Text

NRC Generic Letter 2006/02 60-Day Response
	ML060950462
Person / Time
Site:	Saint Lucie, Seabrook, Turkey Point, Duane Arnold
Issue date:	04/03/2006
From:	Stall J; Florida Power & Light Co, Florida Power & Light Energy Seabrook, Duane Arnold
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	GL-06-002, L-2006-073
	Download: ML060950462 (88)
	v • d • e

Florida Power & Light Company, 700 Universe Boulevard, P.O. Box 14000, Juno Beach, FL 334013-0420 April 3, 2006 FPI.

L-2006-073 10 CFR 50.54(f)

U.S. Nuclear Regulatory Commission Attn: Document Control Desk 11555 Rockville Pike Rockville, Maryland 20852 RE: Florida Power and Light Company St. Lucie Units 1 and 2 Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4 Docket Nos. 50-250 and 50-251 FPL Energy Seabrook, LLC Seabrook Station Docket No. 50-443 FPL Energy Duane Arnold, LLC Duane Arnold Energy Center Docket No. 50-331 NRC Generic Letter 2006-02 60-Day Response Florida Power and Light Company (FPL), the licensee for the St. Lucie Nuclear Plant, Units 1 and 2, and the Turkey Point Nuclear Plant, Units 3 and 4, and FPL Energy Seabrook, LLC (FPL Energy Seabrook), the licensee for Seabrook Station, and FPL Energy Duane Arnold, LLC (FPL Energy Duane Arnold), the licensee for Duane Arnold Energy Center (hereafter referred to collectively as FPL), hereby submit their 60-day response to NRC Generic Letter (GL) 2006-02, Grid Reliability and the Impact on Plant Risk and the Operability of Offsite Power.

Attachment I provides the response for St. Lucie Units I and 2. Attachment 2 provides the response for Turkey Point Units 3 and 4. Attachment 3 provides the response for Seab.-ook Station. Attachment 4 provides the response for Duane Arnold Energy Center.

Questions 2(a) through 2(g) and questions 5(c), 5(f), 6(a), and 7(a) in GL 2006-02 seek information about Transmission System Operator (TSO) analyses, procedures, and activities concerning grid reliability about which FPL, FPL Energy Seabrook and FPL Energy Duane Arnold, has either little or no first-hand knowledge and must, therefore, rely on the TSO to provide appropriate response information. Accordingly, in providing information responsive to these questions, where TSO information is provided, FPL makes no representation as to the accuracy or completeness of their response. Although there is no reason to doubt the accuracy of information provided by the TSO, FPL, FPL Energy Seabrook and FPL Energy Duane Arnold have no authority over the TSO regarding such information.

Although the following information is not directly requested in the Generic Letter, FPL Energy Seabrcok believes that it is germane to the overall issue of grid reliability. The New England ISO has directed Seabrook Station to back down in power to less than 1200 MWe on nineteen occasions in 2006. The directions to commence the downpower come with very short notice, an FPL GrDup company

St. LuciE Units 1and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-073, Page 2 e.g., on the order of 30 minutes, and are not of a long duration, e.g., two to three hours. The downpowers are reported to be required to support grid reliability. It is FPL Energy Seabrook's understanding that the majority of the downpower requirements are related to transmission issues in the New York ISO. FPL Energy Seabrook believes that it is not in the best interest of grid stability for the region for both the New England and New York ISOs to be frequently requiring a large plant such as Seabrook Station to quickly maneuver and decrease or increase power. FPL Energy Seabrook has pursued, and will continue to pursue, the resolution of this issue with the New England and New York ISOs and with the Federal Energy Regulatory Commission in the overall interests of grid stability and grid reliability. FPL Energy Seabrook believes that it is prudent for the NRC to have this information to more effectively evaluate the entire gid reliability issue.

This letter makes the following commitment, as described in Attachment 4, in response to Items 3(a), 3(e), and Item 9:

FPL Energy Duane Arnold will implement a change in operating procedure such that the TS LCO for inoperable offsite circuits will be entered following notification by the TSO that a trip of the DAEC would result in switchyard under-voltage conditions.

If there are any questions regarding this letter, please contact Rajiv S. Kundalkar at (561) 694-4848.

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

Executed on the 3 r day of 0026 1 2006 Sincerely yours, J.A. Stall Senior Vice President Nuclear and Chief Nuclear Officer Attachments: (4) cc: Regional Administrator, Region I Regional Administrator, Region II Regional Administrator, Region IlIl LISNRC Project Manager, St. Lucie and Turkey Point LISNRC Project Manager, Seabrook Station LISNRC Project Manager, Duane Arnold Energy Center

ATTACHMENT 1 St. Lucie Units I and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Amold Energy Center, Docket No. 50-331 L-2006-07"., Attachment 1, Page 1 of 18 St. Lucie Units I & 2 Response to Generic Letter 2006-02

1. Use of protocols between the NPP licensee and the TSO, ISO, or RC/RA to assist the NPP licensee in monitoring grid conditions to determine the operability of offsite power systems under plant Technical Specifications.

(a) Do you have a formal Yes, St. Lucie has a formal interface agreement with the Florida Power and agreement or protocol with Light Company (FPL) Transmission System Operator (TSO). The your TSO? agreement, Power Systems And St Lucie Plant Transmission Switch-lard Interface Agreement, is included in St. Lucie Plant Procedure ADM-16.01, PSL Switchyard Access/ Work Control, as Attachment 1.

Compliance with GDC 17, as documented in St. Lucie Units 1 & 2 licensing basis and plant TS is not predicated on such an agreement.

Note that the TSO is comprised of FPL's Power Supply and Transmission &

Substation Area Operations departments.

(b) Describe any grid Per Procedure ADM-1 6.01, Attachment 2, the TSO notifies St. Lucie if a conditions that would condition exists or is forecasted to exist (i.e. due to the contingency analysis trigger a notification from program) that could result in switchyard low or high voltage limits to be the TSO to the NPP exceeded. The time for notification is within 15 minutes of a condition or licensee and if there is a forecast of a possible condition. The notification includes information on the time period required for the nature of the problem, remedial actions being taken, and expected time of notification restoration to normal voltage limits. The TSO also notifies St. Lucie if the contingency analysis program is unavailable for a period longer than 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for reasons other than scheduled maintenance.

The TSO immediately communicates the following information to St. Lucie in accordance with of Procedure ADM-16.01, Attachment 2:

Any clearance work on the transmission grid impacting the reliability or serviceability of power to the nuclear plants.

Any unplanned transmission outage impacting the reliability of the nuclear plants.

Any action which threatens or could potentially lead to degradation of grid reliability or stability.

Notification of weather related threats, such as hurricanes, tornados, or severe weather activity that could jeopardize the plant or switchyard.

Notification of terrorist or other threats to the electrical facilities that could potentially impact service to the switchyard or jeopardize the stability or reliability of the bulk transmission network.

Responses to notification of a transmission system problem are outlined in St. Lucie Plant Procedures 1-ONP-53.01and 2-ONP-53.01, Main Generator.

(c) Describe any grid St. Lucie plant operators will contact the TSO under the following conditions that would conditions:

cause the NPP licensee to

If switchyard voltage is outside of the normal operating range contact the TSO.

If there are abnormal switchyard voltage fluctuations or main Describe the procedures generator MW/MVAR oscillations.

associated with such a

Loss of one of the three transmission lines between the St. Lucie communication. If you do switchyard and Midway substation.

not have procedures, describe how you assess grid conditions that may Procedures ADM-16.01 and 1(2)-ONP-53.01 are associated with these cause the NPP licensee to communications.

contact the TSO.

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Annold Energy Center, Docket No. 50-331 L-2006-072;, Attachment 1, Page 2 of 18 St. Lucie Units I & 2 Response to Generic Letter 2006-02

1. (continued)

(d) Describe how NPP St. Lucie Licensed Operators are trained in both the classroom and operators are trained and simulator on INPO SOER 99-01, Loss of Grid. The classroom and tested on the use of the simulator takes into account aspects of notification of off-site personnel, procedures or assessing emergency plan implementing procedures, as well as dealing with loss of grid conditions in question power to station equipment. This is performed on a recurring (2 year) cycle, 1(c). with the most recent performance during segment 4 of 2005. Additionally, simulator practice and evaluation scenarios performed more frequency challenge the operators in severe weather conditions, resulting in either a partial loss of power or complete LOOP conditions.

(e) If you do not have a formal St. Lucie has a formal agreement with the TSO. Therefore, this question is agreament or protocol with not applicable.

your TSO, describe why you believe you continue to comply with the provisions of GDC 17 as stated above, or describe what actions you intend to take to assure compliance with GDC 17.

+

(f) If you have an existing The St. Lucie interface agreement with the TSO requires prompt notification formal interconnection of actual or predicted conditions (i.e. contingency analysis program) that agreement or protocol that could cause a degraded voltage condition below the minimum allowable ensures adequate value. There is no low voltage setpoint for the switchyard specified in the communication and TS. The minimum allowable switchyard voltage (actual, post-trip or coordination between the transient) is the value assumed for calculating the plant degraded vo tage NPP licensee and the setpoints which are specified in the TS. Maintaining the switchyard voltage TSO, describe whether above the minimum allowable value ensures that safety-related equipment this agreement or protocol has sufficient voltage to perform the required functions and that the requ res that you be degraded voltage relays will not actuate and transfer to the emergency promptly notified when the diesel generators in the event of a unit trip due to a design basis acc dent.

conditions of the surrounding grid could This notification requirement is described in Procedures ADM-16.01 and result in degraded voltage 1(2)-ONP-53.01.

(i.e., below TS nominal trip setpoint value requ rements; including NPP licensees using allowable value in its TSs) or LOOP after a trip of the reactor unit(s).

(g) Describe the low Both St. Lucie Units 1 & 2 have been analyzed for a minimum switchyard switchyard voltage voltage of 230 kV following a unit trip. Below this switchyard voltage, the conditions that would degraded voltage relays could actuate assuming worst-case accident initiate operation of plant loading conditions. Note that the low switchyard voltage condition (less degraded voltage than 230 kV) must persist for a time greater than the time delay settings protection. specified in the TS for the degraded voltage relays.

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Amrold Energy Center, Docket No. 50-331 L-2006-07"., Attachment 1, Page 3 of 18 St. Lucie Units 1 & 2 Response to Generic Letter 2006-02

2. Use of criteria and methodologies to assess whether the offsite power system will become inoperable as a result of a trip of your NPP.

(a) Does your NPP's TSO use Yes, as described in Procedure ADM-1 6.01, the TSO operates the grid any analysis tools, an using an on-line contingency analysis software program that continuously online analytical calculates the NPP switchyard voltage assuming various 'contingencies" transmission system occur, such as plant trips or transmission line or substation faults. When studies program, or other the St. Lucie switchyard voltage (actual or post-contingency) falls below the equivalent predictive minimum allowable value (230 kV), an alarm is initiated at the TSO control methods to determine the center to alert the TSO to take corrective action and notify St. Lucie within grid conditions that would 15 minutes.

make the NPP offsite power system inoperable In response to the Generic Letter, the TSO has provided the following during various information: "FPL's contingency analysis program evaluates the impact of contingencies? outages of all FPL transmission lines and transformers to identify any If available to you, please overload conditions or voltage problems. It also evaluates the loss of 700 provide a brief description MW class generating units and most 400 MW class generating units.

of the analysis tool that is Outages of 500 kV, 230 kV and selected lower voltage lines are looked at used by the TSO. for foreign systems; none of which tie directly to or support FPL nuclear switchyards."

(b) Does your NPP's TSO use Yes, as described in Procedure ADM-16.01, Attachment 2, the TSO uses an analysis tool as the the contingency analysis program as the basis for notifying St. Lucie of basis for notifying the NPP potential degraded conditions.

licensee when such a condition is identified? If not, how does the TSO determine if conditions on the Grid warrant NPP licensee notification?

(c) If your TSO uses an In response to the Generic Letter, the TSO has provided the following analysis tool, would the information: "The TSO contingency analysis program identifies conditions analysis tool identify a which would result in a switchyard voltage that could actuate the St. Lucie condition in which a trip of degraded voltage protection relays and initiate separation from offsite power the NPP would result in upon a St. Lucie unit trip."

switchyard voltages (immediate and/or long-term) falling below TS nominal trip setpoint value requ rements (including NPP licensees using allowable value in its TSs) and consequent actuation of plant degraded voltage protEction? If not, discuss how such a condition would be identified on the grid.

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook s;tation; Docket No. 50443 Duane Amold Energy Center, Docket No. 50-331 L-2006-07, Attachment 1, Page 4 of 18 St. Lucie Units I & 2 Response to Generic Letter 2006-02

2. (continued)

(d) If your TSO uses an In response to the Generic Letter, the TSO has provided the following analysis tool, how information: "The TSO contingency analysis program calculates the frequently does the expected post-trip St. Lucie switchyard voltage for the various contingencies analysis tool program approximately every 5 minutes."

update?

(e) Prov de details of analysis As specified in the interface agreement, Attachment 1 to Procedure ADM-tool-identified contingency 16.01, the TSO will notify St. Lucie if the contingency analysis (CA) program conditions that would determines that the postulated contingency event would result in switchyard trigger an NPP licensee voltage outside the allowable operating range as specified in the inte.face notification from the TSO. agreement. The low limit is 230 kV and high limit is 244 kV. If one a the unit's loads is being supplied from the startup transformer, the high limit is 241 kV. The TSO will also notify St. Lucie if the CA program determines there is potential or developing grid instabilities.

(f) If an interface agreement Yes, the agreement with the TSO, Attachment 1 to Procedure ADM-1 6.01, exists between the TSO requires St. Lucie to be notified when the contingency analysis program is and Ihe NPP licensee, unavailable for a period longer than four hours for reasons other thar does it require that the scheduled maintenance. St. Lucie would continue to rely on the TSO to NPP licensee be notified of notify them of any change in grid conditions which could affect the quality or pericds when the TSO is reliability of offsite power.

unable to determine if offsite power voltage and In response to the Generic Letter, the TSO has provided the following capacity could be information; "In the event that the FPL CA program is unavailable, the inadequate? responsibility to monitor the grid is turned over to a back-up Reliability If so, how does the NPP Coordinator which is Progress Energy for FPL. Progress Energy has a CA licensee determine that the program which would be used to monitor the Florida transmission system.

offsite power would remain Additionally, FPL system operator has available support studies that identify operable when such a critical operating limits, an on-line power flow program with which he can notification is received? model changing systems conditions, and access to support personnel to run off-line studies."

(g) After an unscheduled Yes, as part of the post trip review, St. Lucie Plant Procedure 00301 9, inadvertent trip of the NPP, Post Trip Review, requires that the actual post-trip voltage be compared are the resultant against the predicted post-trip voltage calculated by the contingency switchyard voltages analysis program. The actual voltage is to be verified as bounded by the verified by procedure to be predicted voltage.

bounded by the voltages predicted by the analysis tool?

(h) If an analysis tool is not This question is not applicable since TSO currently uses a contingency available to the NPP analysis program to monitor grid conditions.

licensee's TSO, do you know if there are any plans for the TSO to obtain one?

If so, when?

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook StaUon, Docket No. 50-443 Duane Amrold Energy Center, Docket No. 50-331 L-2006-072, Attachment 1, Page 5 of 18 St. Lucie Units 1 & 2 Response to Generic Letter 2006-02

2. (continued)

(i) If an analysis tool is not This question is not applicable since TSO currently uses a contingency available, does your TSO analysis program to monitor grid conditions.

perform periodic studies to verify that adequate offsite power capability, including adequate NPP post-trip switchyard voltages (imrrediate and/or long-term), will be available to the NPP licensee over the projected timeframe of the study?

(a) Are the key assumptions and parameters of these periodic studies translated into TSO guidance to ensure that the transmission system is operated within the bounds of the analyses?

(b) If the bounds of the analyses are exceeded, does this condition trigger the notification provisions discussed in question i above?

If your TSO does not use, Not applicable to St. Lucie. The TSO uses a real time contingency analysis or ycu do not have access program to monitor real time grid conditions. St. Lucie is notified by the to the results of an TSO if the contingency analysis program identifies grid conditions that could analysis tool, or your TSO compromise the quality or reliability of offsite power.

does not perform and make available to you St. Lucie is in compliance with GDC 17 and no compensatory actions are pericdic studies that required.

determine the adequacy of offsite power capability, please describe why you believe you comply with the provisions of GDC 17 as stated above, or describe what compensatory actions you intend to take to ensure that the offsite power system will be sufficiently reliable and remain operable with high probability following a trip of ycur NPP.

St. Lucie Units 1 and 2. Docket Nos. 50-335 and 50-389 Turkey Poinit Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-07S., Attachment 1, Page 6 of 18 St. Lucie Units 1 & 2 Response to Generic Letter 2006-02

3. Use of criteria and methodologies to assess whether the NPP's offsite power system and safety-re'ated components will remain operable when switchyard voltages are inadequate.

(a) If the TSO notifies the NPP Yes, if the TSO notifies St. Lucie that a postulated contingency condition operator that: would result in a switchyard voltage below minimum allowed value (230 kV),

a trip of the NPP, or both offsite AC power circuits are declared inoperable and the applicable TS

the loss of the most action is entered, as specified in Procedures 1(2)-ONP-53.01.

critical transmission line or

the largest supply to the grid would result in switchyard voltages (immediate and/or long-term) below TS nominal trip setpoint value requirements (including NPP licensees using allowable value in its TSs) and would actuate plani degraded voltage protection, is the NPP offsite power system declared inoperable under the plant TSs? If not, why not?

(b) If onsite safety-related Double sequencing (LOCA with delayed LOOP) is not part of the licensing equipment (e.g., bases for St. Lucie. The UFSAR accident analyses assume a concurrent emergency diesel LOOP and LOCA. The ability for onsite safety-related equipment to generators or safety- respond to a double sequencing event is not a requirement for operability.

related motors) is lost when subjected to a Note that St. Lucie emergency diesel generators and safety related motors double sequencing (LOCA are not expected to be lost during double sequencing event based on with delayed LOOP event) review of the load sequencer and breaker logic.

as a result of the anticipated system performance and is incapable of performing its safely functions as a result of responding to an emergency actuation signal during this condition, is the equipment considered inoperable? If not, why not?

St. Lucie Units I and 2, Docket Nos. 50-335 and 50-389 Turkey Po! it Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook ltation, Docket No. 50443 Duane Amrold Energy Center, Docket No. 50-331 L-2006-07.;, Attachment 1, Page 7 of 18 St. Lucie Units I & 2 Response to Generic Letter 2006-02

3. (continued)

(c) Describe your evaluation of Not applicable. Since a double sequencing event is not part of St. Lucie onsite safety-related licensing bases, an evaluation has not been performed for St. Lucie to equipment to determine determine the overall impact on safety related equipment response for such whether it will operate as an event.

designed during the condition described in Note that electrical design considerations for a double sequencing event question 3(b). were evaluated for St. Lucie Unit 2 in response to the third request fcr additional information (RAI) regarding a proposed license amendment to allow operation of St. Lucie Unit 2 with a reduced reactor coolant system (RCS) flow, corresponding to a steam generator tube plugging level of 30%

per steam generator. The response of electrical equipment was found to be acceptable. The RAI response is provided in FPL letter (L-2005-0071 to the NRC dated January 7, 2005.

(d) If the NPP licensee is No, the TS action statement would only be entered if the grid conditions notified by the TSO of results in postulated contingency switchyard voltages below the minimum other grid conditions that allowed value. When notified of the specifics of other degraded grid may impair the capability conditions, St. Lucie would perform appropriate operational decision making or availability of offsite to determine if offsite power should be considered inoperable and the power, are any plant TS applicable TS action statement entered.

action statements entered? If so, please identify them.

(e) If you believe your plant The offsite AC power circuits are declared inoperable and the applicable TS TSs do not require you to action is entered when postulated contingency conditions could result in a declare your offsite power switchyard voltage below minimum allowed value (230 kV), assumed for the system or safety-related degraded voltage actuation setpoint.

equipment inoperable in any of these St. Lucie is in compliance with GDC 17 and no compensatory actions are circumstances, explain required.

why you believe you comply with the provisions of GDC 17 and your plant TSs, or describe what compensatory actions you intend to take to ensure that the offsite power system and safety-related components will remain operable when switchyard voltages are inadequate.

(f) Describe if and how NPP Not applicable. No compensatory actions are required.

operators are trained and tested on the compensatory actions mentioned in your answers to questions 3(a) through (e).

St. Lucie Units I and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-07., Attachment 1, Page 8 of 18 St. Lucie Units 1 & 2 Response to Generic Letter 2006-02

4. Use of criteria and methodologies to assess whether the offsite power system will remain operable following a trip of your NPP.

(a) Do the NPP operators Not applicable. There is no voltage regulating equipment included in the have any guidance or determinations of offsite AC circuit operability required by TS. None of the procedures in plant TS analyses prepared for the onsite AC power distribution systems at St. Lucie bases sections, the final take credit for automatic tap changers, capacitor banks, or other reactive safety analysis report, or power compensating equipment.

plant procedures regarding situations in which the The main generator voltage regulator is normally operated in 'ON' position condition of plant- (automatic) in accordance with the Florida Power & Light Company Facility controlled or -monitored Connection Requirements, dated July 30, 2001 and St. Lucie Plant equipment (e.g., voltage Procedures 1(2)-GOP-201, Reactor Plant Startup-Mode 2 to Mode 1. The regulators, auto tap TSO monitors the status of the voltage regulator and evaluates the impact changing transformers, of grid conditions when any of the units' voltage regulators is placed in capacitors, static VAR manual.

compensators, main generator voltage regulators) can adversely affect the operability of the NPP offsite power system?

If so, describe how the operators are trained and tested on the guidance and procedures.

(b) If your TS bases sections, St. Lucie AC power distribution system operability takes no credit for the final safety analysis automatic tap changers, capacitor banks or reactive power compensation report, and plant equipment. The main generator voltage regulator of each unit is operated in procedures do not provide automatic. The TSO monitors the status of the transmission grid anc guidance regarding models possible contingencies that could affect the switchyard voltage.

situations in which the Failure of the main generator voltage regulator is included and enveloped condition of plant- by the possible contingencies. If a contingency is discovered that co ild controlled or -monitored lower the switchyard voltage below 230.0 kV, St. Lucie is notified within 15 equipment can adversely minutes and TS actions will be addressed as required. Therefore, St. Lucie affect the operability of the is in compliance with GDC 17 and no compensatory actions are required.

NPP offsite power system, explain why you believe you comply with the provisions of GDC 17 and the plant TSs, or describe what actions you intend to take to provide such guidance or procedures.

St. Lucie Units I and 2, Docket Nos. 50-335 and 50-389 Turkey Poinit Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Amrold Energy Center, Docket No. 50-331 L-2006-07S, Attachment 1, Page 9 of 18 St. Lucie Units I & 2 Response to Generic Letter 2006-02

5. Performance of grid reliability evaluations as part of the maintenance risk assessments required by 10 CFR 50.65(a)(4).

(a) Is a quantitative or Yes, St. Lucie procedures contain requirements for coordination of plant qualitative grid reliability systems and switchyard maintenance and testing to minimize the risk of a evaluation performed at loss of offsite or onsite power:

your NPP as part of the maintenance risk St. Lucie Plant Procedure ADM-1 0.03, Work Week Management, recuires assessment required by 14 10 that risk assessments be performed for safety related or risk significant CFR 50.65(a)(4) before components or systems including the emergency diesel generators, startup performing grid-risk- transformers, or station blackout cross-tie breakers, for pre-planned and sensitive maintenance emergent activities.

activities? This includes surveillances, post-maintenance testing, and In addition, St. Lucie Plant Procedure ADM-1 7.16, Implementation of the preventive and corrective Configuration Risk Assessment Program, requires consideration of potential maintenance that could grid degradation/instability as part of the Configuration Risk Management increase the probability of Program.

a plant trip or LOOP or impact LOOP or SBO coping capability, for example, before taking a risk-significant piece of equipment (such as an EDG, a battery, a steam-driven pump, an alternate AC power source) out-cf-service?

(b) Is grid status monitored by Yes, grid status is continuously monitored by the TSO, including during the some means for the performance of grid-risk-sensitive maintenance. As required by the ';t.

duration of the grid-risk- Lucie and TSO interface agreement, the TSO will immediately notify St.

sensitive maintenance to Lucie of potential or developing grid instabilities. Procedure ADM-1 7.16 confirm the continued requires that the current risk assessment be reassessed if there is any valid ty of the risk potential increased in grid instability reported by the TSO or as a result of assessment and is risk severe weather conditions.

reassessed when warranted? If not, how is the risk assessed during grid-risk-sensitive maintenance?

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Amold Energy Center, Docket No. 50-331 L-2006-07S, Attachment 1. Page 10 of 18 St. Lucie Units 1 & 2 Response to Generic Letter 2006-02

5. (continued)

(c) Is there a significant Yes, seasonal loads have an impact on grid stress and also influence the variation in the stress on scheduling for plant maintenance outages.

the grid in the vicinity of your NPP site caused by In general, peak load conditions usually occur during the summer months in seasonal loads south Florida. However, plant availability is also maintained at a maximum or maintenance activities during the summer months to ensure grid and service reliability. Grid associated with critical conditions can be stressed during the summer months if unplanned plant or transmission elements? transmission line outages occur. Similar grid stress conditions can a'so occur during other seasons if unexpected cold or hot periods occur when there are multiple planned plant outages.

Is there a seasonal Yes, for St. Lucie, the potential of a LOOP is higher in the late summer and variation (or the potential early fall months due to the increased probability of severe weather (e.g.

for a seasonal variation) in hurricanes, tornadoes).

the LOOP frequency in the local transmission region?

If the answer to either Peak system load conditions resulting in potential grid stress would have a question is yes, discuss greater potential for occurring during the summer months.

the time of year when the variations occur and their magnitude.

(d) Are known time-related No. There is no specific change made to the On Line Risk Monitor during variations in the probability summer months. However, if severe weather conditions are expected and of a lOOP at your plant one of the following conditions is planned, the Core Damage Frequency site considered in the grid- (CDF) on the On Line Risk Monitor will be forced to at least an ORANGE risk-.sensitive maintenance condition:

evaluation? If not, what is

An EDG on either unit is out of service (OOS), or your basis for not

The blackout crosstie is OOS considering them?

A specific evaluation must then be performed to determine the acceptability of the proposed maintenance/surveillance with the severe weather condition. With severe weather conditions expected, St. Lucie Plant Procedure 0005753, Severe Weather Preparations,specifies that an EDG or blackout crosstie would only be removed from service for corrective maintenance (i.e. maintenance required to ensure or restore operability). If an EDG or blackout crosstie is unavailable, they would be restored to service as soon as possible.

St. Lucie Uiits 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-072. Attachment 1, Page 11 of 18 St. Lucie Units I & 2 Response to Generic Letter 2006-02

5. (continued)

(e) Do you have contacts with Yes, Work Control Procedures and Guidelines ADM-10.01, Critical the TSO to determine Maintenance Management, ADM-1 0.03, Work Week Management, and current and anticipated WCG-016, Online Work Management, requires the Work Week Manager to grid conditions as part of contact the TSO Load Dispatcher prior to performing planned grid risk the grid reliability significant maintenance activities. In the event of an emergent or evaluation performed anticipated change in the maintenance activity or grid conditions, an initial before conducting grid- communication is conducted between Load Dispatch and the Shift Manager risk-sensitive maintenance or Unit Supervisor followed by a communication to the Work Control activities. Manager.

(f) Describe any formal The formal interface agreement (Procedure ADM-1 6.01, Attachment 1) agreement or protocol that between St. Lucie and TSO requires the TSO to provide early warning to St.

you have with your TSO to Lucie of potential or developing grid instabilities.

assure that you are promptly alerted to a The agreement also requires TSO emergent activities, as well as the worsening grid condition detailed conduct of planned activities, to be coordinated on a real time basis that may emerge during a with St. Lucie. These activities include, but are not limited to:

maintenance activity.

TSO removing from service any transmission line terminating in Ihe switchyard;

TSO breaker switching which can affect power supply (e.g. switching of line identified in item (a) above;

TSO maintenance activities that can affect power supply.

(g) Do y:u contact your TSO No, St. Lucie would only contact the TSO if plant conditions change that periodically for the duration could impact offsite power or increase the probability of a unit trip. Tine of thet grid-risk-sensitive plant relies on the TSO to monitor grid conditions and contact St. Lucie of maintenance activities? potential grid instabilities.

(h) If you have a formal Training for St. Lucie operators is discussed in the response to Question agreement or protocol with 1(d). Work Control (maintenance) personnel are trained in accordance with your TSO, describe how WCG-01 7, Work Control Departmental Training Plan, which requires NPP operators and training in St. Lucie plant procedures (e.g. ADM-16.01, ADM-10.03, WVCG-maintenance personnel 016, and ADM-1 0.01) governing maintenance activities and include the are trained and tested on requirements for coordination and communications with FPL Power this formal agreement or Supply/System Dispatcher (TSO).

protocol.

(i) If your grid reliability Not applicable. St. Lucie does have a formal agreement for commurication evaluation, performed as with the TSO to facilitate risk assessments required by 10 CFR 50.65(a)(4).

part of the maintenance risk assessment required by 10) CFR 50.65(a)(4),

does not consider or rely on some arrangement for communication with the TSO, explain why you believe you comply with 10 CFR 50.65(a)(4).

St. Lucie Units I and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station. Docket No. 50-443 Duane Amold Energy Center, Docket No. 50-331 L-2006-072, Attachment 1, Page 12 of 18 St. Lucie Units 1 & 2 Response to Generic Letter 2006-02

5. (continued)

() If risk is not assessed As described in Procedure ADM-1 7.16, risk is assessed (when warranted)

(when warranted) based when plant conditions have changed; upon notification from the TSO of on continuing potential grid instabilities; or the onset of severe weather conditions. As communication with the previously discussed in response to Item 1(b), the TSO uses a real timne TSO throughout the contingency analysis program to continuously monitor grid conditions.. St.

dura:ion of grid-risk- Lucie's formal interface agreement with the TSO requires that St. Lucie be sensitive maintenance contacted if there is change in switchyard status or a potential for grid activities, explain why you instability. Therefore, St. Lucie has adequately implemented the provisions believe you have of the endorsed industry guidance associated with the maintenance rule.

effectively implemented the relevant provisions of the endorsed industry guidance associated with the maintenance rule.

(k) With respect to questions No additional actions are required.

5(i) and 50), you may, as an alternative, describe what actions you intend to take to ensure that the increase in risk that may result from proposed grid-risk-sensitive activities is assessed before and during grid-risk-sensitive maintenance activities, respectively.

St. Lucie Ulrts I and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50443 Duane Amold Energy Center, Docket No. 50-331 L-2006-07:, Attachment 1, Page 13 of 18 St. Lucie Units I & 2 Response to Generic Letter 2006-02

6. Use of risk assessment results, including the results of grid reliability evaluations, in managing maintenance risk, as required by 10 CFR 50.65(a)(4).

(a) Does the TSO coordinate Yes, the St. Lucie interface agreement with the TSO, which is included in transmission system Procedure ADM-1 6.01 requires the following coordination activities:

maintenance activities that

The TSO will coordinate planned outages and planned load reductions can have an impact on the with St. Lucie. TSO and St. Lucie maintenance and testing activities NPP operation with the should be coordinated between the parties to prevent inadvertent NPP operator? reductions in nuclear plant defense-in-depth.

St. Lucie will inform the Power Supply system dispatcher of planned outages and planned load reductions.

TSO will coordinate with St. Lucie the activities that may affect the off-site power supply to the nuclear plants. As a minimum, the TSO system dispatcher and/or the TSO maintenance crew will inform St.

Lucie while planning these activities.

Emergent activities, as well as the detailed conduct of planned activities, will be coordinated on a real time basis with St. Lucie. These activities include, but are not limited to: removing from service any transmission line terminating in the switchyard; TSO breaker switching which can affect power supply (e.g. switching of line identified above);

TSO maintenance activities that can affect power supply.

(b) Do you coordinate NPP Yes, work performed at the St. Lucie nuclear plant is controlled through maintenance activities that Procedure ADM-10.03. This procedure references Work Control Guideline can have an impact on the WCG-016 for details for performance of on-line maintenance work transmission system with scheduling. Appendix J of WCG-01 6 details requirements for the TSO? communication between the plant Work Control daily organization and the System Load Dispatcher. The scheduling of activities which will result in a down power and/or the possibility of a removal of a unit from service (Load Threat) shall be communicated to the Load Dispatcher in a timely manner to ensure a stable, cost effective power supply to our customers. The primary notification to the System Dispatcher of a scheduled change or emergent change of unit megawatt output shall be the on-shift Unit Supervisor or Shift Manager, immediately prior to the change if possible. In the event of an emergent change, notification will occur as soon as possible. Any evolution that meets the criteria of a planned down power or load threat is communicated to the System Dispatcher at least 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months prior to the evolution and communications maintained if the System Dispatcher is uncertain of changing conditions.

(c) Do you consider and Yes, Procedure ADM-17.16 requires load threatening surveillance or implement, if warranted, maintenance activities, including EDG or SBO tie breaker maintenance, be the rescheduling of grid- deferred if the potential for increased grid instability exists or hurricane risk-sensitive maintenance warning has been issued. If emergent conditions exist that increase the activities (activities that potential for grid instability when the EDG or SBO tie breaker are could (i) increase the unavailable, the EDG or SBO tie breaker would be restored as soon as likelihood of a plant trip, (ii) possible.

increase LOOP probability, or (iii) reduce LOOP or Procedures 1(2)-ONP-53.01 also require load threatening activities be SBO coping capability) terminated if in progress, or deferred if planned, for degraded switchyard under existing, imminent, voltage conditions.

or worsening degraded grid reliability conditions?

St. Lucie U1its I and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-072. Attachment 1, Page 14 of 18 St. Lucie Units 1 & 2 Response to Generic Letter 2006-02

6. (continued)

(d) If there is an overriding Yes, if grid-risk-sensitive maintenance was required or in progress with need to perform grid-risk- degraded grid conditions, the Core Damage Frequency (CDF) assoc ated sensitive maintenance with the On Line Risk Monitor would be forced to at least an ORANGE activ ties under existing or condition. As described in Procedure ADM-17.16, alternate equipment imminent conditions of protection measures and compensatory actions would be considered. In degraded grid reliability, or general, the primary action would be to restore the System, Structure, or continue grid-risk-sensitive Component (SSC) that is out of service to operable status as soon as; maintenance when grid possible. Other compensatory actions taken, if any, would be dependent on conditions worsen, do you the nature of the grid condition and what SSC was out of service.

implement appropriate risk management actions? If so, describe the actions that you would take.

(These actions could include alternate equipment protection and compensatory measures to limit or minimize risk.)

(e) Describe the actions The Maintenance Rule risk assessment process and actions for the associated with questions coordination of maintenance activities between St. Lucie and the TSO are 6(a) through 6(d) above governed by the following procedures:

that would be taken, state ADM-16.01:

whether each action is . Communications between the TSO and St. Lucie plant regarding governed by documented switchyard or grid activities that could affect the availability of Dffsite procedures and identify power to St. Lucie.

the procedures, and explain why these actions . Interface agreement between Power Systems and St. Lucie.

are effective and will be ADM-1 0.03 & Work Control Guideline WCG-016:

consistently accomplished. . Notification and coordination with the System Dispatcher (TSO) for plant maintenance activities that are load-threatening or affect grid risk sensitive equipment.

Coordination of planned outages and load reductions.

ADM-17.16:

Risk assessment of load threatening or grid risk sensitive equipment.

Consideration for deferral of risk significant maintenance if potential for grid instability or adverse weather conditions.

1(2)-ONP-53.01:

Coordination of degraded switchyard voltage conditions.

Deferral of risk significant maintenance if potential for grid instability.

These actions have proved to be effective during recent grid-risk-sensitive activities associated with the hurricanes of 2004 and 2005 that affected the FPL transmission grid.

St. Lucie Ulits 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Amold Energy Center, Docket No. 50-331 L-2006-072, Attachment 1, Page 15 of 18 St. Lucie Units I & 2 Response to Generic Letter 2006-02

6. (continued)

(f) Describe how NPP Work Control personnel training is defined in Guideline WCG-017.

operators and Required reading on all procedures applicable to Work Control Group and maintenance personnel on the job training provides instruction on the functions and responsibilities are trained and tested to of the WCG personnel. The effectiveness of the training is determine i assure they can through periodic self-assessments and supervisory monitoring of job accomplish the actions performance.

described in your answers to question 6(e). Training for St. Lucie operators is discussed in the response to Question 1(d).

(g) If there is no effective There is effective coordination between the NPP operator and the TSO coordination between the regarding transmission system maintenance or NPP maintenance activities.

NPP operator and the TSO Such coordination is in accordance with established protocols. Therefore, regarding transmission St. Lucie is compliance with 10 CFR 50.65(a)(4).

system maintenance or NPP maintenance activities, please explain why you believe you comply with the provisions of 10 CFR 50.65(a)(4).

(h) If you do not consider and As discussed in questions 6(a) through 6(d), the St. Lucie plant effectively effectively implement implements appropriate risk management actions.

appropriate risk management actions during the conditions described above, explain why you believe you effectively addressed the relevant provisions of the associated NRC-endorsed industry guidance.

(i) You may, as an alternative No alternative actions are required.

to questions 6(g) and 6(h) describe what actions you intend to take to ensure that the increase in risk that may result from grid-risk-sensitive maintenance activ ties is managed in accordance with 10 CFR 50.6!;(a)(4).

St. Lucie UWits 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-072, Attachment 1, Page 16 of 18 St. Lucie Units I & 2 Response to Generic Letter 2006-02

7. Procedures for identifying local power sources (this includes items such as nearby or onsite gas turbine generators, portable generators, hydro generators, and black-start fossil power plants) that could be made available to resupply your plant following a LOOP event.

Note: Section 2, "Offsite Power," of RG 1.155 (ADAMS Accession No. ML003740034) states:

Procedures should include the actions necessary to restore offsite power and use nearby power sources when offsite power is unavailable. As a minimum, the following potential causes for loss of offsite power should be considered:

- Grid under-voltage and collapse

- Weather-induced power loss

- Preferred power distribution system faults that could result in the loss of normal power to essential switchgear buses (a) Briefly describe any St. Lucie does not have an agreement with the TSO to provide a spe.-ific agreement made with the local power source in the event of LOOP.

TSO to identify local power sources that could be St. Lucie has an agreement in place with the TSO to restore power to St.

made available to re- Lucie on a priority basis using any and all transmission lines and power supply power to your plant sources available and provide an estimate of when offsite power will be following a LOOP event. restored to within normal limits.

(b) Are your NPP operators Not applicable. St. Lucie does not rely on specific local power sources to trained and tested on restore power following a LOOP.

identifying and using local power sources to resupply your plant following a LOOP event? If so, describe how.

(c) If you have not established Not applicable. St. Lucie does not take credit or rely on any local power an agreement with your sources to restore power following a LOOP or SBO event. St. Lucie is in plant's TSO to identify compliance with 10 CFR 50.63.

local power sources that could be made available to In response to the Generic Letter, the TSO has provided the following resupply power to your information; "The TSO will utilize the best sources available for speci'c plant following a LOOP events to restore offsite power and to determine the specific power sources event, explain why you and paths, since there is no way to predict the extent and characteristics of believe you comply with a specific blackout. The TSO has many options available to restore offsite the provisions of 10 CFR power and would not be limited to any specific local power sources."

50.63, or describe what actions you intend to take to establish compliance.

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50443 Duane Amold Energy Center, Docket No. 50-331 L-2006-073, Attachment 1, Page 17 of 18 St. Lucie Units 1 & 2 Response to Generic Letter 2006-02

8. Maintaining SBO coping capabilities in accordance with 10 CFR 50.63.

(a) Has your NPP experienced There have been no LOOP events caused by grid failure since St. Lucie's a total LOOP caused by original coping duration was determined under 10 CFR 50.63.

grid failure since the plant's coping duration was initially determined under 10 CFR 50.63?

(b) If so, have you reevaluated Not applicable.

the NPP using the guidance in Table 4 of RG 1.155 to determine if your NPP should be assigned to the P3 offsite power design characteristic group?

(c) If so, what were the results Not applicable.

of this reevaluation, and did the initially determined coping duration for the NPP need to be adjusted?

(d) If your NPP has Not applicable.

experienced a total LOOP caused by grid failure since the plant's coping duration was initially determined under 10 CFR 50.63 and has not been reevaluated using the guidance in Table 4 of RG 1.155, explain why you believe you comply with the provisions of 10 CFR 50.6:3 as stated above, or describe what actions you intend to take to ensure that Ihe NPP maintains its SBO coping capabilities in accordance with 10 CFR 50.6:3.

St. Lucie UWits 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-073, Attachment 1, Page 18 of 18 St. Lucie Units I & 2 Response to Generic Letter 2006-02

9. Actions to ensure compliance If you determine that any St. Lucie is in compliance with the referenced NRC requirements. No action action is warranted to bring is required.

your NPF' into compliance with NRC regulatory requirements, including TSs, GDC 17,10 CFR 50.65(a)(4), 10 CFR 50.63, 101 CFR 55.59 or 10 CFR 50.120, describe the schedule for implementing it.

ATTACHMENT 2 St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-073, Attachment 2, Page 1 of 19 Turkey Point Response to Generic Letter 2006-02

1. Use of protocols between the NPP licensee and the TSO, ISO, or RC/RA to assist the NPP licensee in monitoring grid conditions to determine the operability of offsite power systems under plant Technical Specifications.

(a) Do you have a formal Yes, Turkey Point has a formal interface agreement with the Florida Power agreement or protocol with and Light Company (FPL) Transmission System Operator (TSO). The your TSO? agreement, Power Systems, Turkey Point Nuclear, and Turkey Point Fossil Plants Transmission Switchyard Interface Agreement, is included in Turkey Point Nuclear Plant Procedure O-ADM-216, PTN and PTF Shared System Work Control and Switchyard Access, as Attachment 4.

Compliance with GDC 17, as documented in Turkey Point Units 3 & 4 licensing basis and plant Technical Specifications (TS) is not predicated on such an agreement.

Note that the TSO is comprised of FPL Power Supply and Transmission &

Substation Operations departments.

(b) Describe any grid The following notification are described in the Turkey Point Nuclear Plant conditions that would Basis Document O-BD-ONOP-004.6, Degraded Switchyard Voltage, for trigger a notification from Turkey Point Nuclear Plant Procedure O-ONOP-004.6, Degraded the TSO to the NPP Switchyard Voltage:

licensee and if there is a time period required for the The TSO notifies the Turkey Point control room if conditions exist or are notification. forecasted to exist (i.e., contingency analysis (CA) program) that result in exceeding switchyard low or high voltage limits as established in the interface agreement. The time for notification is within 15 minutes.

The TSO also notifies the Turkey Point control room if the CA program is unavailable for a period longer than 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for reasons other than scheduled maintenance. Turkey Point would continue to rely on the rso to notify them of any change in grid conditions that could affect the quality or reliability of offsite power.

In addition, the TSO immediately communicates the following information to Turkey Point:

1. Any clearance work on the transmission grid impacting the reliability or serviceability of power to the nuclear plants.

2. Any unplanned transmission outage impacting the reliability of power to the nuclear plants.

3. Any action which threatens or could potentially lead to degradation of grid reliability or stability.

4. Notification of weather related threats, such as hurricanes, tornados, or severe weather activity that could jeopardize the plant or switchyard.

5. Notification of terrorist or other threats to the electrical facilities that could potentially impact service to the switchyard or jeopardize the stability or reliability of the bulk transmission network.

St. Lucie Units I and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-073, Attachment 2, Page 2 of 19 Turkey Point Response to Generic Letter 2006-02

1. (conminued)

(c) Describe any grid The Turkey Point control room will contact the TSO if switchyard voltage is concitions that would outside of the normal operating range in accordance with Procedure 0-cause the NPP licensee to ONOP-004.6. Main generator MW/MVAR oscillations will be contact the TSO. communicated to the TSO in accordance with Turkey Point Nuclear Plant Describe the procedures Procedures 3/4-ONOP-090, Abnormal Generator MW/MVAR Oscillai'lon.

associated with such a communication. If you do not I-ave procedures, describe how you assess grid conditions that may cause the NPP licensee to contact the TSO.

(d) Describe how NPP Turkey Point control room operators are trained annually on Procedures 0-operators are trained and ONOP-004.6 and 3/4-ONOP-090 during licensed operator continuing tested on the use of the training (LOCT). Training on Institute of Nuclear Power Operations procedures or assessing Significant Operating Experience Report 99-1, Loss of Grid, is condu.-ted grid conditions in question every three years. Simulator practice and evaluation scenarios challenge 1(c). operators in loss of offsite power (LOOP) conditions.

(e) If you do not have a formal Not applicable. Turkey Point has a formal agreement with the TSO.

agreement or protocol with your TSO, describe why you believe you continue to comply with the provisions of GDC 17 as stated above, or describe what actions you intend to take to assure compliance with GDC 17.

(f) If you have an existing The Turkey Point interface agreement with the TSO requires prompt formal interconnection (within 15 minutes) notification of actual or predicted conditions (i.e., CA agreement or protocol that program) that could cause a voltage condition below the minimum ensures adequate allowable value or greater than the maximum allowable value. The communication and minimum allowable switchyard voltage (actual or post-contingency) is the coordination between the value assumed for calculating the plant undervoltage/degraded voltage NPP licensee and the setpoints that are specified in the TS. Maintaining the switchyard voltage TSO, describe whether above the minimum allowable value ensures that the this agreement or protocol undervoltage/degraded voltage relays will not actuate in the event of a unit requires that you be trip concurrent with a design basis accident. There are no safety-related promptly notified when the requirements for voltage being above the maximum allowable value.

conditions of the surrounding grid could This notification requirement is described in Procedure 0-ONOP-004.6 and result in degraded voltage the associated basis document, 0-BD-ONOP-004.6.

(i.e., below TS nominal trip setpoint value requirements; including NPP licensees using allowable value in its TSs) or LOOP after a trip of the reactor unit(s).

St. Lucie Units I and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane AmDld Energy Center, Docket No. 50-331 L-2006-07:1, Attachment 2, Page 3 of 19 Turkey Point Response to Generic Letter 2006-02

1. (continued)

(g) Describe the low If switchyard voltage drops below 232 kV following a unit trip, the switchyard voltage undervoltage/degraded voltage relays could actuate assuming worst case conditions that would accident loading conditions. Note that the low switchyard voltage initiate operation of plant condition (less than 232 kV) must persist for a time greater than the time degraded voltage delay settings specified in the TS for the undervoltage/degraded voltage protection. relays to actuate.

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane ArnoId Energy Center, Docket No. 50-331 L-2006-07:1, Attachment 2, Page 4 of 19 Turkey Point Response to Generic Letter 2006-02

2. Use of criteria and methodologies to assess whether the offsite power system will become inoperable as a res ult of a trip of your NPP.

(a) Does your NPP's TSO use Yes, as described in Basis Document 0-BD-ONOP-004.6, the TSO any analysis tools, an operates the grid using an online CA software program that continuously online analytical calculates the NPP switchyard voltage assuming various "contingencies" transmission system occur, such as plant trips or transmission line faults. When the Turkey studies program, or other Point switchyard voltage (actual or post-contingency) falls below the equivalent predictive minimum allowable value (232 kV), an alarm is initiated at the TSO control methods to determine the center to alert the TSO to take corrective action and notify the NPP within grid conditions that would 15 minutes.

make the NPP offsite power system inoperable In response to the Generic Letter, the TSO has provided the following during various information: "FPL's CA program evaluates the impact of outages of l:PL contingencies? transmission lines and transformers to identify any overload conditions or If available to you, please voltage problems. It also evaluates the loss of 700 MW class generating provide a brief description units and most 400 MW class generating units. Outages of 500 kV, 230 of the analysis tool that is kV and selected lower voltage lines are looked at in systems outside of used by the TSO. FPL's service territory, none of which tie directly to or support FPL nuclear switchyards."

(b) Does your NPP's TSO use Yes, as described in Basis Document 0-BD-ONOP-004.6, the TSO uses an analysis tool as the the contingency analysis program as the basis for notifying Turkey Point of basis. for notifying the NPP potential degraded conditions.

licensee when such a condition is identified? If not, how does the TSO determine if conditions on the grid warrant NPP licensee notification?

(c) If your TSO uses an In response to the Generic Letter, the TSO has provided the following analysis tool, would the information: "The TSO CA program identifies conditions which would analysis tool identify a result in a switchyard voltage that could actuate the Turkey Point cond tion in which a trip of undervoltage/degraded voltage protection relays and initiate separation the NPP would result in from offsite power upon a Turkey Point unit trip."

switchyard voltages (immediate and/or long-term) falling below TS nominal trip setpoint value requi-ements (including NPP licensees using allowable value in its TSs) and consequent actuation of plant degraded voltage prote-otion?

If not. discuss how such a condition would be identified on the grid.

(d) If your TSO uses an In response to the Generic Letter, the TSO has provided the following analysis tool, how information: "The TSO CA program calculates the expected Turkey Point frequently does the switchyard voltage for the various contingencies, including a Turkey Point analysis tool program unit trip, approximately every 5 minutes."

upda:e?

St. Lucie Units I and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-07:, Attachment 2, Page 5 of 19 Turkey Point Response to Generic Letter 2006-02

2. (continued)

(e) Provide details of analysis As described in Turkey Point Basis Document O-BD-ONOP-004.6, the tool-identified contingency TSO will notify Turkey Point if the CA program determines that the conditions that would postulated contingency event would result in switchyard voltage outside trigger an NPP licensee the allowable operating range as specified in the interface agreement.

notification from the TSO. With Units 3 and 4 on line and on the auxiliary transformer, the low limit is 232 kV and the high limit is 244 kV. If the loads of one of the units are being supplied from the startup transformer, the low limit is 232 kV and the high limit is 241.5 kV. The TSO will also notify the Turkey Point control room if the CA program determines there are potential or developing grid instabilities.

(f) If an interface agreement Yes, the interface agreement with the TSO does require Turkey Point to exists between the TSO be notified when the CA program is unavailable for a period longer than 4 and Mhe NPP licensee, hours for reasons other than scheduled maintenance. Turkey Point would does it require that the continue to rely on the TSO to notify them of any change in grid conditions NPP licensee be notified of which could affect the quality or reliability of offsite power.

periods when the TSO is unable to determine if In response to the Generic Letter, the TSO has provided the following offsite power voltage and information: "in the event that the FPL CA program is unavailable, the capacity could be responsibility to monitor the grid is turned over to a back-up Reliability inadequate? Coordinator which is Progress Energy for FPL. Progress Energy has a CA If so, how does the NPP program which would be used to monitor the Florida transmission system.

licensee determine that the Additionally, the FPL system operator has available support studies that offsite power would remain identify critical operating limits, an online power flow program with which operable when such a he can model changing systems conditions, and access to support notifitation is received? personnel to run off line studies."

(g) After an unscheduled Yes, as part of a unit post trip review, Turkey Point Plant Procedure Cl-inadvertent trip of the NPP, ADM-51 1, Post Trip Review (PTR), requires that the actual post trip are the resultant voltage be compared against the predicted post trip voltage calculated by switchyard voltages the CA program. The actual voltage is verified to be bounded by the verified by procedure to be predicted voltage.

bounded by the voltages predicted by the analysis tool?

(h) If an analysis tool is not Not applicable. The TSO uses a CA program to monitor grid conditions.

available to the NPP licensee's TSO, do you know if there are any plans for the TSO to obtain one?

If so, when?

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50443 Duane AmDld Energy Center, Docket No. 50-331 L-2006-073, Attachment 2, Page 6 of 19 Turkey Point Response to Generic Letter 2006-02

2. (continued)

(i) Ifan analysis tool is not Not applicable. The TSO uses a CA program to monitor grid conditions.

available, does your TSO perform periodic studies to verify that adequate offsite power capability, including adequate NPP post-trip switchyard voltages (immediate and/or long-term), will be available to the NPP licensee over the projected timeframe of the study?

(a)Are the key assuiiptions and parameters of these periodic studies translated into TSO guidance to ensure that the transmission system is operated within the bounds of the analyses?

(b) Ifthe bounds of the analyses are exceeded, does this condition trigger the notification provisions discussed in question I abova?

+

If your TSO does not use, Not applicable. The TSO uses a real time CA program to monitor grid or you do not have access conditions. Turkey Point is notified by the TSO if the CA program to the results of an identifies grid conditions that could compromise the quality or reliabili:y of analysis tool, or your TSO offsite power.

does not perform and makE available to you Turkey Point is in compliance with GDC 17 and no compensatory actions periodic studies that are required.

determine the adequacy of offsite power capability, please describe why you believe you comply with the provisions of GDC 17 as stated above, or describe what compensatory actions you intend to take to ensure that the offsite power system will be sufficiently reliable and remain operable with high probability following a trip of your NPP.

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Poiit Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Staton, Docket No. 50-443 Duane Amazd Energy Center, Docket No. 50-331 L-2006-075i, Attachment 2, Page 7 of 19 Turkey Point Response to Generic Letter 2006-02

3. Use of criteria and methodologies to assess whether the NPP's offsite power system and safety-related components will remain operable when switchyard voltages are inadequate.

(a) If the TSO notifies the NPP Yes, if the TSO notifies Turkey Point that a postulated contingency operator that condition would result in a switchyard voltage below the minimum allowed

a trip of the NPP, or value (232 kV), both startup transformers are declared inoperable and the applicable TS action is entered in accordance with Procedure 0-ONOP-

the loss of the most 004.6.

Critical transmission line or

tine largest supply to the grid would result in switchyard voltages (immediate and/or long-term) below TS nominal trip setpoint value requirements (including NPP licensees using allowable value in its TSs) and would actuate plant degraded voltage protection, is the NPP offsite power system declared inoperable under the plant TSs? If not, why not?

4 (b) If onsite safety-related Double sequencing [loss of coolant accident (LOCA) with delayed LOOP]

equipment (e.g., is not part of the licensing bases for Turkey Point. The UFSAR accident emergency diesel analyses assume a concurrent LOOP and LOCA. The ability of safety generators or safety- related equipment to respond to a double sequencing event is not a related motors) is lost requirement for operability.

when subjected to a doub'e sequencing (LOCA Turkey Point emergency diesel generators and safety related motors are with delayed LOOP event) not expected to be lost during a double sequencing event based on review as a result of the of the load sequencer and breaker logic.

anticipated system performance and is incapable of performing its safety functions as a result of responding to an emergency actuation signal during this condition, is the equipment considered inoperable? If not, why not?

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Poilt Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Am Did Energy Center, Docket No. 50-331 L-2006-073, Attachment 2, Page 8 of 19 Turkey Point Response to Generic Letter 2006-02

3. (continued)

(c) Describe your evaluation of Not applicable. Since a double sequencing event is not part of TurkEy onsite safety-related Point licensing bases, an evaluation has not been performed to determine equipment to determine the overall impact on safety related equipment response to such an event.

whether it will operate as However, a review of the load sequencer and breaker logic indicates that designed during the safety related motors are not expected to be lost during a double condition described in sequencing event.

question 3(b).

(d) If the NPP licensee is No, a TS action would only be entered if the grid conditions result in actual notified by the TSO of or postulated contingency switchyard voltages below the minimum allowed other grid conditions that value. When notified of the specifics of the degraded grid conditions, may impair the capability Turkey Point would perform appropriate operational decision making to or availability of offsite determine if offsite power should be considered available and whether the power, are any plant TS TS for inoperable startup transformers should be entered.

action statements entered? If so, please identify them.

(e) If you believe your plant The applicable TS is entered when Turkey Point is notified by the TSO that TSs do not require you to a Turkey Point unit trip will result in a switchyard voltage below the declare your offsite power minimum value (232 kV), assumed for the degraded voltage actuation system or safety-related setpoint.

equipment inoperable in any of these Turkey Point is in compliance with GDC 17 and no compensatory actions circumstances, explain are required.

why you believe you comply with the provisions of GDC 17 and your plant TSs, or describe what compensatory actions you intend to take to ensure that the offsite power system and safety-related components will remain operable when switchyard voltages are inadequate.

(f) Describe if and how NPP Not applicable. No compensatory actions are required.

operators are trained and tested on the compensatory actions mentioned in your answers to questions 3(a) through (e).

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane AmIld Energy Center, Docket No. 50-331 L-2006-073, Attachment 2, Page 9 of 19 Turkey Point Response to Generic Letter 2006-02

4. Use of criteria and methodologies to assess whether the offsite power system will remain operable following a trip of your NPP.

(a) Do the NPP operators Not Applicable. There is no voltage regulating equipment included ir the have any guidance or determinations of startup transformer operability required by TS or for procedures in plant TS determining if offsite power is functional. None of the analyses prepared bases sections, the final for the onsite AC power distribution systems at Turkey Point take credit for safely analysis report, or automatic tap changers, capacitor banks, main generator voltage plant procedures regarding regulators, or other reactive power compensating equipment.

situations in which the condition of plant- The main generator voltage regulator is normally operated in automatic in controlled or -monitored accordance with Florida Power & Light Company Facility Connection equipment (e.g., voltage Requirements, dated July 30, 2001 and Turkey Point Plant Procedures regulators, auto tap 3/4-GOP-301, Hot Standby to Power Operation. The TSO monitors the changing transformers, status of the voltage regulator and evaluates the impact of grid condi ions capacitors, static VAR when any of the units' voltage regulators is placed in manual. Conditions compensators, main which require the voltage regulator to be placed in manual are closely/

generator voltage coordinated with the TSO in accordance with Procedures 3/4-ONOP' 090.

regulators) can adversely affect the operability of the NPP offsite power system? Operators are required to review Procedures 3/4-ONOP-090 annually.

If so, describe how the operators are trained and tested on the guidance and procedures.

(b) If your TS bases sections, Turkey Point is in compliance with GDC 17 and no compensatory actions the final safety analysis are required.

repoit, and plant procedures do not provide guidance regarding situations in which the condition of plant-controlled or -monitored equipment can adversely affect the operability of the NPP offsite power system, explain why you believe you com ply with the provisions of GDC 17 and the plant TSs, or describe what actions you intend to take to provide such guidance or procedures.

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Poilt Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arn2ld Energy Center, Docket No. 50-331 L-200607., Attachment 2, Page 10 of 19 Turkey Point Response to Generic Letter 2006-02

5. Performance of grid reliability evaluations as part of the maintenance risk assessments required by 10 CFR 50.65(a)(4).

(a) Is a quantitative or Yes, Turkey Point procedures contain requirements for coordination of qualitative grid reliability plant systems and switchyard maintenance and testing to minimize the risk evaluation performed at of a loss of offsite or onsite power:

your NPP as part of the maintenance risk Turkey Point Plant Procedure 0-ADM-068, Work Week Management, assessment required by 10 requires that risk assessments be performed for safety related or risk CFR 50.65(a)(4) before significant components or systems including the emergency diesel performing grid-risk- generators (EDG), startup transformers, or station blackout (SBO) crass-sensitive maintenance tie breakers, for pre-planned and emergent activities.

activities? This includes surveillances, post-maintenance testing, and In addition, Turkey Point Plant Procedure 0-ADM-225, Online Risk preventive and corrective Assessment and Management, requires consideration of potential grid maintenance that could degradation/instability as part of the Configuration Risk Management increase the probability of Program.

a plant trip or LOOP or impact LOOP or SBO coping capability, for example, before taking a risk-significant piece of equipment (such as an EDG, a battery, a steam-driven pump, an alternate AC power source) out-of-service?

(b) Is grid status monitored by Yes, grid status is continuously monitored by the TSO, including during the some means for the performance of grid-risk-sensitive maintenance. As required by the Turkey duration of the grid-risk- Point and TSO interface agreement, the TSO will immediately notify sens tive maintenance to Turkey Point of potential or developing grid instabilities. Procedure 0-confirm the continued ADM-225 requires that the current risk assessment be reassessed if there validity of the risk is any potential increase in grid instability reported by the TSO or as a assessment and is risk result of severe weather conditions.

reassessed when warranted? If not, how is the risk assessed during grid-risk-sensitive maintenance?

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Am Dld Energy Center, Docket No. 50-331 L-2006-071, Attachment 2, Page 11 of 19 Turkey Point Response to Generic Letter 2006-02

5. (con':inued)

(c) Is there a significant Yes, seasonal loads have an impact on grid stress and also influence the variation in the stress on scheduling for plant maintenance outages.

the grid in the vicinity of your NPP site caused by In general, peak load conditions usually occur during the summer months seasonal loads or in South Florida. However, plant availability is also maintained at a maintenance activities maximum during the summer months to ensure grid and service reliability.

associated with critical Grid conditions can become stressed during any season if unplanned plant tranE mission elements? or transmission line outages occur. Similar grid stress conditions can also occur if unexpected cold or hot periods occur when there are multiple planned plant outages.

Is there a seasonal Yes, for Turkey Point, the potential for a LOOP is higher in the late variation (or the potential summer and early fall months due to the increased probability of severe for a seasonal variation) in weather (i.e., hurricanes, tornadoes).

the LOOP frequency in the local transmission region?

If the answer to either Peak system load conditions resulting in potential grid stress would have a question is yes, discuss greater potential for occurring during the summer months.

the time of year when the variations occur and their magnitude.

(d) Are known time-related No, there is no specific change made to the On Line Risk Monitor (OlRM) variations in the probability during summer months. However, if severe weather conditions are of a LOOP at your plant expected and one of the following conditions is planned, the Core Damage site considered in the grid- Frequency (CDF) on the OLRM will be forced to an ORANGE condition.

risk-sensitive maintenance

An EDG on either unit is Out-of-Service (OOS), or evaluation? If not, what is

The SBO cross-tie is OOS, your basis for not cons dering them? A specific evaluation must then be performed to determine the acceptability of the proposed maintenance/surveillance with the severe weather condition. With severe weather conditions expected, Turkey Point Plant Procedures 0-ONOP-1 03.3, Severe Weather Preparations, anc 0-EPIP-20106, Natural Emergencies, provide appropriate risk management actions to minimize risk.

+

(e) Do you have contacts with Yes, Procedure 0-ADM-068 requires the Work Week Manager (WWM) to the TSO to determine ensure that the TSO is notified of planned grid-risk-sensitive maintenance current and anticipated activities no less than 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months prior to the work activity. The WWM will grid conditions as part of evaluate rescheduling the work activity if the TSO grid risk evaluation the grid reliability indicates that degraded grid reliability conditions may exist during the evalLation performed maintenance activity. Procedure 0-ADM-225 requires the Turkey Point before conducting grid- control room to communicate the "start and stop" of grid-risk-sensitive risk-sensitive maintenance maintenance activities to the TSO.

activities?

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Poi it Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Amold Energy Center, Docket No. 50-331 L-2006-073, Attachment 2, Page 12 of 19 Turkey Point Response to Generic Letter 2006-02

5. (continued)

(f) Describe any formal The formal Interface Agreement between Turkey Point and the TSO agreement or protocol that requires the TSO to provide early warning to Turkey Point of potential or you have with your TSO to developing grid instabilities.

assure that you are prornptly alerted to a The Interface Agreement also requires TSO emergent activities, as well as worsening grid condition the detailed conduct of planned activities, to be coordinated on a real time that may emerge during a basis with Turkey Point. These activities include, but are not limited lo:

maintenance activity.

a. TSO removing from service any transmission line terminating in the switchyard;

b. TSO breaker switching which can affect power supply (e.g.

switching of line identified in item (a) above;

c. TSO maintenance activities that can affect power supply.

(g) Do you contact your TSO No, in accordance with the Interface Agreement, Turkey Point relies on the periodically for the duration TSO to monitor grid conditions and contact the control room of potential of the grid-risk-sensitive grid instabilities. Turkey Point will contact the TSO if plant conditions maintenance activities? change that could impact offsite power or increase the probability of a unit trip.

(h) If you have a formal The formal Interface Agreement between Turkey Point and FPL TSO is agreement or protocol with included in Procedure 0-ADM-216, as Attachment 4. Training is provided your TSO, describe how in initial training for licensed and non-licensed operators. Additionally, NPP operators and training was provided in licensed operator continuing training for the 2005 maintenance personnel segments. There is no formal method for periodic review of this are trained and tested on document.

this formal agreement or protocol.

(i) If your grid reliability Not applicable. Turkey Point does have a formal agreement for evaluation, performed as communication with the TSO to facilitate risk assessments required ty 10 part of the maintenance CFR 50.65(a)(4).

risk assessment required by 101 CFR 50.65(a)(4),

does not consider or rely on some arrangement for communication with the TSO, explain why you believe you comply with 10 CFR 50.65(a)(4).

St. Lucie Units I and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-073, Attachment 2, Page 13 of 19 Turkey Point Response to Generic Letter 2006-02

5. (con-inued)

I) risk is not assessed If Risk is assessed when plant conditions have changed, notification is (when warranted) based received from the TSO of potential grid instabilities, or severe weather on continuing conditions are imminent. The TSO uses a real time CA program to communication with the continuously monitor grid conditions. Turkey Point's formal agreement TSO throughout the with the TSO requires that Turkey Point be contacted if there is a change duration of grid-risk- in switchyard status or a potential for grid instability. Therefore, Turkey sensitive maintenance Point has adequately implemented the provisions of Section 11 of activities, explain why you NUMARC 93-01, Industry Guideline for Monitoring the Effectiveness of believe you have Maintenance at Nuclear Power Plants, the endorsed industry guidance effectively implemented associated with the maintenance rule.

the relevant provisions of the endorsed industry guidance associated with the maintenance rule.

(k) With respect to questions No additional actions are required.

5(i) and 50), you may, as an alternative, describe what actions you intend to take to ensure that the increase in risk that may result from proposed grid-risk-sensitive activities is assessed before and during grid-risk-sensitive maintenance activities, respectively. .-

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Poiit Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Am Id Energy Center, Docket No. 50-331 L-2006-073I, Attachment 2, Page 14 of 19 Turkey Point Response to Generic Letter 2006-02

6. Use of risk assessment results, including the results of grid reliability evaluations, in managing maintenance risk, as required by 10 CFR 50.65(a)(4).

(a) Does the TSO coordinate Yes, the Turkey Point interface agreement with the TSO, which is included transmission system in Procedure 0-ADM-216, requires the following coordination activities:

maintenance activities that

The TSO will coordinate planned outages and planned load reductions can have an impact on the with Turkey Point. TSO and Turkey Point maintenance and testing NPP operation with the activities should be coordinated between the parties to prevent NPP operator? inadvertent reductions in nuclear plant defense-in-depth.

Turkey Point will inform the TSO system dispatcher of planned outages and planned load reductions.

TSO will coordinate with Turkey Point the activities that may affect the offsite power supply to the nuclear plants. As a minimum, the T'iO system dispatcher and/or the TSO maintenance crew will inform the Turkey Point control room while planning these activities.

Emergent activities, as well as the detailed conduct of planned activities, will be coordinated on a real time basis with Turkey Point.

These activities include, but are not limited to: removing from service any transmission line terminating in the switchyard; TSO breaker switching which can affect power supply (e.g. switching of line identified above); TSO maintenance activities that can affect power supply.

(b) Do you coordinate NPP Yes, see response to 5(e).

maintenance activities that can have an impact on the transmission system with the TSO?

(c) Do you consider and Yes, Procedure 0-ADM-225 considers the deferral of load threatening implement, if warranted, surveillances or maintenance activities if a potential for increased grid the rescheduling of grid- instability exists or a hurricane warning has been issued. Additionally, this risk-sensitive maintenance Procedure states that the SBO cross-tie breaker or an EDG should be activities (activities that removed from service only for corrective maintenance, e.g., maintenance could (i) increase the required to ensure or restore operability. If emergent conditions exis': that likelihood of a plant trip, (ii) increase the potential for grid instability when the EDG or SBO cross-tie increase LOOP probability, breaker are unavailable, the EDG or SBO cross-tie breaker would be or (iii) reduce LOOP or restored, as a priority work activity, as soon as possible.

SBO coping capability) under existing, imminent, Plant Procedure 0-ONOP-004.6 also requires load threatening activities to or worsening degraded be terminated if in progress or deferred if planned for degraded switchyard grid reliability conditions? voltage conditions.

St. Lucie Uniits 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Amold Energy Center, Docket No. 50-331 L-2006-073, Attachment 2, Page 15 of 19 Turkey Point Response to Generic Letter 2006-02

6. (continued)

(d) If there is an overriding Yes, if grid-risk-sensitive maintenance was required or in progress with need to perform grid-risk- degraded grid conditions, the CDF associated with the OLRM would be sens tive maintenance forced to an Orange condition. Alternate equipment protection measures activities under existing or and compensatory actions would be considered. In general, the primary imminent conditions of action would be to restore the Structure, System, or Component (SSC) degraded grid reliability, or that is out of service to operable status as soon as possible. Other contilue grid-risk-sensitive compensatory actions taken, if any, would be dependent on the nature of maintenance when grid the grid condition and what SSC was out of service.

conditions worsen, do you implement appropriate risk management actions? If so, describe the actions that you would take.

(ThesBe actions could include alternate equipment protection and compensatory measures to limit or minimize risk.)

(e) Describe the actions The maintenance rule risk assessment process and actions for the associated with questions coordination of maintenance activities between Turkey Point and the TSO 6(a) through 6(d) above are governed by the following Plant Procedures:

that would be taken, state 0-ADM-21 6:

whether each action is

Coordination of planned outages and load reductions gove ned by documented procedures and identify

Coordination of emergent activities that could affect offsite power the procedures, and to Turkey Point explain why these actions 0-ADM-068:

are effective and will be

Notification and coordination of Turkey Point maintenance consistently accomplished. activities that affects grid-risk-sensitive equipment 0-ADM-225:

. Risk assessment of load threatening or grid-risk-sensitive equipment.

Deferral of load threatening surveillances or maintenance activities if a potential for increased grid instability exists or a hurricane warning has been issued.

0-ONOP-004.6:

Coordination of degraded switchyard voltage conditions.

Deferral of risk significant maintenance if potential for grid instability These actions have proved to be effective during recent grid-risk-sensitive activities associated with 2005 Hurricanes Katrina and Wilma.

(f) Describe how NPP Work Control and Operations personnel are trained to utilize the OLRM operators and during daily online schedule development. They received initial training maintenance personnel from the FPL Probabilistic Safety Assessment (PSA) group. The Wo-k are trained and tested to Control Department and/or Operations will contact the PSA group when a assure they can risk assessment is outside the bounds of Procedure 0-ADM-225 or doubt accomplish the actions exists as to the validity of the assessment. Continuing training is primarily described in your answers on-the-job.

to question 6(e).

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-073, Attachment 2, Page 16 of 19 Turkey Point Response to Generic Letter 2006-02

6. (continued)

(g) If there is no effective There is effective coordination between the Turkey Point control room and coordination between the the TSO regarding transmission system maintenance or Turkey Point NPP operator and the TSO maintenance activities. Such coordination is in accordance with regarding transmission established protocols. Therefore, Turkey Point is in compliance with 10 system maintenance or CFR 50.65(a)(4).

NPP maintenance activities, please explain why you believe you comply with the provisions of 10 CFR 50.65(a)(4).

(h) If you do not consider and As discussed in questions 6(a) through 6(d), Turkey Point effectively effectively implement implements appropriate risk management actions.

appropriate risk management actions during the conditions desc'ibed above, explain why you believe you effectively addressed the relevant provisions of the asso iated NRC-endorsed industry guidance.

(i) You may, as an alternative No alternative actions are required.

to questions 6(g) and 6(h) desc ibe what actions you intend to take to ensure that the increase in risk that may result from grid-risk-sensitive maintenance activities is managed in accordance with 10 CFR 50.65(a)(4).

St. Lude Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Poirt Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50443 Duane Amcid Energy Center, Docket No. 50-331 L-2006073 Attachment 2, Page 17 of 19 Turkey Point Response to Generic Letter 2006-02

7. Procedures for identifying local power sources (this includes items such as nearby or onsite gas turbine generators, portable generators, hydro generators, and black-start fossil power plants) that could be made available to resupply your plant following a LOOP event.

Note: Section 2, 'Offsite Power," of RG 1.155 (ADAMS Accession No. ML003740034) states:

Procedures should include the actions necessary to restore offsite power and use nearby power sources when offsite power is unavailable. As a minimum, the following potential causes for loss of offsite power should be considered:

- Grid under-voltage and collapse

- Weather-induced power loss

- Preferred power distribution system faults that could result in the loss of normal power to essential switchgear buses (a) Briefly describe any Turkey Point does not have an agreement with the TSO to provide a agreement made with the specific local power source in the event of a LOOP.

TSO to identify local power sources that could be Turkey Point has an agreement in place with the TSO to restore power to made available to re- Turkey Point on a priority basis using any and all transmission lines and supply power to your plant power sources available. The Turkey Point switchyard is connected to the following a LOOP event. state transmission network through eight (8) 230 kV circuits.

(b) Are your NPP operators Not applicable. Turkey Point does not rely on specific local power soirces trained and tested on to restore power following a LOOP.

ident fying and using local power sources to resupply your plant following a LOOP event? If so, describe how.

(c) If you have not established Not applicable. Turkey Point does not take credit or rely on any local an agreement with your power sources to restore power following a LOOP or SBO event.

plant's TSO to identify local power sources that In response to the Generic Letter, the TSO has provided the following could be made available to information; 'The TSO will utilize the best sources available for specific resupply power to your events to restore offsite power and to determine the specific power plant following a LOOP sources and paths, since there is no way to predict the extent and even:, explain why you characteristics of a specific LOOP. The TSO has many options available believe you comply with to restore offsite power and would not be limited to any specific local the provisions of 10 CFR power sources."

50.63, or describe what actions you intend to take to establish compliance. Turkey Point is in compliance with 10 CFR 50.63.

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Poirt Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Amcld Energy Center, Docket No. 50-331 L-2006-073 Attachment 2, Page 18 of 19 Turkey Point Response to Generic Letter 2006-02

8. Maintaining SBO coping capabilities in accordance with 10 CFR 50.63.

(a) Has your NPP experienced There have been no LOOP events caused by grid failure since the Turkey a totel LOOP caused by Point's original coping duration was determined under 10 CFR 50.63.

grid failure since the plant's coping duration was initially determined under 10 CFR 50.63?

(b) If so, have you reevaluated Not applicable.

the NPP using the guidance in Table 4 of RG 1.1155 to determine if your NPP should be assigned to the P3 offsite power design characteristic group?

(c) If so, what were the results Not applicable.

of this reevaluation, and did the initially determined coping duration for the NPP need to be adjusted?

(d) If your NPP has Not applicable.

experienced a total LOOP caused by grid failure since the plant's coping duration was initially determined under 10 CFR 50.63 and has not been reevaluated using the guidance in Table 4 of RG 1.155, explain why you believe you comply with the provisions of 10 CFR 50.6'; as stated above, or describe what actions you intend to take to ensure that the NPP maintains its SBO coping capabilities in accordance with 10 CFR 50.63;.

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Poirt Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane AmcId Energy Center, Docket No. 50-331 L-2006-073. Attachment 2, Page 19 of 19 Turkey Point Response to Generic Letter 2006-02

9. Actions to ensure compliance If you determine that any Turkey Point is in compliance with all referenced requirements. No action action is warranted to bring is required.

your NPF' into compliance with NRC regulatory requirements, including TSs, GDC 17, 10 CFR 50.65(a)(4), 10 CFR 50.63, 10 CFR 55.59 or 10 CFR 50.120, describe the schedule for implementing it.

ATTACHMENT 3 St. Lucie Units I and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane AmDld Energy Center, Docket No. 50-331 L-2006-073, Attachment 3, Page 1 of 18 Seabrook Response to Generic Letter 2006-02

1. Use of protocols between the NPP licensee and the TSO, ISO, or RC/RA to assist the NPP licensee in monitoring grid conditions to determine the operability of offsite power systems under plant Techr ical Specifications.

(a) Do you have a formal Yes, Seabrook Station has formal agreements with the TSO (ISO-NE) agreement or protocol with in the form of a Service Agreement and with the Transmission Owner your TSO? in the form of an Interconnection Agreement.

Compliance with GDC 17, as documented in the Seabrook Station licensing basis and plant Technical Specifications (TS), is not predicated on such an agreement.

(b) Describe any grid conditions Per the ISO-NE Transmission Operating Guides, the TSO will make that would trigger a notification notifications, as soon as practical, upon identification of any of the from the TSO to the NPP following conditions:

licensee and if there is a time

Overall system wide warning or alert conditions.

period required for the notification. . If the computerized contingency monitoring program (Real Time Contingency Analysis Program) determines that the post-trip off-site voltage could degrade below a value specified by Seabrook.

. In the event that the ISO-NE Control Center's and the Local Control Center's Real Time Contingency Analysis Program becomes unavailable.

A local system configuration, which would cause Seabrook Station to become unstable in the event of a potential transmission system contingency.

(c) Describe any grid conditions Seabrook Station monitors local grid conditions (e.g. voltage, that would cause the NPP frequency, breaker position and voltage regulator mode), which may licensee to contact the TSO. require the TSO or its Local Control Center to be notified. Conditions that would cause Seabrook Station to contact the TSO include:

Describe the procedures

changes in capability (power uprate) associated with such a

changes to Switchyard Voltage, Switchyard Breaker alignment, communication. If you do not Generator VAR loading have procedures, describe modifications resulting in changes to generator electrical how you assess grid conditions characteristics that may cause the NPP licensee to contact the TSO.

changes in post trip power loading

changes in status of offsite power voltage regulating devices (such as voltage regulators in manual versus auto.)

Examples of procedures that require contacting the ISO or the EESCC (Electric System Control Center) include: alarm response procedures D6667, 345 Kv Line Sys 2 Trouble, B8470, 345 Kv Line 394 Voltage Low, and D6670, 345 Kv Line Voltage Loss. Any required notifications are made using dedicated communication equipment.

(d) Des-ribe how NPP operators Several industry events involving the electrical grid have been are trained and tested on the incorporated into simulator and classroom training lesson plans.

use of the procedures or Licensed operator requalification training lesson plans include assessing grid conditions in training/simulations and/or demonstrations of loss of off-site power.

question 1(c). Requalification program simulator lessons are updated and presented repetitively over several years per the training program description.

The operators are examined in accordance with NUREG 1021 guidance. Examination methods use simulator and written examinations and job performance measures. All three methods test operator response to off-site electrical power (grid) disturbances.

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Amzld Energy Center, Docket No. 50-331 L-2006-0731, Attachment 3, Page 2 of 18 Seabrook Response to Generic Letter 2006-02

1. (continued)

(e) Ifyou do not have a formal Seabrook Station does have a formal agreement with the TSO.

agreement or protocol with Therefore, this question is not applicable.

your TSO, describe why you believe you continue to comply with the provisions of GDC 17 as stated above, or describe what actions you intend to take to assure compliance with GDC 17.

(f) If you have an existing formal Seabrook Station's agreement with the TSO does require notification interconnection agreement or of actual or predicted conditions (i.e. contingency analysis program) protocol that ensures adequate that could cause a degraded voltage condition below the minimum communication and allowable value.

coordination between the NPP licensee and the TSO, describe whether this agreement or protocol requires that you be promptly notified when the conditions of the surrounding grid could result in degraded voltage (i.e., below TS nominal trip setpoint value requirements; including NPP lice isees using allowable value in its TSs) or LOOP after a trip of the reactor unit(s).

(g) Describe the low switchyard If the voltage on a 4.16 kV emergency bus is below that required to voltage conditions that would ensure the continued operation of safety-related equipment, the initiate operation of plant second level undervoltage protection scheme is activated. If the degraded voltage protection. activation occurs coincidentally with an accident signal, then the unit auxiliary transformer and reserve auxiliary transformer incoming line breakers are automatically tripped after a time delay to prevent spurious operation due to transients such as starting of large motors.

If the second level undervoltage protection scheme is activated without the coincident presence of an accident signal, then only an alarn is received. Established plant procedures require the operator to :ake specific steps to assess the magnitude and expected duration of the disturbance causing the undervoltage. If the operator is not assured that the disturbance is transitory, and that recovery is imminent, the operator may choose to manually trip the offsite power circuit breakers after ensuring that further deterioration of safety will not result from his proposed action.

The minimum anticipated post-contingency switchyard voltage at Seabrook Station is 345 kV. A voltage below this value is required to operate the degraded voltage relays. The minimum switchyard value of 345 kV ensures that required safety systems operate without actuation of safety bus degraded voltage protection relays.

St. Lucie Units I and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-073, Attachment 3, Page 3 of 18 Seabrook Response to Generic Letter 2006-02

2. Use of criteria and methodologies to assess whether the offsite power system will become inoperable as a result of a trip of your NPP.

(a) Does your NPP's TSO use Yes, the TSO and its Local Control Centers (LCC) employ a Real any analysis tools, an online Time Contingency Analysis (RTCA) Program. As provided by ISO-NE analytical transmission system this Program utilizes real-time transmission system information and studies program, or other Seabrook Station specific shutdown loads and minimum voltage equivalent predictive methods requirements. The program creates a real-time network model to determine the grid starting with bus/branch connectivity, branch impedance and ratings, conditions that would make the and steady state generator models. The program then superimposes NPP offsite power system real-time switch and breaker status to determine network topology.

inoperable during various Real-time generation and bus loads are also applied to this model.

contingencies? Statistical techniques are used to resolve telemetering inconsistencies If available to you, please (state estimation). The result forms the basis upon which contingent provide a brief description of events (contingencies) are tested. A pre-defined list of contingencies the analysis tool that is used includes loss of each generator (including each NPP) and by the TSO. transmission events. Contingency results are automatically compared to limits; if any limit is violated, alarms are generated and Seabrook Station would be notified.

Additionally, online monitoring is performed every 60 seconds by ISO-NE to verify that predetermined interface limits are not exceeded. This monitoring program totals the fundamental quantities (line flows, VAR output, etc.) and compares this total to a limit that was determined through offline studies.

(b) Does your NPP's TSO use an Yes, the TSO uses the contingency analysis program as the ba:3is for analysis tool as the basis for notifying Seabrook Station of potential degraded conditions.

notifying the NPP licensee when such a condition is identified? If not, how does the TSO determine if conditions on the grid warrant NPP licensee notilcation?

(c) If your TSO uses an analysis Yes, ISO-NE's analysis tool has this function.

tool, would the analysis tool identify a condition in which a trip of the NPP would result in switchyard voltages (immediate and/or long-term) falling below TS nominal trip setpoint value requirements (including NPP licensees using allowable value in its TSs) and consequent actuation of plant degraded voltage protection?

If nc't, discuss how such a condition would be identified on tie grid.

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-073, Attachment 3, Page 4 of 18 Seabrook Response to Generic Letter 2006-02

2. (co itinued)

(d) If your TSO uses an analysis As provided by ISO-NE, the online Real Time Contingency Analysis tool, how frequently does the calculations are performed at least every 5 minutes at the ISO-NE and analysis tool program update? at least every 10 minutes at the LCC. In addition, online monitoring is performed every 60 seconds by ISO-NE to verify that predetermined interface limits are not exceeded.

(e) Provide details of analysis tool- See the response to question 2(a).

identified contingency As discussed in the response to question 2(a), the real time on-line AC corditions that would trigger an contingency monitor program will determine if existing conditions NP? licensee notification from coupled with a trip of the nuclear generator would result in adecuate or the TSO. inadequate post trip voltages.

(f) If an interface agreement Yes, the TSO has an Operating Procedure, which requires the Tso to exists between the TSO and notify Seabrook Station if they are unable to determine if offsite power the NPP licensee, does it voltage and capacity could be inadequate.

req ire that the NPP licensee This is considered an unlikely event because:

be notified of periods when the TSO is unable to determine if

This analysis capability exists at multiple ISO-NE locations.

offsite power voltage and

The analysis capability also exists at the ESCC.

capacity could be inadequate?

There are multiple methods to determine offsite voltage adequacy If so, how does the NPP both automatic real-time and system operator manual analysis.

lice nsee determine that the offsite power would remain

With minimum system real-time data the ISO-NE and ESCC operable when such a operators can provide Seabrook Station with an experience based notification is received? opinion on the capability of the offsite source.

Seabrook Station would continue to rely on the TSO to notify them of any change in the grid conditions which could affect the quality or reliability of offsite power.

(g) After an unscheduled No, the post trip switchyard voltages are not verified by procedure to inadvertent trip of the NPP, are be bounded by the analysis tool. If, before the trip, the analysis tool the resultant switchyard were to predict a post trip voltage below the allowable level the TSO voltages verified by procedure would notify Seabrook Station. ISO-NE occasionally benchmarks to be bounded by the voltages analysis results with data collected after actual events.

predicted by the analysis tool?

(h) If an analysis tool is not This question is not applicable since the TSO currently uses a ava lable to the NPP licensee's contingency analysis program to monitor grid conditions.

TSO, do you know if there are any plans for the TSO to obtain one? If so, when?

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane AmDId Energy Center, Docket No. 50-331 L-2006-073, Attachment 3, Page 5 of 18 Seabrook Response to Generic Letter 2006-02

2. (continued)

(i) Ifan analysis tool is not This question is not applicable since TSO currently uses a contingency available, does your TSO analysis program to monitor grid conditions.

perform periodic studies to verify that adequate offsite power capability, including adequate NPP post-trip switchyard voltages (immediate and/or long-term),

will be available to the NPP licensee over the projected timeframe of the study?

(a) Are the key assumptions and parameters of these periodic studies translated into TSO guidance to ensure that the transmission system is operated within the bounds of the analyses?

(b) If the bounds of the analyses are exceeded, does this condition trigger the notification provisions discussed in question 1 above?

If your TSO does not use, or This question is not applicable to Seabrook Station as the TSO uses a you do not have access to the real time contingency analysis program to monitor grid conditions.

results of an analysis tool, or Seabrook Station is in compliance with GDC 17 and no compensatory you -TSO does not perform actions are required.

and make available to you periodic studies that determine the adequacy of offsite power capability, please describe why you believe you comply with the provisions of GDC 17 as stated above, or describe what corr pensatory actions you intend to take to ensure that the offsite power system will be sufficiently reliable and remain operable with high probability following a trip of your NPP.

St. Lucie Units I and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane AmeId Energy Center, Docket No. 50-331 L-2006-073, Attachment 3, Page 6 of 18 Seabrook Response to Generic Letter 2006-02

3. Use of criteria and methodologies to assess whether the NPP's offsite power system and safety-related components will remain operable when switchyard voltages are inadequate.

(a) If the TSO notifies the NPP Yes, Main Plant Evolution Procedure OS1000.10, Operation------ - at Power, opetrator that requires: 'lf notified by the Dispatcher that Post Contingency Voltage

a trip of the NPP, or is less than 345 kV, entry in TS 3.8.1.1 for loss of two physically independent circuits is required. Post Contingency Voltage is the

the loss of the most critical calculated grid voltage expected after a Seabrook Station trip. The transmission line or Dispatcher is responsible for realigning the grid within 30 minutes to

the largest supply to the raise the Post Contingency Voltage to greater than 345 kV".

grid would result in switchyard Seabrook Station does not declare offsite power inoperable for a voltages (immediate and/or postulated trip of another unit or transmission line.

long-term) below TS nominal trip setpoint value requirements (including NPP licensees using allowable value in its TSs) and would actuate plant degraded voltage protection, is the NPP offsite powter system declared inoperable under-the plant TSs? If not, why not?

1-(b) If onsite safety-related Double sequencing (LOCA with delayed LOOP event) is not pail of the equipment (e.g., emergency licensing bases for Seabrook Station. The UFSAR accident analysis diesel generators or safety- does not assume double sequencing. No consideration of double related motors) is lost when sequencing is appropriate at Seabrook Station for operability due to subjected to a double the licensing bases.

sequencing (LOCA with delayed LOOP event) as a result of the anticipated system performance and is incapable of performing its safety functions as a result of responding to an emergency actuation signal during this condition, is the equipment considered inoperable? If not, why not? .

St. Lucie Units I and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane AmDld Energy Center, Docket No. 50-331 L-2006-07:1, Attachment 3, Page 7 of 18 Seabrook Response to Generic Letter 2006-02

3. (continued)

(c) Describe your evaluation of Not applicable for Seabrook Station.

onsite safety-related See response to 3(b) equipment to determine whether it will operate as designed during the condition described in question 3(b).

(d) If the NPP licensee is notified No, TS are not entered for grid conditions that might occur.

by the TSO of other grid conditions that may impair the capability or availability of Per Operating Procedure OS1000.10, Operation at Power, Seabrook offs ite power, are any plant TS Station declares offsite power inoperable when the predicted voltage action statements entered? If following a Seabrook Station trip is low enough to cause actuat on of so, please identify them. the degraded voltage relays and a consequential LOOP.

Postulated contingencies on the transmission grid are not used as a basis for operability determinations since:

such events are only postulated and have not actually occurred,

. the offsite power circuits remain capable of effecting a safe shutdown and mitigating the effects of an accident, and the GDC 17 criterion discussed in the Generic Letter are still met, i.e., loss of power from the transmission network would not occur as a result of loss of power generated by the nuclear power un't.

The TSO contingency analysis program analyzes various types of bounding single contingencies including plant trips or transmission line faults. If any contingency results in a switchyard voltage below the minimum allowed value, then the TSO will notify Seabrook Station, per the ISO-NE Transmission Operating Guides.

(e) If you believe your plant TSs The applicable TS are entered when Seabrook Station is notified by do not require you to declare the TSO that a single contingency, including a unit trip, will result in a your offsite power system or switchyard voltage below the minimum value. Seabrook Station is in safety-related equipment compliance with GDC 17 and no compensatory actions are required.

inoperable in any of these circumstances, explain why you believe you comply with the provisions of GDC 17 and your plant TSs, or describe what compensatory actions you intend to take to ensure that the offsite power system and safety-related components will remain operable when swilchyard voltages are inadequate.

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-073, Attachment 3, Page 8 of 18 Seabrook Response to Generic Letter 2006-02

3. (continued) l (f) Describe if and how NPP Several industry events involving the electrical grid have been operators are trained and incorporated into lesson plans for licensed operator requalification tes:ed on the compensatory training.

act ons mentioned in your answers to questions 3(a) through (e). Licensed operator requalification training lesson plans include training/simulations and/or demonstrations of loss of off-site power.

Requalification program simulator lessons are updated and presented repetitively over several years per the training program description.

The operators are examined in accord with NUREG-1021 guidance.

Examination methods use simulator and written examinations and job performance measures. All three methods test operator response to various aspects of off-site electrical power interruption.

The simulator training lessons and both simulator and written examinations include TS evaluations of grid conditions and theih effect on the operability of in-plant equipment.

St. Lucie Lnits 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-07.3, Attachment 3, Page 9 of 18 Seabrook Response to Generic Letter 2006-02

4. Use of criteria and methodologies to assess whether the offsite power system will remain operable following a trip of your NPP.

(a) Do the NPP operators have Yes, Seabrook Station procedures require TSO notification any time any guidance or procedures in that the voltage regulator is operated in manual. Seabrook Station plant TS bases sections, the has no auto tapping transformers or VAR compensators.

final safety analysis report, or plant procedures regarding situations in which the The operators are not specifically trained or tested on the guidance condition of plant-controlled or and procedures. Procedure compliance, use and application are

-monitored equipment (e.g., considered operator skills. No knowledge elements are required.

voltage regulators, auto tap changing transformers, capacitors, static VAR cormpensators, main generator voltage regulators) can adversely affect the operability of the NPP offsite power system? If so, describe how the operators are trained and tested on the guidance and procedures.

(b) If your TS bases sections, the Seabrook Station Operating Procedure OS1000.10 provides the findI safety analysis report, and necessary guidance on how to operate the main generator voltage plant procedures do not regulator.

provide guidance regarding situations in which the condition of plant-controlled or Seabrook Station is in compliance with GDC 17 and no compensatory

-monitored equipment can actions are required.

adversely affect the operability of tie NPP offsite power system, explain why you believe you comply with the provisions of GDC 17 and the plant TSs, or describe what actions you intend to take to provide such guidance or procedures.

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane AmIld Energy Center, Docket No. 50-331 L-2006-07.1, Attachment 3, Page 10 of 18 Seabrook Response to Generic Letter 2006-02

5. Performance of grid reliability evaluations as part of the maintenance risk assessments required ty 10 CFR 50.65(a)(4).

(a) Is a quantitative or qualitative Yes, all scheduled activities are procedurally required to be reviewed grid reliability evaluation to determine if the activities could increase the probability of a plant performed at your NPP as part trip or LOOP, impact LOOP or SBO coping capability before taking risk of the maintenance risk impact equipment out of service.

assessment required by 10 CFR 50.65(a)(4) before performing grid-risk-sensitive In accordance with Procedures WM10.1, Online Maintenance, and mantenance activities? This RM-201, Risk Evaluation Process for Online Maintenance, a includes surveillances, post- qualitative grid reliability evaluation is performed prior to removing ma ntenance testing, and equipment from service when the TSO has notified Seabrook Station preventive and corrective of grid related activities. If an activity impacts a 'component' that is ma ntenance that could modeled in the Seabrook Station PRA (e.g. a 345 kV line) or if the increase the probability of a activity is judged to have a potential impact on the frequency of LOOP, plant trip or LOOP or impact a quantitative evaluation is performed using the Safety Monitor model.

LOOP or SBO coping capability, for example, before taking a risk-significant piece of equipment (such as an EDG, a battery, a steam-driven pump, an alternate AC power source) out-of-service?

(b) Is grid status monitored by Yes, the grid status is continuously monitored by the TSO, including some means for the duration of during the performance of grid-risk-sensitive maintenance.

the grid-risk-sensitive maintenance to confirm the continued validity of the risk A qualitative grid reliability evaluation is performed prior to removing assessment and is risk equipment from service when the TSO has notified Seabrook Station reassessed when warranted? of grid related activities. If an activity impacts a 'component" that is If not, how is the risk assessed modeled in the Seabrook Station PRA (e.g. a 345 kV line) or if the during grid-risk-sensitive activity is judged to have a potential impact on the frequency of LOOP, maintenance? a quantitative evaluation is performed using the Safety Monitor model.

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Am Dld Energy Center, Docket No. 50-331 L-2006-073., Attachment 3, Page 11 of 18 Seabrook Response to Generic Letter 2006-02

5. (continued)

(c) Is there a significant variation Yes, as provided by ISO-NE, entry into alert conditions in the context in the stress on the grid in the of NERC Emergency Preparedness and Operating Standard EOP-vicinity of your NPP site 002-0 is more prevalent in the summer months.

calsed by seasonal loads or maintenance activities associated with critical There is not a significant variation in the stress on the grid in the transmission elements? vicinity of Seabrook Station in regard to maintenance activities.

Is there a seasonal variation (or the potential for a seasonal Based on the limited number of LOOP events there is no seasonal variation) in the LOOP variation in the LOOP frequency in the local transmission region.

frequency in the local transmission region?

If the answer to either question is yes, discuss the time of year Appendix B of WCAP-1 6316, Lessons Learned from the Augus! 14, when the variations occur and 2003 Loss of Offsite Power Events in North America, identifies 7 their magnitude. events described as 'major disturbances and unusual occurrences" that impacted ISO New England from 1999 to 2003. Two of these events occurred in Summer (July, August), one in the fall (November),

three in Winter (December and 2 in March), and one in Spring (June).

This shows no seasonal variation in this limited data set. Also nDte that these events impacted only a small area of the ISO New England grid or resulted in only a voltage reduction. These events may be identified as precursor events to a LOOP at Seabrook Station, but were not significant with regard to actual Seabrook Station-area grid performance.

(d) Are known time-related No, there are no known time related variations in the probability of a variations in the probability of a LOOP at Seabrook Station.

LOOP at your plant site considered in the grid-risk-sensitive maintenance evaluation? If not, what is your basis for not considering them?

(e) Do you have contacts with the Yes, there are normal communication protocols with the TSO (ISO-TSC to determine current and NE) per established procedures.

anticipated grid conditions as All grid related work performed at Seabrook Station is planned and part of the grid reliability scheduled with the ISO and the ESCC. A one-year look-ahead evaluation performed before schedule is provided to the ESCC every month. Seabrook Station's con ducting grid-risk-sensitive schedule is then reviewed for conflict, integrated with the rest o1 the maintenance activities? ESCC district and forwarded to the TSO for area integration and posting on the Long Term Transmission Operation Plan.

(f) Describe any formal The TSO has Operating Procedures which require ISO-NE or it; Local agreement or protocol that you Control Center to notify Seabrook Station if grid conditions are Linder have with your TSO to assure stress. This notification takes place regardless of whether that you are promptly alerted to maintenance is taking place.

a worsening grid condition that may emerge during a maintenance activity. Important alerts such as the one suggested by this question would be made to all generators in the control area.

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-07.1, Attachment 3, Page 12 of 18 Seabrook Response to Generic Letter 2006-02

5. (continued)

(g) Do you contact your TSO No, the TSO is not periodically contacted during maintenance viork.

periodically for the duration of As discussed in response to question 5.b, the grid conditions are the grid-risk-sensitive continuously monitored by ISO-NE and the Local Control Center maintenance activities? (ESCC). Seabrook Station is notified of changing grid conditions in accordance with ISO-NE and Local Control Center (ESCC) procedures.

(h) If you have a formal Seabrook Station trains maintenance personnel on conduct of work agreement or protocol with activities that the plant has agreed to, such as requesting TSO tags for your TSO, describe how NPP the LP cutout when we add SF6 gas in the switchyard. We trail the operators and maintenance electricians on requirements for immediate notification of ESCC: and personnel are trained and ISO for identified problems with transmission equipment, even if no tes':ed on this formal line outage is anticipated. This includes delays in returning equipment agreement or protocol. to service.

Licensed and non-licensed operators receive on-the-job training on ESCC and ISO procedures, switching orders and communications.

This training is documented in qualification guides. Licensed operator training and examination includes simulated communication with ESCC and ISO.

Training on the interface agreement is covered in initial and continuing Switching and Tagging training, which is attended by Operations and Maintenance department personnel.

(i) If your grid reliability The question is not applicable to Seabrook Station, as Seabrook evaluation, performed as part Station has a communications arrangement with the TSO.

of the maintenance risk assessment required by 10 CFR 50.65(a)(4), does not consider or rely on some arrangement for communication with the TSO, explain why you believe you comply with 10 CFR 50.65(a)(4).

() If risk is not assessed (when Not applicable for Seabrook Station.

warranted) based on continuing communication with the TSO throughout the Risk is assessed/reassessed, by Seabrook Station, using the Safety duration of grid-risk-sensitive Monitor Program when warranted based on communication from the maintenance activities, explain TSO or changing weather conditions (see answer to 5b). Risk why you believe you have assessment under 10CFR50.65(a)(4) is not intended to be a numerical effectively implemented the exercise, but rather to highlight the condition of the plant and ersure relevant provisions of the that the plant staff is aware of the safety implications of the work so endorsed industry guidance that the proper risk management actions can be taken.

associated with the maintenance rule.

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-073, Attachment 3, Page 13 of 18 Seabrook Response to Generic Letter 2006-02

5. (continued)

(k) With respect to questions 5(i) Not applicable for Seabrook Station.

and 50), you may, as an alternative, describe what actions you intend to take to No additional actions are required.

enc ure that the increase in risk that may result from proposed grid-risk-sensitive activities is assessed before and during gricl-risk-sensitive maintenance activities, respectively.

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50443 Duane Amrid Energy Center, Docket No. 50-331 L-2006-073, Attachment 3, Page 14 of 18 Seabrook Response to Generic Letter 2006-02

6. Use of risk assessment results, including the results of grid reliability evaluations, in managing maintenance risk, as required by 10 CFR 50.65(a)(4).

(a) Does the TSO coordinate Yes, outages of lines supplying the Seabrook Station switchyard are transmission system discussed before implementation.

ma ntenance activities that can have an impact on the NPP operation with the NPP The long term maintenance schedule (12-month look-ahead) for operator? Seabrook Station is communicated to the TSO each month and becomes part of the integrated long range schedule.

(b) Do you coordinate NPP Yes, see response to question 6a.

ma ntenance activities that can have an impact on the transmission system with the Short of inducing a trip of the main generator, no work at Seabrook TSO? Station is able to make a significant change to the status of the grid in the vicinity of the plant or the grid at-large. For switchyard work the long term maintenance schedule (12-month look-ahead) for Seabrook Station is communicated to the TSO each month and becomes part of the integrated long range schedule.

(c) Do :ou consider and Yes, Seabrook Station has rescheduled maintenance activities after implement, if warranted, the contact from the TSO regarding potential degraded grid conditions.

rescheduling of grid-risk-sensitive maintenance activities (activities that could (i) increase the likelihood of a plant trip, (ii) increase LOOP probability, or (iii) reduce LOOP or SBO coping capability) under existing, imminent, or worsening degraded grid reliability conditions?

(d) If there is an overriding need Yes, the risk assessment required by 10CFR50.64(a)(4) would to perform grid-risk-sensitive consider all of the parameters of interest, including the risk impact of maintenance activities under the condition of overriding need, the actual condition of the grid, existing or imminent conditions duration of the proposed maintenance or duration left to complete of degraded grid reliability, or maintenance or restore equipment, etc. If the risk assessment yields a continue grid-risk-sensitive result above 1E-06 ICDP, then risk management actions would be maintenance when grid implemented as required by the guidance. In accordance with the conditions worsen, do you Seabrook Station Work Management Manual, the actual actions imp ement appropriate risk implemented would depend on the specific circumstances, however, management actions? If so, such things as restoration or cessation of maintenance in progress, des ribe the actions that you confirmation and protection of alternate equipment would be would take. (These actions considered.

cou'd include alternate equipment protection and compensatory measures to limit or minimize risk.)

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-073, Attachment 3, Page 15 of 18 Seabrook Response to Generic Letter 2006-02

6. (continued)

(e) Describe the actions 6(a), 6(b), and 6(c) are governed by the agreement with the TSO. 6(d) associated with questions 6(a) is governed byWM10.1, On-Line Maintenance. The actions ccmply through 6(d) above that would with the industry guidance in NEI 93-01, Rev 3, as endorsed by N.R.C.

be taken, state whether each Regulatory Guide 1.182.

act on is governed by documented procedures and identify the procedures, and explain why these actions are effective and will be consistently accomplished.

(f) Describe how NPP operators Electrical Maintenance coordinates with the TSO for work effecting and maintenance personnel transmission through their clearance request process. Maintenance are trained and tested to receives specific training on the clearance requesting process at assure they can accomplish ESCC.

the actions described in your Operations assesses risk when warranted by communication with the answers to question 6(e). TSO, thus allowing proper risk management actions to be taken by the plant staff.

Training in the use of the Safety Monitor software for risk assessment was initially presented to all crews in on-shift briefings. Safety Monitor training is included in licensed operator initial and continuing training.

(g) If there is no effective Not applicable for Seabrook Station.

coordination between the NPP There is effective coordination between the Seabrook Station operator operator and the TSO and the TSO regarding transmission system maintenance and station regarding transmission system maintenance activities. Such coordination is in accordance with the maintenance or NPP ma ntenance activities, please protocols.

explain why you believe you comply with the provisions of 10 CFR 50.65(a)(4).

(h) If you do not consider and Not applicable for Seabrook Station.

effectively implement As discussed in questions 6(a) through 6(d), Seabrook Station appropriate risk management effectively implements appropriate risk management actions.

actions during the conditions described above, explain why you believe you effectively addressed the relevant provisions of the associated NRC-endorsed industry guidance.

(i) You may, as an alternative to Not applicable to Seabrook Station.

questions 6(g) and 6(h) describe what actions you intend to take to ensure that the increase in risk that may result from grid-risk-sensitive maintenance activities is managed in accordance with 10 CFR 50.65(a)(4).

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-073, Attachment 3, Page 16 of 18 Seabrook Response to Generic Letter 2006-02

7. Procedures for identifying local power sources (this includes items such as nearby or onsite gas turbine gererators, portable generators, hydro generators, and black-start fossil power plants) that could be made available to resupply your plant following a LOOP event.

Note: Section 2, "Offsite Power," of RG 1.155 (ADAMS Accession No. ML003740034) states:

Procedures should include the actions necessary to restore offsite power and use nearby power sources when offsite power is unavailable. As a minimum, the following potential causes for loss of offsite power should be considered:

- Grid under-voltage and collapse

- Weather-induced power loss

- Preferred power distribution system faults that could result in the loss of normal power to essential switchgear buses (a) Briefly describe any agreement The TSO has a detailed system blackout recovery procedure (C)P6) made with the TSO to identify which describes the process by which the New England electric; local power sources that could system would be re-established if power was lost to part or the entire be made available to re-supply ISO-NE region. Included in this procedure (OP6) is notification to the power to your plant following a Local Control Centers of the importance of re-establishing power to LOOP event. the NPPs as a priority action.

Based on the recovery procedure (OP6), the TSO will utilize the best sources available for specific events to restore offsite power and to determine the specific power sources and paths, since there is no way to predict the extent and characteristics of a specific blackout.

The NPPs in the ISO-NE region have participated as an active player in the annual system recovery exercises. During this exercise the NPPs and TSO have discussed the NPPs off-site power requirements and restart limitations.

(b) Are your. NPP operators Seabrook Station's 345 kV switchyard has no "local power sources" trained and tested on capable of re-supplying it following a LOOP event. Restart of the plant identifying and using local under these conditions is dependent upon 345 kV power being power sources to resupply restored by the TSO.

your plant following a LOOP When off-site power is restored, Seabrook Station's EOPs and AOPs event? If so, describe how. for LOOP contain recovery actions for the in-plant distribution system.

Operators are trained and tested on these procedures. See item 1.d.

(above) for a description of operator training and testing.

Electrical Maintenance trains electricians on the procedure for aligning alternate control power to switchyard equipment, thus allowing 345 kV restoration following a LOOP.

(c) If you have not established an Not applicable for Seabrook Station; an agreement with the TSO agreement with your plant's exists.

TSO to identify local power sou-ces that could be made ava lable to resupply power to Our TSO has agreements with and has verified the adequacy oF you plant following a LOOP regional units which have black-start capability. These units are event, explain why you believe started and dispatched under the direction of TSO, in accordance with you comply with the provisions TSO (OP6) system recovery process. NPPs are considered a priority of 10 CFR 50.63, or describe to have power restored.

what actions you intend to take to establish compliance.

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-073, Attachment 3, Page 17 of 18 Seabrook Response to Generic Letter 2006-02

8. Maintaining SBO coping capabilities in accordance with 10 CFR 50.63.

(a) Has your NPP experienced a Seabrook Station has not experienced a total LOOP caused by grid total LOOP caused by grid failure since the plant's coping duration was initially determined under failure since the plant's coping 10CFR 50.63.

duration was initially determined under 10 CFR 50.53?

(b) If so, have you reevaluated the Not applicable to Seabrook Station.

NPP using the guidance in Table 4 of RG 1.155 to determine if your NPP should be assigned to the P3 offsite power design characteristic group?

(c) If so, what were the results of Not applicable to Seabrook Station.

this reevaluation, and did the initially determined coping duration for the NPP need to be adjusted?

(d) If your NPP has experienced a Not applicable to Seabrook Station.

toteI LOOP caused by grid failure since the plant's coping duration was initially determined under 10 CFR 50.63 and has not been reevaluated using the guidance in Table 4 of RG 1.155, explain why you believe you comply with the provisions of 10 CFR 50.63 as stated above, or describe what actiDns you intend to take to ensure that the NPP maintains its SBO coping capabilities in accordance with 10 CFR 50.63.

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Amaod Energy Center, Docket No. 50-331 L-2006-073, Attachment 3, Page 18 of 18 Seabrook Response to Generic Letter 2006-02

9. Actions to ensure compliance If you determine that any action is Not applicable to Seabrook Station.

warranted to bring your NPP into compliance with NRC regulatory requirements, including TSs, GDC 17, 10 GFR 50.65(a)(4), 10 CFR 50.63, O, 0 CFR 55.59 or 10 CFR 50.120, describe the schedule for implementing it.

ATTACHMENT 4 St. Lucie Urits I and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-073, Attachment 4, Page 1 of 27 Duane Arnold Energy Center Response to Generic Letter 2006-02

1. Use of protocols between the NPP licensee and the TSO, ISO, or RC/RA to assist the NPP licensee in monitoring grid conditions to determine the operability of offsite power systems under plant Technical Specifications.

(a) Do you have a formal Yes, Duane Arnold Energy Center (DAEC) does have a formal agreement agreement or protocol with with the TSO (American Transmission Company (ATC)) and the Midwest your TSO? Independent System Operator (Midwest ISO). The agreement is documented in Procedure ACP 101.16, Midwest ISO Real-Time Operations Communication and Mitigation Protocols for Nuclear Plant/Electrical System Interfaces (Note this is MISO procedure RTO-OP-03). Compliance with GDC 17, as documented in the DAEC license bases and plant TS, is not predicated on such an agreement.

(b) Descibe any grid The TSO is required to notify DAEC whenever an impaired or potentially conditions that would degraded grid condition is recognized by the TSO. Specific examples of trigger a notification from known potentially degrading conditions identified in the agreement include:

the TSO to the NPP 1. Midwest ISO Real-Time Operations Communication and Mitigaticn licensee and if there is a Protocols for Nuclear Plant/Electrical System Interfaces states time period required for the "Transmission Operator (ATC) will immediately initiate communication notification. with the Nuclear Plant and the Midwest ISO if the Transmission Operator verifies an actual violation to the operating criteria [system limits] affecting the Nuclear Plant. The Transmission Operator a id the Midwest ISO will immediately initiate steps to mitigate the actual violation."

2. Midwest ISO Real-Time Operations Communication and Mitigation Protocols for Nuclear Plant/Electrical System Interfaces states: "The Midwest ISO or the Transmission Operator will initiate communication with each other to verify study results that indicate a post-contingent violation of operating criteria [system limits]. Upon verification, the Transmission Operator and the Midwest ISO will immediately initiate steps to mitigate the pre and post contingent operating criteria violation. If the violation is not mitigated within 15 minutes of the verification of the study results, the Transmission Operator shall immediately notify the Nuclear Plant."

3. In response to this Generic Letter the ATC provided the following information: 'ATC will notify FPL-Duane Arnold within 15 minutes after verification whenever the real time voltage on the Duane Arnold 161 kV bus goes lower than 156 kV or higher than 169 kV. ATC will notify FPL-Duane Arnold within 15 minutes after verification whenever the loss of any single transmission element or generator connected to the IP&L [Interstate Power and Light] transmission system will cause the Duane Arnold 161 kV bus voltage to go lower than 153 kV or higher than 177 kV. When notified by FPL, ATC will change the real tirre and post-contingent low voltage limits to 158 kV in response to in-plant configuration changes. ATC will notify FPL-Duane Arnold of forced outages to either end of any 345 kV or 161 kV transmission line connected to the Duane Arnold Substation."

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-073, Attachment 4, Page 2 of 27 Duane Arnold Energy Center Response to Generic Letter 2006-02

1. (continued)

(b) 4. In response to this Generic Letter, the Midwest ISO provided the following information: The Midwest ISO Communication Protoccl, RTO-OP-03 states "Midwest ISO will monitor the appropriate system conditions and notify the nuclear plant's operating personnel via the local transmission operator when operating conditions are outside of established limits, as well as, when they are restored to within acceptable criteria. This communication shall take place within 15 minutes of verification of the results."

The occurrence of a grid contingency that impacts DAEC requires immediate DAEC notification.

(c) Describe any grid The observable grid parameters of the DAEC operator include; voltage conditions that would and frequency, generator reactive output, breaker status, line status and cause the NPP licensee to certain switchyard alarm points.

contact the TSO.

Describe the procedures Procedure AOP 304, Grid Instability, is entered whenever the grid reaches associated with such a a limited reserve condition, essential bus voltage reaches 95%, main communication. If you do generator reaches 200 MVAR, when the main transformer loading is not have procedures, greater than 95%, when the local transmission lines are heavily loaded or describe how you assess at the discretion of the OSM. This procedure directs communication with grid conditions that may the local grid operator to assess grid conditions. Procedure ACP 101.16, cause the NPP licensee to Midwest ISO Real-Time Operations Communications and Mitigation contact the TSO. Protocols for Nuclear Plant/Electric System Interfaces, is the protocol established for such communications.

(d) Describe how NPP DAEC operators are trained and tested on the following:

operators are trained and . LOOP tested on the use of the

System Restoration procedures or assessing grid conditions in question . Degraded voltage conditions 1(c).

VARs

Breaker status

Offsite power trip

Notification by TSO of changed conditions.

Procedures associated with this training and testing include; AOP 301, Loss of Essential Power, AOP 301.1, Station Blackout, ACP 304, Grid Instability, and AOP 304.1, Loss of Non-essential Power.

These procedures are covered in the Initial License Training program, as well as the Licensed Operator Continuing Training program on a once per two year basis.

St. Lucie Lnits 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arnold Energy Center, Docket No. 50-331 L-200&-073, Attachment 4, Page 3 of 27 Duane Arnold Energy Center Response to Generic Letter 2006-02

1. (continued)

(e) If you do not have a formal DAEC does have a formal agreement with the TSO. Therefore, this agreement or protocol with question is not applicable.

your TSO, describe why you believe you continue to comply with the provisions of GDC 17 as stated above, or describe what actions you intend to take to assure compliance with GDC 17.

(f) If you have an existing As previously stated, DAEC does have a formal TSO agreement. Prompt formal interconnection notification and a pre-trip analysis of post-trip voltage are included.

agreement or protocol that Procedures associated with these communications are in Procedure ACP ensures adequate 101.16, Midwest ISO Real-Time Operations Communication and Mitigation communication and Protocols for Nuclear Plant/Electrical System Interfaces.

coordination between the NPP licensee and the In response to this Generic Letter, the Midwest ISO provided the following TSO, describe whether information: 'The Midwest ISO Communication Protocol, RTO-OP-03 this agreement or protocol states; the Midwest ISO or the Transmission Operator will initiate requires that you be communication with each other to verify study results that indicate a post-promptly notified when the contingent violation of operating criteria. Upon verification, the conditions of the Transmission Operator and the Midwest ISO will immediately initiate steps surrounding grid could to mitigate the pre and post contingent operating criteria violation. If the result in degraded voltage violation is not mitigated within 15 minutes of the verification of the study (i.e., below TS nominal trip results, the Transmission Operator shall immediately notify the Nuclear setpoint value Plant".

requ rements; including NPP licensees using allowable value in its TSs) or LOOP after a trip of the reactor unit(s).

(g) Describe the low The DAEC degraded voltage protection is set so that sufficient powe will switchyard voltage be available for starting large ECCS motors without risking damage to the conditions that would motors that could disable the ECCS function. Power supply to the bus is initiate operation of plant transferred from offsite power to the onsite DG power when the voltage on degraded voltage the bus drops below the Degraded Voltage Function Allowable Values, protection. i.e., 92.2% of 4.16 kV for 8.5 seconds. The 92.2% of 4.16 kV equates to 98.8% voltage on the 161 kV switchyard buses with the essential buses under load.

St. Lucie Units I and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-073, Attachment 4, Page 4 of 27 Duane Arnold Energy Center Response to Generic Letter 2006-02

2. Use of criteria and methodologies to assess whether the offsite power system will become inoperable as a result of a trip of your NPP.

(a) Does your NPP's TSO use Yes, the TSO makes use of analysis tools to predict grid conditions that any analysis tools, an would affect the DAEC offsite power system. The tools presently used by online analytical the TSO to manage the grid programs, control the transmission related transmission system activities, and monitor grid actions are outside the control of the DAEC.

studies program, or other In response to this Generic Letter the ATC provided the following equivalent predictive information: uATC uses both offline (PSSE, Areva, POM/OPM, VSA7, methods to determine the etc.) and online (Areva energy management system) analytical tools to grid conditions that would determine grid conditions under a variety of situations. The online analysis make the NPP offsite is performed approximately once every 5 minutes while the offline analysis power system inoperable is performed on an as needed basis."

during various In response to this Generic Letter, the Midwest ISO provided the following contingencies? information: uMidwest ISO Energy Management System (EMS) includes a If available to you, please State Estimator (SE) that currently runs every 90 seconds and Real-rime provide a brief description Contingency Analysis (RTCA) programs that analyzes over 7000 of the analysis tool that is contingencies based on the transmission owner's criteria. One of the used by the TSO. contingencies analyzed by the MISO EMS is the trip of the NPP. The analysis provides results with respect to thermal, voltage, and voltage drop limit violations."

(b) Does your NPP's TSO use Yes, the TSO and ISO uses the above analysis tools, in conjunction with an analysis tool as the procedures, as the basis for determining when conditions warrant DAEC basis for notifying the NPP notification.

licensee when such a In response to this Generic Letter, the Midwest ISO provided the following condition is identified? If information: 'The results of the MISO RTCA program application contain not, how does the TSO the specific contingency of the nuclear power plant tripping as the determine if conditions on contingent element. Operation outside of the voltage limits for a unit trip the grid warrant NPP contingency would result in notification to the NPP per MISO Procedure licensee notification? RTO-OP-03. If Midwest ISO determines the transmission system is outside of operating criteria, the Midwest ISO will notify the local transmission operator."

Refer to the response to question 1(b).

(c) If your TSO uses an Yes, the TSO analysis tool, in conjunction with DAEC plant analysis, analysis tool, would the identifies conditions which would actuate the DAEC degraded voltage analysis tool identify a protection logic and initiate separation from an offsite power source upon a condition in which a trip of DAEC trip.

the KPP would result in In response to this Generic Letter, the ATC provided the following switchyard voltages information; "The analysis tools identify when a trip of the Duane Arnold (immediate and/or long- unit would result in switchyard voltages falling below the values provided term) falling below TS to ATC by FPL."

nominal trip setpoint value In response to this Generic Letter, the Midwest ISO provided the following requirements (including information: "Midwest ISO RTCA program simulates the loss of NPP and NPP licensees using analyzes the post-trip condition against the criteria provide by the allowable value in its TSs) transmission owner. If the conditions were exceeded, the Midwest ISO and consequent actuation RC would notify the local transmission operator per MISO Procedure RTO-of plant degraded voltage OP-03".

protection?

If not, discuss how such a cond tion would be identfied on the grid.

St. Lucie Units I and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-073, Attachment 4, Page 5 of 27 Duane Arnold Energy Center Response to Generic Letter 2006-02

2. (continued)

(d) If your TSO uses an In response to this Generic Letter, the ATC provided the following analysis tool, how information; "ATC's on line analysis tool updates approximately evern 5 frequently does the minutes, immediately following the operation of any breaker 100 kV or analysis tool program greater, or as initiated by the system operator. ATC completes off line update? studies on an as needed basis."

In response to this Generic Letter, the Midwest ISO provided the following information; "Midwest ISO State Estimate runs every 90 seconds and Real-Time Contingency Analysis program runs every 5 minutes or by Midwest ISO Reliability Coordinator Action."

(e) Provide details of analysis The notification from the TSO is based upon the predicted post-trip tool- dentified contingency switchyard voltage given actual (RTCAs) grid conditions.

conditions that would trigger an NPP licensee In response to this Generic Letter, the ATC provided the following notification from the TSO. information; "The contingencies that are modeled and studied include the loss of any single transmission line or transformer as well as [large]

generator (including the Duane Arnold unit) connected to the Alliant West system. FPL Energy Duane Arnold is notified whenever any activated contingency results in voltages outside of predefined limits [per MISO protocol]."

In response to this Generic Letter, the Midwest ISO provided the following information; 'If Midwest ISO observes the transmission system is in real-time or has post-contingent analysis, which indicates the system would be outside of operating criteria, the Midwest ISO will notify the local transmission operator. The Midwest ISO criterion for contingency analysis is to monitor all generators greater than 100 MW, all non-radial lines above 100 kV, and all transformers with two windings greater than 100 kV. This contingency list is validated with the local transmission operator to ensure inclusion of all critical contingencies, and may include lower voltage facilities and smaller generators if deemed critical."

Refer to the response to question 1(b).

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Po nt Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arr old Energy Center, Docket No. 50-331 L-2006-073, Attachment 4, Page 6 of 27 Duane Arnold Energy Center Response to Generic Letter 2006-02

2. (continued)

(f) If an interface agreement Yes, the agreement does specifically require DAEC notification for periods exists between the TSO of time when grid conditions are indeterminate.

and the NPP licensee, does it require that the Procedure ACP 101.16 states: 'Should the Transmission Operator 1Dse its NPP licensee be notified of ability to monitor or predict the operation of the transmission system periods when the TSO is affecting off-site power to the Nuclear Plant, the Transmission Operator unable to determine if shall notify the Midwest ISO, validate Midwest ISO's ability to monitor and offside power voltage and predict the operation of the transmission system and then communicate to capacity could be the Nuclear Plant. Transmission Operator will communicate to the Nuclear inadequate? Plant and Midwest ISO when this capability is restored. This If so. how does the NPP communication should be as soon as practicable or per established licensee determine that the agreements with the Transmission Operator".

offsile power would remain operable when such a In response to this Generic Letter, the ATC provided the following notification is received?

information; 'Yes, ATC will notify FPL-Duane Arnold per the MISO Communication and Mitigation Protocols for Nuclear Plant/Electric System Interfaces."

Should Midwest ISO lose its ability to monitor or predict the operation of the transmission system affecting off-site power to the Nuclear Plant, MISO shall notify the Transmission Operator.

In response to this Generic Letter, the Midwest ISO provided the following information; "Per the Midwest ISO Nuclear Plant Communication protocol, should the Transmission Operator lose its ability to monitor or predict: the operation of the transmission system affecting off-site power to the Nuclear Plant, the Transmission Operator shall notify the Midwest ISO, validate Midwest ISO's ability to monitor and predict the operation of the transmission system and then communicate to the Nuclear Plant.

Transmission Operator will communicate to the Nuclear Plant and Midwest ISO when this capability is restored. This communication should be as soon as practicable or per established agreements with the Transmission Operator. Should Midwest ISO lose its ability to monitor or predict the operation of the transmission system affecting off-site power to the Nuclear Plant, MISO shall notify the Transmission Operator.

The Midwest ISO has developed Abnormal Operating Procedures (AOP) to guide its transmission system operation for failures of different components of analytical and communication tools. For loss of the MISO RTCA, Midwest ISO will consider the results of the local transmission operator's analytical tools. For loss of both sets of tools, Midwest ISO Operating Engineer will attempt to use off-line power flow tools to replicate operating conditions and predict contingent operation."

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-073, Attachment 4. Page 7 of 27 Duane Arnold Energy Center Response to Generic Letter 2006-02

2. (continued)

(g) After an unscheduled No, for post event analysis, the TSO does not verify by procedure the inadvertent trip of the NPP, switchyard voltages are bounded by the analysis tools.

are the resultant switchyard voltages In response to this Generic Letter, the Midwest ISO provided the following verified by procedure to be information: 'There is no formal process for comparing the actual post-trip bounded by the voltages voltages to the post-trip contingency voltage results calculated by the predicted by the analysis MISO RTCA program. Because many [of] the MISO transmission owning tool' member companies have similar RTCA programs, there are many opportunities to compare the results. This results in a high confidence that the RTCA results are accurate. However, if the resultant voltages are outside of the criteria, when they are predicted to be within, MISO would be initiating an investigation".

(h) If an analysis tool is not This question is not applicable to DAEC, since TSO analysis tools are available to the NPP presently in use.

licensee's TSO, do you know if there are any plans for the TSO to obtain one?

If so, when?

(i) If an analysis tool is not This question is not applicable to DAEC, since TSO analysis tools are available, does your TSO presently in use. Specifically, the TSO performs periodic studies for DAEC perform periodic studies to in addition to the offsite power analysis tool.

verify that adequate offsite power capability, including adecuate NPP post-trip switchyard voltages (immediate and/or long-term), will be available to the NPP licensee over the projected timeframe of the study?

(a) Are the key assumptions and parameters of these periodic studies translated into TSO guidance to ensure that the transmission csystem is operated within the bounds of the analyses?

(b) I 'the bounds of the analyses are exceeded, does this condition trigger the notification provisions discussed in question I above?

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-073, Attachment 4, Page 8 of 27 Duane Arnold Energy Center Response to Generic Letter 2006-02

2. (continued)

() If your TSO does not use, This question is not applicable to DAEC, since the TSO utilizes analysis or you do not have access tools and communicates the applicable conclusions to the DAEC.

to the results of an analysis tool, or your TSO does not perform and make available to you periodic studies that determine the adequacy of offsii:e power capability, please describe why you believe you comply with the provisions of GDC 17 as slated above, or describe what compensatory actions you interd to take to ensure that the offsite power system will be sufficiently reliable and remain operable with high probability following a trip of ycur NPP.

St. Lucie Units I and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook station, Docket No. 50443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-073, Attachment 4, Page 9 of 27 Duane Arnold Energy Center Response to Generic Letter 2006-02

3. Use of criteria and methodologies to assess whether the NPP's offsite power system and safety-related components will remain operable when switchyard voltages are inadequate.

(a) If the TSO notifies the NPP As outlined in DAEC's response to question (9) below, FPL Energy Duane operator that Arnold will implement a change in operating procedure such that the TS

a trip of the NPP, or LCO for inoperable offsite circuits will be entered following notification by the TSO that a trip of the DAEC would result in switchyard under-vol :age

. the loss of the most conditions.

critical transmission line or

the largest supply to the grid would result in switchyard voltages (immediate and/or long-term) below TS rominal trip setpoint valuei requirements (including NPP licensees using allowable value in its TSs; and would actuate plan: degraded voltage protection, is the NPP offsite power system declared inoperable under the plant TSs? If not, why not?

(b) If on site safety-related No, double sequencing events (LOCA with a delayed LOOP) are not part equipment (e.g., of the DAEC current licensing basis. As stated in the DAEC UFSAR emergency diesel (Chapter 15.2.1), loss-of-offsite power is concurrent with the postulated generators or safety- LOCA, not subsequent to it. Therefore, plant safety equipment was not relatad motors) is lost specifically designed to cope with 'double sequencing events' and thus, when subjected to a such capability does not constitute "operability" requirements for this double sequencing (LOCA equipment.

with delayed LOOP event) as a result of the anticipated system performance and is incapable of performing its safety functions as a result of responding to an emer gency actuation signal during this condition, is the equipment considered inoperable? If not, why not?

(c) Describe your evaluation of As stated in the response to question 3(b) above, such scenarios are not onsile safety-related part of the DAEC design or licensing basis. Therefore, no such evaluation equipment to determine has been performed for the DAEC.

whether it will operate as designed during the condition described in question 3(b).

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Poiit Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane AmDId Energy Center, Docket No. 50-331 L-2006-073, Attachment 4, Page 10 of 27 Duane Arnold Energy Center Response to Generic Letter 2006-02

3. (continued)

(d) If the NPP licensee is No, as committed to in the response to question 3(a) above, only a notified by the TSO of condition where the trip of the NPP itself would lead to degraded other grid conditions that switchyard voltage would cause the TS actions for offsite circuits to be may impair the capability entered. Other "N-1 contingencies" would not cause the offsite circuits to or availability of offsite be declared inoperable.

power, are any plant TS action statements entered? If so, please identify them.

(e) If you believe your plant As outlined in DAEC's response to question (9) below, FPL Energy Duane TSs do not require you to Arnold will implement a change in operating procedure such that the TS declare your offsite power LCO for inoperable offsite circuits will be entered following notification by system or safety-related the TSO that a trip of the DAEC would result in switchyard under-vollage equipment inoperable in conditions.

any of these circumstances, explain The DAEC switchyard design meets the intent of GDC 17 (Note: DAEC why you believe you was issued its Operating License before the GDC were issued as "final.").

comply with the provisions The DAEC switchyard design has the requisite number of lines of AC; of GD)C 17 and your plant power from the transmission network (i.e., more than 2), that are TSs, or describe what appropriately independent of each other, and the associated transfer compensatory actions you breakers, disconnects, etc., are all currently capable of performing their intend to take to ensure intended safety function, i.e., meet the TS definition of Operability. The that the offsite power DAEC switchyard (offsite circuits), upon a trip of the DAEC system and safety-related turbine/generator, has been analyzed to demonstrate this event does not components will remain lead to a grid instability (UFSAR 8.2.2.2), under the most probable "N-1" operable when switchyard scenarios, as specified in GDC 17.

voltages are inadequate.

The current Loss-of-Power (LOP) instrumentation (TS LCO 3.3.8.1) is capable of detecting actual degraded grid voltages and transferring cffsite sources from the preferred to the alternate preferred source when required and in the extreme event, disassociation from the offsite sources and starting and loading of essential equipment onto the on-site, standby AC sources (Emergency Diesel Generators), i.e., they meet their TS definition of Operability.

However, as discussed in the Reponses to questions 5 and 6 below, compensatory measures are taken to ensure that overall plant risk is managed, as required by 10 CFR 50.65(a)(4).

(f) Describe if and how NPP When DAEC operators are notified by the TSO of potential grid problems, operators are trained and DAEC enters and executes Procedure AOP 304, Grid Instability.

tested on the Procedure AOP 304 lists a probable indication of potential grid instability compensatory actions as notification from the System Operating Center (SOC).

men ioned in your answers to questions 3(a) through Procedure AOP 304 is trained on in both Initial License Training and (e). License Operator Requalification Training on a once per two year bas3is.

St. Lucie Units I and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-073, Attachment 4, Page 11 of 27 Duane Arnold Energy Center Response to Generic Letter 2006-02

4. Use of criteria and methodologies to assess whether the offsite power system will remain operable following a trip of your NPP.

(a) Do the NPP operators DAEC TS do not address voltage regulating equipment.

have any guidance or procedures in plant TS Due to the fact that a trip of a 345 kV transmission line in Wisconsin lKing-bases sections, the final Eau Claire- Arpin) had the potential of tripping the DAEC offline a safet:y analysis report, or capacitor bank was installed in the DAEC switchyard in 2001. This plant procedures regarding capacitor bank is operated by the TSO to provide voltage support wl-en situations in which the required.

concition of plant-controlled or -monitored equipment (e.g., voltage The main generator voltage regulator is operated in accordance with regulators, auto tap Operating Instruction 01-698, Main Generator System. The voltage changing transformers, regulator is normally operated in the automatic mode of operation. The capacitors, static VAR automatic voltage regulator contains over excitation and under excitation compensators, main (Under Excited Reactive Ampere Limit) limiters integral to the regulator.

generator voltage These limiters are not installed in the manual voltage regulator. Operating regulators) can adversely Instruction 01-698 directs coordinating with the local grid operator to limit affect the operability of the reactive loading of the generator when the unit is operated in manual.

NPP offsite power system? Additionally, Operating Instruction 01-698 and Procedure ARP 1C08C B-3, If so, describe how the Generator and Auxiliary Power Annunciator Procedure, directs informing operators are trained and the grid operator of the voltage regulator operating mode, auto or manual.

tested on the guidance and procedures. DAEC has no auto tapping transformers or static VAR compensators.

Training is provided in both Initial License Training and License Requalification Training for the Main Generator Tasks that would require operators to contact the TSO. The tasks covering these procedures are 57.02, Prepare Main Generator System to Be Placed on the Grid, and 57.03, Place Main Generator on the Grid.

The Initial License Training lesson plan for the main generator coven; both of these tasks, and also covers Operating Instruction 01-698 and Procedure ARP 1C08C B-3.

These two tasks are also selected for License Requalification Training.

These tasks were trained in Cycle 2005A. This task is trained on a once per two year basis.

St. Lucie Units I and 2, Docket Nos. 50-335 and 50-389 Turkey Poant Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arrold Energy Center, Docket No. 50-331 L-200-07;3, Attachment 4, Page 12 of 27 Duane Arnold Energy Center Response to Generic Letter 2006-02

4. (continued)

(b) If yoir TS bases sections, DAEC complies with the NERC Standard (VAR-001-0-Voltage and the final safety analysis Reactive Control) requirements of reporting the voltage regulator and report, and plant power system stabilizer status to the local grid operator.

procedures do not provide guidance regarding Per this standard: "Each Generator Operator shall provide information to situations in which the its Transmission Operator on the status of all generation reactive power condition of plant- resources, including the status of voltage regulators and power system controlled or -monitored stabilizers." Also per this standard, "When a generator's voltage regulator equipment can adversely is out of service, the Generator Operator shall maintain the generator field affect the operability of the excitation at a level to maintain Interconnection and generator stability."

NPF offsite power system, explain why you believe you comply with the provisions of GDC 17 and the plant TSs, or describe what: actions you intend to take to provide such guidance or procedures.

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Po'nt Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arrofd Energy Center, Docket No. 50-331 L-2006-07.3, Attachment 4, Page 13 of 27 Duane Arnold Energy Center Response to Generic Letter 2006-02

5. Performance of grid reliability evaluations as part of the maintenance risk assessments required by 10 CFR 50.65(a)(4).

(a) Is a quantitative or Yes, per Guideline WPG-2, On-line Risk Management Guideline, the qualitative grid reliability Control Room Supervisor/Operations Shift Manager is responsible for evaluation performed at ensuring the grid operator is contacted to verify grid stability prior to taking your NPP as part of the the following equipment out of service for maintenance or testing:

maintenance risk

Emergency Diesel Generators assessment required by 10 CFR 50.65(a)(4) before

Startup Transformer performing grid-risk-

Standby Transformer sensitive maintenance

HPCI activities? This includes

RCIC surveillances, post-maintenance testing, and

125 Volt Battery preventive and corrective

250 Volt Battery maintenance that could increase the probability of a plant trip or LOOP or impact LOOP or SBO coping capability, for example, before taking a risk-significant piece of equipment (such as an EDG, a battery, a steam-driven pump, an alternate AC power source) out-of-service?

(b) Is grid status monitored by Yes, the grid is monitored by the grid operator, during these times.

some means for the Procedure ACP 101.16 contains communications requirements. In duration of the grid-risk- addition Plant Shift Orders dated March 20, 2006 states: '...when We! have sensitive maintenance to risk significant equipment out of service, contact ATC once per day on confirm the continued nights for predicted grid status regarding stability and log it in the control validity of the risk room logs."

assessment and is risk reassessed when warranted? If not, how is the risk assessed during grid-risk-sensitive maintenance?

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Pont Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Amold Energy Center, Docket No. 50-331 L-2006-073, Attachment 4, Page 14 of 27 Duane Arnold Energy Center Response to Generic Letter 2006-02

5. (continued)

(c) Is there a significant No, in response to this Generic Letter, the ATC provided the following variation in the stress on information: 'Grid stress varies, but there is not necessarily a correlation the grid in the vicinity of between stress and season. ATC does not track the frequency of LOOP your NPP site caused by at Duane Arnold and therefore cannot report on the variation of LOOP seasonal loads or frequency with season. Transmission outages are typically scheduled maintenance activities when overall grid stress is low. However, scheduled outages increase the associated with critical stress on the remaining in service elements."

transmission elements?

Is theare a seasonal In response to this Generic Letter, the Midwest ISO provided the following variation (or the potential information; "After review of Energy Emergency Alerts within the Midwest for a seasonal variation) in ISO Reliability Footprint, there is no correlation between grid stress and the L.OOP frequency in the seasonal load or maintenance activities. Part two of the question shculd local transmission region? be answered by the nuclear power plant and local transmission operator."

If the answer to either EPRI TR-1 011759, dated December 2005, has shown that there is no question is yes, discuss statistically significant seasonal-regional variation in recorded LOOP the tine of year when the events from 1997 to 2004.

variations occur and their mag nitude. Some observations from EPRI TR-1 011759 indicate:

a LOOP in the fall is rare

Several grids regions appeared to be more stable than other grids.

To gather a statistically significant sample of LOOP events by region for EPRI TR-1011759, the national grid is subdivided into the major Norlh American Electric Reliability Council regions. This grouping keeps events at "remote plants" from skewing the LOOP counted as appropriate to any particular plant.

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Po nt Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arr old Energy Center, Docket No. 50-331 L-2006-07.3, Attachment 4, Page 15 of 27 Duane Arnold Energy Center Response to Generic Letter 2006-02

5. (continued)

(d) Are known time-related As part of the DAEC's risk management process, time related variations variations in the probability (e.g., grid instability, severe weather) are always considered as follows:

of a LOOP at your plant

Severe weather is routinely considered separately as an emergent site considered in the grid- condition.

risk-sensitive maintenance

Switchyard maintenance and test activities are considered within the evaluation? If not, what is SENTINEL risk tool.

your basis for not considering them?

Other events (not only grid specific) outside the plant are under heightened risk conditions considered separately.

The DAEC's procedures require increased controls on maintenance during the described conditions. Risk is usually not calculated solely due to changes in grid reliability (i.e., assessed in conjunction with plant equipment being out of service).

According to preliminary work by the Westinghouse Owners Group (WOG), (Note: WOG data on LOOP frequency would also pertain to BWRs) there is no statistically significant time-of-day or day-of-week variation in the frequency of LOOP at nuclear power plants. This is largely a result of a small number of LOOP events. The analysis has yet to normalize factors such as:

most tasks are done on the day-shift, and

most tasks are performed from Monday to Friday.

Thus, the risk assessment for the purposes of 10 CFR 50.65(a)(4) does not vary the LOOP frequency strictly as a function of 'time-related" issues.

(e) Do you have contacts with Yes, per Guideline WPG-2, the Control Room Supervisor/Operations Shift the TSO to determine Manager is responsible for ensuring the grid operator is contacted to verify current and anticipated grid stability prior to taking the following equipment out of service for grid Conditions as part of maintenance or testing:

the grid reliability

Emergency Diesel Generators evaluation performed

Startup Transformer befo e conducting grid-risk-sensitive maintenance

Standby Transformer activities?

HPCI

RCIC

125 Volt Battery

250 Volt Battery Typically, the TSO uses pre-evaluated nomographs or computer programs to identify conditions where the minimum grid voltage could not be maintained. As a result of the dynamic nature of loads and active generation on the power-grid, the TSO is only able to comment on the grid conditions shortly before (on the order of hours) maintenance tasks commence. Obviously, the TSO can provide commentaries on grid conditions at anytime maintenance tasks are underway. The same dynamic nature of loads and active generation make prediction of grid conditions days or weeks ahead of time highly uncertain.

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-07:3, Attachment 4, Page 16 of 27 Duane Arnold Energy Center Response to Generic Letter 2006-02

5. (continued)

(f) Describe any formal Per the Midwest ISO Communications Protocol, RTO-OP-03, the agreement or protocol that Transmission Operator will immediately initiate communication with the you have with your TSO to nuclear plant and the Midwest ISO if the Transmission Operator verifies an assure that you are actual violation to the operating criteria affecting the nuclear plant. The promptly alerted to a Midwest ISO or the Transmission Operator will initiate communication with worsening grid condition each other to verify study results that indicate a post-contingent violation that may emerge during a of operating criteria. Upon verification, the Transmission Operator and the maintenance activity. Midwest ISO will immediately initiate steps to mitigate the pre and post contingent operating criteria violation. If the violation is not mitigated within 15 minutes of the verification of the study results, the Transmission Operator shall immediately notify the nuclear plant.

Notification occurs whether or not maintenance is on-going. The type of alerts provided to the DAEC conform to the accepted practice promulgated by the NERC. Important alerts such as the one suggested by this question would be made to all generators in the control area.

(g) Do you contact your TSO Plant Shift Orders dated March 20, 2006 states; "...when we have ri k periodically for the duration significant equipment out of service, contact ATC once per day on nights of the grid-risk-sensitive for predicted grid status regarding stability and log it in the control room maintenance activities? logs."

St. Lucie Lnits 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-07:3, Attachment 4, Page 17 of 27 Duane Arnold Energy Center Response to Generic Letter 2006-02

5. (continued)

(h) If you have a formal The Midwest ISO Real-Time Operations: Communication And Mitigation agreement or protocol with Protocols For Nuclear Plant/Electric System Interfaces (DRAFT) was your TSO, describe how introduced during Licensed Operator Requalification Training 2005 C:ycle NPP operators and B, SOER 99-01, Loss of Grid. The introduction of this draft agreement maintenance personnel was NOT formal training (no objectives based upon the draft agreement).

are trained and tested on this formal agreement or protocol. At the time, this communications agreement was NOT formally agreed upon between DAEC and MISO. Since then, it has been formally accepted by both DAEC and MISO. This document has been incorporated into our procedures as Administrative Control Procedure (ACP) 101.16. A corrective action item has been assigned to perform Job Task Analysis for Procedure ACP 101.16 for inclusion into the Initial License and License Requalification programs (OTH01 1965). This action will be complete by April 30, 2006.

Maintenance personnel are NOT trained in this protocol since the Operations personnel are the interface between DAEC and MISO.

Operations personnel contact the TSO about maintenance activities that may be affected by grid conditions.

(i) If your grid reliability Most of the PRA analyses to assess the viability of planned maintenance evaluation, performed as tasks are run days and weeks prior to the actual work to help plan the part Df the maintenance sequencing of tasks. At this rolling maintenance planning stage, the TSO risk assessment required can provide no statistically valid input to the process.

by 10 CFR 50.65(a)(4),

does not consider or rely Once degraded grid conditions are identified, the degraded grid conditions on some arrangement for will be considered a change in plant configuration and a 10 CFR communication with the 50.65(a)(4) risk assessment will be triggered. This assessment will result TSO, explain why you in a review of available plant equipment out of service. A higher priolity is believe you comply with 10 placed on:

CFR 50.65(a)(4).

repairing grid-risk-sensitive equipment

ensuring grid-risk-sensitive equipment is not removed from service and

post-poning optional maintenance activities on trip sensitive equipment.

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Po nt Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50443 Duane Arrold Energy Center, Docket No. 50-331 L-2006-07.3, Attachment 4, Page 18 of 27 Duane Arnold Energy Center Response to Generic Letter 2006-02

5. (continued)

G) If risk is not assessed Plant configuration maintenance and PRA personnel are well aware of the (when warranted) based importance of LOOP sequences and how they are impacted by plant:

on continuing configuration. The communication with the TSO, including the associated communication with the process, is a plant-specific and situation-specific attribute. 10 CFR TSC throughout the 50.65(a)(4) is a risk informed performance based rule; it is not intended to duration of grid-risk- be prescriptive with regard to "one size fits all" risk assessment and sensitive maintenance management actions.

activities, explain why you beliEve you have The point of risk assessment under 10 CFR 50.65(a)(4) is not intended to effectively implemented be a numerical exercise but rather to highlight the condition of the plant the relevant provisions of and ensure the plant staff is aware of the safety implications of the endorsed industry maintenance work so that the proper risk management actions can be guidance associated with taken. Once the implications of the work are known, well rehearsed risk the maintenance rule. management practices can be implemented. Sometimes, the risk management action is to defer the work to another time.

(k) With respect to questions No alternative actions.

5(i) and 50), you may, as an alternative, describe what actions you intend to take to ensure that the increase in risk that may result from proposed grid-risk-sensitive activities is assessed before and during grid-risk-sensitive maintenance activities, respectively.

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-073, Attachment 4, Page 19 of 27 Duane Arnold Energy Center Response to Generic Letter 2006-02

6. Use of risk assessment results, including the results of grid reliability evaluations, in managing maintenance risk, as required by 10 CFR 50.65(a)(4).

(a) Does the TSO coordinate Yes, the TSO informs the plant of transmission system maintenance transmission system activities. The TSO sends DAEC a schedule of transmission work which maintenance activities that includes; current activities in progress, work scheduled for the can have an impact on the upcoming weeks as well as proposed future work activities. Per NPP operation with the Guideline WPG-2, Engineering is responsible for ensuring that the NPP operator? Switchyard System Engineer or Maintenance Engineer reviews the weekly transmission outage schedule and notifying the Operations Shift Manager/Control Room Supervisor and the Scheduling Team Leader of potential impacts to offsite power circuits terminating at the DAEC substation.

Additionally as transmission system maintenance pertains to equipment located within the DAEC switchyard, Procedure ACP 1408.23, ContrDls to the DAEC Switchyard, states: 'The Operation and Maintenance Agreement between FPL Energy Duane Arnold, LLC and Interstate Power and Light Company (IP&L) specifies the scope, responsibilities, and requirements for coordination and control of access, design, operation, and maintenance of the DAEC switchyard, associated equipment, and transmission lines. It requires that IP&L obtain FPL Energy Duane Arnold review and approval of any procedure changes, design changes, tests, and changes to other activities that might affect compliance with DAEC's Operating License or regulatory commitments involving DAEC's switchyard and associated equipment and transmission lines.'

Any work performed by the DAEC staff in the switchyard, in accordance with Procedure ACP1408.23, is coordinated with the TSO. If required both the Alliant Request for Clearance and the DAEC tagout program control the work activities per Procedure ACP 1410.5, Tagout Procedure. Work activities on Alliant Energy transmission lines, switchyards, and substations are controlled from the DDC and SOC by use of the Request for Clearance tagout system. Tagouts within the DAEC switchyard and substations may impact plantISFSI operation; and therefore are controlled by DAEC Tagout Program in addition to the Request for Clearance. The long term work schedule of work performed in the DAEC switchyard by DAEC personnel is transmitted to the TSO in the spring as part of the summer readiness policy. Required requests for clearance for scheduled work iscoordinated several weeks in advance.

At DAEC access to the plant switchyard is controlled by the Operaticns Shift Manager/Control Room Supervisor. Procedure ACP 1408.23 directs switchyard access and controls switchyard activities. The Control Room Supervisor shall be informed of what work is to be performed and of potential effects on the plant. Thus, the outside entity and the on-shift personnel jointly coordinate transmission system maintenance activities in the switchyard. Success of such activities is verified by the plant operator rounds that routinely include tours of the switchyard and other high-voltage equipment.

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-073, Attachment 4, Page 20 of 27 Duane Arnold Energy Center Response to Generic Letter 2006-02

6. (continued)

(a) Continued In response to this Generic Letter the Midwest ISO provided the following information; 'Midwest ISO is responsible for approving maintenance schedule of transmission facilities and coordinating the scheduling of generation facilities. The decision to approve transmission and generation facility maintenance schedules is based on the ability of the Midwest ISO to operate the transmission system within the criteria set forth by the transmission owner and NERC and the applicable regional reliability organization.

Outage scheduling process analyzes the outages under expected operating conditions. On the day prior and on the outage start day, the system is analyzed by MISO before permitting the equipment to be switched out of service.

Once the equipment is switched out of service, grid status is automatically captured by the MISO State Estimator and continually evaluated by the MISO RTCA program."

In response to this Generic Letter, the ATC provided the following information: "Alliant Energy Service, through it's contact with ATC, coordinates transmission system maintenance activities that have an impact on the DAEC operation."

Specific high-voltage circuit outages or substation work is not directly indicative of "grid conditions" that are relevant to determining offsite power operability. The reason is that the power-grid outages affect transmission, which is only one factor affecting the quality of voltage available in the plant switchyard. Besides transmission, the quality cf voltage is affected by the amount of generating resources and the load on the network.

The TSO has no means of predicting voltage in the DAEC switchyard more than a few hours in advance. Thus, whether or not the TSO coordinates transmission system maintenance activities with the DAIEC has little bearing on the operation of the DAEC, except in the case oil the plant switchyard.

When the transmission system maintenance activities involve the plant switchyard or an important substation in the immediate vicinity, then there are some effective risk management actions available, i.e.,

deferring work on auxiliary feedwater pumps or postponing testing.

(b) Do you coordinate NPP See response 5(e).

mairtenance activities that can have an impact on the transmission system with the TSO? I

St. Lucie Units I and 2, Docket Nos. 50-335 and 50-389 Turkey Po'nt Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-073, Attachment 4, Page 21 of 27 Duane Arnold Energy Center Response to Generic Letter 2006-02 (6. (continued)

(c) Do you consider and Yes, Procedure AOP 304, states:

implement, if warranted, 1. In order to minimize the possibility of a plant trip or reduced electric the rescheduling of grid- output:

risk-sensitive maintenance a. Surveillance tests which cause half scrams or half group one activities (activities that isolations should be stopped and rescheduled if possible.

could (i) increase the

b. Maintenance which may reduce plant electric output or has the likelihood of a plant trip, (ii) increase LOOP probability, potential to trip the plant should be postponed.

or (iii) reduce LOOP or c. Maintenance or surveillance tests which could force the plant into SBO coping capability) a required shutdown condition of less than 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months should be under existing, imminent, postponed.

or worsening degraded d. If any surveillance or maintenance is postponed, contact the grid reliability conditions? Work Week Coordinator to reschedule.

NOTE:The maximum excitation limiter and the URAL (Under-exciled Reactive Amperes Limit) are only part of the AUTO VOLTAGE REGULATOR and are not in operation when the Regulator is in MANUAL.

2. If the Auto Voltage Regulator is operable verify the generator is in the AUTO Voltage Regulator Mode.

3. Limit electrical distribution system work, especially on the SBDGs, batteries, and in the switchyard.

4. Return Safety equipment to service, if available to do so.

5. Verify SBDGs are in standby readiness. This may be accomplished by a review of the NSPEO logs.

6. As available, non-essential site loads may be secured in order to minimize site electrical usage. This load reduction should be based upon the condition of the grid as well as the economic worth of doing so. It shall NOT negatively affect the operation of the plant."

Rescheduling is not in the Maintenance Rule definitions, the risk informed Maintenance Rule allows many choices for the DAEC.

Grid-risk sensitive maintenance is performed when the on-shift DAEG.

personnel conclude that the risk of the work is small compared to the safety benefit. When the maintenance work is done in response to a TS, the risk assessment is informative for sequencing tasks, but not controlling.

Emergent issues with the grid are managed to maintain a high level of plant safety. At times appropriate management means rescheduling activities. At other times, the shift-supervisor will order the on-shift DAEC staff to back-out of the task and restore the safety-related function of the equipment.

St. Lucie Units I and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-07:3, Attachment 4. Page 22 of 27 Duane Arnold Energy Center Response to Generic Letter 2006-02

6. (continued)

(d) If there is an overriding Yes, per Guideline WPG-2, Section 6.4, when the overall risk result need to perform grid-risk- presented by SENTINEL is ORANGE or RED, the Cycle Scheduler, sensitive maintenance Work Week Coordinator or Operations Shift Manager (OSM) should activities under existing or attempt to reduce the color to GREEN or YELLOW by separating imminent conditions of maintenance activities. When reducing the color is not possible or degraded grid reliability, or practical, appropriate compensatory actions and/or contingency plans cont nue grid-risk-sensitive shall be discussed and agreed upon at the management challenge maintenance when grid board meeting. The Scheduling Department is then responsible for conditions worsen, do you maintaining separation between activities and communicating implement appropriate risk compensatory actions to the Control Room and other affected management actions? If organizations. Definition of SENTINEL colors and recommended so, c'escribe the actions response to colors are summarized in the WPG.

that you would take.

(These actions could Per Guideline WPG-2, Section 6.3, Emergent and Fill In Work Activities:

include alternate 'Emergent and/or Fill-in work activities shall not be added to the equipment protection and schedule without first verifying their risk significance. When emergent compensatory measures work affects risk-significant equipment, the OSM should have the STA to limit or minimize risk.) perform a SENTINEL risk analysis prior to authorizing start of the scheduled work. The PSA Significant Train Interactions Matrix...may also be used for this analysis. The assessment should also consider qualitatively, the impact of potentially adverse external conditions such as high winds, flooding, or degraded offsite power availability if such conditions are imminent or have a high probability of occurring during the planned out of service duration. The OSM has final authority for this decision."

Guideline WPG-2, Section 6.3, goes on to state: "Activities that would require an overall risk of orange or red should be evaluated by the management team for an IPTE per Procedure ACP 102.17. When emergent activities occur that have placed or will place the plant in an overall risk of orange or red, the Operations Shift Manager will dictate what compensatory actions are required, and will determine the plant's priorities for return-to-service of the risk significant systems/components."

(e) Describe the actions Procedure AOP 304 and Guideline WPG-2 govern the actions to be associated with questions taken, see discussion in the responses to questions 6(c) and 6(d) 6(a) through 6(d) above above.

that would be taken, state whether each action is governed by documented procedures and identify the procedures, and explain why these actions are Effective and will be consistently accomplished.

St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Amold Energy Center, Docket No. 50-331 L-2006-07.3, Attachment 4, Page 23 of 27 Duane Arnold Energy Center Response to Generic Letter 2006-02

6. (continued)

(f) Describe how NPP For Procedure AOP 304; Task 94.48 is titled 'Respond to Grid operators and Instability" and is trained and evaluated per the Initial License Trainirg maintenance personnel Program Description. Specifically, this task is covered in Lesson Plan are trained and tested to 94.47 and Simulator Exercise Guide 24. This task is also trained and assLre they can evaluated per the License Operator Requalification Training Program accomplish the actions Description. It is selected in the two-year plan, and was covered in described in your answers Cycle 2005B in both the classroom setting and the simulator. This task to question 6(e). is trained on a once per two-year basis.

The actions described above are taken by Operations personnel, therefore, Maintenance personnel are NOT trained on these actions.

For Guideline WPG-2; Task 1.11; Ensure the Conduct of Plant Operations and Maintenance are in Compliance with Administrative Procedures, is covered in the Initial Senior License Operator program.

The lesson plan where Guideline WPG-2 is covered is LP 1.13, Administrative Control Procedures.

(g) If there is no effective There is effective coordination between the DAEC operator and the coordination between the TSO regarding transmission system maintenance or DAEC NPP operator and the TSO maintenance activities. Such coordination is in accordance with the regarding transmission protocols.

system maintenance or NPP maintenance activities, please explain why you believe you comply with the provisions of 10( CFR 50.65(a)(4).

(h) If you do not consider and As discussed in the responses to questions 6(a) through 6(d), the effectively implement DAEC effectively implements appropriate risk management actions.

appropriate risk management actions durirg the conditions described above, explain why you believe you effectively addressed the relevant provisions of the associated NRC-endorsed industry guidance.

(i) You may, as an alternative No alternative actions.

to questions 6(g) and 6(h) describe what actions you intend to take to ensure that the increase in risk that may result from grid-risk-sensitive maintenance activities is managed in accordance with 10 CFR 50.65(a)(4).

St. Lucie Units I and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-073, Attachment 4, Page 24 of 27 Duane Arnold Energy Center Response to Generic Letter 2006-02

7. Procedures for identifying local power sources (this includes items such as nearby or onsite gas turbine generators, portable generators, hydro generators, and black-start fossil power plants) that could be made available to resupply your plant following a LOOP event.

Note: Section 2, 'Offsite Power," of RG 1.155 (ADAMS Accession No. ML003740034) states:

Procedures should include the actions necessary to restore offsite power and use nearby power sources when offsite power is unavailable. As a minimum, the following potential causes for loss of offsite power should be considered:

- Grid under-voltage and collapse

- Weather-induced power loss

- Preferred power distribution system faults that could result in the loss of normal power to essential switchgear buses (a) Briefly describe any The Large Generator Interconnection Agreement among Midwest agreement made with the Independent Transmission System Operator, Inc. and Interstate Power TSO to identify local power and Light Company and FPL Energy Duane Arnold, LLC states sources that could be 'Interconnection Customer, Transmission Provider, Transmission made available to re- Owner or their designated agents, as applicable, shall comply with supply power to your plant applicable NRC Requirements and Commitments, concerning offsite following a LOOP event. supply of energy to nuclear units and station black out recovery action."

The current Black start plan's primary objectives list "Supply off-site power to DAEC within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months ."

In response to this Generic Letter, the Midwest ISO provided the following information; "The Midwest ISO restoration process coordinates the development of individual Transmission Owner Restoration Plans. Midwest ISO conducts reviews, workshops and drills to ensure the effectiveness of the restoration plan.

The Midwest ISO restoration process will provide updates to the TSO and NPP on transmission system status during emergency restoration, and will give the highest priority to restoring power to essential affected nuclear facilities, per NERC standard EOP-005-0.

However, due to the myriad of possible restoration scenarios, no specific power sources to resupply NPPs are identified. The MISO restoration process allows for the fact that the blacked out area may Dr may not be separated from the remainder of the system. The MISO restoration process allows to the use of black start unit or cranking path from non-blacked out areas. Regardless of the scenario, there is a clear recognition of the importance of expeditious restoration of an N 'P offsite power source."

Existing plant procedures and commitments are adequate. The TSO will utilize the best sources available for specific events to restore offsite power and to determine the specific power sources and paths, since there is no way to predict the extent and characteristics of a specific blackout.

St. Lucie Units I and 2. Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-073, Attachment 4, Page 25 of 27 Duane Arnold Energy Center Response to Generic Letter 2006-02

7. (continued)

(b) Are your NPP operators Yes, DAEC Procedure AOP 301.1, Station Blackout, directs operator trained and tested on response to the LOOP and also offsite power recovery. Operators are identifying and using local trained and tested on this procedure in both Initial License Training and power sources to resupply License Operator Requalification Training on a once per two year ba 3is.

your plant following a LOOP event? If so, NOTE: on October 12, 2005, DAEC participated in a Midwest ISO loss describe how.

of grid drill. DAEC's participation included Engineering and Operations representation. The drill included a table top walkthrough of DAEC site procedures and communications with the drilling participants of the TSO and Midwest ISO. The drill simulated a loss of power to the DAEC switchyard and subsequent restoration. Power was restored to the switchyard in 3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months and 8 minutes.

(c) If you have not established Not applicable; an agreement exists.

an agreement with your plant's TSO to identify The TSO has the responsibility to restore offsite power to the NPP as a local power sources that priority. Details are available in the protocol that exists between the could be made available to NPP and the TSO. Identifying local power sources that could be made resupply power to your available to resupply power to the NPP following a LOOP is not part of plant. following a LOOP the NPP licensing bases.

event, explain why you believe you comply with the provisions of 10 CFR 50.6:3, or describe what actions you intend to take to establish compliance.

St. Lucie L nits 1 and 2, Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-07:3, Attachment 4, Page 26 of 27 Duane Arnold Energy Center Response to Generic Letter 2006-02

8. Maintaining SBO coping capabilities in accordance with 10 CFR 50.63.

(a) Has your NPP experienced The plant's initial coping duration was initially determined in the early a total LOOP caused by 1990s. Since that time, DAEC has not experienced a total LOOP grid failure since the caused by a grid failure.

plant's coping duration was initially determined under 10 CFR 50.63?

(b) If so, have you reevaluated There have been no grid related events, not applicable.

the NPP using the guidance in Table 4 of RG 1.155 to determine if your NPP should be assigned to the P3 offsite power design characteristic grouo?

(c) If so, what were the results There have been no grid related events, not applicable.

of this reevaluation, and did the initially determined coping duration for the NPP need to be adjusted?

(d) If your NPP has There have been no grid related events, not applicable.

experienced a total LOOP caused by grid failure since the plant's coping duration was initially determined under 10 CFR 50.6:3 and has not been reevaluated using the guidance in Table 4 of RG 1.155, explain why you believe you comply with the provisions of 10 CFR 50.63 as stated above, or describe what actions you intend to take to ensure that the NPP maintains its SBO coping capabilities in accordance with 10 CFR 50.63.

St. Lucie Units I and 2. Docket Nos. 50-335 and 50-389 Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251 Seabrook Station, Docket No. 50-443 Duane Arnold Energy Center, Docket No. 50-331 L-2006-073, Attachment 4, Page 27 of 27 Duane Arnold Energy Center Response to Generic Letter 2006-02

9. Actions to ensure compliance If you determine that any action is As discussed in the responses above, FPL Energy Duane Arnold warranted to bring your NPP into will implement a change in operating procedure such that the TS compliance with NRC regulatory LCO for inoperable offsite circuits will be entered following requirements, including TSs, GDC notification by the TSO that a trip of the DAEC would result in 17, 10 CFR 50.65(a)(4), 10 CFR switchyard under-voltage conditions. Actions associated with 50.63, 10 CFR 55.59 or 10 CFR implementation are as follows:

50.120, describe the schedule for . A TS Bases change will be developed to implement this implementing it. commitment;

Applicable procedures will be revised to reflect the TS Bases change; and,

Licensed Operator notification on the TS Bases and procedure changes will be conducted.

These actions will be completed by June 15, 2006.