View source for NRC Generic Letter 06-02, Grid Reliability and the Impact on Plant Risk and the Operability of Offsite Power


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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
GL 2006-02
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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.

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.
GL 2006-02
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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
GL 2006-02
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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).
GL 2006-02
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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.”
GL 2006-02
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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.
GL 2006-02
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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
GL 2006-02
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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
GL 2006-02
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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
GL 2006-02
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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.
GL 2006-02
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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
GL 2006-02
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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).
GL 2006-02
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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
Page 17 of 21
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
Page 19 of 21
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.
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