OMB Control No.: 3150-0011

UNITED STATES

NUCLEAR REGULATORY COMMISSION

OFFICE OF NUCLEAR REACTOR REGULATION

WASHINGTON, D.C. 20555-0001

February 1, 2006

NRC GENERIC LETTER 2006-02: GRID RELIABILITY AND THE IMPACT ON PLANT RISK

AND THE OPERABILITY OF OFFSITE POWER

ADDRESSEES

All holders of operating licenses for nuclear power reactors except those who have permanently

ceased operations and have certified that fuel has been permanently removed from the reactor

vessel.

PURPOSE

To determine if compliance is being maintained with U.S. Nuclear Regulatory Commission

(NRC) regulatory requirements governing electric power sources and associated personnel

training for your plant, the NRC is issuing this generic letter (GL) to obtain information from its

licensees in four areas:

(1) use of protocols between the nuclear power plant (NPP) and the transmission system

operator (TSO), independent system operator (ISO), or reliability coordinator/authority

(RC/RA) and the use of transmission load flow analysis tools (analysis tools) by TSOs to

assist NPPs in monitoring grid conditions to determine the operability of offsite power

systems under plant technical specifications (TSs). (The TSO, ISO, or RA/RC is

responsible for preserving the reliability of the local transmission system. In this GL the

term TSO is used to denote these entities);

(2) use of NPP/TSO protocols and analysis tools by TSOs to assist NPPs in monitoring grid

conditions for consideration in maintenance risk assessments;

(3) offsite power restoration procedures in accordance with Section 2 of NRC Regulatory

Guide (RG) 1.155, “Station Blackout;” and

(4) losses of offsite power caused by grid failures at a frequency equal to or greater than

once in 20 site-years in accordance with RG 1.155.

Pursuant to 10 CFR 50.54(f), addressees are required to submit a written response to this GL.

ML060180352
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1

 In this GL, GDC 17 includes equivalent plant specific principal design criteria.

BACKGROUND

Based on information obtained from inspections and risk insights developed by an internal NRC

expert panel (further described below), the staff is concerned that several conditions associated

with assurance of grid reliability may impact public health and safety and/or compliance with

applicable regulations. These conditions include use of long-term periodic grid studies and

informal communication arrangements to monitor real-time grid operability, potential

shortcomings in grid reliability evaluations performed as part of maintenance risk assessments,

lack of preestablished arrangements identifying local grid power sources and transmission

paths, and potential elimination of grid events from operating experience and training. The staff

identified these issues as a result of considering the August 14, 2003, blackout event.

On August 14, 2003, the largest power outage in U.S. history occurred in the Northeastern

United States and parts of Canada. Nine U.S. NPPs tripped. Eight of these lost offsite power,

along with one NPP that was already shut down. The length of time until power was available

to the switchyard ranged from approximately one hour to six and one half hours. Although the

onsite emergency diesel generators (EDGs) functioned to maintain safe shutdown conditions,

this event was significant in terms of the number of plants affected and the duration of the

power outage.

The loss of all alternating current (AC) power to the essential and nonessential switchgear

buses at a NPP involves the simultaneous loss of offsite power (LOOP), turbine trip, and the

loss of the onsite emergency power supplies (typically EDGs). Such an event is referred

to as a station blackout (SBO). Risk analyses performed for NPPs indicate that the SBO can

be a significant contributor to the core damage frequency. Although NPPs are designed to

cope with a LOOP event through the use of onsite power supplies, LOOP events are

considered precursors to SBO. An increase in the frequency or duration of LOOP events

increases the probability of core damage.

The NRC issued a regulatory issue summary ((RIS) 2004-5, “Grid Operability and the Impact on

Plant Risk and the Operability of Offsite Power,” dated April 15, 2004) to advise NPP

addressees of the requirements in Title 10 of the Code of Federal Regulations

(10 CFR) Section 50.65, “Requirements for monitoring the effectiveness of maintenance at

nuclear power plants;” 10 CFR 50.63, “Loss of all alternating current power;” 10 CFR Part 50,

Appendix A, General Design Criterion (GDC) 17,1 “Electric power systems;” and plant technical

specifications on operability of offsite power. In addition, the NRC issued Temporary Instruction

(TI) 2515/156, “Offsite Power System Operational Readiness,” dated April 29, 2004, and TI

2515/163, “Operational Readiness of Offsite Power,” dated May 05, 2005, which instructed the

regional offices to perform followup inspections at plant sites on the issues identified in the RIS.

The NRC needs additional information from its licensees in the four areas identified above in

order to determine if regulatory compliance is being maintained.
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On April 26, 2005, the Commission was briefed on grid stability and offsite power issues by a

stakeholder panel that included representatives of the Federal Energy Regulatory Commission,

the North American Electric Reliability Council (NERC), the National Association of Regulatory

Utilities Commissioners, PJM Interconnection (one of the country’s largest transmission system

operators), a FirstEnergy Corporation executive representing the Nuclear Energy Institute

(NEI), and the NRC staff. In light of this briefing, the Commission issued a staff requirements

memorandum (SRM) dated May 19, 2005, in which the Commission directed the staff to review

NRC programs related to operator examination and training and ensure that these programs

adequately capture the importance of grid conditions and offsite power issues to the design,

assessment, and safe operation of the plant, including appropriate interactions with grid

operators. The SRM further directed the staff to determine whether the operator licensing

program needs to be revised to incorporate additional guidance on grid reliability.

DEFINITIONS

The following definitions provided clarification to the terms used in this GL.

Adequate Offsite Power

The existence of power from the transmission system of sufficient voltage and capacity

to power the safety-related loads under defined NPP load conditions. Sufficient voltage

is generally related to the degraded voltage relay setpoints.

Degraded Grid Reliability Conditions

Those conditions on the grid caused by load flow, operation of a transmission element

or maintenance on a transmission element that could significantly increase the

probability of a NPP trip or loss of adequate offsite power supply.

Grid Stress or a Stressed Grid

Inadequate generation or transmission paths that require entry into an Alert condition in

the context of NERC Emergency Preparedness and Operating Standard EOP-002-0,

Attachment 1, “Energy Emergency Alerts.”

N–1 Contingency

The unexpected failure or outage of a single system component, such as a generator,

transmission line, circuit breaker, switch or other electrical element. An N-1 contingency

would include the trip of the NPP unit, the trip of the largest generator on the system,

trip of a transmission path or loss of a power transformer.
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Stability

The ability of an electric system to maintain a state of equilibrium during normal and

abnormal conditions or disturbances. The focus of this GL is on adequate offsite

voltage, not system stability.

Transmission Load Flow Analysis Tools (Analysis Tools)

Any controlled analysis tool that enables the TSO or the NPP licensee to predict the

resultant NPP offsite power voltage during plant operation for any N–1 contingency

defined above. It is not the intent that an analysis tool be a transient analysis program.

DISCUSSION

Use of protocols between the NPP licensee and the TSO, ISO, or RC/RA and the use of

analysis tools by TSOs to assist the NPP licensee in monitoring grid conditions to determine the

operability of offsite power systems under plant TSs.

A licensee’s ability to comply with TSs for offsite power may depend on grid conditions and

plant status; in particular, maintenance on, and degraded conditions of, key elements of the

plant switchyard and offsite power grid can affect the operability of the offsite power system,

especially during times of high grid load and high grid stress. A communication interface with

the plant’s TSO, together with training and other local means to maintain NPP operator

awareness of changes in the plant switchyard and offsite power grid, is important to enable the

licensee to determine the effects of these changes on the operability of the offsite power

system. The staff found a good deal of variability in the TI 2515/156 and TI 2515/163

responses on the use of these NPP licensee/TSO communication protocols. Some licensees

apparently rely on informal NPP licensee/TSO communication arrangements and long-term grid

studies without real-time control of operation to within the limits of the studies to assure offsite

power operability. However, the staff also learned that most TSOs serving NPP sites now

have, or will shortly have, an analysis tool.

Analysis tools give the TSO the capability to determine the impact of the loss or unavailability of

various transmission system elements (called contingencies) on the condition of the

transmission system. The transmission systems can generally cope with several contingencies

without undue impairment of grid reliability, but it is important that the NPP operator know when

the transmission system near the NPP can no longer sustain NPP voltage based on the TSO’s

analysis of a reasonable number of contingencies. This knowledge helps the operator

understand the general condition of the NPP offsite power system. To satisfy the maintenance

rule, the NPP operator should know the grid’s condition before taking a risk-significant piece of

equipment out-of-service, and should monitor it for as long as the equipment remains

out-of-service.

It is especially important that the NPP operator know when the trip of the NPP will result in

LOOP to the plant. As stated earlier, a reduction in NPP switchyard voltage due to a trip is the

main cause of a LOOP event. It is important to understand that the transmission systems can
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generally tolerate voltages lower than required by plant TS for NPP system, structures and

components (SSC) operability. As a result, the TSO will not necessarily keep the transmission

system voltage above the level needed for the NPP unless the TSO has been informed of the

needed voltage level and agreements have been formalized to maintain the voltage level.

It was not always clear from the data collected in accordance with TI 2515/156 whether the

TSO would notify the NPP licensee of inadequate transmission system contingency voltages or

inadequate voltages required for the NPP SSC operability.

Inadequate NPP contingency post-trip switchyard voltages will result in TS inoperability of the

NPP offsite power system due to actuation of NPP degraded voltage protection circuits during

certain events that result in an NPP trip. NPPs of certain designs have occasionally

experienced other inoperabilities in these circumstances (e.g., overloaded EDGs or loss of

certain safety features due to interaction with circuit breaker logic). Safety-related motors may

also be started more than once under these circumstances, which could result in operation

outside the motors’ specifications and actuation of overload protection. Unavailability of

plant-controlled equipment such as voltage regulators, transformer auto tap changers, and

generator automatic voltage regulation can contribute to the more frequent occurrence of

inadequate NPP post-trip voltages.

Analysis tools in use by the TSOs, together with properly implemented NPP licensee/TSO

communication protocols and training, can keep NPP operators better informed about

conditions affecting the NPP offsite power system. However, the analysis tools are not always

available to the TSO. This was the case during the period leading up to the August 14, 2003,

blackout; and events have shown that the data used in the programs sometimes do not

represent actual conditions and capabilities. These shortcomings have been offset to some

degree by notification of the unavailability of analysis tools to NPP operators. The NPP

operators then perform operability determinations to assess post-trip switchyard voltages

following inadvertent NPP trips.

Use of NPP licensee/TSO protocols and analysis tools by TSOs to assist NPP licensees in

monitoring grid conditions for consideration in maintenance risk assessments

As discussed above (when warranted by worsening grid conditions, etc.), grid reliability

evaluations should be performed as part of the maintenance risk assessment required by

10 CFR 50.65 (or in any reassessment). To perform meaningful and comprehensive grid

reliability evaluations (or reevaluations as appropriate), it is essential that the NPP licensee

communicate with the TSO before, and periodically for the duration of, grid-risk-sensitive

maintenance activities. The communication between the NPP licensee and its TSO should

enable the NPP operator to obtain up-to-date information on existing and projected grid

reliability for use in maintaining a current and valid maintenance risk assessment and in

managing possibly changing risk. The communication with the TSO should include whether a

loss of the NPP’s electrical output could impact the local grid, as do two of the three types of

grid-risk-sensitive maintenance (activities that increase the likelihood of (1) a plant trip and (2) a

LOOP).
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With regard to risk management, an internal NRC expert panel convened to obtain short-term,

grid-related risk insights found that it is important to have effective NPP configuration risk

management (including the maintenance risk management required by Section 50.65(a)(4))

when grid reliability is degraded or threatened. In particular, a potentially significant increase in

NPP risk may occur if equipment required to prevent and mitigate station blackout is

unavailable when the grid is degraded. Recent NRC studies have found that since 1997, LOOP

events have occurred more frequently during the summer (May through October) than before

1997, that the probability of a LOOP event due to a reactor trip has also increased during the

summer months, and the durations of LOOP events have generally increased. The staff is

concerned about extended maintenance activities scheduled for equipment required to prevent

and mitigate station blackout during, periods that may be more susceptible to a LOOP

especially in areas of the country that may also experience a high level of grid stress.

The staff found a good deal of variability in the data collected in accordance with TI 2515/156

and TI 2515/163 regarding grid reliability evaluations performed when warranted as discussed

above, as part of the maintenance risk assessment required by 10 CFR 50.65. Some licensees

communicate routinely with their TSOs once per shift to determine grid conditions, while others

rely solely on the TSOs to inform them of deteriorating grid conditions and do not inquire about

grid conditions before performing grid-risk-sensitive maintenance activities. Some licensees do

not consider the NPP post-trip switchyard voltages in their evaluations, and some do not

coordinate grid-risk-sensitive maintenance with their TSOs. The NPP licensee/TSO

communication protocol is a useful tool for obtaining the information necessary for the grid

reliability evaluations that should be performed, when warranted, as discussed above, as part of

the maintenance risk assessment required by 10 CFR 50.65. The protocol is also useful in

effectively implementing the guidance in the 2000 revision of Section 11 of NUMARC 93-01,

Rev. 2, on reassessing plant risk in light of emergent conditions. As discussed under the

previous topic, the analysis tools available to most TSOs give them the capability to determine

the impact of various transmission system contingencies on the condition of the transmission

system. It is important that the NPP operator know when the transmission system near the

NPP cannot sustain a reasonable level of contingencies. In summary, the NPP operator should

know and stay informed of the general condition of the NPP offsite power system and be

adequately trained to assess and manage risk under the Maintenance Rule before performing

and for the duration of grid-risk-sensitive maintenance activities (i.e., activities that could

increase risk under degraded grid reliability conditions).

Offsite power restoration procedures in accordance with Section 2 of RG 1.155

LOOP events can also have numerous unpredictable initiators such as natural events, potential

adversaries, human error, or design problems. Pursuant to 10 CFR 50.63, “Loss of all

alternating current power,” the NRC requires that each NPP licensed to operate be able to

withstand an SBO for a specified duration and recover from the SBO. NRC RG 1.155 provides

NRC guidance for licensees on developing their approaches for complying with 10 CFR 50.63.

Section 2 of RG 1.155 provides guidance on the procedures necessary to restore offsite power,

including losses following “grid undervoltage and collapse.” Section 2 states: “Procedures

should include the actions necessary to restore offsite power and use nearby power sources

when offsite power is unavailable.”
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Preestablished agreements between NPP licensee and TSOs that identify local power sources

and transmission paths that could be made available to resupply NPPs following a LOOP event

and NPP operator training help to minimize the durations of LOOP events, especially

unpredictable LOOP events. Discussions with NPP licensees indicate that some licensees do

not have such agreements in place, but instead only attempt restoration of their EDGs following

a potential SBO. RIS 2004-05 states that NPP licensees should have procedures available

consistent with the guidance in Section 2 of RG 1.155 for restoration of offsite power following a

LOOP or SBO event.

Losses of offsite power caused by grid failures at a frequency equal to or greater than once in

20 site-years in accordance with RG 1.155

The data collected in accordance with TI2515/156 indicate that grid failures that caused total

loss of offsite power at some nuclear power plants have occurred since the nuclear power

plants were initially analyzed in accordance with the criteria in RG 1.155. The staff is

concerned that these nuclear power plants have not been reanalyzed to determine whether

their SBO coping durations have remained consistent with the guidance in RG 1.155 after these

LOOP events. The staff is also concerned that some plants may be inappropriately eliminating

some of these grid events from their operating experience database.

Thus, power reactor licensees may depend on information obtained from their TSOs to make

operability determinations for TS compliance, to perform risk assessments under the

Maintenance Rule, and to assure compliance with the SBO Rule. Accordingly, the NRC staff is

requesting information on such matters from addressees.

However, the NRC staff has not identified any corrective actions that might be warranted.

APPLICABLE REGULATORY REQUIREMENTS

GDC 17 and plant TSs

For NPPs licensed in accordance with the GDC in Appendix A to 10 CFR Part 50, the design

criteria for onsite and offsite electrical power systems are provided in GDC 17. For NPPs not

licensed in accordance with the GDC in Appendix A, the applicable design criteria are provided

in the updated final safety analysis report. These reports set forth criteria similar to GDC 17,

which requires, among other things, that an offsite electric power system be provided to permit

the functioning of certain SSCs important to safety in the event of anticipated operational

occurrences and postulated accidents.

The transmission network (grid) is the source of power to the offsite power system. The final

paragraph of GDC 17 requires, in part, provisions to minimize the probability of the loss of

power from the transmission network given a loss of the power generated by the nuclear power

unit(s). The loss of the power generated by the nuclear power unit (trip) is an anticipated

operational occurrence. The offsite power circuits must therefore be designed to be available

following a trip of the unit(s) to permit the functioning of SSCs necessary to respond to the

event.
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The trip of an NPP can affect the grid so as to result in a LOOP. Foremost, among such effects

is a reduction in the plant’s switchyard voltage as a result of the loss of the reactive power

supply to the grid from the NPP’s generator. If the voltage is low enough, the plant’s degraded

voltage protection could actuate and separate the plant safety buses from offsite power.

Less likely results of the trip of a nuclear plant are grid instability, potential grid collapse, and

subsequent LOOP due to the loss of the real and/or reactive power support supplied to the grid

from the plant’s generator.

In general, plant TSs require the offsite power system to be operable as part of the limiting

condition for operation and specify actions to be taken when the offsite power system is not

operable. Plant operators should therefore be aware of (1) the capability of the offsite power

system to supply power, as specified by TS, during operation and (2) situations that can result

in a LOOP following a trip of the plant. If the offsite power system is not capable of providing

the requisite power in either situation, the system should be declared inoperable and pertinent

plant TS provisions followed.

10 CFR 50.65

Section 50.65(a)(4) requires that licensees assess and manage the increase in risk that may

result from proposed maintenance activities before performing the maintenance activities.

These activities include, but are not limited to, surveillances, post-maintenance testing, and

corrective and preventive maintenance. The scope of the assessment may be limited to SSCs

that a risk-informed evaluation process has shown to be significant to public health and safety.

In NRC RG 1.182, the NRC endorsed the February 22, 2000, revision to Section 11 of

NUMARC 93-01, Revision 2, as providing acceptable methods for meeting 10 CFR 50.65(a)(4).

(The revised Section 11 was later incorporated into Revision 3 of NUMARC 93-01.) 

The revised Section 11 addressed grid stability and offsite power availability in several areas.

Section 11.3.2.8 states that:

emergent conditions may result in the need for action prior to conduct of the

assessment, or could change the conditions of a previously performed

assessment. Examples include plant configuration or mode changes, additional

SSCs out of service due to failures, or significant changes in external conditions

(weather, offsite power availability) [emphasis added].

Additionally, Section 11.3.4 states that “the assessment for removal from service of a single

SSC for the planned amount of time may be limited to the consideration of unusual external

conditions that are present or imminent (e.g., severe weather, offsite power instability)”

[emphasis added].

Accordingly, licensees should perform grid reliability evaluations as part of the maintenance

risk assessment required by 10 CFR 50.65 before performing “grid-risk-sensitive” maintenance

activities (such as surveillances, post-maintenance testing, and preventive and corrective

maintenance). Such activities are those which could increase risk under existing or imminent

degraded grid reliability conditions, including (1) conditions that could increase the likelihood of
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a plant trip, (2) conditions that could increase the likelihood of LOOP or SBO, and (3) conditions

impacting the plant’s ability to cope with a LOOP or SBO, such as out-of-service risk-significant

equipment (e.g., an EDG, a battery, a steam-driven pump, an alternate AC power source, etc.).

The likelihood of LOOP and SBO should be considered in the maintenance risk assessment,

whether quantitatively or qualitatively. If the grid reliability evaluation indicates that degraded

grid reliability conditions may exist during maintenance activities, the licensee should consider

rescheduling any grid-risk-sensitive maintenance activities (i.e., activities that tend to increase

the likelihood of a plant trip, increase LOOP frequency, or reduce the capability to cope with a

LOOP or SBO). If there is some overriding need to perform grid-risk-sensitive maintenance

activities under existing or imminent conditions of degraded grid reliability, the licensee should

consider alternate equipment protection measures and compensatory actions to manage the

risk.

With regard to conditions that emerge during a maintenance activity in progress,

Section 11.3.2.8 in the 2000 revision to Section 11 of NUMARC 93-01 states that emergent

conditions could change the conditions of a previously performed risk assessment. Offsite

power availability is one example given of an emergent condition that could change the

conditions of a previously performed risk assessment. Licensees should reassess the plant risk

in view of an emergent condition that affects an existing maintenance risk assessment, except

as discussed below, and should take a worsening grid condition into account when doing so.

However, as discussed in the Statements of Consideration for 10 CFR 50.65(a)(4) and also in

the associated industry guidance (revised Section 11 of NUMARC 93-01), this reassessment of

the risk should not interfere with or delay measures to place and maintain the plant in a safe

condition, in general, or in response to or preparation for the worsening grid conditions.

Note also that as discussed in the Statements of Consideration for 10 CFR 50.65(a)(4) and also

in the associated industry guidance (revised Section 11 of NUMARC 93-01, Revision 3), if the

emergent condition (including degrading grid reliability) is corrected (or ceases to exist) before

the risk reassessment is completed, the reassessment need not be completed.

10 CFR 50.63

Pursuant to 10 CFR 50.63, “Loss of all alternating current power,” the NRC requires that each

NPP licensed to operate be able to withstand an SBO for a specified duration and recover from

the SBO. NRC RG 1.155 provides guidance for licensees to use in developing their approach

for complying with 10 CFR 50.63. A series of tables in the RG define a set of pertinent plant

and plant site parameters that have been found to affect the likelihood of a plant experiencing

an SBO event of a given duration. Using the tables allows a licensee to determine a plant’s

relative vulnerability to SBO events of a given duration and identify an acceptable minimum

SBO coping duration for the plant.

With regard to grid-related losses of offsite power, Table 4 in RG 1.155 indicates that the

following plant sites should be assigned to Offsite Power Design Characteristic Group P3:

Sites that expect to experience a total loss of offsite power caused by grid

failures at a frequency equal to or greater than once in 20 site-years, unless the

site has procedures to recover AC power from reliable alternative
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(nonemergency) AC power sources within approximately one-half hour following

a grid failure.

The majority of U.S. NPPs fall into the four hour minimum coping capability category set forth in

RG 1.155. However, Table 2 in RG 1.155 indicates that a typical plant with two redundant

EDGs per nuclear unit should have at least an eight hour minimum coping duration if it falls into

the P3 group. Therefore, plants that have experienced a grid-related LOOP that were

evaluated in accordance with the SBO guidance in RG 1.155 may no longer be consistent with

that guidance.

Section 2 of RG 1.155 provides guidance on the procedures necessary to restore offsite power,

including losses following “grid undervoltage and collapse.” Section 2 states: “Procedures

should include the actions necessary to restore offsite power and use nearby power sources

when offsite power is unavailable.” These procedures are a necessary element in minimizing

LOOP durations following a LOOP or SBO event.

10 CFR 55.59 and 10 CFR 50.120

Pursuant to 10 CFR 55.59(c)(2), operator requalification programs must include preplanned

lectures on a regular basis throughout the license period in areas where operator and senior

operator written examinations and facility operating experience indicate that more scope and

depth of coverage is needed in the following subjects:

(i) Theory and principles of operation;

(ii) General and specific plant operating characteristics;

(iii) Plant instrumentation and control systems;

(iv) Plant protection systems;

(v) Engineered safety systems;

(vi) Normal, abnormal, and emergency operating procedures;

(vii) Radiation control and safety;

(viii) Technical specifications; and

(ix) Applicable portions of Title 10, Chapter I, Code of Federal Regulations.

Section 55.59(c)(3)(i) requires operator requalification programs to include on-the-job training

on a number of control manipulations and plant evolutions if they are applicable to the plant

design; the loss of electrical power (or degraded power sources) is but one of the evolutions to

be performed annually by each operator. Moreover, 10 CFR 55.59(c)(3)(iv) requires each

licensed operator and senior operator to review the contents of all abnormal and emergency

procedures on a regularly scheduled basis.

In addition, 10 CFR 55.59(c) states that, in lieu of the programs specified in 10 CFR 55.59(c)(2)

and (3) above, the Commission may approve a program developed by using a systems

approach to training (SAT).

According to 10 CFR 50.120, each nuclear power plant licensee must establish, implement, and

maintain a SAT-based program for training and qualifying nonlicensed operators, shift
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supervisors, and electrical and mechanical maintenance personnel (among several other job

categories). The training program must be periodically evaluated and revised as appropriate to

reflect industry experience and changes to the facility and procedures (among other things).

SAT-based training programs, which are developed, implemented, and maintained by facility

licensees and accredited by the National Nuclear Accrediting Board, should incorporate lessons

learned as a result of industry operating events, such as the 2003 blackout. The NRC staff

routinely monitors the industry’s accreditation process, administers the initial operator licensing

examinations, conducts biennial licensed operator requalification training program inspections,

and retains authority to conduct for-cause training program inspections. However, these

activities do not provide the staff with information sufficient to verify that all facility licensee

training programs have adequately captured the importance of grid conditions and offsite power

issues in advance of the 2006 peak summer cooling season. Accordingly, the staff has

included questions on operator training in the information requested below.

REQUESTED INFORMATION

In accordance with 10 CFR 50.54(f), addressees are required to submit written responses to

this GL within 60 days of its date.

In their responses, addressees are requested to answer the following questions and provide the

information to the NRC with respect to each of their NPPs:

Use of protocols between the NPP licensee and the TSO, ISO, or RC/RA and the use of

analysis tools by TSOs to assist NPP licensee in monitoring grid conditions to determine the

operability of offsite power systems under plant TS.

GDC 17, 10 CFR Part 50, Appendix A, requires that licensees minimize the probability of the

loss of power from the transmission network given a loss of the power generated by the nuclear

power unit(s).

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 TS.

(a) Do you have a formal agreement or protocol with your TSO?

(b) Describe any grid conditions that would trigger a notification from the TSO to the

NPP licensee and if there is a time period required for the notification.

(c) Describe any grid conditions that would cause the NPP licensee to contact the TSO.

Describe the procedures associated with such a communication. If you do not have

procedures, describe how you assess grid conditions that may cause the NPP licensee

to contact the TSO.
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(d) Describe how NPP operators are trained and tested on the use of the procedures or

assessing grid conditions in question 1(c).

(e) If you do not have a formal 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 formal interconnection agreement or protocol that ensures

adequate communication and 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 licensees using allowable value

in its TSs) or LOOP after a trip of the reactor unit(s).

(g) Describe the low switchyard voltage conditions that would initiate operation of plant

degraded voltage protection.

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 any analysis tools, an online analytical transmission

system studies program, or other equivalent predictive methods to determine the grid

conditions that would make the NPP offsite power system inoperable during various

contingencies? If available to you, please provide a brief description of the analysis tool

that is used by the TSO.

(b) Does your NPP’s TSO use an analysis tool as the basis for 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 notification?

(c) If your TSO uses an analysis 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 not, discuss how such a condition would be identified on the grid.

(d) If your TSO uses an analysis tool, how frequently does the analysis tool program

update?

(e) Provide details of analysis tool-identified contingency conditions that would trigger an

NPP licensee notification from the TSO.

(f) If an interface agreement exists between the TSO and the NPP licensee, does it

require that the NPP licensee be notified of periods when the TSO is unable to
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determine if offsite power voltage and capacity could be inadequate? If so, how does

the NPP licensee determine that the offsite power would remain operable when such a

notification is received?

(g) After an unscheduled inadvertent trip of the NPP, are the resultant switchyard

voltages verified by procedure to be bounded by the voltages predicted by the analysis

tool?

(h) If an analysis tool is not available to the NPP 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 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 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?

(j) If your TSO does not use, or you do not have access 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 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.

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 operator that a trip of the NPP, or the loss of the most

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 plant degraded voltage protection, is the NPP offsite power system declared

inoperable under the plant TSs? If not, why not?

(b) If onsite safety-related equipment (e.g., emergency diesel generators or

safety-related motors) is lost when subjected to a double sequencing (LOCA with

delayed LOOP event) as a result of the anticipated system performance and is 
GL 2006-02

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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?

(c) Describe your evaluation of onsite safety-related equipment to determine whether it

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

(d) If the NPP licensee is notified by the TSO of other grid conditions that may impair the

capability or availability of offsite power, are any plant TS action statements entered?

If so, please identify them.

(e) If you believe your plant TSs do not require you to declare your offsite power system

or safety-related equipment 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 switchyard voltages are

inadequate.

(f) Describe if and how NPP operators are trained and tested on the compensatory

actions mentioned in your answers to questions 3(a) through (e).

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 any guidance or procedures in plant TS bases sections,

the final safety analysis report, or plant procedures regarding situations in which the

condition of plant-controlled or -monitored equipment (e.g., voltage regulators, auto tap

changing transformers, capacitors, static VAR 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, the final safety analysis report, 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 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.

Use of NPP licensee/TSO protocols and analysis tool by TSOs to assist NPP licensees in

monitoring grid conditions for consideration in maintenance risk assessments

The Maintenance Rule (10 CFR 50.65(a)(4)) requires that licensees assess and manage the

increase in risk that may result from proposed maintenance activities before performing them.

5. Performance of grid reliability evaluations as part of the maintenance risk assessments

required by 10 CFR 50.65(a)(4).
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(a) Is a quantitative or qualitative grid reliability evaluation performed at your NPP as

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

performing grid-risk-sensitive maintenance activities? This includes surveillances, 

post-maintenance testing, and preventive and corrective 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 some means for the duration of the grid-risk-sensitive

maintenance to confirm the continued validity of the risk assessment and is risk

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

maintenance?

(c) Is there a significant variation in the stress on the grid in the vicinity of your NPP site

caused by seasonal loads or maintenance activities associated with critical transmission

elements? Is there a seasonal variation (or the potential for a seasonal variation) in the

LOOP frequency in the local transmission region? If the answer to either question is

yes, discuss the time of year when the variations occur and their magnitude.

(d) Are known time-related variations in the probability of a 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 TSO to determine current and anticipated grid

conditions as part of the grid reliability evaluation performed before conducting

grid-risk-sensitive maintenance activities?

(f) Describe any formal agreement or protocol that you have with your TSO to assure

that you are promptly alerted to a worsening grid condition that may emerge during a

maintenance activity.

(g) Do you contact your TSO periodically for the duration of the grid-risk-sensitive

maintenance activities?

(h) If you have a formal agreement or protocol with your TSO, describe how NPP

operators and maintenance personnel are trained and tested on this formal agreement

or protocol.

(i) If your grid reliability evaluation, performed as 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).

(j) If risk is not assessed (when warranted) based on continuing communication with the

TSO throughout the duration of grid-risk-sensitive maintenance activities, explain why 
GL 2006-02

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you believe you have effectively implemented the relevant provisions of the endorsed

industry guidance associated with the maintenance rule.

(k) With respect to questions 5(i) and 5(j), 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.

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 transmission system maintenance activities that can have

an impact on the NPP operation with the NPP operator?

(b) Do you coordinate NPP maintenance activities that can have an impact on the

transmission system with the TSO?

(c) Do you consider and implement, if warranted, the 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 to perform grid-risk-sensitive maintenance activities

under existing or imminent conditions of degraded grid reliability, or continue

grid-risk-sensitive maintenance when grid conditions worsen, do you 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 associated with questions 6(a) through 6(d) 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.

(f) Describe how NPP operators and maintenance personnel are trained and tested to

assure they can accomplish the actions described in your answers to question 6(e).

(g) If there is no effective coordination between the NPP operator and the TSO

regarding transmission 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 effectively implement 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.
GL 2006-02

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2 This includes items such as nearby or onsite gas turbine generators, portable

generators, hydro generators, and black-start fossil power plants. 

(i) You may, as an alternative 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).

Offsite power restoration procedures in accordance with 10 CFR 50.63 as developed in

Section 2 of RG 1.155

Pursuant to 10 CFR 50.63, the NRC requires that each NPP licensed to operate be able to

withstand an SBO for a specified duration and recover from the SBO. NRC RG 1.155 gives

licensees guidance on developing their approaches for complying with 10 CFR 50.63.

7. Procedures for identifying local power sources2 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 undervoltage 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 made with the TSO to identify local power sources

that could be made available to resupply power to your plant following a LOOP event. 

(b) Are your NPP operators trained and tested on identifying and using local power

sources to resupply your plant following a LOOP event? If so, describe how.

(c) If you have not established an agreement with your plant’s TSO to identify local

power sources that could be made available to resupply power to your plant following a

LOOP event, explain why you believe you comply with the provisions of 10 CFR 50.63,

or describe what actions you intend to take to establish compliance.
GL 2006-02

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Losses of offsite power caused by grid failures at a frequency of equal to or greater than once

in 20 site-years in accordance with Table 4 of Regulatory Guide 1.155 for complying with

10 CFR 50.63

Pursuant to 10 CFR 50.63, the NRC requires that each NPP licensed to operate be able to

withstand an SBO for a specified duration and recover from the SBO. NRC RG 1.155 gives

licensees guidance on developing their approaches for complying with 10 CFR 50.63.

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

(a) Has your NPP experienced a total LOOP caused by grid failure since the plant’s

coping duration was initially determined under 10 CFR 50.63?

(b) If so, have you reevaluated 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 of this reevaluation, and did the initially determined

coping duration for the NPP need to be adjusted?

(d) If your NPP has 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 50.63 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.

Actions to ensure compliance

9. If you determine that any action is warranted to bring your NPP 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.

REQUIRED RESPONSE

In accordance with 10 CFR 50.54(f), in order to determine whether a facility license should be

modified, suspended, or revoked, or whether other action should be taken, an addressee is

required to respond as described below.

An addressee should consult RIS 2005-26, “Control of Sensitive Unclassified Nonsafeguards

Information Related to Nuclear Power Reactors,” SECY-04-0191, “Withholding Sensitive

Unclassified Information Concerning Nuclear Power Reactors From Public Disclosure,” dated

October 19, 2004, and 10 CFR 2.390 to determine if its response contains sensitive 
GL 2006-02

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unclassified (nonsafeguards) information and should be withheld from public disclosure.

RIS 2005-26 and SECY-04-0191 are available on the NRC public Web site.

Within 60 days of the date of this GL, an addressee is required to submit a written response. If

an addressee is unable to provide the requested information or can not meet the requested

completion date, it must address in its response any alternative course of action that it proposes 

to take, including the basis for the acceptability of the proposed alternative course of action.

The required written response should be addressed to the U.S. Nuclear Regulatory

Commission, ATTN: Document Control Desk, 11555 Rockville Pike, Rockville, Maryland 20852,

under oath or affirmation under the provisions of Section 182a of the Atomic Energy Act of

1954, as amended, and 10 CFR 50.54(f). In addition, a copy of the response should be sent to

the appropriate regional administrator.

REASONS FOR INFORMATION REQUEST

This GL requests addressees to submit information. The requested information will enable the

NRC staff to determine whether applicable requirements (plant TSs in conjunction with 10 CFR

Part 50, Appendix A, General Design Criteria 17; 10 CFR 50.65(a)(4); 10 CFR 50.63; 10 CFR

55.59; and 10 CFR 50.120) are being met in regard to the grid topics addressed.

RELATED GENERIC COMMUNICATIONS

NRC Regulatory Issue Summary 2004-05, “Grid Reliability and the Impact on Plant Risk and

the Operability of Offsite Power,” dated April 15, 2004 (ADAMS Accession No. ML040990550).

BACKFIT DISCUSSION

Under the provisions of Section 182a of the Atomic Energy Act of 1954, as amended, and

10 CFR 50.54(f), this GL transmits an information request for the purpose of verifying

compliance with applicable existing requirements. Specifically, the requested information will

enable the NRC staff to determine whether applicable requirements (plant TSs in conjunction

with 10 CFR Part 50, Appendix A, General Design Criteria 17; 10 CFR 50.65(a)(4); 10 CFR

50.63; 10 CFR 55.59; and 10 CFR 50.120) are being met in regard to the grid topics

addressed. No backfit is either intended or approved in the context of issuance of this GL.

Therefore, the staff has not performed a backfit analysis.

FEDERAL REGISTER NOTIFICATION

A notice of opportunity for public comment on this GL was published in the Federal Register

(70 FR 19125) on April 12, 2005. Approximately 65 comments were received from 10 nuclear

entities comprising of utilities, owners groups, and nuclear organizations such as NEI; one

comment each was received from the Oak Ridge National Laboratory, the State of New Jersey,

the Department of Energy (Bonneville Power Administration), and Mr. K. M. Strickland. There

were 15 comments on GDC 17 and the use of a real-time contingency analysis program, 8

comments on the Maintenance Rule, 8 comments on the Station Blackout Rule, and 4

comments on applicable regulations and rules; 28 comments were categorized as
GL 2006-02

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miscellaneous since they could not be binned into other categories, and 1 comment was on

extending the response time of the proposed GL. The staff considered all comments that were

received. The staff’s evaluation of the comments is publicly available through the NRC’s

Agency wide Documents Access and Management System (ADAMS) under Accession No.

ML052440417. In accordance with Staff Requirements Memorandum-SECY-05-219, the staff

also held a public workshop on January 9 and 10, 2006, to seek the views of stakeholders. 

Changes were made to the draft GL following the public workshop. These changes were

described in a Commission memorandum (Accession No. ML060180334).

SMALL BUSINESS REGULATORY ENFORCEMENT FAIRNESS ACT

The NRC has determined that this action is not subject to the Small Business Regulatory

Enforcement Fairness Act of 1996.

PAPERWORK REDUCTION ACT STATEMENT

This generic letter contains information collection requirements that are subject to the

Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.). These information collections were

approved by the Office of Management and Budget (OMB), approval number 3150-0011, which

expires on February 28, 2007.

The burden to the public for these mandatory information collections is estimated to average

122 hours per response, including the time for reviewing instructions, searching existing data

sources, gathering and maintaining the data needed, and completing and reviewing the

information collection. Send comments regarding this burden estimate or any other aspect of

these information collections, including suggestions for reducing the burden, to the Records

and FOIA/Privacy Services Branch (T-5 F52), U.S. Nuclear Regulatory Commission,

Washington, DC 20555-0001, or by Internet electronic mail to INFOCOLLECTS@NRC.GOV;

and to the Desk Officer, Office of Information and Regulatory Affairs, NEOB-10202,

(3150-0011), Office of Management and Budget, Washington, DC 20503.
GL 2006-02

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Public Protection Notification

The NRC may not conduct or sponsor, and a person is not required to respond to, a request for

information or an information collection requirement unless the requesting document displays a

currently valid OMB control number.

CONTACT

Please direct any questions about this matter to the technical contact or the lead project

manager listed below.

 /RA/

Christopher I. Grimes, Director

Division of Policy and Rulemaking

Office of Nuclear Reactor Regulation

Technical Contact: Paul Gill, NRR

301-415-3316

Lead PM: Matthew W. McConnell, NRR

301-415-1597

Note: NRC generic communications may be found on the NRC public website,

http://www.nrc.gov under Electronic Reading Room/Document Collections.