DG expires at 0230 on March 26, 2012. This request also corrects a simple typographical error in the Completion Time for Required Action B.5 (except instead of expect) for clarity.

The B DG was declared inoperable at 0230 hours9.583 days 1.369 weeks 0.315 months on March 19, 2012, for planned maintenance. During the maintenance activities to inspect the flex drive gear, no movement was found to be present in the gear. The necessary parts are on hand; however flex drive gear repairs, along with subsequent restoration of the B DG to OPERABLE status will result in exceeding the 7 day Completion Time of TS 3.8.1, Required Action B.5.

NextEra Duane Arnold requests approval of this emergency License Amendment Request on an emergency basis by March 25, 2012.

2.0 PROPOSED CHANGE

The proposed change will insert a note related to the Completion Times of Condition B.5 of TS 3.8.1 that specifies the following:

The Completion Time for Required Action B.5 may be extended beyond the 7 days and up to 8 days from discovery of failure to meet the LCO except for Condition A up to a total of 9 days to enable repairs to the B DG flex drive gear. This allowance is only applicable to the B DG for the period from March 19, 2012 0230 hours9.583 days 1.369 weeks 0.315 months through March 28, 2012 0230 hours9.583 days 1.369 weeks 0.315 months .

This note will allow an extension of 2 days to the current 7 day Completion Time of TS 3.8.1, Required Action B.5 to enable repairs to the B DG flex drive gear, subject to the conditions specified by the note. This request also corrects a simple typographical error in the Completion Time for Required Action B.5. A marked-up Bases page is also included for information only.

NG-12-0145 Exhibit A Page 3 of 21

3.0 BACKGROUND

The B DG was declared inoperable at 0230 hours9.583 days 1.369 weeks 0.315 months on March 19, 2012, for planned maintenance. During the maintenance activities to inspect the flex drive gear, no movement was found to be present in the gear. The necessary parts are on hand, however flex drive gear repairs, along with subsequent restoration of the B DG to OPERABLE status will result in exceeding the 7 day Completion Time of TS 3.8.1, Required Action B.5. The current 7 day Completion Time for the B DG expires at 0230 on March 26, 2012.

The onsite standby power source for 4.16 kV essential buses 1A3 and 1A4 consists of two DGs. DGs 1G-31 and 1G-21 are dedicated to essential buses 1A3 and 1A4, respectively. A DG starts automatically on a Loss of Coolant Accident (LOCA) signal (i.e., low reactor water level signal or high drywell pressure signal) or on an essential bus degraded voltage or undervoltage signal.

After the DG has started, it automatically ties to its respective bus after offsite power is tripped as a consequence of essential bus undervoltage or degraded voltage, independent of or coincident with a LOCA signal. The DGs also start and operate in the standby mode without tying to the essential bus on a LOCA signal alone. Following the trip of offsite power, non emergency loads powered from essential buses are load shed. When the DG is tied to the essential bus, loads are then sequentially connected to its respective essential bus. The sequencing logic controls the permissive and starting signals to motor breakers to prevent overloading the DG.

Scavenging air is supplied to each engine through the combination of an engine driven positive displacement, lobe-type blower and two exhaust driven turbo-chargers. During engine start and low load conditions, the blower provides scavenging air to the engine. The scavenging air blower draws air from the Diesel Generator Room through an air intake filter-silencer and discharges it to the engine through two turbo-chargers and air coolers. As engine load is increased, the turbo-charger demand will overrun the blower supply. An intake check valve, located on the common header between the scavenging air blower and the turbo-chargers, will open progressively and admit air directly to the turbo-chargers through a second air intake filter-silencer. When the diesel is fully loaded, the scavenging air blower is virtually unloaded; the scavenging air is being supplied by the turbo-chargers. Please refer to the figure below for more detail:

NG-12-0145 Exhibit A Page 4 of 21 The blower flexible drive gear is mounted on the end of the upper crankshaft. It consists of a radially grooved drive hub which is keyed to the crankshaft. Leaf spring packs fitted in radial groove extend into a channel in the blower drive gear.

Pins through the gear on either side of the spring packs complete the drive. The intent of the flex drive gear is to transmit torque between the upper drive shaft through the springs to the gears to absorb torsional vibration and to minimize shock loading between the gear teeth. Please refer to the figure below for more detail:

NG-12-0145 Exhibit A Page 5 of 21 Based on information supplied by the Fairbanks Morse vendor, the two potential causes for the flex drive gear not to perform its design function are:

1. Failure of the leaf springs -this could be a portion of a broken leaf (or several) that have lodged between the drive lugs of the hub and gear causing the locked condition; or

2. Failure of the chrome plating on the OD of the hub causing a galled spot by accumulating metal debris between the gear and hub causing the locked condition.

The failure of the flex drive gear to perform its design function will manifest in the following ways:

NG-12-0145 Exhibit A Page 6 of 21

1. Abnormal gear wear

2. Gear teeth damage or breakage Leaf springs were replaced in 1984 with the replacement/ rebuild of the blower.

No indication exist that the flexibility of the gear has been checked in the past.

This check is not included in the site procedure or owners group recommendations.

A review of the site maintenance procedure, GENERA-F010, and the Fairbanks Morse vendor manual found no requirement to perform the flexibility check, of the flex drive gear and no acceptance criteria for this check. A review of the Fairbanks Morse Owners Group (FMOG) maintenance procedure which includes the maintenance that is recommended to be performed on Fairbanks Morse diesel generators and approved by the OEM also does not include this test or provide any acceptance criteria.

Inspection of the flex and blower gear was performed in March 2012. The gear mesh, gear wear, lobe timing, blower timing gear backlash and blower drive flexible drive gear pinion backlash were inspected for evidence that this would be indication of an issue with the flex drive gear assembly. No evidence of an issue with the flexible drive other then the inability to flex the gear was identified by this work order. No abnormal gear wear, gear teeth damage or fretting was identified. Below are the acceptance criteria along with the as found readings for this work order and the two previous inspections.

Component Acceptance Criteria 2008 2010 2012 Blower 0.002 to 0.004 in Not taken, Not taken, 0.025 in Timing Gear gear wear gear wear (backlash) is normal is normal Blower 0.002 to 0.008 in Not taken, Not taken, 0.007 in Drive - gear wear gear wear Flexible is normal is normal drive gear to pinion (backlash)

Lobe Timing Inlet: 0.058 (+/-0.005) 0.056 0.059 0.058 Outlet: 0.041 (+/-0.005) 0.038 0.040 0.038 Gear wear Normal/Abnormal Normal Normal Normal Blower Flex None specified by the Not taken Not taken 0.0 drive gear OEM The potential failure mode as described by Fairbanks Morse is tooth damage -

either chipped teeth or tooth breakage. The surface of the teeth appears to be in like-new condition with no visible signs of wear or uneven contact. Therefore, an evaluation was performed to estimate the bending stress to determine if tooth

NG-12-0145 Exhibit A Page 7 of 21 breakage is a credible failure mode with the current condition of the flex drive gear.

To bound the evaluation, the blowers maximum horse power demand of 250 Hp was utilized along with conservative 300Bhn hardness for the gears. The conclusion of this evaluation was that the approximate bending stress based on the conservative assumptions and the vendors verbal information is 3,560 psi.

While the allowable bending stress on a 300 Bhn gear material is 36,000 psi.

Therefore, both the flex drive gear and pinion gear are very lightly loaded even with this issue.

Fairbanks Morse has recommended that the flex drive gear be inspected and replaced as necessary. There appears to be a clearance issue between the hub and the bull gear. Repair of these issues necessitates shimming of both components followed by re-chroming that involves shipping the components offsite and back. This repair activity is anticipated to take until the evening of Monday March 26, 2012 to complete due to the labor and shipping involved in completing these repairs.

MORE HERE..

Common Cause argument

4.0 TECHNICAL ANALYSIS

The risk associated with extending the current 7 day DG Completion Time by 60 hours2.5 days 0.357 weeks 0.0822 months was assessed based on the guidance in RG 1.177, An Approach for Plant-Specific, Risk-Informed Decisionmaking Technical Specifications, . For the base case, all plant equipment is assumed to be available, including the B DG. For the Completion Time extension case, the B DG is unavailable without any compensatory actions taken beyond those credited in the PRA.

The results are based on the combined results from the Full Power Internal Events PRA model and the External Events PRA model (Fire and Seismic).

ICCDP and ICLERP were calculated using the definitions in Regulatory Guide 1.177.

CDFAOT = 2.496E-05/yr CDFBase = 3.948E-06/yr LERFAOT = 8.244E-06/yr LERFBase = 1.318E-06/yr

NG-12-0145 Exhibit A Page 8 of 21 ICCDP = (CDFAOT - CDFBase) * (AOT days)/365 ICLERP = (LERFAOT - LERFBase) * (AOT days)/365 Risk Metric RESULTS RG 1.77 Criteria ICCDP 1.44E-07 <5E-7 ICLERP 4.74E-08 <5E-8 COMPENSATORY ACTIONS Based on a review of the PRA cutsets, the following compensatory actions will be performed during the period of the extension:

A. Systems and components will be protected in accordance with procedure OP-AA-102-1003 (DAEC), Protected Trains and Guarded Equipment.

B. Containment Venting DAEC procedure SAMP-706, Venting the Primary Containment Following Loss of Pneumatic Supply / DC Power, provides guidance for containment venting without the pneumatic supply. This is an important action during a Station Blackout (SBO) event if offsite power is not recovered within 23 hours0.958 days 0.137 weeks 0.0315 months . DAEC procedure SAMP-706 provides detailed direction for venting the primary containment given an unavailable pneumatic supply.

Compensatory action: Operators and support staff will be briefed on implementing SAMP-706 in an extended SBO situation requiring containment venting.

C. Alignment of the Portable DC for SRV Operation DAEC procedure SAMP-707, Emergency SRV Operation Using Portable DC Power, represents a final option to depressurize the Reactor Pressure Vessel (RPV) to allow alternate coolant injection (e.g. firewater) to the reactor when high pressure core injection is not available or is not an effective option.

Compensatory action: Operators and support staff will be briefed on implementing SAMP-707 in an extended SBO situation requiring alternate coolant injection.

NG-12-0145 Exhibit A Page 9 of 21 D. Diesel Fire Pumps [fixed and portable]

Relevant procedures:

Diesel fire pump injection (AIP 404, Injection with Fire Water)

Portable diesel fire pump (SAMP-708, Emergency RPV Makeup with the Portable Diesel Fire Pump)

Compensatory action: A portable diesel fire pump will be staged. Operators and support staff will be briefed on implementing plant procedures AIP-404 and SAMP-708 in SBO conditions requiring reactor injection. Additional staffing beyond current normal staffing to assure actions will be expedited.

E. No discretionary switchyard maintenance will be performed.

F. No work will be performed on trip sensitive equipment. Activities that could potentially cause a plant scram, turbine trip, or generator trip will either be deferred or carefully evaluated to identify compensatory actions that eliminate or reduce this risk.

G. Maintenance work will continue to be reviewed using the risk monitor. The PRA staff will evaluate all work to assure the RG 1.777 criteria are not exceeded.

Additionally, prior to the release of work for execution, Operations personnel must consider the effects of severe weather and grid instabilities on plant operations. This qualitative evaluation is inherent of the duties of the Work Control Center Senior Reactor Operator (SRO). Responses to actual plant risk due to severe weather or grid instabilities are programmatically incorporated into applicable plant emergency or response procedures.

Therefore, the requested additional time for restoring the B DG had been evaluated and shown to involve a small increase in quantitative risk, offset by qualitative considerations.

In addition to the compensatory measures listed above in the PRA calculation, the following extra compensatory measures will be implemented:

All maintenance on the A DG during the time period of this extension will be suspended. The A DG will be guarded.

NG-12-0145 Exhibit A Page 10 of 21

The system load dispatcher will be contacted once per day to ensure no significant grid perturbations (high grid loading unable to withstand a single contingency of line or generation outage) are expected during the extended AOT.

Component testing or maintenance of safety systems and important non safety equipment in the offsite power systems which can increase the likelihood of a plant transient (unit trip) or LOOP will be avoided.

TS required systems, subsystems, trains, components, and devices that depend on the remaining power sources will be verified to be operable and positive measures will be provided to preclude subsequent testing or maintenance activities on these systems, subsystems, trains, components, and devices.

Wind and External Flood Hazards Extreme wind and external flood hazards were evaluated for the Individual Plant Examination for External Events (IPEEE). For extreme winds, contribution to core damage frequency was estimated at 1.4E-07 per year. Safety related systems at DAEC, including the diesel generators, are housed in Class I buildings and therefore have minimal exposure to the effects of high winds and tornadoes. With regard to external flood, the DAEC design was shown to meet 1975 Standard Review Plan criteria and thus, the contribution to core damage frequency is estimated at less than 1.0E-06 per year. Increase in core damage probability and large/early release probability due to these hazards is judged to be negligible with the B DG out of service for an additional 60 hours2.5 days 0.357 weeks 0.0822 months .

Quality of PRA TS Amendment 280, dated February 24, 2012, (Reference 1, ML120110282) stated the following regarding the quality of the DAEC PRA:

The quality of the DAEC PRA must be compatible with the safety implications of the proposed TS change and the role the PRA plays in justifying the change.

That is, the more the potential change in risk or the greater the uncertainty in that risk from the requested TS change, or both, the more rigor that must go into ensuring the quality of the PRA.

RG 1.200 is NRC's developed regulatory guidance for assessing the technical adequacy of a PRA. Revision 2 to RG 1.200 endorses (with comments and qualifications) the use of the American Society of Mechanical Engineers (ASME)

I American Nuclear Society (ANS) RA-Sa-2009, "Addenda to ASME/ANS RA-S-2008 Standard for Level1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications," NEI 00-02, "Probabilistic Risk Assessment Peer Review Process Guidelines," and NEI 05-04, "Process for Performing Follow-on PRA Peer Reviews Using the ASME PRA Standard.

NG-12-0145 Exhibit A Page 11 of 21 Revision 1 to RG 1.200 had endorsed the internal events PRA standard ASME RA-Sb-2005, "Addenda to ASME RA-S-2002 Standard for Probabilistic Risk Assessment for Nuclear Power Plant Applications." For the internal events PRA, there are no significant technical differences in the standard requirements and, therefore, assessments using the previously endorsed internal events standard are acceptable.

The licensee has performed an assessment of the PRA models used to support the SFCP using the guidance of RG 1.200, Revisions 1 and 2, to assure that the PRA models are capable of determining the change in risk due to changes to surveillance frequencies of SSCs, using plant specific data and models.

Capability Category II of the standard is required by NEI 04-10 for the internal events PRA, and any identified deficiencies to those requirements are assessed further to determine any impacts to proposed decreases to surveillance frequencies, including the use of sensitivity studies where appropriate.

The Boiling Water Reactor Owner's Group performed a peer review of the DAEC internal events PRA model in December 2007, using the NEI 05-04 PRA peer review process and the ASME PRA Standard ASME RA-Sb-2005, along with the clarifications provided in Regulatory Guide 1.200, Revision 1. The DAEC PRA peer review was a full-scope review of all the technical elements of the internal events, at-power PRA. Also in December 2007, the licensee completed a gap analysis against the ASME PRA Standard RA-Sb-2005 and RG 1.200, Revision 1, to identify potential gaps to Capability Category II of the Standard. The licensee provided open gap items for their Internal Events PRA model, Revision 5C, for NRC staff review, in the license amendment request (LAR) submittal

[Reference 2 (ML110550570)].

Subsequently, on June 30, 2011, the licensee completed a DAEC Internal Events PRA model update to Revision 6, to be used for the TSTF-425 application. To support this model update, a focused peer review was completed in March 2011.

The focused peer review utilized the ASME/ANS RA-Sa-2009 standard and RG 1.200, Revision 2. The scope of the review included those open gap items provided in the LAR submittal, as well as the additional gap items from the 2007 full scope peer review. The focused peer review included a review of new methods implemented in the model upgrade.

The licensee provided the results of the focused peer review to the NRC staff in its letters dated April 20, and August 15, 2011. As a result of the focused peer review, many of the open gap items identified in the LAR submittal were closed.

The focused peer review team found twelve (12) open gap items that were assessed as not meeting Capability Category II per the ASME/ANS RA-Sa-2009 standard, five of which the licensee addressed and closed after the focused peer review. To assess the technical adequacy of the DAEC Internal Events PRA model for TSTF-425 application, the NRC staff reviewed the remaining seven open gap items for the Revision 6 model to ensure the deficiency, in not meeting

NG-12-0145 Exhibit A Page 12 of 21 Capability Category II, may be addressed and dispositioned for each surveillance frequency per the NEI 04-10 methodology.

The following is the NRC staff's evaluation of the seven remaining open gap items identified for the Revision 6 model.

IE-83-01A: SR IE-83 provides requirements for grouping of initiating events. The staff's review finds that loss of bus 1A1, 1A2, 1A3, and 1A4 initiators need to be evaluated separately from the turbine trip initiator. This conclusion is based on a sensitivity study and insights obtained in response to requests for additional information. The licensee's sensitivity analysis, performed with the Internal Events PRA model, found the loss of these bus initiators to be a very small contributor to core damage frequency. However, uncertainties need to be fully considered in surveillance test interval evaluations in accordance with NEI 04-10.

For these loss-of-bus initiators, uncertainties include the potential of fire resulting, for example, from an electrical fault, with possible event complications other than those assumed in the Internal Events PRA model, as well as the potential of human error resulting in a loss-of-bus initiating event during maintenance or testing. These uncertainties can be considered qualitatively or quantitatively. NEI 04-10 guidance can be used to address this open gap item. Therefore, the NRC staff agrees that this deficiency may be addressed and dispositioned for each surveillance frequency evaluation per the NEI 04-10 methodology.

Based on the licensee's assessment using the applicable PRA standard and RG 1.200, the level of PRA quality, combined with the proposed evaluation and disposition of gaps, is sufficient to support the evaluation of changes proposed to surveillance frequencies within the SFCP, and is consistent with Regulatory Position 2.3.1 of RG 1.177.

3.1.4.2 Scope of the PRA The licensee is required to evaluate each proposed change to a relocated surveillance frequency using the guidance contained in NEI 04-10 to determine its potential impact on risk, due to impacts from internal events, fires, seismic, other external events, and from shutdown conditions. Consideration is made of both COF and LERF metrics. In cases where a PRA of sufficient scope or where quantitative risk models were unavailable, the licensee uses bounding analyses, or other conservative quantitative evaluations. A qualitative screening analysis may be used when the surveillance frequency impact on plant risk is shown to be negligible or zero.

The licensee uses a full-scope PRA model for evaluation of at-power internal events, fires, and seismic events. Since a PRA has not been developed for shutdown conditions, the licensee utilizes guidance provided in NUMARC 91-06, "Guidelines for Industry Actions to Assess Shutdown Management." The licensee has analyzed high winds, floods, and other external hazards events against the

NG-12-0145 Exhibit A Page 13 of 21 1975 Standard Review Plan criteria, and will use insights from this evaluation to analyze these hazards.

Based on the above, the NRC staff concludes that the licensee's evaluation methodology is sufficient to ensure the scope of the risk contribution of each surveillance frequency change is properly identified for evaluation, and is consistent with Regulatory Position 2.3.2 of RG 1.177.

PRA Modeling The licensee will determine whether the SSCs affected by a proposed change to a surveillance frequency are modeled in the PRA. Where the SSC is directly or implicitly modeled, a quantitative evaluation of the risk impact may be carried out.

The methodology adjusts the failure probability of the impacted SSCs, including any impacted common cause failure modes, based on the proposed change to the surveillance frequency. Where the SSC is not modeled in the PRA, bounding analyses are performed to characterize the impact of the proposed change to the surveillance frequency. Potential impacts on the risk analyses due to screening criteria and truncation levels are addressed by the requirements for PRA technical adequacy consistent with guidance contained in RG 1.200, and by sensitivity studies identified in NEI 04-10.

The licensee will perform quantitative evaluations of the impact of selected testing strategy (i.e., staggered testing or sequential testing) consistent with the guidance of NUREG/CR-6141 and NUREG/CR-5497, as discussed in NEI 04-10.

Thus, through the application of NEI 04-10, the NRC staff concludes that the DAEC PRA modeling is sufficient to ensure an acceptable evaluation of risk for the proposed changes in surveillance frequency, and is consistent with Regulatory Position 2.3.3 of RG 1.177.

Assumptions for Time-Related Failure Contributions For SSCs that are normally in a standby mode, the on-demand failure probability of SSCs modeled in typical PRAs may include a standby time-related contribution and cyclic demand related contribution. NEI 04-10 criteria adjust the time-related failure contribution of SSCs affected by the proposed change to surveillance frequency. This is consistent with RG 1.177, Section 2.3.3, which permits separation of the failure rate contributions into demand and standby for evaluation of surveillance requirements. If the available data do not support distinguishing between the standby time-related failures and cyclic demand failures, then the change to surveillance frequency is assumed to impact the total failure probability of the SSC, including both standby and cyclic demand contributions. The licensee informed the NRC staff that they do not explicitly include a separate standby time-related contribution. As such, the licensee will

NG-12-0145 Exhibit A Page 14 of 21 assume that changes to the surveillance frequency impact the total failure probability of the SSC consistent with NEI 04-10 guidance. The SSC failure rate (per unit time) is assumed to be unaffected by the change in test frequency, and will be confirmed by the required monitoring and feedback implemented after the change in surveillance frequency is implemented. Selecting the testing strategy, such as staggered testing, is important in providing monitoring and feedback on performance for surveillance testing intervals and, as noted previously, the licensee will perform quantitative evaluations of the impact of the testing strategy as discussed in NEI 04-10. In addition, the process requires consideration of qualitative sources of information with regards to potential impacts of test frequency on SSC performance, including industry and plant-specific operating experience, vendor recommendations, industry standards, and code-specified test intervals. Thus the process is not reliant upon risk analyses as the sole basis for the proposed changes.

The potential beneficial risk impacts of reduced surveillance frequency, including reduced downtime, lesser potential for restoration errors, reduction of potential for test-caused transients, and reduced test-caused wear of equipment, are identified qualitatively, but are conservatively not required to be quantitatively assessed. Thus, through the application of NEI 04-10, the licensee has employed reasonable assumptions with regard to extensions of surveillance test intervals, and is consistent with Regulatory Position 2.3.4 of RG 1.177.

Sensitivity and Uncertainty Analyses NEI 04-10 requires sensitivity studies to assess the impact of uncertainties from key assumptions of the PRA, uncertainty in the failure probabilities of the affected SSCs, impact to the frequency of initiating events, and of any identified deviations from Capability Category II of the PRA standard. Where the sensitivity analyses identify a potential impact on the proposed change, revised surveillance frequencies are considered, along with any qualitative considerations that may bear on the results of such sensitivity studies. Required monitoring and feedback of SSC performance once the revised surveillance frequencies are implemented will also be performed. Thus, through the application of NEI 04-10, the licensee has appropriately considered the possible impact of PRA model uncertainty and sensitivity to key assumptions and model limitations, and is consistent with Regulatory Position 2.3.5 of RG 1.177.

Acceptance Guidelines The licensee will quantitatively evaluate the change in total risk (including internal and external events contributions) in terms of CDF and LERF for both the individual risk impact of a proposed change in surveillance frequency and the cumulative impact from all individual changes to surveillance frequencies using the guidance contained in NRC-approved NEI 04-10 in accordance with the TS SFCP. Each individual change to surveillance frequency must show a risk impact

NG-12-0145 Exhibit A Page 15 of 21 below 1E-6 per year for change to CDF, and below 1E-7 per year for change to LERF. These are consistent with the limits of RG 1.174 for very small changes in risk. Where the RG 1.174 limits are not met, the process either considers revised surveillance frequencies which are consistent with RG 1.174 or the process terminates without permitting the proposed changes. Where quantitative results are unavailable to permit comparison to acceptance guidelines, appropriate qualitative analyses are required to demonstrate that the associated risk impact of a proposed change to surveillance frequency is negligible or zero. Otherwise, bounding quantitative analyses are required which demonstrate the risk impact is at least one order of magnitude lower than the RG 1.174 acceptance guidelines for very small changes in risk. In addition to assessing each individual SSC surveillance frequency change, the cumulative impact of all changes must result in a risk impact below 1 E-5 per year for change to CDF, and below 1 E-6 per year for change to LERF, and the total CDF and total LERF must be reasonably shown to be less than 1 E-4 per year and 1 E-5 per year, respectively. These are consistent with the limits of RG 1 .174 for acceptable changes in risk, as referenced by RG 1.177 for changes to surveillance frequencies. The NRC staff interprets this assessment of cumulative risk as a requirement to calculate the change in risk from a baseline model utilizing failure probabilities based on the surveillance frequencies prior to implementation of the SFCP, compared to a revised model with failure probabilities based on changed surveillance frequencies. The NRC staff further notes that the licensee includes a provision to exclude the contribution to cumulative risk from individual changes to surveillance frequencies associated with insignificant risk increases (less than 5E-8 CDF and 5E-9 LERF) once the baseline PRA models are updated to include the effects of the revised surveillance frequencies.

The quantitative acceptance guidance of RG 1.174 is supplemented by qualitative information to evaluate the proposed changes to surveillance frequencies, including industry and plant-specific operating experience, vendor recommendations, industry standards, the results of sensitivity studies, and SSC performance data and test history.

The final acceptability of the proposed change is based on all of these considerations and not solely on the PRA results compared to numerical acceptance guidelines. Post implementation performance monitoring and feedback are also required to assure continued reliability of the components. The NRC staff concludes that the licensee's application of NEI 04-10 provides reasonable acceptance guidelines and methods for evaluating the risk increase of proposed changes to surveillance frequencies, consistent with Regulatory Position 2.4 of RG 1.177.

Based on the above, the NRC staff concludes that the proposed methodology satisfies the fourth key safety principle of RG 1.177 by assuring that any increase in risk is small and consistent with the intent of the Commission's Safety Goal Policy Statement.

NG-12-0145 Exhibit A Page 16 of 21 The Impact of the Proposed Change Should Be Monitored Using Performance Measurement Strategies The licensee's adoption of TSTF-425 requires application of NEI 04-10 in the SFCP. NEI 04-10 requires performance monitoring of SSCs whose surveillance frequency has been revised as part of a feedback process to assure that the change in test frequency has not resulted in degradation of equipment performance and operational safety. The monitoring and feedback includes consideration of maintenance rule monitoring of equipment performance. In the event of degradation of SSC performance, the surveillance frequency will be reassessed in accordance with the methodology, in addition to any corrective actions which may apply as part of the maintenance rule requirements. The performance monitoring and feedback specified in NEI 04-10 is sufficient to reasonably assure acceptable SSC performance and is consistent with Regulatory Position 3.2 of RG 1.177.

Based on the above, the NRC staff concludes that the fifth key safety principle of RG 1.177 is satisfied.

Weather From the National Weather Service website (http://www.nws.noaa.gov/), the forecast on Friday March 23, 2012 for the Palo, IA area from Friday March 23, 2012 through Wednesday March 28, 2012 is as follows:

Today: Isolated showers. Partly sunny, with a high near 70. Calm wind becoming north around 5 mph. Chance of precipitation is 20%.

Tonight: Scattered showers. Mostly cloudy, with a low around 52. North wind around 5 mph. Chance of precipitation is 40%.

Saturday: A 20 percent chance of showers. Partly sunny, with a high near 71. North wind between 5 and 10 mph.

Saturday Night: Partly cloudy, with a low around 51.

Sunday: Mostly sunny, with a high near 73.

Sunday Night: Partly cloudy, with a low around 49.

Monday: A 20 percent chance of showers. Partly sunny, with a high near 63.

Monday Night: A chance of showers and thunderstorms. Mostly cloudy, with a low around 48.

NG-12-0145 Exhibit A Page 17 of 21 Tuesday: A chance of showers and thunderstorms. Partly sunny, with a high near 71.

Tuesday Night: A slight chance of showers. Partly cloudy, with a low around 49.

Wednesday: Sunny, with a high near 67.

No severe weather is currently forecasted for the Palo, IA area for the time period of concern.

Temporary Power NextEra Energy Duane Arnold had made provisions for connecting a temporary 1400 kW, 4160 volt AC, diesel powered generator at the low side of the Standby Transformer. All equipment, materials, work documents, and procedures will be staged and ready to support restoration of power to the 1A4 emergency bus within eight hours. The generator has been sized to supply the loads necessary to bring the unit to cold shutdown in case of a loss of offsite power concurrent with a single failure of the currently operable diesel during plant operation in Mode 1.

5.0 REGULATORY ANALYSIS

5.1 No Significant Hazards Consideration According to 10 CFR 50.92, Issuance of amendment, paragraph (c), a proposed amendment to an operating license involves no significant hazards consideration if operation of the facility in accordance with the proposed amendment would not:

1. Involve a significant increase in the probability or consequence of an accident previously evaluated; or

2. Create the possibility of a new or different kind of accident from any accident previously evaluated; or

3. Involve a significant reduction in margin of safety.

NextEra Energy Duane Arnold has evaluated the proposed change to the TS using the criteria in 10 CFR 50.92, and has determined that the proposed change does not involve a significant hazards consideration. The following information is provided to support a finding of no significant hazards consideration.

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

NG-12-0145 Exhibit A Page 18 of 21 No. Reactor protection system performance will remain within the bounds of the previously performed accident analyses and will continue to function in a manner consistent with the plant design basis. The additional allowed time does not result in a condition where the design, material, and construction standards that were applicable prior to the change are altered. The proposed change will not modify any system interface. The proposed change will not affect the probability of any event initiators. There will be no change to the normal plant operating parameters or accident mitigation performance. The proposed change will not alter any assumptions or change any mitigation action in the radiological consequence evaluations in the UFSAR.

Implementation of the proposed change will minimize risk impact. The proposed one-time only change to the TS 3.8.1 Required Action B.5 Completion Time does not, of itself, increase the probability of any accident previously evaluated. The proposed change has been shown to involve a small increase in quantitative risk, offset by qualitative considerations.

The proposed change does not adversely affect accident initiators or precursors nor alter the design assumptions or the manner in which the plant is normally operated and maintained. The proposed change does not affect source term, containment isolation, or radiological release assumptions used in evaluating the radiological consequences of an accident previously evaluated. The proposed change is consistent with safety analysis assumptions, which apply when the plant is operating in compliance with LCO requirements.

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

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

No. The proposed change does not result in a change in the manner in which the electrical distribution systems provide plant protection. The change does not alter assumptions made in the safety analysis. The one-time extension of the Completion Time does not change any existing accident scenarios, nor create any new or different accident scenarios. The proposed change is consistent with the safety analysis assumptions and current plant operating practice.

Therefore, the proposed request does not create a new or different kind of accident from any accident previously evaluated.

3. Does the proposed change involve a significant reduction in a margin of safety?

No. Based upon the availability of redundant systems, the mitigating actions that have been taken and the low probability of an accident, NextEra Energy Duane

NG-12-0145 Exhibit A Page 19 of 21 Arnold concludes that the reduction in availability of the B EDG does not result in a significant reduction in the margin of safety. The margin of safety is related to the confidence in the ability of the fission product barriers to perform their design functions during and following an accident situation. These barriers include the fuel cladding, the reactor coolant system, and the containment system. The performance of the fuel cladding, containment and the reactor coolant system will not be significantly impacted by the proposed change.

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

Based upon the above, NextEra Energy Duane Arnold concludes that the proposed amendment presents no significant hazards consideration under the standards set forth in 10 CFR 50.92 (c), and accordingly a finding of no significant hazards consideration is justified.

In conclusion, based on the considerations discussed above, (1) there is a 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 US NRCs 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.

CONCLUSION Based on the preceding 10 CFR 50.92 evaluation, NextEra Energy Duane Arnold concludes that the proposed amendment presents no significant hazards consideration under the standards set forth in 10 CFR 50.92(c), and, accordingly, a finding of no significant hazards consideration is justified.

5.2 Applicable Regulatory Requirements/Criteria By letter dated March 23, 2012, NextEra Energy Duane Arnold, LLC has submitted a request for revision of the Technical Specifications for the Duane Arnold Energy Center (DAEC). The proposed one-time amendment allows permits additional time to complete repairs to the B DG flex drive gear and restore the B DG before a plant shutdown was required. An additional 2 days beyond that currently provided in TS 3.8.1, Required Action B.5 is requested to restore the B DG to OPERABLE status such that entry into MODE 3 would not be required until 0230 hours9.583 days 1.369 weeks 0.315 months on March 28, 2012. The current 7 day Completion Time for the B DG expires at 0230 on March 26, 2012. . This request also corrects a simple typographical error in the Completion Time for Required Action B.5.

Evaluation:

NG-12-0145 Exhibit A Page 20 of 21 The proposed change is consistent with the current regulations and thus, an exemption pursuant to 10 CFR 50.12 is not required. The current regulations (e.g., §50.36) do not dictate the specific actions to be taken when a DG is inoperable; only that Limiting Conditions for Operability (LCO) are included in the TS that are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When a limiting condition for operation of a nuclear reactor is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the technical specifications until the condition can be met. The proposed extension for the B DG Completion Time continues to demonstrate these CFR requirements, as the Required Action for the B DG will continue to provide the necessary remedial actions until the LCO is again met.

The DAEC Construction Permit was issued in 1970, prior to the issuance of 10 CFR 50, Appendix A, General Design Criteria (GDC), and thus, the DAEC was not specifically licensed to the GDC (Ref. SECY-92-223). The following describes the DAEC UFSAR commitment to the GDCs pertinent to this application and the impact of the requested change on those commitments.

GDC 17 deals with the design of the Electrical Power Systems for the unit, both offsite and onsite power systems. The proposed change does not affect the design of the onsite or offsite power systems, thus GDC 17 is not impacted by this change.

GDC 18 deals with testing of Electric Power Systems for the unit, both offsite and onsite power systems. The proposed change also does not involve onsite or offsite power circuit testing, which is covered by GDC 18. No other changes in the design, operation or testing of the offsite power circuits are being proposed.

GDCs 37, 40, 43 and 46, all contain provisions for testing of key safety systems (other than the Electrical Power Systems), including the performance of the full operational sequence that brings the systems into operation, including the transfer between normal and emergency power sources. The proposed extension for the B DG Completion Time does not impact this capability, as the normal onsite and offsite power circuit Surveillances, along with the various system simulated automatic actuation Surveillances, will continue to demonstrate that these GDCs are met.

Safety Guide 6 (i.e., original revision of Regulatory Guide 1.6) deals with the electrical independence of each division of the electrical distribution system. The proposed extension for the B DG Completion Time will not impact the design of the electrical distribution system, nor the associated interlocks between the onsite and offsite electrical distribution systems. Thus, the proposed change does not impact the DAECs ability to meet Safety Guide 6, as described in UFSAR Section 1.8.6.

NG-12-0145 Exhibit A Page 21 of 21

6.0 ENVIRONMENTAL CONSIDERATION

10 CFR Section 51.22(c)(9) identifies certain licensing and regulatory actions which are eligible for categorical exclusion from the requirement to perform an environmental assessment. A proposed amendment to an operating license for a facility requires no environmental assessment if operation of the facility in accordance with the proposed amendment would not: (1) involve a significant hazards consideration; (2) result in a significant change in the types or significant increase in the amounts of any effluents that may be released offsite; and (3) result in a significant increase in individual or cumulative occupational radiation exposure. NextEra Energy Duane Arnold has reviewed this request and determined that the proposed amendment meets the eligibility criteria for categorical exclusion set forth in 10 CFR Section 51.22(c)(9). Pursuant to 10 CFR Section 51.22(b), no environmental impact statement or environmental assessment needs to be prepared in connection with the issuance of the amendment. The basis for this determination follows.

Basis The change meets the eligibility criteria for categorical exclusion set forth in 10 CFR Section 51.22(c)(9) for the following reasons:

1. As demonstrated in the 10 CFR 50.92 evaluation included in this exhibit, the proposed amendment does not involve a significant hazards consideration.

2. The proposed changes do not result in an increase in power level, do not increase the production, nor alter the flow path or method of disposal of radioactive waste or byproducts. There is no significant change in the types or significant increase in the amounts of any effluents that may be released offsite.

3. The proposed changes do not result in changes in the level of control or methodology used for processing of radioactive effluents or handling of solid radioactive waste nor will the proposal result in any change in the normal radiation levels within the plant. There is no significant increase in individual or cumulative occupational radiation exposure.

7.0 PRECEDENT

1. NRC Approval of the McGuire Unit 1 license amendment request of June 7, 2007 (ML071700272) requesting a one limited duration exception from the Completion Time for the Unit 1 A Emergency Diesel Generator (EDG) Amendment 241 dated June 8, 2007 and the conclusions of the associated NRC Safety Evaluation Report (ML071570599).

NG-12-0145 Exhibit A Page 22 of 21

2. NRC approval of the D. C. Cook Nuclear Plant, Unit 2 license amendment request of December 9, 2003 (ML033460380) requesting a one-time limited duration exception from the allowed outage time (AOT) for the Unit 2AB EDG, Amendment 264, dated December 10, 2003, and the conclusions of the associated NRC Safety Evaluation Report (ML042600115).

3. NRC approval of the Browns Ferry Nuclear Plant, Unit 3 license amendment request of April 6, 2007 (ML071010092) requesting a one-time limited duration exception from the allowed outage time (AOT) for the Unit 3D EDG, Amendment 257, dated April 6, 2007, and the conclusions of the associated NRC Safety Evaluation (ML071070289).

8.0 REFERENCES

1. Letter from Terry A. Beltz (USNRC) to Peter Wells (NextEra Energy Duane Arnold), Duane Arnold Energy Center - Issuance of Amendment Re: Adoption of Technical Specifications Task Force Traveler (TSTF-425) to Relocate Specifica Surveillance Frequencies to a Licensee-Controlled Program (TAC No. ME5744), dated February 24, 2012 (ML120110282)

2. Letter from Christopher R. Costanzo (NextEra Energy Duane Arnold) to USNRC (Document Control Desk), License Amendment Request (TSCR-120): Application for Technical Specification Change Regarding Risk-Informed Justification for the Relocation of Specific Surveillance Frequency Requirements to a Licensee Controlled Program (TSTF-425, Rev. 3, dated February 23, 2011 (ML110550570)

NG-12-0145 Exhibit B EXHIBIT B PROPOSED TECHNICAL SPECIFICATION AND BASES CHANGES (MARK-UP) 2 Pages Follow

AC Sources Operating 3.8.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) B.3 Determine OPERABLE 24 hours1 days 0.143 weeks 0.0329 months DG is not inoperable due to common cause failure.

AND

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

Not required to be performed when the cause of the inoperable DG is pre-planned, preventive maintenance and testing.

B.4 Perform SR 3.8.1.2 for Once per 72 OPERABLE DG. hours AND B.5 Restore DG to 7 days*

OPERABLE status.

AND 8 days from discovery of failure to meet LCO except expect for Condition A*

C. Two offsite circuits C.1 Declare required 12 hours0.5 days 0.0714 weeks 0.0164 months from inoperable. feature(s) inoperable discovery of Condition when the redundant C concurrent with required feature(s) are inoperability of inoperable. redundant required feature(s)

AND (continued)

NOTE: The Completion Time for Required Action B.5 may be extended beyond the 7 days and up to 8 days from discovery of failure to meet the LCO except for Condition A up to a total of 9 days to enable repairs to the B DG flex drive gear. This allowance is only applicable to the B DG for the period from March 19, 2012 0230 hours9.583 days 1.369 weeks 0.315 months through March 28,, 2012 0230 hours9.583 days 1.369 weeks 0.315 months .

DAEC 3.8-3 TSCR-134

BASES ACTIONS B.5 (continued)

The second Completion Time for Required Action B.5 establishes a limit based on the maximum time allowed for the combination of one DG and two offsite AC power sources to be inoperable during any single contiguous occurrence of failing to met the LCO except for Action A. If Condition B is entered while, for instance, two offsite circuits are inoperable and one circuit is subsequently restored OPERABLE, the LCO may already have been not met for up to 24 hours1 days 0.143 weeks 0.0329 months . This situation could lead to a total of 8 days, since initial failure of the LCO (except for Condition A), to restore the DG. At this time, the second offsite circuit could again become inoperable, the DG restored OPERABLE, and an additional 24 hours1 days 0.143 weeks 0.0329 months (for a total of 9 days) allowed prior to complete restoration of the LCO (except for Condition A). The 8 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 B and C are entered concurrently, and when corrective actions are completed prior to completing the shutdown required by LCO 3.0.3 (which is required to be entered by Action F). The AND connector between the 7 day and 8 day Completion Times means that both Completion Times apply simultaneously, and the more restrictive must be met.

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

An Amendment was approved that provides a Note allowing the Completion Time for Required Action B.5 may be extended up to 9 days from discovery of failure to meet the LCO to enable repairs to the B DG flex drive gear. This allowance is only applicable to the B DG for the period from March 19, 2012 0230 hours9.583 days 1.369 weeks 0.315 months through March 28, 2012 0230 hours9.583 days 1.369 weeks 0.315 months . This will allow continued operation during repairs to the B DG flex drive gear.

(continued)

DAEC B 3.8-10 TSCR-134

NG-12-0145 Exhibit C EXHIBIT C PROPOSED TECHNICAL SPECIFICATION PAGE (RE-TYPED) 1 Page Follows

AC Sources Operating 3.8.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) B.3 Determine OPERABLE 24 hours1 days 0.143 weeks 0.0329 months DG is not inoperable due to common cause failure.

AND

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

Not required to be performed when the cause of the inoperable DG is pre-planned, preventive maintenance and testing.

B.4 Perform SR 3.8.1.2 for Once per 72 OPERABLE DG. hours AND B.5 Restore DG to 7 days*

OPERABLE status.

AND 8 days from discovery of failure to meet LCO except for Condition A*

C. Two offsite circuits C.1 Declare required 12 hours0.5 days 0.0714 weeks 0.0164 months from inoperable. feature(s) inoperable discovery of Condition when the redundant C concurrent with required feature(s) are inoperability of inoperable. redundant required feature(s)

AND (continued)

NOTE: The Completion Time for Required Action B.5 may be extended beyond the 7 days and up to 8 days from discovery of failure to meet the LCO except for Condition A up to a total of 9 days to enable repairs to the B DG flex drive gear. This allowance is only applicable to the B DG for the period from March 19, 2012 0230 hours9.583 days 1.369 weeks 0.315 months through March 28, 2012 0230 hours9.583 days 1.369 weeks 0.315 months .

DAEC 3.8-3 Amendment No.

NG-12-0145 Exhibit D Page 1 of 2 EXHIBIT D LIST OF COMMITMENTS

NG-12-0145 Exhibit D Page 2 of 2 LIST OF COMMITMENTS The following contingency actions will be instituted at the DAEC during the applicability of this license amendment:

Systems and components will be protected in accordance with procedure OP-AA-102-1003, Protected Trains and Guarded Equipment.

Operators and support staff will be briefed on implementing SAMP-706 in an extended SBO situation requiring containment venting.

Operators and support staff will be briefed on implementing SAMP-707 in an extended SBO situation requiring alternate coolant injection.

A portable diesel fire pump will be staged. Operators and support staff will be briefed on implementing plant procedures AIP-404 and SAMP-708 in SBO conditions requiring Reactor injection. Additional staffing beyond current normal staffing to assure actions will be expedited.

No discretionary switchyard maintenance will be performed.

No work will be performed on trip sensitive equip. Activities that could potentially cause a plant scram, turbine trip, or generator trip will either be deferred or carefully evaluated to identify compensatory actions that eliminate or reduce this risk.

Maintenance work will continue to be reviewed using the risk monitor. The PRA staff will evaluate all work to assure the RG 1.777 criteria are not exceeded.

All maintenance on the A DG during the time period of this extension will be suspended. The A DG will be guarded.

The system load dispatcher will be contacted once per day to ensure no significant grid perturbations (high grid loading unable to withstand a single contingency of line or generation outage) are expected during the extended AOT.

Component testing or maintenance of safety systems and important non safety equipment in the offsite power systems which can increase the likelihood of a plant transient (unit trip) or LOOP will be avoided.

TS required systems, subsystems, trains, components, and devices that depend on the remaining power sources will be verified to be operable and positive measures will be provided to preclude subsequent testing or maintenance activities on these systems, subsystems, trains, components, and devices.

NG-12-0145 Exhibit E Page 1 of 2 EXHIBIT E EXPLANATION OF THE WHY THE EMERGENCY SITUATION OCCURRED AND WHY THE SITUATION COULD NOT HAVE BEEN AVOIDED

NG-08-0500 Exhibit E Page 2 of 2 EXPLANATION OF THE WHY THE EMERGENCY SITUATION OCCURRED AND WHY THE SITUATION COULD NOT HAVE BEEN AVOIDED The B DG was declared inoperable at 0230 hours9.583 days 1.369 weeks 0.315 months on March 19, 2012, for preplanned maintenance. During the maintenance activities to inspect the flex drive gear, no movement was found to be present in the gear. The necessary parts are on hand, however flex drive gear repairs, along with subsequent restoration of the B DG to OPERABLE status will result in exceeding the 7 day Completion Time of TS 3.8.1, Required Action B.5.

The flex drive gear inspection is not specified in the Fairbanks Morse DG Technical Manual, nor is it in ant test procedure. NextEra Energy Duane Arnold personnel were not aware that this inspection was being performed. Fairbanks Morse personnel are trained to perform this inspection as a good practice only.

Upon visual review of the assembly by the Fairbanks Morse Technical Representatives on site, and the observations that indicate no abnormal condition other than the gear being locked up on the flex drive hub. This would indicate a possible first stage failure that can be either of two causes.

1) Failure of the leaf springs - this could be a portion of a broken leaf (or several) that have lodged between the drive lugs of the hub and gear causing the locked condition; or

2) Failure of the chrome plating on the OD of the hub causing a "galled" spot by accumulating metal debris between the gear and hub causing the locked condition.

Either of these conditions are the precursor of a more drastic failure that could (and have been known to) lead to a catastrophic engine failure during loaded operation. This type of major failure has been known to extend to destruction and removal of the gear teeth on both gears, bending the blower drive shaft, causing contact of the blower rotors and dispersal of aluminum particles and debris from the rotors into the air receiver and onto the liners and piston rings entailing a complete rebuild of the engine.

The official recommendation of Fairbanks Morse is to repair the relatively minor condition of the locked drive gear before any major failures occur. This can be accomplished by removal of the blower and disassembly and repair of the gear in place.

BLIND CARBON COPY LIST FOR NG-12-0145 March 22, 2012 D. Curtland CTS Project IRMS CNRB GDS Associates, Inc. CIPCO (w/o)

ORG (S. Hamed) Cornbelt (w/o)

S. Catron B. Lawrence Mark Lingenfelter

Subject:

Technical Specification Change Request (TSCR -134) - Emergency License Amendment Request for One-Time Allowance to Allow Continued Operation with the B Diesel Generator Inoperable

NUREG-0800 U.S. NUCLEAR REGULATORY COMMISSION STANDARD REVIEW PLAN BRANCH TECHNICAL POSITION 8-8 ONSITE (EMERGENCY DIESEL GENERATORS) AND OFFSITE POWER SOURCES ALLOWED OUTAGE TIME EXTENSIONS REVIEW RESPONSIBILITIES Primary - Organization responsible for electrical engineering Secondary - None A. BACKGROUND Regulatory Guide (RG) 1.93 [Reference 1] provides guidance with respect to operating restrictions, that is Allowed Outage Time (AOT), if the number of available onsite emergency diesel generators (EDGs) and offsite power sources is less than that required by the Technical Specifications (TS). In particular, this RG prescribes a maximum AOT of 72 hours3 days 0.429 weeks 0.0986 months for an inoperable onsite or offsite power source.

Initial - February 2012 USNRC STANDARD REVIEW PLAN This Standard Review Plan (SRP), NUREG-0800, has been prepared to establish criteria that the U.S. Nuclear Regulatory Commission (NRC) staff responsible for the review of applications to construct and operate nuclear power plants intends to use in evaluating whether an applicant/licensee meets the NRC's regulations. The Standard Review Plan is not a substitute for the NRC's regulations, and compliance with it is not required. However, an applicant is required to identify differences between the design features, analytical techniques, and procedural measures proposed for its facility and the SRP acceptance criteria and evaluate how the proposed alternatives to the SRP acceptance criteria provide an acceptable method of complying with the NRC regulations.

The SRP sections are numbered in accordance with corresponding sections in Regulatory Guide 1.70, "Standard Format and Content of Safety Analysis Reports for Nuclear Power Plants (LWR Edition)." Not all sections of Regulatory Guide (RG) 1.70 have a corresponding review plan section. The SRP sections applicable to a combined license application for a new light-water reactor (LWR) are based on RG. 1.206, "Combined License Applications for Nuclear Power Plants (LWR Edition)."

These documents are made available to the public as part of the NRC's policy to inform the nuclear industry and the general public of regulatory procedures and policies. Individual sections of NUREG-0800 will be revised periodically, as appropriate, to accommodate comments and to reflect new information and experience. Comments may be submitted electronically by e-mail to NRR_SRP@nrc.gov.

Requests for single copies of SRP sections (which may be reproduced) should be made to the U.S. Nuclear Regulatory Commission, Washington, D.C. 20555, Attention: Reproduction and Distribution Services Section, or by fax to (301) 415-2289; or by e-mail to DISTRIBUTION@nrc.gov . Electronic copies of this section are available through the NRC's public Web site at http://www.nrc.gov/reading-rm/doc-collections/nuregs/staff/sr0800/ , or in the NRC's Agencywide Documents Access and Management System (ADAMS), at http://www.nrc.gov/reading-rm/adams.html , under Accession # ML113640138.

Additionally, the regulatory evaluation that staff applies in its review of the licensees request for proposed changes to Limited Condition for Operations were developed consistent with the objectives of the Commissions Probabilistic Risk Assessment (PRA) Policy Statement, Use of Probabilistic Risk Assessment Methods in Nuclear Activities: Final Policy Statement, for enhanced decision making and will result in more efficient use of resources, improvement in safety, and reduction of unnecessary burden.

The following regulatory guidance provides the staff position:

a. RG 1.174, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis, [Reference 2] describes a risk-informed approach, acceptable to the NRC, for assessing the nature and impact of proposed licensing-basis changes by considering engineering issues and applying risk insights.

b. RG 1.177, An Approach for Plant-Specific, Risk-Informed Decisionmaking:

Technical Specifications, [Reference 3] describes an acceptable risk-informed approach specifically for assessing proposed TS changes in AOTs.

c. RG 1.200, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities.

These RGs also provide PRA quality and acceptance guidelines for evaluating the results of such evaluations.

As noted in its approval of the final policy statement on the use of PRA methods (Use of Probabilistic Risk Assessment Methods In Nuclear Regulatory Activities, [60 Federal Register 42622]), the Commission stated an expectation that "the use of PRA technology should be increased to the extent supported by the state of the art in PRA methods and in a manner that complements the NRCs deterministic approach and supports the NRCs traditional defense-in-depth philosophy." The staff has defined an acceptable approach to analyzing and evaluating changes requested by licensees for AOT extensions. The staff approach supports the NRCs desire to base its decisions on the results of traditional engineering evaluations, supported by insights (derived from the use of PRA methods) about the risk significance of the proposed changes. Decisions concerning proposed changes are expected to be reached in an integrated fashion, considering traditional deterministic engineering evaluation that is supplemented by risk insights information. As stated in RG 1.177, the licensee should determine how the change impacts defense-in-depth aspects of the plant's design and operation and should determine the adequacy of safety margins following the proposed change.

The licensee should consider how plant and industry operating experience relates to the proposed change, and whether potential compensatory measures could be taken to offset any negative impact from the proposed change.

NRC staff has been receiving license amendment requests for one-time or permanent AOT extensions for the EDGs and offsite power sources from the current AOT up to 14 days to perform online maintenance of EDGs and offsite power sources. Maintenance may include both planned and unplanned activities. The purpose of this Branch Technical Position (BTP) is to provide guidance from a deterministic perspective in reviewing such amendment requests.

8-8-2 Initial - February 2012

B. BRANCH TECHNICAL POSITION The Electrical Engineering Branch (EEB) staff evaluates AOT extension requests for onsite or offsite power sources to allow on-line maintenance on EDGs that would normally be performed during refueling outages or maintenance of offsite power source(s) such as a transformer or bus. The on-line maintenance can help reduce the risk for loss of power during plant refueling outages when refueling activities are conducted. The staff evaluates the licensees request for AOT extension from deterministic as well as PRA perspectives. The risk-impact evaluation is performed by the PRA Licensing Branch. The traditional deterministic evaluation is performed by EEB.

Consistent with the Commissions final policy statement, it is expected that a license amendment request for an onsite or offsite AOT extension will contain a PRA assessment.

However, this BTP specifically discusses the defense-in-depth aspects for onsite and offsite power sources from a deterministic perspective. A supplemental power source should be available as a backup to the inoperable EDG or offsite power source, to maintain the defense-in-depth design philosophy of the electrical system to meet its intended safety function. The supplemental source must have capacity to bring a unit to safe shutdown (cold shutdown)1 in case of a loss of offsite power (LOOP) concurrent with a single failure during plant operation (Mode 1). According to NUREG-1784 [Reference 4], considering the changes in electric grid performance post-deregulation, the duration of LOOP events has increased and the probability of a LOOP as a consequence of a reactor trip has increased. This evaluation was done before the August 14, 2003, Blackout in the Northeast. The lessons learned from this Blackout event indicate that restoration of offsite power will take longer than previously considered, indicating that post-deregulation conditions challenge grid reliability. The staffs objective of requiring an extra (i.e., supplemental) power source for an inoperable EDG or offsite power source is to avoid a potential extended Station Blackout (SBO) event during the period of an extended AOT and to enable safe shutdown (cold shutdown) of the unit if normal power sources cannot be restored in a timely manner.

The current design of boiling-water reactor (BWR) and pressurized-water reactor (PWR) safety systems, required for reactor core decay heat removal and containment heat removal, are dependent on alternating current (AC) power. The projected time for restoration of offsite power is now considered to be more than the time previously evaluated for the SBO rule. The staff considers that a replacement (i.e., supplemental) AC power source is needed to back up an inoperable EDG or offsite power source during an extended AOT to maintain the defense-in-depth of the electrical power sources. The staff has previously granted AOT extensions to those licensees who have installed an alternate alternating current (AAC)2 power source (i.e., additional diesels, gas or combustion turbines, hydro units, or other power sources) credited for

1. By cold shutdown it is not implied that the plant needs to go to cold shutdown during LOOP. The unit can remain in either hot shutdown or hot standby in accordance with its licensing basis for the short term.

However if the offsite power is not recovered in a timely manner it may become necessary for the unit to go to cold shutdown, therefore the supplemental or AAC power source must have the capacity and capability to accomplish this function if needed.

2. The AAC power source is a supplementary AC power source, such as non-safety diesel or gas turbine that can be substituted as a replacement power source for an EDG to power one train of LOOP loads to take the plant to cold shutdown if necessary.

8-8-3 Initial - February 2012

SBO events which can be substituted for an inoperable EDG in the event of a LOOP, provided the power source has enough capacity to carry all LOOP loads to bring the unit to a cold shutdown without any load shedding.

In order to facilitate approval of an extended AOT for onsite or offsite power source, some licensees have provided a detailed PRA risk-informed evaluation and installed commercial-grade diesel generators capable of supplying power to the required safe-shutdown loads on the train removed from service for the maintenance outage. Some licensees at multi-unit sites have qualified their existing EDGs as an AAC source for meeting the SBO rule requirements (see Reference 5 for qualifications of the AAC source). For existing Class 1E EDGs to qualify as a supplemental AC source in the adjacent unit (provided with cross-connection within the same division of loads) for extending the AOT, the EDGs must have excess capacity to meet their units LOOP safe shutdown loads (without load shedding) while complying with the single failure criteria, and have spare capacity to support the other unit in maintenance to bring the plant to cold shutdown without any load shedding.

The permanent or temporary power source can be either a diesel generator, gas or combustion turbine, or power from nearby hydro units. This source can be credited as a supplemental source, that can be substituted for an inoperable EDG during the period of extended AOT in the event of a LOOP, provided the risk-informed and deterministic evaluation supports the proposed AOT and the power source has enough capacity to carry all LOOP loads to bring the unit to a cold shutdown.

Multi-unit sites that have installed a single AAC power source for SBO cannot substitute it for the inoperable diesel when requesting AOT extensions unless the AAC source has enough capacity to carry all LOOP loads to bring the unit to a cold shutdown as a substitute for the EDG in an extended AOT and carry all SBO loads for the unit that has an SBO event without any load shedding. The staff rationale is that if LOOP should occur during the period of extended AOT, the single AAC power source for SBO must be dedicated to the unit without the extended AOT to meet the SBO rule. Therefore for the unit in extended AOT, the licensee must provide a permanent or a temporary power source as a substitute for the EDG in an extended AOT to maintain the same level of defense-in-depth for safe shutdown of the plant. The staff believes that relying on a single AAC power source for an SBO in one unit and an inoperable EDG in the adjacent unit erodes the defense-in-depth aspects of the plant's design and operation and thereby reduces the safety margins due to a planned extended AOT.

For some boiling water reactors, the Division III diesel generator (High Pressure Core Spray Pump (HPCS) diesel generator) may be used as a supplemental AC source. The staff has determined that the HPCS diesel generator can be considered a supplemental AC source provided cross-connect capability exists so that the HPCS diesel generator can be cross-connected to either Division I or Division II AC buses to power safe-shutdown loads. All support systems for HPCS diesel generator should be verified to be available during the extended AOT. The HPCS diesel generator should have the capacity to power LOOP loads to bring the unit to cold shutdown without any load shedding.

For plants using AAC or supplemental power sources discussed above, the time to make the AAC or supplemental power source available, including accomplishing the cross-connection, should be approximately one hour to enable restoration of battery chargers and control reactor 8-8-4 Initial - February 2012

coolant system inventory. The availability of AAC or supplemental power source should be verified within the last 30 days before entering extended AOT by operating or bringing the power source to its rated voltage and frequency for 5 minutes and ensuring all its auxiliary support systems are available or operational. To support the one-hour time for making this power source available, plants must assess their ability to cope with loss of all AC power for one hour independent of an AAC power source. The plant should have formal engineering calculations for equipment sizing and protection and have approved procedures for connecting the AAC or supplemental power sources to the safety buses.

The EDG or offsite power AOT should be limited to 14 days to perform maintenance activities.

This time period is based on industry operating experience; for example, a maximum of 216 hours9 days 1.286 weeks 0.296 months (13.5 days, consisting of two shifts, each shift working 8 hours0.333 days 0.0476 weeks 0.011 months ) is considered to be sufficient for a major EDG overhaul or offsite power major maintenance. The licensee must provide justification for the duration of the requested AOT (actual hours plus margin based on plant-specific past operating experience). An EDG or offsite power AOT license amendment of more than 14 days should not be considered by the staff for review.

The TS must contain Required Actions and Completion Times to verify that the supplemental AC source is available before entering extended AOT. The availability of AAC or supplemental power source shall be checked every 8-12 hours0.5 days 0.0714 weeks 0.0164 months (once per shift). If the AAC or supplemental power source becomes unavailable any time during extended AOT, the unit shall enter the LCO and start shutting down within 24 hours1 days 0.143 weeks 0.0329 months . This 24-hour period will be allowed only once within any given extended EDG AOT. Additionally, the staff expects that the licensee will provide the following Regulatory Commitments:

The extended AOT will be used no more than once in a 24-month period (or refueling interval) on a per diesel basis to perform EDG maintenance activities, or any major maintenance on offsite power transformer and bus.

The preplanned maintenance will not be scheduled if severe weather conditions are anticipated.

The system load dispatcher will be contacted once per day to ensure no significant grid perturbations (high grid loading unable to withstand a single contingency of line or generation outage) are expected during the extended AOT.

Component testing or maintenance of safety systems and important non safety equipment in the offsite power systems that can increase the likelihood of a plant transient (unit trip) or LOOP will be avoided. In addition, no discretionary switchyard maintenance will be performed.

TS required systems, subsystems, trains, components, and devices that depend on the remaining power sources will be verified to be operable and positive measures will be provided to preclude subsequent testing or maintenance activities on these systems, subsystems, trains, components, and devices.

Steam-driven emergency feed water pump(s) in case of PWR units, and Reactor Core Isolation Cooling and High Pressure Coolant Injection systems in case of BWR units, will 8-8-5 Initial - February 2012

be controlled as protected equipment.

In summary, in light of the recent experiences in grid outages, it is the staffs position that the availability of an additional power source is a condition for approval of the extended EDG or offsite power AOT. Therefore, a supplemental power source must be available when extending the current AOT allowed by the plant TS for a single inoperable EDG or offsite power source up to 14 days provided the extended AOT is also supported by a risk-informed evaluation. License amendments requesting an extended EDG or offsite power AOT without a risk-informed evaluation must include adequate justification for the requested AOT based solely on deterministic criteria. Licensees requesting an extension of the onsite or offsite AOT should either install permanently, or make available on a temporary basis, a supplemental AC source capable of powering the inoperable onsite or offsite power source bus LOOP loads during the period of AOT extension. Although this extended AOT is allowed for pre-planned maintenance activities, it could be used for corrective maintenance on a limited base, provided the licensee meets risk-informed criteria, the maintenance rule availability/reliability requirements, and the reactor oversight process performance indicator criteria for availability/reliability.

Although the installation of a supplemental power source could be temporary for only the time duration of the AOT, a permanent source would maintain multiple independent AC sources capable of providing power to necessary equipment needed for safe shutdown and could also reduce the risk of core damage frequency due to a LOOP.

C. REFERENCES

1. RG 1.93, December 1974, Availability of Electric Power Sources

2. RG 1.174, May 2011, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis

3. RG 1.177, May 2011, An Approach for Plant-Specific, Risk-Informed Decision-making:

Technical Specifications

4. RG 1.200, March 2009, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities.

5. NUREG-1784, December 2003, Operating Experience Assessment - Effects of Grid Events on Nuclear Power Plant Performance

6. RG 1.155, August 1988, Station Blackout

7. Commission Policy Statement: Use of Probabilistic Risk Assessment Methods In Nuclear Regulatory Activities; Final Policy Statement (60 Federal Register 42622, August 16, 1995) 8-8-6 Initial - February 2012

PAPERWORK REDUCTION ACT STATEMENT The information collections contained in the Standard Review Plan are covered by the requirements of 10 CFR Part 50 and 10 CFR Part 52, and were approved by the Office of Management and Budget, approval number 3150-0011 and 3150-0151.

PUBLIC PROTECTION NOTIFICATION The NRC may not conduct or sponsor, and a person is not required to respond to, a request for information or an information collection requirement unless the requesting document displays a currently valid OMB control number.

8-8-7 Initial - February 2012

SRP BTP 8-8 Onsite (Emergency Diesel Generators) and Offsite Power Sources Allowed Outage Time Extensions Description of Changes This is the initial issuance of this BTP simultaneously with SRP Section 8.1, Revision 4 in February 2012.

8-8-8 Initial - February 2012

v t e Letter Sequence Acceptance Review
TAC:ME8251, (Open)
Initiation Acceptance Administration Questions Answers Results Approval... Other:
MONTHYEAR2012-04-13 [Table View]

ML12107A153

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========== original message =========

Subject:

Subject:

1.0 DESCRIPTION

2.0 PROPOSED CHANGE

3.0 BACKGROUND

4.0 TECHNICAL ANALYSIS

5.0 REGULATORY ANALYSIS

6.0 ENVIRONMENTAL CONSIDERATION

8.0 REFERENCES

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1.0 DESCRIPTION

2.0 PROPOSED CHANGE

3.0 BACKGROUND

4.0 TECHNICAL ANALYSIS

5.0 REGULATORY ANALYSIS

6.0 ENVIRONMENTAL CONSIDERATION

8.0 REFERENCES

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