thereby reducing the reliability of the Bulk-Power System.
    1615. LPPC states that business reasons often drive a longer lead
time for outage planning to allow market participants to better
understand the congestion and market impacts of the planned outage.
LPPC believes that the Commission should exercise caution and avoid
adopting a business practice as part of the Reliability Standard.
Reliability concerns often dictate that an outage should not be planned
and set in stone too far in advance because the circumstances may
change. According to LPPC, the Commission should refrain from
prescribing a lead time that would cut into an operator's flexibility,
which is needed to respond to real-time situations.
    1616. In response to the Commission's question regarding the lead
time for planned outages, MidAmerican states that although it believes
that a requirement for extending the lead time will result in higher
costs and less flexibility, a two-week advance notice for planned
outages of 345 kV facilities and one-week advance notice for 161 and 69
kV facilities is appropriate. TVA proposes one-week advance notice for
all planned outages and recommends that TOP-003-0 should be modified to
include breaker outages within the meaning of the facilities that are
subject to advance notice for planned outages.
    1617. CAISO states that its current tariff provides for three days
of lead time for providing outage information and that this is a
standard practice throughout WECC. It maintains, however, that the
three-day lead time is not sufficient for the needed review and
coordination of outages. In fact, CAISO states that many ISOs and RTOs
are moving toward a lead time of either 30 days or 45 days prior to the
beginning of the outage month. CAISO contends that rather than basing
the outage information on a certain kV level, the emphasis should be on
facilities that may have a significant effect on congestion revenue
rights resource adequacy.
    1618. Entergy and FirstEnergy support the proposed modification to
include any facility below the thresholds that, in the opinion of the
transmission operator, balancing authority, or reliability coordinator,
will have a direct impact on the operation of the Bulk-Power System
subject to Requirement R1 for planned outage coordination. They
maintain that such a modification will provide the transmission
operator much needed flexibility. APPA, on the other hand, opposes the
proposal. APPA states that the Commission should allow the ERO in the
first instance to consider whether to add this specific requirement to
TOP-003-0. If the Commission is concerned that TOP-003-0 as it now
stands might ``not include all facilities that have a significant
impact on the operation of the Bulk-Power System,'' it should direct
NERC to consider that issue on remand using its Reliability Standards
development process.
    1619. Xcel notes that Requirement R4 of the Reliability Standard
provides that each reliability coordinator should resolve any potential
conflicts in scheduling of planned outages. Xcel argues that if a
reliability coordinator requires an entity to move its planned outage
to accommodate another entity's unplanned outage, the entity that
agrees to move its planned outage to another time should receive
compensation.
ii. Commission Determination
    1620. The Commission approves TOP-003-0 as mandatory and
enforceable. We address the concerns raised by commenters below.
    1621. In Order No. 890, the Commission directed that information
concerning ATC calculations be consistent and transparent.\409\ The
timing of facility outages is one important piece of information in ATC
calculations. In Order No. 890, the Commission directed that specific
data be exchanged among transmission providers, including transmission
planned and contingency outages, for the purpose of ATC modeling.\410\
Consistent with this determination in Order No. 890, the Commission
directs the ERO to develop a modification to TOP-003-0 that requires
the communication of scheduled outages to all affected entities well in
advance to ensure reliability and accuracy of ATC calculations.\411\ We
believe this addresses LPPC's concern regarding the interplay between
reliability and business practices.
    1622. Several commenters raised concerns regarding the Commission's
proposal to require outage information well in advance. Specifically,
they argue that the term ``well in advance'' is vague, that the
requirement would reduce flexibility and that it would cause entities
to postpone needed maintenance work, thereby reducing reliability. In
response to the Commission's request for comments on lead time for
planned outages, entities provide information on current lead time
practices indicating that lead times range from one week to 45 days. We
direct the ERO to modify the Reliability Standard to incorporate an
appropriate lead time for planned outages. The ERO should utilize the
information filed by commenters in the Reliability Standards
development process. In doing so the ERO should take into consideration
the need for flexibility, as well the lead time required for
coordination with other entities and outage assessments. Proper
coordination will ensure that priority is given to needed maintenance
work for critical facilities to ensure reliability.
---------------------------------------------------------------------------

    \409\ See Order No. 890 at P 68-69, 207-213.
    \410\ Id. at P 292.
    \411\ The Commission notes that PJM has developed an outage
scheduling process in response to Commission directives to avoid the
possibility of undue discrimination. http://www.pjm.com/committees/mrc/downloads/20060630-item-06-draft-manual-14b-changes.pdf.
 The

outage scheduling process was developed through a stakeholder
process and has been utilized in the entire PJM footprint for a
number of years. PJM's outage scheduling program is one example of
the type of program that should be implemented through the
Reliability Standard.
---------------------------------------------------------------------------

    1623. With regard to TVA's request to include breaker outages
within the meaning of the facilities that are subject to advance notice
for planned outages, we direct the ERO to consider this suggestion in
the Reliability Standards development process.
(a) Applicability
    1624. As noted above, the Commission proposed to direct the ERO to
modify TOP-003-0 to make any facility below the thresholds that, in the
opinion of the transmission operator, balancing authority, or
reliability coordinator, will have a direct impact on the operation of
Bulk-Power System subject to Requirement R1 for planned outage
coordination.
    1625. Entergy and FirstEnergy support the proposed modification to
include any facility below the threshold that in the opinion of the
reliability coordinator, balancing authority or transmission operator
will have a direct impact on the operation of the Bulk-Power System. On
the other hand, APPA opposes this proposal and contends that the
Commission should allow the ERO, as the expert entity charged with
developing Reliability Standards, to consider whether to add this
specific requirement. The Commission disagrees because registered
entities below the thresholds currently defined in Requirement R1 of
the Reliability Standard may have an impact on reliability and
therefore should be required to submit data on their planned outages.
The Commission therefore directs the ERO to modify the

Reliability Standard to require that any facility below the thresholds
that, in the opinion of the transmission operator, balancing authority,
or reliability coordinator will have a direct impact on the reliability
of the Bulk-Power System be subject to Requirement R1 for planned
outage coordination.
(b) Other Issues
    1626. In response to Xcel's proposal that entities that agree to
reschedule their previously-approved planned outages to accommodate
another entity's unplanned outage be compensated, the Commission notes
that whereas rescheduling of the outage is a reliability matter,
compensation is not and therefore is outside the scope of this
proceeding.
(c) Summary of Commission Determination
    1627. Planned outage coordination is a necessary element of
reliable operations, and TOP-003-0 promotes that goal. Accordingly, the
Commission approves the Reliability Standard as mandatory and
enforceable. In addition, pursuant to section 215(d)(5) of the FPA and
Sec.  39.5(f) of our regulations, the Commission directs the ERO to
develop a modification to TOP-003-0 through the Reliability Standards
development process that: (1) Includes a new requirement to communicate
longer term outages well in advance to ensure reliability and accuracy
of ATC calculation; (2) makes any facility below the voltage thresholds
that, in the opinion of the transmission operator, balancing authority,
or reliability coordinator, will have a direct impact on the operation
of Bulk-Power System, subject to Requirement R1 for planned outage
coordination and (3) incorporates an appropriate lead time for planned
outages as discussed above.
d. Transmission Operations (TOP-004-1)
    1628. This Reliability Standard requires transmission operators to
operate the transmission system within SOL and IROL.\412\ The N-1
operating criterion for the transmission system is also established in
this Reliability Standard. It provides that operating configurations
for which limits have not yet been determined should be treated as
emergencies. The goal of the Reliability Standard is to maintain Bulk-
Power System facilities within limits, thereby protecting transmission,
generation, distribution and customer equipment and preventing
cascading failures of the interconnected grid.
    1629. The Commission proposed in the NOPR to approve the
Reliability Standard as mandatory and enforceable. In addition, the
Commission proposed to direct that NERC submit a modification that: (1)
Includes Measures and Levels of Non-Compliance; (2) clarifies that the
system should be restored as soon as possible, taking no more than 30
minutes and (3) defines high risk conditions under which the system
must be operated to respect multiple outages in Requirement R3. The
Commission also proposed to direct the ERO to perform a survey of the
prevailing operating practices and actual operating experiences
surrounding drifting in and out of IROL limits.
    1630. Requirement R3 requires that each transmission operator
shall, when practical, operate the system to respect multiple outages
as specified by the regional reliability organization policy. The
Commission noted in the NOPR that Requirement R3 does not define
conditions under which multiple outages must be considered. The NOPR
proposed to interpret such conditions ``to include high risk conditions
such as hurricanes, ice storms or periods of high solar magnetic
disturbances during which the probability of multiple outages
approaches that of a single element outage.'' \413\
i. Comments
    1631. PG&E and APPA oppose a modification to the Reliability
Standard that changes the requirement allowing operators to return the
system to a reliable operating state within 30 minutes to a requirement
that they do so as soon as possible and in no longer than 30 minutes.
PG&E is concerned that during emergencies operators would be subject to
uncertainty in complying with such a requirement, which could lead to
overly hasty responses with a corresponding detrimental effect on
reliability. PG&E states that to avoid the confusion and ambiguity from
a subjective standard, the Commission and NERC should only clarify that
operators should seek to return the system to a reliable operating
state as soon as possible, but maintain the current requirement of 30
minutes as stated in Requirement R4 of TOP-004-1. APPA states that if
the Commission is concerned about the need to require a response time
that is quicker than 30 minutes, it should direct the ERO to consider
this issue as part of the Reliability Standards development process.
    1632. Entergy and MidAmerican support the Commission's proposal to
have NERC conduct a survey and report the operating practices and
actual experiences surrounding drifting in and out of IROL violations.
MISO, on the other hand, opposes the survey because there are already
requirements for reporting IROL violations elsewhere in the Reliability
Standards. APPA proposes that the Commission should ask the ERO to
determine if such information would improve reliable operations. If it
is determined that such information will improve reliability, NERC
should include this type of information in compliance violation
reporting procedures.
    1633. LPPC and Xcel recommend that the Commission not require NERC
to define in Requirement R3 the specific high-risk conditions under
which the system must be operated to respect multiple outages. Xcel
argues that it is unnecessary and impractical to attempt to define in
advance all of the possible scenarios that will result in a high-risk
condition. Not all high-risk conditions can be defined at any one time
because changes in the system will introduce new high-risk conditions.
Even if a list of high-risk conditions is developed, then, by
definition, all other conditions not listed are excluded from
consideration under this Reliability Standard. LPPC states that the
proposed modification to deal with high-risk conditions is an
unnecessarily prescriptive approach and could be detrimental to
reliability by excluding scenarios that should be listed under this
Requirement.
---------------------------------------------------------------------------

    \412\ In its November 15, 2006, filing, NERC submitted TOP-004-
1, which has an effective date of October 1, 2007, at which time it
will supercede the Version 0 Reliability Standard. TOP-004-1 adds
Measures and Levels of Non-Compliance to the Version 0 Reliability
Standard. Because TOP-004-0 will be in effect until October 1, 2007
and TOP-004-1 thereafter, we address both versions of the
Reliability Standard.
    \413\ NOPR at P 997.
---------------------------------------------------------------------------

    1634. California PUC states that the Commission should not
interpret hurricanes and ice storms as high risk conditions for
studying multiple outages because events such as hurricanes and ice
storms actually reduce the stress on the Bulk-Power System. This is
because such events cause outages at the local distribution system
level. California PUC maintains that since events such as hurricanes
and ice storms rarely cause cascading outages, the proper approach for
dealing with such situations is to focus on system restoration planning
rather than including them in the contingency analysis that the
proposed modification will require as a result of including such
natural events within the meaning of high risk conditions.
    1635. Santa Clara states that Requirement R2 of the Reliability
Standard should be revised to include

frequency monitoring in addition to the monitoring of voltage, real and
reactive power flows.
ii. Commission Determination
    1636. The Commission approves TOP-004-0 as mandatory and
enforceable until October 1, 2007, when TOP-004-1 will be mandatory and
enforceable. We address the concerns raised by commenters below.
    1637. We adopt our proposal to require the ERO to clarify that the
system should be restored as soon as possible, taking no more than 30
minutes. Requirement R4 of TOP-004-1 (as well as the Version 0
standard) provides that if a transmission operator enters an unknown
state, i.e., any state for which valid operating limits have not been
determined, operations should be restored to respect proven reliable
power system limits within 30 minutes. However, as we stated in the
NOPR, this language may be interpreted as a grace period to the
detriment of reliability.\414\ The Commission, therefore, directs that
the ERO develop a modification to Requirement R4 providing that the
system should be restored to respect proven reliable power system
limits as soon as possible and in no longer than 30 minutes. In
response to PG&E's point that the phrase ``as soon as possible'' would
add confusion, we note that Measure M1 in TOP-004-1 would measure
performance against the 30-minute period specified in Requirement R4.
---------------------------------------------------------------------------

    \414\ See NOPR at P 995.
---------------------------------------------------------------------------

    1638. Entergy and MidAmerican support our proposal to direct the
ERO to conduct a survey and report the operating practices and actual
experiences surrounding drifting in and out of IROL violations. We
disagree with MISO that TOP-007-0 covers reporting of ``drifting'' in
and out of IROL violations because that Reliability Standard only
requires reporting of IROL violations exceeding 30 minutes. With regard
to APPA's suggestion that NERC should determine whether such
information would improve reliable operations, we believe a survey is
appropriate to determine actual practices, and simply modifying the
compliance reporting procedures may not provide sufficient data to
determine the reliability impacts of such practices and whether a
modification to the Reliability Standard is appropriate. Accordingly,
we direct the ERO to conduct a survey on the operating practices and
actual experiences surrounding drifting in and out of IROL violations.
Such a survey will provide factual support for whether additional
modifications to the Reliability Standard are needed. The survey will
also indicate whether additional vigilance on the part of compliance
auditors is warranted in this area to ensure Bulk-Power System
reliability.
    1639. As mentioned above, the Commission proposed to interpret
``multiple outages'' in the context of Requirement R3 to include
multiple element outages resulting from high-risk conditions such as
hurricanes, wild fires, ice storms or periods of high solar magnetic
disturbances during which the probability of multiple outages
approaches that of a single element outage. This is not an exhaustive
list but is meant to contain illustrative examples, and the Reliability
Standards development process should develop a procedure to identify
applicable high risk conditions. Under the high-risk conditions, the
Commission understands that systems are normally operated in a more
secure manner so that the Bulk-Power System can withstand multiple
outages. These multiple outages exceed the normal N-1 criterion because
the probability of multiple outages during high-risk conditions
approaches that of a single outage during normal conditions. This does
not preclude development of restoration plans as suggested by
California PUC. Thus, we direct the ERO to develop a modification to
the Reliability Standard that explicitly incorporates this
interpretation with the details identified in the Reliability Standards
development process.
    1640. We direct the ERO to consider Santa Clara's suggestion
regarding changes to Requirement R2 in the Reliability Standards
development process.
    1641. Accordingly, the Commission approves Reliability Standard
TOP-004-0. Further, we approve TOP-004-1 so that it will become
mandatory and enforceable on the stated effective date of October 1,
2007. In addition, pursuant to section 215(d)(5) of the FPA and Sec.
39.5(f) of our regulations, the Commission directs the ERO to develop a
modification to the Reliability Standard through the Reliability
Standards development process that: (1) Modifies Requirement R4 to
state that the system should be restored to respect proven limits as
soon as possible, taking no more than 30 minutes and (2) defines high
risk conditions under which the system must be operated to respect
multiple outages in Requirement R3, consistent with the discussion
above.
    1642. In addition, the Commission directs the ERO to perform a
survey of the prevailing operating practices and actual operating
experiences surrounding drifting in and out of IROL limits as discussed
more fully in this Final Rule in connection with the IRO group of
Reliability Standards. As an example of the type of data that would be
appropriate in the survey, we would expect to have reliability
coordinators report any violation of an IROL not exceeding 30 minutes,
its causes, the date and time of the violation, and the duration for
which actual operations exceeded IROL to the ERO on a monthly basis for
one year beginning two months after the effective date of the Final
Rule. The ERO should report the results to the Commission in an
informational filing within 18 months from the effective date of this
Final Rule.
e. Operational Reliability Information (TOP-005-1)
    1643. Reliability Standard TOP-005-1 seeks to ensure that
reliability information is shared among reliability coordinators,
transmission operators and balancing authorities. It requires the
transmission operator and the balancing authority to provide operating
data to each other and to the reliability coordinator, and it provides
a list of typical operating data that must be provided. TOP-005-1 also
provides that each data recipient must execute a confidentiality
agreement as a condition of receiving data from NERC's Interregional
Security Network.\415\
---------------------------------------------------------------------------

    \415\ Interregional Security Network is a data exchange system
that facilitates the exchange of real-time and other operational
data among reliability coordinators, balancing authorities and
transmission operators to help ensure reliable electric power system
operations.
---------------------------------------------------------------------------

    1644. The Commission proposed in the NOPR to approve Reliability
Standard TOP-005-1 as mandatory and enforceable. The Commission also
proposed to direct NERC to submit a modification to TOP-005-1 that: (1)
Includes information about the operational status of special protection
systems and power system stabilizers in Attachment 1 and (2) deletes
references to confidentiality agreements, but addresses the issue
separately to ensure that necessary protections are in place related to
confidential information.
i. Comments
    1645. FirstEnergy states that TOP-005-1 should also apply to
transmission providers because some of the information listed in
Attachment 1 to the Reliability Standard is in their possession.
Attachment 1 should be modified so that it allows each entity to know
what data it is expected to provide. As currently written, Attachment 1
lists various entities that are supposed to provide data without

specifying who will provide which information. FirstEnergy states that
transmission operators, for example, may not have all the information
listed in item 1.5 of Attachment 1.
    1646. APPA and Entergy agree that TOP-005-1 should be modified to
include information about the operational status of special protection
systems and power system stabilizers in Attachment 1. However, APPA
contends that the Commission's directive should be revised so that this
change is developed through the Reliability Standards development
process.
    1647. ISO-NE recommends that the reference to ``purchasing-selling
entity'' in Requirement R4 should be replaced with ``generator owner,
transmission owner, and LSE.'' \416\ It argues that since NERC's
glossary defines the term ``purchasing-selling entity'' as ``[t]he
entity that purchases or sells, and takes title to, energy, capacity,
and Interconnected Operation services,'' many entities can fall within
this category (e.g., commodity traders such as financial/power
marketers) that may possess little or none of the operational or
reliability data the host balancing authority and transmission operator
need to conduct reliability assessments.
---------------------------------------------------------------------------

    \416\ Requirement R4 states: ``Each Purchasing-Selling Entity
shall provide information as requested by its Host Balancing
Authorities and Transmission Operators to enable them to conduct
operational reliability assessments and coordinate reliable
operations.''
---------------------------------------------------------------------------

    1648. A number of commenters discussed the Commission's proposal to
delete references to confidentiality agreements in the Reliability
Standard but to address the issue separately to ensure that necessary
protections are in place related to confidential information. Those
comments are summarized above in connection with the same proposal made
by the Commission in the case of TOP-002-1.
ii. Commission Determination
    1649. For the reasons stated in the NOPR,\417\ we direct the ERO to
develop a modification to TOP-005-1 through the Reliability Standards
development process regarding the operational status of special
protection systems and power system stabilizers in Attachment 1.
Several commenters agree with this directive, and we believe that this
information will provide a more comprehensive list in Attachment 1.
---------------------------------------------------------------------------

    \417\ NOPR at P 1005.
---------------------------------------------------------------------------

    1650. We are adopting our proposal regarding deletion of references
to confidentiality agreements from the Requirements. Our discussion of
this matter in connection with TOP-002-1 applies equally here.
    1651. The Commission directs the ERO to consider FirstEnergy's
recommended modifications to Attachment 1 to the Reliability Standard
and ISO-NE's recommended revision to Requirement R4 in the Reliability
Standards development process.
    1652. Accordingly, the Commission approves Reliability Standard
TOP-005-1. In addition, pursuant to section 215(d)(5) of the FPA and
Sec.  39.5(f) of our regulations, the Commission directs the ERO to
develop a modification to TOP-005-1 through the Reliability Standards
development process that: (1) Includes information about the
operational status of special protection systems and power system
stabilizers in Attachment 1 and (2) deletes references to
confidentiality agreements, but addresses the issue separately to
ensure that necessary protections are in place related to confidential
information.
f. Monitoring System Conditions (TOP-006-1)
    1653. TOP-006-1 requires operating personnel to continuously
monitor essential Bulk-Power System parameters such as line flows,
circuit breaker status, generator resources, relays, weather forecasts
and frequency to ensure that the facilities do not exceed their
operating limits.
    1654. The Commission proposed in the NOPR to approve the
Reliability Standard as mandatory and enforceable.\418\ The Commission
also proposed to direct NERC to submit a modification that: (1)
Includes Measures and Levels of Non-Compliance; (2) includes a new
Requirement related to the provision of a minimum set of analytical
tools that will aid in situational awareness and (3) clarifies the
meaning of ``appropriate technical information'' concerning protective
relays.
---------------------------------------------------------------------------

    \418\ In its November 15, 2006 filing, NERC submitted TOP-006-1,
which supersedes the Version 0 Reliability Standard. TOP-006-1 adds
Measures and Levels of Non-Compliance to the Version 0 Reliability
Standard. In this Final Rule, we review the November version, TOP-
006-1.
---------------------------------------------------------------------------

i. Comments
    1655. Dominion supports including a new requirement for a minimum
set of analytical tools. It argues that such a requirement will ensure
that operators have a minimum set of tools with which to perform their
duties. The Reliability Standard should also specify metrics that can
be audited, such as minimum availability times, so that these tools are
adequately maintained. However, Alcoa states that requiring a minimum
set of tools will be unduly onerous, especially to smaller balancing
authorities and transmission operators. Although situational awareness
tools, such as state estimators, are critical for an ISO and RTO,
smaller balancing authorities and transmission operators should provide
necessary data to the reliability coordinator that monitors a wide
region using such tools.
    1656. Alcoa claims that developing additional capability at the
balancing authority and transmission operator levels when such
capability already exists at the reliability coordinator level will be
redundant. Requiring state estimation for a small balancing area that
is under an ISO would provide little benefit for grid reliability since
the scope of the balancing area's visibility is limited.
    1657. APPA does not support the proposed requirement related to the
provision of a minimum set of analytical tools and claims that
inclusion of specific analytical tools is counterproductive because the
tools become obsolete within two to five years due to technical
advances. APPA states that deciding whether to add a new requirement
for a minimum set of analytical tools should be left to NERC in the
first instance. Similarly, TAPS argues that NERC should consider in the
first instance whether minimum analytical tools are necessary and for
what subset of generator operators and transmission operators.
    1658. LPPC maintains that the Commission should require NERC to
list the capabilities required rather than specific tools because tools
will change over time.
    1659. APPA states that the ERO's filing on November 15, 2006
includes new Measures M1 through M6, which only measure Requirements
R1, R2, R4, R5 and R7.
ii. Commission Determination
    1660. The Commission approves TOP-006-1 as mandatory and
enforceable. In addition, the Commission directs the ERO to develop
modifications to TOP-006-1 through the Reliability Standards
development process, as discussed below.
    1661. We adopt our proposal to require the ERO to develop a
modification related to the provision of a minimum set of analytical
tools. In response to LPPC and others, we note that our intent was not
to identify specific sets of tools, but rather the minimum capabilities
that are necessary to enable operators to deal with real-time
situations and to ensure reliable operation of the Bulk-Power System.
In response to APPA that the inclusion of specific analytical tools is
counterproductive because the tools

will become obsolete, we note that we are not seeking specific
analytical tools, but rather minimum capabilities.
    1662. In regard to Alcoa's concern that this new Requirement would
be unduly onerous, especially for smaller balancing authorities and
transmission operators, the Commission's intent is not to subject
smaller balancing authorities and transmission operators to the same
requirements placed on larger balancing authorities and transmission
operators. As part of the modification of this Reliability Standard to
develop a new requirement for minimum capability for analytical tools,
the ERO should take into account what would be required of smaller
balancing authorities and transmission operators for the Reliable
Operation of the Bulk-Power System, instead of applying the same
requirements as are placed on other reliability entities such as
reliability coordinators and larger balancing authorities and
transmission operators.
    1663. We disagree with Alcoa that developing additional capability
at the balancing authority and transmission operator levels when such
capability already exists at the reliability coordinator level will be
redundant. We are not seeking to duplicate the same capability for each
reliability entity, but rather the new requirement should specify the
minimum capability taking into account the role played by each entity.
For example, a reliability coordinator may need to have access to state
estimator and contingency analysis whereas a generator operator may not
need these capabilities.\419\
---------------------------------------------------------------------------

    \419\ We note that TOP-006-0 applies to transmission operators,
balancing authorities, generator operators and reliability
coordinators.
---------------------------------------------------------------------------

    1664. No commenters addressed our proposal with respect to the
meaning of ``appropriate technical information'' concerning protective
relays in Requirement R3 of the Reliability Standard. To provide more
clarity, criteria that define what ``appropriate technical
information'' is necessary should be specified so that operators can
make better informed decisions. An example of such information would be
the allowable reclosing angle set in the existing relays and the
maximum angle at specific points in the Bulk-Power System that would be
acceptable to allow closing of lines during system restoration.
    1665. The ERO should consider APPA's comment regarding the missing
Measures in the ERO's Reliability Standards development process.
    1666. Accordingly, the Commission approves Reliability Standard
TOP-006-1. In addition, pursuant to section 215(d)(5) of the FPA and
Sec.  39.5(f) of our regulations, the Commission directs the ERO to
develop a modification to TOP-006-1 through the Reliability Standards
development process that: (1) Includes a new requirement related to the
provision of minimum capabilities that are necessary to enable
operators to deal with real-time situations and to ensure reliable
operation of the Bulk-Power System and (2) clarifies the meaning of
``appropriate technical information'' concerning protective relays.
g. Reporting SOL and IROL Violations (TOP-007-0)
    1667. TOP-007-0 requires that violations of SOL and IROL be
promptly reported to the reliability coordinator so that it can direct
corrective action and inform other affected systems. It also requires a
transmission operator to mitigate an IROL violation as soon as possible
but in no longer than 30 minutes. A transmission operator must take
``all appropriate actions up to and including shedding firm load'' to
return its system to a stable state within IROL. Finally, the
Reliability Standard requires that the reliability coordinator take
action to mitigate an SOL or IROL violation if the transmission
operator's actions are not effective.
    1668. The Commission proposed in the NOPR to approve TOP-007-0 as
mandatory and enforceable.
    1669. In the NOPR, the Commission solicited comment on potentially
overlapping matters addressed in Reliability Standards TOP-007-0 and
TOP-008-0.
i. Comments
    1670. NERC recognizes that there are some redundancies and awkward
relationships among the various Reliability Standards, which are the
result of the translation from the previous operating policies where
each policy was treated as a separate set of concepts. NERC states that
its 2007-2009 Reliability Standards Work Plan addresses work to be done
to eliminate redundancies and better organize the Requirements across
Reliability Standards so as to provide a more logical presentation.
    1671. APPA states that the concerns expressed in the NOPR about
overlapping matters between TOP-007-0 and TOP-008-0 should be referred
to the NERC Reliability Standards development process to better comport
with the statutory division of responsibility. FirstEnergy and SoCal
Edison state that Requirements R2 through R4 are clearly not reporting
activities and should be combined with the requirements of TOP-008.
    1672. NRC states that some nuclear power plant voltage requirements
would result in SOL, i.e., the nuclear power plant voltage limits would
be an SOL as a result of the minimum and maximum voltages required at
the nuclear power plant switchyard, which typically has a tighter
operating band (a higher minimum and a lower maximum) than other nodes
in the system. It therefore recommends adding a new requirement that
states as follows: ``Following discovery of a potential contingency
that could result in an SOL being exceeded at a nuclear power plant
(e.g., at post-trip voltage), the transmission owner shall notify the
nuclear power plant operator as soon as possible but not longer than 30
minutes if the contingency has not been corrected.'' NRC also suggests
modifying the Measures and Compliance sections and Table 1 to account
for the new requirement, and provides specific language to be included
in those places.
ii. Commission Determination
    1673. The Commission approves TOP-007-0 as mandatory and
enforceable. We agree with APPA, FirstEnergy and SoCal Edison that the
Reliability Standards would benefit from the elimination of overlapping
matters in TOP-007-0 and TOP-008-1. The ERO indicates that it plans to
address this as part of its Work Plan and this suffices.
    1674. NRC has raised some significant issues regarding the
consideration of nuclear power plants voltage requirements. Consistent
with our general approach in this Final Rule, we direct the ERO to
consider NRC's comments in the Reliability Standards development
process when addressing TOP-007-0 as part of its Work Plan.
    1675. Accordingly, the Commission approves Reliability Standard
TOP-007-0 as mandatory and enforceable.
h. Response to Transmission Limit Violations (TOP-008-1)
    1676. TOP-008-1 requires a transmission owner to take immediate
steps to mitigate SOL and IROL violations.
    1677. The Commission proposed in the NOPR to approve Reliability
Standard TOP-008-0 as mandatory and enforceable. The Commission also
proposed to direct that NERC submit a modification to TOP-008-0 that:
(1) Includes Measures and Levels of Non-Compliance and (2) includes
reliability

coordinators in the applicability section.\420\
---------------------------------------------------------------------------

    \420\ In its November 15, 2006, filing, NERC submitted TOP-008-
1, which supersedes the Version 0 Reliability Standard. TOP-008-1
adds Measures and Levels of Non-Compliance to the Version 0
Reliability Standard. In this Final Rule, we review the November
version, TOP-008-1.
---------------------------------------------------------------------------

i. Comments
    1678. APPA questions whether TOP-008-1 should be modified to apply
to reliability coordinators. It claims that the Requirement R3 simply
mentions that the reliability coordinator will receive information
provided by the transmission operator and does not play any substantive
role under TOP-008-1. MISO notes that the reliability coordinators'
responsibility related to IROL violations are outlined in connection
with IRO Reliability Standards and the reasons for adding the
reliability coordinator as applicable entity in multiple locations is
unclear.
    1679. APPA states that NERC has not submitted a Measure for the
Requirement R2 of the Reliability Standard. The new Measures M1 through
M5 included in TOP-008-1 only measure Requirements R1, R3, and R4. In
addition, the data retention and compliance levels reference Measures
M1 through M5. Therefore, an entity subject to TOP-008-1 could arguably
comply with Requirements R1, R3 and R4 and be in compliance with the
entire Reliability Standard.
ii. Commission Determination
    1680. For the reasons stated in the NOPR,\421\ the Commission
approves TOP-008-1 as mandatory and enforceable. We address the
concerns raised by commenters below.
---------------------------------------------------------------------------

    \421\ See NOPR at P 1035-36.
---------------------------------------------------------------------------

    1681. We agree with APPA that the reliability coordinator merely
receives information provided by the transmission operator and does not
play any substantive role under TOP-008-1. We also agree with MISO that
the reliability coordinators' responsibility related to IROL violations
are outlined in connection with the IRO Reliability Standards and
therefore there is no need to modify the applicability section of TOP-
008-1 to include the reliability coordinator.
    1682. The ERO should consider APPA's comment regarding the missing
Measures in the ERO's Reliability Standards development process.
    1683. Accordingly, the Commission approves Reliability Standard
TOP-008-1 as mandatory and enforceable.
12. TPL: Transmission Planning
    1684. The Transmission Planning (TPL) group of Reliability
Standards consists of six Reliability Standards that are applicable to
transmission planners, planning authorities and regional reliability
organizations. These Reliability Standards are intended to ensure that
the transmission system is planned and designed to meet an appropriate
and specific set of reliability criteria. Transmission planning is a
process that involves a number of stages including developing a model
of the Bulk-Power System, using this model to assess the performance of
the system for a range of operating conditions and contingencies,
determining those operating conditions and contingencies that have an
undesirable reliability impact, identifying the nature of potential
options, and the need to develop and evaluate a range of solutions and
selecting the preferred solution, taking into account the time needed
to place the solution in service. The proposed TPL Reliability
Standards address: (1) The types of simulations and assessments that
must be performed to ensure that reliable systems are developed to meet
present and future system needs \422\ and (2) the information required
to assess regional compliance with planning criteria and for self-
assessment of regional reliability.\423\
---------------------------------------------------------------------------

    \422\ See TPL-001-0, TPL-002-0, TPL-003-0 and TPL-004-0.
    \423\ See TPL-005-0 and TPL-006-0.
---------------------------------------------------------------------------

    1685. The TPL group of Reliability Standards contains a table
designated ``Table 1'' (Transmission System Standards--Normal and
Emergency Conditions), which is a key part of this group of Reliability
Standards. It lays out the system performance requirements for a range
of contingencies grouped according to the number of elements forced out
of service as a result of the contingency. For example: Category A
applies to the normal system with no contingencies; Category B applies
to contingencies resulting in the loss of a single element, defined as
a generator, transmission circuit, transformer, single DC pole with or
without a fault; Category C applies to a contingency resulting in loss
of two or more elements, such as any two circuits on a multiple circuit
tower line or both poles of a bi-polar DC line; while Category D
applies to extreme contingencies resulting in loss of multiple
elements, such as a substation or all lines on a right-of-way. The
system performance expectations for Category C contingencies are lower
than those for Category B contingencies, in that they allow unspecified
amounts of planned or controlled loss of load.
a. General Issues
    1686. Commenters raise a number of issues that apply generally to
Reliability Standards TPL-001-0 through TPL-004-0. These issues are
related to the transmission planning process, sensitivity studies and
critical system conditions, element-based versus event-based
contingencies, spares strategy, and resource information for planning
and sharing information with neighboring systems. We address these
general issues here, and the conclusions reached will apply to our
discussion of individual TPL Reliability Standards.
i. Transmission Planning Process
    1687. The Commission stated in the NOPR that the Reliability
Standards are not intended to make the Bulk-Power System failure-
proof.\424\ In addition, we did not propose to modify the TPL
Reliability Standards to require that the system be able to withstand
all multiple-contingency and extreme contingency events without loss of
load. Nonetheless, we stated that we believe that the planning-related
Reliability Standards could be improved to better account for probable
contingencies when conducting planning studies. Much of our proposal
was consistent with the potential improvements NERC recognized in its
comments on the Staff Preliminary Assessment. In addition, we noted
that a number of regions currently utilize superior planning practices
that may be characterized as ``best practices'' and are more stringent
than the proposed TPL Reliability Standards.\425\ Accordingly, we
proposed that the ERO submit to the Commission such regional
differences in transmission planning criteria that are more stringent
than those specified in the TPL group of Reliability Standards.
---------------------------------------------------------------------------

    \424\ NOPR at P 1042.
    \425\ Examples include practices cited in NERC's ``Examples of
Excellence'' found in its Readiness Audits (available at http://www.nerc.com
) and filings for jurisdictional utilities in Part 4 of

FERC Form No. 715, Transmission Planning Reliability Criteria.
Regional reliability organizations also specify requirements that
exceed NERC Reliability Standards, such as WECC's Minimum Operating
Requirement Criteria and the NPCC Document A-02--Basic Criteria for
Design and Operation of Interconnected Power Systems.
---------------------------------------------------------------------------

(a) Comments
    1688. EEI and APPA strongly believe that the transmission planning
processes performed under these Reliability Standards have served this
nation extremely well. The Reliability Standards have evolved with
changes in industry structure, computer and

communications technology, electric generation and transmission
technology and a broad range of state and federal regulatory demands.
EEI and APPA state that it is unclear whether the Commission is
proposing a significant expansion of this reliability planning process,
which would amount to a fundamental shift in the nature of that
process, or whether the Commission is proposing a more specific
description of today's comprehensive planning approach. EEI and APPA
state that they can interpret the Commission's proposal either as
suggesting that planning should support a robust and flexible network
that can ``bend'' to a broad range of critical system conditions, as
practiced up to now, or that planning should be ``finely tuned'' so
that reliability can be maintained under conditions where both
resources and loads are highly controlled. They find the source for the
latter interpretation in the Commission's request that the industry
move toward more explicit requirements that transmission planners
consider the effects of load control or other forms of DSM, or conduct
planning studies for far more combinations of resource alternatives.
EEI and APPA state that the existing Reliability Standards fully meet
the Commission's criteria as set forth in Order No. 672, unless the
Commission envisions a very different transmission system planning
process or seeks to move away from current network design toward the
development of a much ``tighter'' transmission system through
substantially higher saturations of controllable resources and loads.
    1689. SDG&E notes that the NOPR's characterization of the dual
objectives of ``appropriateness'' and ``specificity'' speaks, on the
one hand, to the need for Reliability Standards that are tailored to
each transmission planner's area of responsibility, and, on the other
hand, clear, consistent and workable rules. SDG&E urges the Commission
to be mindful of the need to assess and balance these considerations in
future iterations of the transmission planning Reliability Standards.
    1690. Northern Indiana states that the presentation of TPL-001-0
through TPL-004-0 as individual Reliability Standards creates a great
deal of confusion. In practice, most transmission planners take an
integrated view of these Reliability Standards and treat them as if
they were a single standard. Accordingly, Northern Indiana suggests
that the Commission ask NERC to file a substitute proposal that would
integrate the transmission planning standards and improve their clarity
and quality.
    1691. SDG&E supports the Commission's proposal to direct NERC to
submit for approval regional transmission planning criteria that have
been adopted and extensively used that are more stringent than those
specified in the current TPL Reliability Standards. NCPA states that
whenever a RTO/ISO adopts criteria that differ from ERO or regional
standards, those criteria should be made public and transparent.
(b) Commission Determination
    1692. EEI and APPA raise an important question on the Commission's
intent regarding the transmission planning process and proposed
modifications to the transmission planning standards. They ask whether
the Commission is proposing a fundamental shift in the nature of the
planning process that would result in a move away from the current
network design towards a much ``tighter'' transmission system through
substantially increased use of controllable resources and loads. The
Commission is not proposing a fundamental shift in the nature of the
planning process as it is practiced today. We clarify that all the
proposed modifications to the TPL group of Reliability Standards are
aimed at ensuring Reliable Operation of the Bulk-Power System. To
achieve this goal, it is necessary, among other things, to ensure that
the planning process and the Reliability Standards produce a Bulk-Power
System that is robust enough to be able to withstand a range of
probable contingencies while reliably serving customer demand and
preventing the identified outages, and flexible enough to accommodate a
broad range of system conditions over a planning horizon that takes
into account lead times to place facilities in service. Further, the
proposed modifications are intended to ensure that the planning
requirements are specific enough to promote rigor and consistency in
assessments and provide clear and measurable rules for mandatory and
enforceable Reliability Standards. The Commission therefore agrees with
SDG&E's comments in this regard and on the need to balance
``appropriateness'' and ``specificity.''
    1693. The Commission agrees with Northern Indiana that the
Reliability Standards TPL-001-0 through TPL-004-0 would be improved if
they were integrated into a single Reliability Standard. Such an
approach conforms more closely to common planning practices, and
integrating these Reliability Standards therefore could enhance their
practical effectiveness. The Commission notes that the Work Plan
submitted by the ERO has earmarked this group of Reliability Standards
for revision during the early stages of the plan. The Commission
directs the ERO to consider integrating Reliability Standards TPL-001-0
through TPL-004-0 into a single Reliability Standard through the
Reliability Standards development process.
    1694. The Commission agrees with SDG&E and NCPA that any criteria
that are more stringent than the ERO planning criteria should be made
public and transparent. It is essential that such criteria be
accessible to and understood by the entities to which they apply.
Accordingly, the Commission directs the ERO to submit to the Commission
in an informational filing, in addition to regional criteria, all
utility and RTO/ISO differences in transmission planning criteria that
are more stringent than those specified by the TPL group of Reliability
Standards. We believe that this information will provide us, as well as
the ERO and industry with an indication of the actual transmission
practices utilized in the industry today. This should be used by the
ERO in the Reliability Standards development process.
ii. Sensitivity studies and critical system conditions
    1695. The Commission stated in the NOPR that it is not realistic to
expect the ERO to develop Reliability Standards that anticipate every
conceivable critical operating condition applicable to unknown future
configurations for regions with various configurations and operating
characteristics.\426\ The practical solution implemented by many in the
industry is to perform sensitivity studies that define and provide
documentation of the reliability impact on the system. The Commission
therefore stated that it would be appropriate for planning entities to
conduct sensitivity studies to ``bracket'' the range of probable
outcomes. Thus, without having to anticipate ``every conceivable
critical operating condition,'' planning entities will have a means to
identify an appropriate range of critical operating conditions. Both
staff and commenters on the Staff Preliminary Assessment noted that
system conditions are as important as contingencies in evaluating the
performance of present and future systems.
---------------------------------------------------------------------------

    \426\ NOPR at P 1047.
---------------------------------------------------------------------------

(a) Comments
    1696. Most of the commenters agree with the Commission's proposal
on sensitivity studies to determine critical

system conditions. These include FirstEnergy, TVA, MidAmerican, Entergy
and SDG&E. However, a few commenters, including EEI, APPA, MISO and
Northern Indiana, take the view that such a requirement is unnecessary
and overly prescriptive.
    1697. FirstEnergy states that it is appropriate for the Commission
to require sensitivity analyses, because assessing multiple
sensitivities against a set of system contingencies is prudent system
planning.
    1698. TVA agrees that an appropriate range of critical operating
conditions that will ``stress'' the Bulk-Power System needs to be
identified for use in transmission planning. It states that sensitivity
studies should be performed and historic data analyzed to determine the
most probable range of operating conditions that will stress the Bulk-
Power System.
    1699. MidAmerican believes that the proposal to require sensitivity
studies to ``bracket'' the range of probable outcomes and determine
critical system conditions is reasonable. It states that, while
critical conditions may be determined in a similar manner for the
different TPL Reliability Standards, different critical conditions are
pertinent to each Reliability Standard. For example, thermal overloads
occur under peak load conditions and dynamic instability occur under
light load conditions.
    1700. Entergy does not object to an assessment of critical system
conditions using the factors identified in the NOPR,\427\ but it
contends that the Commission's guidance is problematic to the extent
that it may require constructing facilities to address potential
constraints identified through these assessments. Entergy states that
such construction may not create a desirable result and may instead
threaten reliability. For example, assessing a system using alternative
generation dispatch and transaction patterns could bias a transmission
provider in favor of transmission plans that benefit a specific
generator or set of generators.
---------------------------------------------------------------------------

    \427\ Id. at P 1061.
---------------------------------------------------------------------------

    1701. SDG&E sees the Commission's treatment of sensitivity studies
and critical system conditions as requiring transmission planning
entities to exercise judgment in determining the scope, content and
number of their sensitivity studies so that they are appropriate given
unique system characteristics and reasonably anticipated contingencies.
SDG&E state that this guidance is welcome and should be reflected in
future Requirements.
    1702. MISO agrees that planning entities should have a process to
identify appropriate critical system conditions for planning purposes.
However, it does not believe that the Reliability Standard needs to be
prescriptive in terms of the specific sensitivities that should be
evaluated. If an entity's approach to selecting the critical planning
conditions is appropriate, sensitivities to variations from these
conditions are unnecessary. MISO and Northern Indiana state that
requiring sensitivities in planning studies as a mandatory standard
practice could result in unnecessary additional analysis that could
overwhelm the planning process and detract from more appropriate
focused analysis and evaluation of solutions.
    1703. EEI and APPA state that the Commission's proposal on
sensitivity studies would add an unnecessarily redundant process that
ignores the totality of the studies contained in study libraries that
inform planners' decisions. The historical libraries of system studies
provide a strong base for selecting critical transmission system
conditions. EEI believes that the knowledge and experience of planners
who have conducted these studies provides reliable guidance and that a
new array of sensitivity analyses would offer no additional benefit
over existing practices.
    1704. Regarding specific variables to be included in sensitivity
studies, EEI and APPA note that load power factors, controllable loads
and DSM at specific locations and outages of reactive devices have much
more to do with distribution operations planning than long-term system
planning. They state that while transmission system planners will study
a broad range of combinations of substation loadings, system
configurations and resource availabilities over the planning horizon,
changes in the variables of the sort identified by the Commission have
very little influence on the long-term study outcomes except for the
loss of load that could occur under extreme circumstances. MISO
believes that transmission reactive power devices should be treated
like any other transmission facility and included in the required
contingency analysis. The current Reliability Standards are not
explicit in this regard, and MISO agrees that this would be an
appropriate clarification. It believes that power factor sensitivity
studies are best suited for operational planning studies rather than
long-term planning since corrective actions have relatively short lead
times. In regard to alternative dispatch scenarios, MISO states that if
a variation from the expected dispatch leads to unacceptable
performance, it becomes an economic planning question, rather than a
planning standard issue, whether expansion should be undertaken or
whether the dispatch becomes a congestion cost.
(b) Commission Determination
    1705. In response to Entergy's comments, the Commission reiterates
the statement from the NOPR \428\ that the results of the sensitivity
studies would be used to document the selection of critical system
conditions and study years used in assessing system conditions. The
Commission notes that it is not the purpose of sensitivity studies to
identify remedial actions, but, as stated in the NOPR, if different
scenarios that lead to criteria violations are probable they require
mitigation plans.\429\ Entergy goes on to state that constructing
facilities, the need for which is determined through sensitivity
studies, may not create a desirable result, in that they may bias
transmission plans towards a specific generator or set of generators
and as a result may threaten reliability. The Commission disagrees that
constructing well-planned facilities may threaten reliability. The
planning process should anticipate any inter-regional impacts, and the
net result should be higher local and inter-regional reliability. In
any case, we are not requiring the construction of additional
facilities.
---------------------------------------------------------------------------

    \428\ Id. at P 1061.
    \429\ Id. at n 324.
---------------------------------------------------------------------------

    1706. MISO, EEI, APPA and others question the value of sensitivity
studies and their role in mandatory Reliability Standards given the
knowledge and experience of planners and the historical library of
system studies. The Commission notes that while specificity was not
required in the regime of voluntary standards, it is required in a
regime of mandatory Reliability Standards to ensure consistency in
system assessment and provide clear and measurable requirements.
Further, as stated in the NOPR \430\ and concurred with by commenters
to the Staff Preliminary Assessment, system conditions are as important
as contingencies in evaluating the performance of present and future
systems. Indeed, Table 1 lists the contingencies to be evaluated, but
there is no corresponding requirement for selecting critical system
conditions.
---------------------------------------------------------------------------

    \430\ Id. at P 1046.
---------------------------------------------------------------------------

    1707. The Commission believes it is important to clarify the type
of analysis

required in determining critical system conditions, which is the intent
of the directed modifications on sensitivity studies. The Commission
proposed in the NOPR a range of variables to be included in sensitivity
studies, specifically: firm transfers, demand levels, existing and
planned facilities, reactive power resources, control devices, load
power factors, generation retirements, generation dispatch, transaction
patterns, controllable loads, DSM and transmission outages including
outages of reactive power devices.\431\ The Commission also stated that
it is not precluding other approaches to defining and documenting
critical system conditions that have proven to be effective. The
Commission also notes that in analyzing contingencies as part of
Requirement R1.3.1 in Reliability Standards TPL-002-0 through TPL-004-
0, not all contingencies need be assessed for every system element but
only those that would produce the more severe reliability impacts with
documentation of selection rationale. The same applies to the range of
variables specified for sensitivity studies. The Commission expects
that the full range of variables will be considered, but only those
deemed to be significant need to be assessed and documentation provided
that explains the rationale for the selection of variables assessed.
---------------------------------------------------------------------------

    \431\ Id. at P 1047.
---------------------------------------------------------------------------

iii. Element-Based vs. Event-Based Contingencies
    1708. The Commission stated in the NOPR that planning Reliability
Standards must influence system design and not the other way
around.\432\ To achieve this objective, planning Reliability Standards
should promote system designs that result in the minimum set of
elements being removed from service for ``unanticipated failures of
system elements.'' \433\ The NOPR goes on to say that the Commission
believes that the simulations used in planning assessments should
faithfully duplicate what will happen in the actual power system and
not a generic listing of outages. The Bulk-Power System also must be
operated, and planned to be operated, within a number of conditions
after a contingency or cyber event. The contingency can be a sudden
disturbance or an unanticipated failure of any system element. If a
specific portion of the system has been designed such that the response
to a failure results in multiple lines, transformers, generators,
circuit breakers, etc., being removed from service, the Commission
proposed that this is what should be simulated.\434\
---------------------------------------------------------------------------

    \432\ Id. at P 1049.
    \433\ Section 215(a) of the FPA defines ``Reliable Operation''
as ``operating the elements of the Bulk-Power System within
equipment and electric system thermal, voltage, and stability limits
so that instability, uncontrolled separation, or cascading failures
of such system will not occur as a result of sudden disturbance,
including a Cybersecurity Incident, or unanticipated failure of
system elements'' (emphasis added).
    \434\ With respect to failure, the element includes a single
transmission line, transformer, generator or single pole of a DC
line.
---------------------------------------------------------------------------

(a) Comments
    1709. National Grid, MidAmerican and SDG&E support the principles
set forth in the NOPR. National Grid states that event-based planning
is a more robust form of contingency analysis than element-based
planning because the former focuses on contingencies regardless of how
many elements may be affected while the latter focuses on losses of
specific elements that may not have a direct relationship to the
severity of the impact on or risks to reliability. As such it supports
the Commission's statement that ``simulations should faithfully
duplicate what will happen in the actual power system and not a generic
listing of outages.'' \435\
---------------------------------------------------------------------------

    \435\ NOPR at P 1049.
---------------------------------------------------------------------------

    1710. MidAmerican states that it supports the Commission's proposal
to interpret a ``single contingency'' to include all elements of the
system, irrespective of their number, that go out of service in
response to failure of a single element, as it has historically
performed this analysis as a part of normal planning in the interest of
reliability. MidAmerican is concerned, however, that this proposal may
be too restrictive for system planning, particularly with regard to the
double contingencies of Category C. It states that if a multi-element
single contingency occurs first, as part of system adjustment, the
reliability coordinator or transmission operator will switch back the
unfaulted elements to service prior to the next contingency. Therefore
this N-1-1 contingency at its worst will consist of a single element
outage followed by a multi-element outage. Therefore MidAmerican states
that the extent of a multiple-element single contingency is better
determined through coordinated efforts of neighboring systems in
conjunction with the planning authority and reliability coordinator.
    1711. SDG&E agrees that further modifications to the TPL
Reliability Standards should be guided by the NOPR's directive that
simulations should faithfully duplicate what will happen in the actual
power system and not a generic listing of outages. However, it states
that the Commission should provide further guidance in defining an
event so that planning studies can assess electrical system
contingencies consistently and numerically. A simulation that
faithfully duplicates reasonably expected scenarios will necessarily
involve the transmission planner's sound engineering judgment and
knowledge of elements that would be expected to be removed from service
during the contingency. SDG&E states that the updated TPL Reliability
Standard should reflect and implement these concerns.
    1712. EEI believes the planning Reliability Standards and practices
clearly reflect the language in FPA section 215 regarding ``element
based'' planning. Planners study single contingency and multiple
contingency events covering a broad range of system elements and not a
list of generic outages.
    1713. TANC recommends that the Commission direct that transmission
planning in the West be based on probability of an event occurring and
the severity of the consequences, rather than on a deterministic
approach that uses single and multiple contingency categories as
exemplified by Table 1. It states that WECC has assessed the
probability of an event occurring for each category and assigned
probabilities accordingly. TANC states that to be more cost effective
and efficient, investments to remedy a problem should be based on a
combination of the probability of the occurrence of the event and the
severity of the associated consequences.
    1714. In response to the Commission's request in the NOPR for
comment on whether planning for cyber security events should be
addressed in the planning Reliability Standards or in the Critical
Infrastructure Protection (CIP) Reliability Standards,\436\
MidAmerican, EEI, APPA, ISO-NE and SoCal Edison state they believe that
events requiring study under the CIP Reliability Standards should be
included in that specialized forum rather than the TPL Reliability
Standards. Such events are identified using approaches provided for in
the CIP Reliability Standards. Therefore the best place to explore
those events and determine their impacts using the full background of
the information about the events is the CIP Reliability Standards,
although some of these events will require

implementation of elements from other Reliability Standards.
---------------------------------------------------------------------------

    \436\ Id. at P 1050.
---------------------------------------------------------------------------

    1715. National Grid and International Transmission take the view
that cyber security incidents are no different than other events that
remove single or multiple elements from service at a single time and
require analysis of system impacts. Planning assessment for cyber
security incidents therefore is most appropriately addressed in the TPL
Reliability Standards. International Transmission states that although
Table 1 of the TPL Reliability Standards does not list the initiating
event, cyber security events could be included in the list of
contingencies as an initiating event. National Grid cautions that
provisions detailing specific cyber security protections should be
addressed in CIP Reliability Standards, and emergency response
procedures for response to cyber security events should be addressed in
EOP Reliability Standards.
(b) Commission Determination
    1716. Several commenters \437\ agree with the Commission's
statement in the NOPR \438\ that ``simulations should faithfully
duplicate what will happen in the actual power system and not a generic
listing of outages.'' It follows that in simulating the failure of a
single element, as required in Category B of TPL-002-0, all of the
elements that are removed from service to isolate the single faulted
element should be modeled in the simulation rather than restricting the
simulation to just the single faulted element, as Table 1 of TPL-002-0
implies. As SDG&E notes, this will require the transmission planner's
sound engineering judgment and knowledge of elements that would be
expected to be removed from service during the single contingency. The
Commission agrees with MidAmerican that for Category C contingencies of
TPL-003-0, the worst N-1-1 contingency would be a single element outage
followed by a multiple element outage, provided that following the
first N-1 contingency, capability exists to switch the unfaulted
elements back into service promptly, i.e., within 30 minutes, as part
of the adjustments that the Reliability Standard allows.
---------------------------------------------------------------------------

    \437\ National Grid, MidAmerican and SDG&E.
    \438\ NOPR at P 1049.
---------------------------------------------------------------------------

    1717. SDG&E agrees that simulations should faithfully duplicate
what will happen in the actual power system and not a generic listing
of outages, but it seeks Commission guidance on how an event should be
defined. In the Commission's view, a single contingency consists of a
failure of a single element that faithfully duplicates what will happen
in the actual system.\439\ Such an approach is necessary to ensure that
planning will produce results that will enhance the reliability of that
system. Thus, if the system is designed such that failure of a single
element removes from service multiple elements in order to isolate the
faulted element, then that is what should be simulated to assess system
performance. Accordingly, the Commission directs the ERO to submit
modifications to Category B of Table 1 consistent with this approach.
Entities whose systems may have been planned and designed on the basis
of a different approach to single contingencies should work with the
ERO in developing plans to transition to this approach.
---------------------------------------------------------------------------

    \439\ A ``single element'' means a transmission line, a
transformer, a generator or a single pole of a DC line.
---------------------------------------------------------------------------

    1718. The Commission disagrees with EEI that the planning
Reliability Standards and practices clearly reflect the language in FPA
section 215 regarding ``element based'' planning. Section 215(a) of the
FPA defines ``Reliable Operation'' as ``operating the elements of the
Bulk-Power System'' within certain limits so that ``instability,
uncontrolled separation or cascading failures of that system will not
occur as a result of sudden disturbances, including a cyber security
incident, or unanticipated failure of system elements.'' This
definition specifies an ultimate goal and does not dictate any specific
type of planning. The approach to a single contingency the Commission
has set forth above ensures that transmission planners analyze
contingencies based on the actual number of elements that would be
removed from service in the actual power system for ``an unanticipated
failure of system elements,'' rather than simulating only the limited
number of outages listed in Table 1 of the TPL Reliability Standards.
In short, the Commission's approach speaks directly to the problem that
the statute requires be addressed.
    1719. In response to TANC's proposal that the Commission direct
that probabilistic approaches to transmission planning be adopted in
the West, the Commission notes that proposals of this type should be
submitted to the ERO for approval as a regional difference. If such a
proposal is developed for the Western Interconnection, to assist the
ERO and the Commission in its assessment of such a proposal, we
encourage WECC to also submit operating information that quantifies the
level of actual performance that has been achieved with the present
deterministic planning approach. Such performance metrics would assist
us in determining whether a probabilistic approach would result in
equivalent or higher levels of Reliable Operation than currently
achieved.
    1720. In response to the comments received on how best to address
planning for cyber security events, it is clear that the nature of
risks as well as the contingencies and measures needed to overcome them
are best addressed in the CIP Reliability Standards because this forum
has the specialized knowledge to deal with cyber security matters.
However, the system impacts of cyber security events are best addressed
in the TPL group of Reliability Standards, particularly TPL-004-0,
alongside other similar common mode failures. Emergency plans and
restoration procedures to deal with cyber security events are best
addressed by the EOP Reliability Standards because these Reliability
Standards deal with emergency plans and restoration procedures. The
Commission directs the ERO to consider appropriate revisions to the
Reliability Standards through its Reliability Standards development
process to address these matters.
iv. Spare Equipment Strategy
    1721. The Commission stated in the NOPR that while Reliability
Standards TPL-002 through TPL-004 require consideration of planned
outages at those demand levels for which planned outages are performed,
they do not address situations where critical equipment, such as a
transformer or phase angle regulator, may be unavailable for a
prolonged period. Including such a requirement would ensure the
coordination of contingency plans, including the entity's spare
equipment strategy, to return facilities to service in a timely manner
for reliability. The Commission therefore proposed that the Reliability
Standards be modified to include a new requirement to assess the
reliability impact of an entity's existing spare equipment strategy.
(a) Comments
    1722. SDG&E states that it generally supports a new requirement
that would include assessing the reliability impact of an entity's
spare equipment strategy, but several key features of this requirement
need clear and thorough definition. For example, the requirement should
provide an industry-developed finite list of ``critical items,'' and
the meaning of ``impact IROL'' would need further clarification. SDG&E
submits that, absent a careful delineation of the requirement and its

terms, this proposed modification will not enhance system reliability.
    1723. MidAmerican, LPPC, EEI, APPA and SoCal Edison state that they
understand the Commission's concern about spare equipment planning and
acquisition strategy. However, MidAmerican and LPPC note that typically
spare equipment strategy is of more concern in operating studies than
planning studies. MidAmerican states that most equipment can be
installed in a year or less even if it is not on hand. It maintains
that it may be appropriate to add this requirement to the TPL
Reliability Standards because scarcity of new equipment due to recent
disasters has led to longer lead times. LPPC cautions the Commission
that associating spare equipment strategy with the planning Reliability
Standards could lead to Reliability Standards that overstep the limits
of FPA section 215(i)(2) through proposing a Reliability Standard that
would, indirectly, come close to authorizing the ERO to order the
construction of transmission capacity. LPPC states that it is unclear
how to separate: (1) Requiring a utility to assess its spare equipment
strategy; (2) requiring a utility to have spares on hand to meet
anticipated reliability needs and (3) requiring a utility to use spare
equipment to meet the reliability needs.
    1724. EEI, APPA and SoCal Edison question the need to address this
issue in the context of a Reliability Standard. EEI states that, where
delivery delay could occur for long lead time equipment such as
transformers, the existing Reliability Standards provide for study of
the full range of single and multiple-event contingencies with that
piece of equipment modeled off-line. According to EEI, the Commission's
general concern regarding the current policies and practices related to
equipment acquisition can be addressed in the NERC forum without
revising the Reliability Standards. This forum also will account for
the need to protect information on critical infrastructure facilities.
(b) Commission Determination
    1725. Several commenters stated that they understand the
Commission's concern about requiring a reliability impact assessment of
an entity's spare equipment strategy, but they question the need to
address this issue in the Reliability Standards in general and the
transmission planning Reliability Standards in particular. The
Commission disagrees with EEI that the existing Reliability Standards
provide for situations that cover the delivery of long lead time
equipment, such as transformers, by requiring a full range of single
and multiple contingency studies with that equipment modeled off-line.
TPL-002-0 and TPL-003-0 currently state explicitly in Requirement
R1.3.12 that the assessments shall include planned outages of bulk
electric equipment at those demand levels for which planned (including
maintenance) outages are performed. However, equipment such as
transformers may not be available for service for a year or more and
therefore their unavailability cannot be scheduled when system
conditions permit.
    1726. The current Reliability Standards do not require assessment
of the reliability impacts that result from not having this long lead
time equipment available under those system conditions likely to be
experienced during the course of the year when the system is heavily
stressed. Clearly the consideration of planned outages is inextricably
linked with spare equipment strategy. Thus, if an entity's spare
equipment strategy for the permanent loss of a transformer is to use a
``hot spare'' or to relocate a transformer from another location in a
timely manner, the outage of the transformer need not be assessed under
peak system conditions. However, if the spare equipment strategy
entails acquisition of a replacement transformer that has a one-year or
longer lead time, then the outage of the transformer must be assessed
under the most stressed system conditions likely to be experienced.
Accordingly, the Commission directs the ERO to modify the planning
Reliability Standards to require the assessment of planned outages
consistent with the entity's spare equipment strategy.
    1727. LPPC questions whether the Commission's proposal oversteps
the limits of FPA section 215(i)(2) because assessing the impact on
reliability of an entity's decision concerning spare equipment could
force an entity to construct transmission capability. FPA section
215(i)(2) prohibits the ERO and the Commission from ordering the
construction of ``additional'' transmission capacity. A requirement to
assess the reliability impacts of an entity's spare equipment strategy
is no different than a requirement to assess the reliability impacts of
any number of contingencies. Even if an entity was forced to conclude
that its spare strategy was inadequate, rectifying the problem would
not require that the entity construct ``additional'' transmission
capacity, only that it possess adequate spares, or take other
appropriate action, to ensure the reliable operation of its system. In
short, while FPA section 215(i)(2) precludes ordering expansion of
transmission or generation capacity, section 215 clearly authorizes
requiring entities to take appropriate steps to ensure that their
existing capacity operates reliably.
    1728. With regard to SDG&E's suggestion to clarify specific
elements of this Reliability Standard, we direct the ERO to consider
such suggestions in its Reliability Standards development process.
v. Resource Information for Planning
    1729. The Commission in the NOPR requested comments on whether
transmission planners and planning authorities are currently able to
obtain and validate resource information on new generation and
retirements for assessments over the ten year planning horizon.
Further, if transmission planners and planning authorities currently
experience difficulty obtaining this information, the Commission asked
how this potential information gap should be addressed.\440\
---------------------------------------------------------------------------

    \440\ NOPR at P 1060.
---------------------------------------------------------------------------

(a) Comments
    1730. The Commission noted in the NOPR that transmission planning
requires information on forecasted loads and probable generation plans
to supply those loads.\441\ While the MOD Reliability Standards require
information on forecasted loads, energy, interruptible loads and direct
control load management over the next ten years, there is no
requirement to inform transmission planners and planning authorities of
new or retiring generation resources. The Commission sought comments on
whether transmission planners and planning authorities are currently
able to obtain and validate resource information on new generation and
retirements for assessments over the ten year planning horizon and if
not, how this potential gap should be addressed.
---------------------------------------------------------------------------

    \441\ Id.
---------------------------------------------------------------------------

    1731. NERC stated that it and the regional reliability
organizations have generally not had problems obtaining the data and
information required for reliability assessments. NERC believes that
given its authority and responsibility as the ERO, it will be
successful in obtaining all the data and information it needs to
conduct reliability assessments without the need to include these
requirements in Reliability Standards. In the event that it and the
regional reliability organizations are unsuccessful in obtaining such
data and information,

the ERO will turn to the Commission for assistance.
    1732. ISO-NE states that as the planning authority it obtains
resource plans for additions, capacity changes, deactivations and
retirements for a ten year planning horizon. Although these plans
cannot be expected to occur exactly as projected, they serve as useful
information in projecting needs for new resources or new or upgraded
transmission facilities. As the administrator of wholesale electric
markets, ISO-NE relies on the development of robust market rules
accompanied by a regulated transmission planning process to achieve its
goal of encouraging the availability of sufficient resources. ISO-NE
states that planning for the introduction and retirement of specific
resources ten years in advance not only is unnecessary, it is
inconsistent with relying on markets to determine the most efficient
allocation of resources to meet system needs.
    1733. FirstEnergy and SoCal Edison state that currently they are
able to obtain information regarding new generation from publicly
available information and from the generator interconnection queue.
Typically, a generation application that is in the interconnection
agreement phase is considered for transmission planning studies. New
generation has a longer lead time, and thus information on it may be
available sooner than information about retirements, which have a much
shorter lead time before they are announced. FirstEnergy states that
despite the unpredictability of such information, assessments can be
conducted using assumptions of new generation and retirements, and the
results should recognize that the inputs were based on reasonably
foreseeable conditions.
    1734. In contrast, CAISO, National Grid and Northern Indiana state
that obtaining resource information has been a challenge given that the
Reliability Standards impose no obligation on generation owners to
provide information to planning authorities and transmission service
providers about new and retiring generation. Northern Indiana states
that this issue is among the greatest challenges for its transmission
planners. Because transmission planning is focused on matching the
source to the sink, having the sources unknown, in the case of future
generation, creates a weakness in the entire transmission planning
process. Northern Indiana contends that weakness will be difficult to
eliminate because information about siting of future generation units
is considered commercially sensitive information. This lack of
information makes it difficult for transmission planners to reflect
accurately the amount and location of new generation in their
transmission studies. CAISO agrees that there is a gap in its ability
to obtain this information particularly from adjacent balancing
authorities. CAISO suggests that to bridge this gap, generator owners
and operators should be required to provide data about new and retiring
generation to their planning authorities and that the planning
authorities be required to share this information with neighboring
balancing authorities, subject to appropriate non-disclosure
agreements. CAISO notes that there currently exists no centralized
database for the collection and dissemination of this information
within the Western Interconnection.
    1735. National Grid states that forward capacity markets and the
generation interconnection queue provide some understanding about new
generation but only for five to seven years, even though transmission
planning horizons are considerably longer. National Grid and Northern
Indiana contend that it may be reasonable to conclude that certain
areas are prime locations for new resources, particularly inexpensive
and renewable resources that are dependent on ``non-transportable''
fuel supplies. National Grid states that the Commission should embrace
efforts of transmission planners to facilitate new generation entry
when such initiatives are expected to increase customer access to
inexpensive, renewable and diverse sources of supply.
    1736. Entergy believes that from a transmission provider's point of
view it would be desirable to have LSEs provide ten or even five-year
resource forecasts. Entergy recognizes that such a requirement may not
be practical when LSEs depend significantly on short-term purchases due
to the abundance of independent power producers or in areas that have
an locational marginal pricing-like market structure. MISO states that
its experience suggests that LSEs do not identify new generation
resources except in very general terms past the second or third year.
In most cases LSEs show future capacity requirements served from
generic base load and peaking power resources or from potential
contract purchases with no information on location. This increases the
difficulty of accurate long-range transmission planning studies.
    1737. National Grid states that it is also vitally important to
acknowledge that generation retirements may pose a greater threat to
reliability in some areas of the country than the slow down of new
generation. Because required notice periods for retirements may be as
little as ninety days in some areas, it is imperative that transmission
planners use a robust statistical approach to identify vulnerable
sources of generation and conduct such modeling as an integral part of
the transmission planning process.
    1738. MISO states that planning assumptions around generation
retirements are particularly difficult because such assumptions are
driven by complex economic factors that may or may not prevail. While
MISO has the tools to project what unit may be more likely to retire
than others, it contends that the preferred approach is to have in
place tariff provisions that require suppliers to announce retirement
intentions six months in advance of the retirement. This permits
reliability studies to be performed with certainty and corrective
actions to be implemented that could include placing the unit on
contract to continue operations until appropriate operating measures or
system expansions can be made.
    1739. SoCal Edison states that business decisions by generator
owners to retire or mothball units are outside of SoCal Edison's
control, and generally SoCal Edison does not receive this information
in a timely manner for transmission planning studies.
    1740. National Grid urges the Commission to support longer planning
horizons. It states that in many respects, the ten year planning
horizon may be too short a time frame for assessing transmission needs,
particularly with regard to long distance extra high voltage facilities
that pose considerable siting and permitting challenges. Establishing
planning horizons that are shorter than transmission construction lead
times may create gaps where the identification of a reliability need to
which transmission may be the best solution occurs too late to head off
the identified reliability violation. National Grid states that PJM is
establishing a fifteen year planning horizon that will accommodate
large-scale projects that are needed for reliability and to support
regional transactions.
    1741. MISO and International Transmission note that while it is
important for planners to have quality information on available
resources, the enabling legislation for the ERO specifically excludes
authority regarding resource adequacy. MISO states it is not certain
how far the Reliability Standards can go. International Transmission
states that, in the absence of a standard on resource

adequacy, transmission service providers must use their judgment on
potential new generation or retirements to create base cases and plan
the system accordingly.
    1742. Reliant states that, while section 215 of the FPA requires
the ERO to develop Reliability Standards that provide an adequate level
of Bulk-Power System reliability, the proposed Reliability Standards
surprisingly lack any substantive consideration of planning reserve
obligations to ensure capacity available to meet the needs of a
reliable system. Reliant proposes that each regional reliability
organization develop and enforce its own minimum planning reserve
margin. Such a program would be critical to the development of new
generation, demand response and distributed generation resources and
allow each region to retain its own autonomy in developing its own
resource adequacy standards.
    1743. Process Electricity Committee supports long-term planning as
a vital part of any economic and thorough set of Reliability Standards.
However, it is concerned that transmission service providers who are
also market participants will have an incentive to exploit commercially
sensitive data on generation plans to the disadvantage of other
competing suppliers. Process Electricity Committee asks the Commission
to clarify that transmission planners may not use the Reliability
Standard to obtain and exploit such information, and it urges the
Commission to take all appropriate measures to guard against such
abuse.
(b) Commission Determination
    1744. Several commenters addressed separately the availability of
information on new generation resources and generation retirements,
given that these have very different lead times. NERC, ISO-NE and
others appear to be able to acquire the resource information they need
on new resources and retirements for reliability assessments. Others,
such as National Grid and MISO, have had difficulty in obtaining this
information in a timely manner, particularly as it relates to
generation retirements.
    1745. The Commission disagrees with ISO-NE's statement that
planning for the introduction of resources ten years in advance is not
necessary. The existing Reliability Standard requires that the planning
horizon must take into account the lead times for siting and permitting
of new long-distance transmission lines and other solutions that can
exceed ten years. In short, the need for long-term planning has already
been widely recognized. The Commission agrees with National Grid that
establishing planning horizons that are shorter than transmission lead
times may create gaps where the identification of a reliability need to
which transmission may be the best solution occurs too late to avert
the identified reliability violation. Indeed, this point is supported
by the fact that PJM is establishing a fifteen year planning
horizon.\442\
---------------------------------------------------------------------------

    \442\ See http://www.pjm.com/contributions/pjm-manuals/manuals.html
.

---------------------------------------------------------------------------

    1746. In the absence of information about future generation
resources required for transmission planning the Commission notes that
entities conduct assessments using assumptions based on the knowledge
that certain areas are prime locations for new resources, particularly
those resources that use non-transportable fuels. National Grid states
that generation retirements may pose a greater threat to reliability in
some areas than the slowdown of new generation construction. As a
result, it states that it is imperative that transmission planners use
robust statistical approaches to identify vulnerable sources of
generation and conduct such modeling as an integral part of the
transmission planning process. The Commission understands this as a
further endorsement of its proposal to require a full range of
sensitivity studies discussed above.
    1747. MISO, International Transmission and Reliant raise important
issues about the absence of a Reliability Standard on resource
adequacy. Reliant points out the inconsistency between the statutory
requirement to provide an adequate level of Bulk-Power System
reliability and the lack of any substantive consideration of planning
reserve obligations to ensure capacity is available to meet the needs
of a reliable system. In the same vein, the Commission notes that
Requirement R7 of TOP-002-0 requires each balancing authority to plan
to meet capacity and energy reserve requirements in the operating time-
frame but that there is no explicit corresponding consideration
required of generation reserves in the planning time-frame.
    1748. Section 215(a)(3) of the FPA makes clear that enforceable
Reliability Standards may not address requirements to enlarge
facilities or construct new generation capacity. We have noted that
when a state or appropriate jurisdictional entity has such a
requirement, it should be included in transmission planning analysis.
Resource adequacy levels are set to achieve a number of goals, one of
which is system reliability. Our jurisdiction is to approve and enforce
Reliability Standards that provide for an adequate level of reliability
for the Bulk-Power System. The TPL group of Reliability Standards
includes load growth, changes in the transmission topology, existing
generation, generation retirements, and confirmed new generation as
inputs to the analyses. When an entity does not meet a reliability
criterion, including the inability of generation to be deliverable to
load, mitigation plans are required. Although the Commission
anticipates that some of those mitigation plans may include new
generation, we do not require this.
    1749. Some entities have proposed possible solutions to address the
gap of inadequate and unreliable resource information for long-term
planning as required by the TPL group of Reliability Standards. CAISO
suggests that generator owners and operators be required to provide
data on new generation and retirements to their planning authorities.
Entergy proposes requiring LSEs to provide this information, but
recognizes that this approach has its limitations. MISO contends the
preferred approach to retirements is to have in place tariff provisions
that require suppliers to announce retirement intentions six months in
advance of retirements. Process Electricity Committee is concerned
about the implications of sharing non-public transmission or customer
information which could then be exploited to the disadvantage of
competing suppliers. The Commission's Standards of Conduct addresses
the sharing of such information and generally prohibits the sharing of
commercially sensitive information between the transmission
organization and affiliated merchant functions.\443\ In response to
Process Electricity Committee, the Commission will continue to enforce
the information sharing prohibition in the Standards of Conduct.
---------------------------------------------------------------------------

    \443\ See Order No. 2004.
---------------------------------------------------------------------------

    1750. The responses to the Commission's inquiry on these matters
are helpful. The comments further point out the importance of
conducting a wider range of sensitivity studies on generation
scenarios. However, the Commission is not directing at this time any
modifications to address the Commission's concerns.

vi. Sharing of Information With Neighboring Systems
    1751. In the NOPR, the Commission stated that, because neighboring
systems may be adversely impacted, such systems should be involved in
determining and reviewing system conditions and contingencies to be
assessed in connection with Requirement R1.3 of TPL-001-0 to TPL-004-
0.\444\
---------------------------------------------------------------------------

    \444\ NOPR at P 1063.
---------------------------------------------------------------------------

(a) Comments
    1752. EEI, APPA, FirstEnergy, ERCOT and SDG&E support or
acknowledge the value of sharing of various kinds of planning
information with neighboring systems. FirstEnergy states that the
proposed requirement that system conditions and contingencies assessed
be shared and reviewed by neighboring systems will improve
communications with interconnected companies. This process was
established among former ECAR companies through the ``ECAR Peer Review
Process,'' and FirstEnergy recommends that regional reliability
organizations be encouraged to establish a similar process going
forward. EEI and APPA state that sharing of various kinds of planning
information, including expected generation additions and retirements,
planned outages, demand forecasts and estimates of firm transfers will
go a long way to improving the quality and consistency of planning
study efforts. However, it is not clear to EEI whether a formal
Reliability Standard would be the most effective approach. An
alternative could be to request that NERC oversee an informal process
to explore alternatives and report back to the Commission by a specific
date. Although ERCOT states that this proposal is a sensible
recommendation, it also states that it would not be appropriate for
ERCOT since the transmission service provided there is not subject to
interruption by the ISO, and outbound flows are also not interrupted if
there is a shortage of capacity.
    1753. SDG&E notes that under the auspices of the CAISO it regularly
convenes stakeholder meetings with the general public, neighboring
utilities, generator owners, regulators and the CAISO. In these
meetings, SDG&E reviews the grid assessment process and receives
comments from participants about all aspects of its process. As a
member of WECC, SDG&E states that it also holds meetings to discuss
inter-area projects that SDG&E has proposed to construct. This review
group consists of neighboring utilities, generator owners and other
stakeholders who are members of WECC. Similarly, SDG&E maintains that
it participates in other California-based utility review groups. SDG&E
finds that these existing processes provide ample opportunities for
regular sharing of relevant information with neighboring transmission
planning entities. It thus recommends that the Reliability Standards
development process take into account existing forums for apprising
neighboring utilities of current and anticipated transmission planning
issues and projects. If the Commission believes additional
communications are needed, SDG&E strongly recommends that the
Commission, through NERC or the applicable Regional Entity, specify in
greater detail the nature and periodicity of the information to be
shared pursuant to the TPL Reliability Standards.
    1754. SoCal Edison states that TPL-001-0 is for systems operating
under normal conditions, and as such there should not be a need for any
review by neighboring systems.
(b) Commission Determination
    1755. Most commenters agree with the Commission's proposal that
neighboring systems be involved in a peer review of system assessments
in connection with Requirement R1.3 of TPL-001-0 through TPL-004-0.
Given that neighboring systems assessments by one entity may identify
possible interdependent or adverse impacts on its neighboring systems,
this peer review will provide an early opportunity to provide input and
coordinate plans. The Commission therefore disagrees with SoCal
Edison's view that there is no need for any review by neighboring
systems for TPL-001-0. For example, the planning authorities needs to
be consistent in the line flow values that they use.
    1756. While supporting the concept of a peer review, EEI questions
whether making this a Requirement in a Reliability Standard is the most
effective approach or whether NERC should explore alternatives and
report to the Commission by a specific date. The Commission sees no
reason why peer reviews should not be part of a Reliability Standard
since TPL-001-0 through TPL-004-0 already include in Requirement R1.3 a
review of assessments by the associated regional reliability
organization. The Commission understands that some regions include peer
review as part of their procedures. Accordingly, to ensure that
neighboring systems are not adversely affected and to provide an early
opportunity for input and coordination of plans, the Commission directs
the ERO to include these modifications to the Reliability Standard
through its Reliability Standards development process to provide for
the appropriate sharing of information with neighboring systems.
    1757. The Commission has taken action on its OATT reform initiative
in Order No. 890. In that order, the Commission encourages the
formation of regional planning processes and economic planning
studies.\445\ Sharing of information and peer review are the first
steps in a regional planning process. The Commission provides guidance
and direction on these subjects in our discussion of Reliability
Standard TPL-005-0.
---------------------------------------------------------------------------

    \445\ Order No. 890 at P 526, 542.
---------------------------------------------------------------------------

b. System Performance Under Normal (No Contingency) Conditions (TPL-
001-0)
    1758. Reliability Standard TPL-001-0 deals with planning related to
system performance under normal conditions, i.e., a situation where no
system contingency or no unexpected failure or outage of a system
component has occurred.\446\ The Reliability Standard seeks to ensure
that the Bulk-Power System is planned to meet the system performance
requirements under these normal conditions by requiring the
transmission planner and the planning authority to evaluate their
transmission system annually and document the ability of that system to
meet the performance requirements established in the Reliability
Standard under conditions where no system contingencies are
present.\447\ Meeting these requirements means two things. First, when
all system facilities are in service and normal operating procedures
are in effect, the system can be operated to supply projected customer
demands and projected firm (non-recallable reserved) transmission
services at all demand levels over the range of forecast system
demands. Secondly, the system remains stable and within the applicable
ratings for thermal and voltage limits, no loss of demand or curtailed
firm transfers occurs, and no cascading outages occur. TPL-001-0
applies both to near-term and longer-term planning horizons.
---------------------------------------------------------------------------

    \446\ The NERC Glossary defines a ``contingency'' as ``[t]he
unexpected failure or outage of a system component, such as a
generator, transmission line, circuit breaker, switch or other
electrical element.'' NERC Glossary at 3.
    \447\ The performance requirements are set forth in Category A
of Table I of the Reliability Standard.
---------------------------------------------------------------------------

    1759. The Requirements of TPL-001-0 specify that the planning
authority and transmission planner must

demonstrate through a valid assessment that the Reliability Standard's
system performance requirements can be met. The assessment must be
supported by a current or past study and/or system simulation testing
that addresses various categories of conditions to be simulated as set
forth in the Reliability Standard to verify system performance under
normal conditions. When system simulations indicate that the system
cannot meet the performance requirements set forth in the Reliability
Standard, a documented plan to achieve system performance requirements
must be prepared. The specific study elements selected from each of the
categories for assessments are subject to approval by the associated
regional reliability organization.
    1760. The Commission proposed in the NOPR to approve Reliability
Standard TPL-001-0 as mandatory and enforceable. In addition, pursuant
to section 215(d)(5) of the FPA and Sec.  39.5(f) of our regulations,
we proposed to direct NERC to submit a modification to TPL-001-0 that:
(1) Requires that critical system conditions be determined by
conducting sensitivity studies; (2) requires that system conditions and
contingencies assessed be reviewed by neighboring systems; (3) modifies
Requirement R1.3 to substitute the reference to regional reliability
organization with Regional Entity; (4) requires consideration of
planned outages of critical equipment; and (5) modifies footnote (a) of
Table 1 to not apply emergency ratings to compare stresses on the
system under normal conditions as recommended by the Transmission
Issues Subcommittee of the NERC Planning Committee \448\ and require
that normal facility ratings be in accordance with Reliability Standard
FAC-008-1 and that normal voltages be in accordance with Reliability
Standard VAR-001-1.\449\
---------------------------------------------------------------------------

    \448\ See NERC Transmission Issues Subcommittee Report:
Evaluation of Criteria, Methods and Practices Used in System Design,
Planning and Analysis in Response to NERC Blackout Recommendation
13c. Appendix B, November 28, 2005.
    \449\ NOPR at P 1065-67.
---------------------------------------------------------------------------

i. Comments
    1761. APPA agrees with the Commission that TPL-001-0 is sufficient
for approval as a mandatory and enforceable standard.
    1762. MidAmerican and others generally support the Commission's
proposal to improve TPL-001-0 but caution that: (1) Planned outages
should only be considered at load levels and conditions under which
they commonly occur and (2) emergency ratings should recognize the
varying timeframes of overloads that result from various contingency
events. Further, MidAmerican states that, while it is appropriate that
planning margins for normal voltages be calculated in accordance with
VAR-001-1 as proposed by the Commission, it would be better if the
proposed modification provided that voltage criteria do not conflict
with VAR-001-1. Northern Indiana agrees with the Commission's position
regarding consideration of planned outages and states that it considers
them currently in its transmission planning studies. International
Transmission states that both planned outages of critical equipment and
the extended forced outages of similar equipment should be considered.
FirstEnergy states that planned outages should be accounted for at load
levels and conditions under which they commonly apply.
    1763. Other commenters disagree that planned outages of critical
equipment should be included in TPL-001-0.\450\ They contend that the
Reliability Standard has a very simple aim, namely, to examine whether
a system can perform under normal system intact conditions, i.e., when
all elements are in service and operating as expected. The outages
contemplated are appropriate for TPL-002-0 through TPL-004-0 where the
planned outage could be a line outage caused by a maintenance project
that extends into a period where the system is heavily loaded. SDG&E
states that for near-term planned outages, the transmission planning
entity should retain an appropriate amount of latitude to plan the
outage's timing and details and to modify them as necessary. SDG&E
comments that, for outages planned with a more distant horizon (one
year or longer), this information can be accounted for in sensitivity
analyses. SoCal Edison states that no information will be available
about planned outages of critical equipment to be used for short-term
(five years) or long-term (10 years) simulations. It may be possible to
consider planned outages of critical equipment if there is a major
project construction activity. If generators and transmission lines are
out for scheduled maintenance during off-peak load conditions, then
these outages should be considered.
---------------------------------------------------------------------------

    \450\ See, e.g., EEI, APPA, SDG&E, Entergy, SoCal Edison and
TVA.
---------------------------------------------------------------------------

    1764. EEI supports the Commission's recommendation to modify
footnote (a) in Table 1. International Transmission states that the
footnotes in Table 1 are not footnotes but rather requirements for
transmission system performance. These should be made requirements of
the Reliability Standards so that they are more obvious and easier to
monitor. APPA, LPPC and TANC recommend that changes to footnotes of
Table 1 be subject to the Reliability Standards development process.
They state that the footnotes have been extensively reviewed by
technical experts at NERC for several years and currently represent a
general consensus among these industry technical experts. Changes to
the footnotes impact Table 1 and have a direct impact on the
determination of the severity of consequences that were approved along
with the original Reliability Standard. Therefore, the Commission
should give due weight to the ERO and allow the Reliability Standards
development process to resolve any existing ambiguities in the Table 1
footnotes.
ii. Commission Determination
    1765. The Commission approves TPL-001-0 as a mandatory and
enforceable Reliability Standard. In addition, we direct the ERO to
develop modifications to TPL-001-0 through the Reliability Standards
development process, as discussed below.
    1766. In assessing system conditions, Requirement R1.3.1 of TPL-
001-0 requires entities to cover ``critical system conditions and study
years,'' as deemed appropriate by the entity performing the study. As
stated in the NOPR, system conditions are as important as contingencies
in evaluating the performance of present and future systems,\451\ and
yet TPL-001-0 does not specify the rationale for determining critical
system conditions and study years. Consistent with our discussion of
the issue above regarding sensitivity studies and critical system
conditions, the Commission concludes that proposed modification (1),
which requires that critical system conditions be determined by
conducting sensitivity studies, is justified. Accordingly, we direct
the ERO to modify the Reliability Standard to require that critical
system conditions and study years be determined by conducting
sensitivity studies with due consideration of the range of factors
outlined above.
---------------------------------------------------------------------------

    \451\ NOPR at P 1046.
---------------------------------------------------------------------------

    1767. Requirement R1.3 of TPL-001-0 states that the planning
authority and transmission planner must provide studies and simulations
to support its planning assessments, and that the specific elements
selected for the study shall be acceptable to the associated regional
reliability organization. Given that neighboring systems may be

adversely affected, our goal is to ensure that they are involved in the
determination and review of system assessments to permit an early
opportunity to provide input and coordinate plans. We discussed above
the issue of information sharing as it applies to the TPL group of
Reliability Standards generally and, consistent with our conclusions
there, we direct the ERO to modify TPL-001-0 to require a peer review
of planning assessments with neighboring entities.
    1768. The Commission received no comments on its proposal that
Requirement R1.3 be modified to substitute the reference to the
regional reliability organization with a reference to the Regional
Entity. The Commission has explained the need for this modification
above, and therefore it directs the ERO to modify Requirement R1.3 of
TPL-001-0 to substitute the reference to the regional reliability
organization with a reference to the Regional Entity.
    1769. While some commenters support the consideration of planned
outages at load levels for conditions under which they are performed,
others disagree on the grounds that the goal of TPL-001-0 is to ensure
that the Bulk-Power System can perform reliably when all elements are
in service and operating as expected. The Commission notes that
Reliability Standards TPL-002-0 through TPL-004-0 include consideration
of planned outages, as initial system conditions, at load levels for
conditions under which they are performed. Because these Reliability
Standards, and not TPL-001-0, will govern the adequacy of the Bulk-
Power System under planned outage conditions, the Commission will not
adopt the NOPR proposal to require consideration of planned outages at
load levels for conditions under which they are performed for
Reliability Standard TPL-001-0. However, consistent with our discussion
above on spare equipment strategy, the Commission directs a
modification to this Reliability Standard to require assessments of
outages of critical long lead time equipment, consistent with the
entity's spare equipment strategy. Thus, for example, if an entity's
spare equipment strategy for the permanent loss of a transformer is to
use a ``hot spare'' or to relocate a transformer from another location
in a timely manner, the outage of the transformer need not be assessed
under peak system conditions. However, if the spare equipment strategy
entails acquisition of a replacement transformer that has a one-year or
longer lead time, then the outage of the transformer must be assessed
under peak loading conditions likely to be experienced. This approach
will ensure that system conditions are adequately assessed.
    1770. While commenters generally agree with the Commission's
proposal to modify footnote (a) of Table 1, they caution that any
changes to the footnotes affect Table 1 and should be reviewed through
NERC's Reliability Standards development process. International
Transmission states that the footnotes in Table 1 are not footnotes but
rather requirements for transmission system performance and therefore
should be made Requirements in the Reliability Standard. The Commission
agrees with International Transmission because this will promote
clarity in and consistent application of the Reliability Standard. The
Commission therefore directs the ERO to modify the Reliability Standard
to address the concerns regarding footnote (a) of Table 1, including
the applicability of emergency ratings and consistency of normal
ratings and voltages with values obtained from other Reliability
Standards. As with any modification to a Reliability Standard,
modifications to TPL-001-0 should be developed through the ERO's
Reliability Standards development process.
    1771. Accordingly, the Commission approves Reliability Standard
TPL-001-0 as mandatory and enforceable. In addition, the Commission
directs the ERO to develop a modification to TPL-001-0 through the
Reliability Standards development process that: (1) Requires that
critical system conditions and study years be determined by conducting
sensitivity studies with due consideration of the range of factors
outlined above; (2) requires a peer review of planning assessments with
neighboring entities; (3) modifies Requirement R1.3 to substitute the
reference to regional reliability organization with Regional Entity;
(4) requires assessments of outages of critical long lead time
equipment, consistent with the entity's spare equipment strategy; and
(5) address the concerns regarding footnote (a) of Table 1, including
the applicability of emergency ratings and consistency of normal
ratings and voltages with values obtained from other Reliability
Standards and the concerns raised by International Transmission in
regard to the footnotes in Table 1.
c. System Performance Following Loss of a Single Element (TPL-002-0)
    1772. Reliability Standard TPL-002-0 addresses system planning
related to performance under contingency conditions involving the
failure of a single element with or without a fault, i.e., the
occurrence of an event such as a short circuit, a broken wire or an
intermittent connection. The Reliability Standard seeks to ensure that
the future Bulk-Power System is planned to meet the system performance
requirements, with the loss of one element, by requiring that the
transmission planner and planning authority annually evaluate and
document the ability of the transmission system to meet the performance
requirements where an event results in the loss of a single
element.\452\ Meeting these requirements means two things. First, it
means that the system can be operated following the event to supply
projected firm customer demands and projected firm (non-recallable
reserved) transmission services at all demand levels over the range of
forecast system demands. Second, it means that the system remains
stable and within the applicable ratings for thermal and voltage
limits, no loss of demand or curtailed firm transfers occurs, and no
cascading outages occur.\453\ The Reliability Standard applies both to
near-term and longer-term planning horizons.
---------------------------------------------------------------------------

    \452\ The performance requirements are set forth in Category B
of Table 1 of the Reliability Standard.
    \453\ Footnote b to Table 1 allows for the interruption of firm
load for consequential load loss.
---------------------------------------------------------------------------

    1773. TPL-002-0 specifies that the planning authority and
transmission planner must demonstrate through a valid assessment that
the Reliability Standard's system performance requirements can be met.
The assessment must be supported by a current or past study and/or
system simulation testing that addresses various categories of
conditions to be simulated, as set forth in the Reliability Standard,
to verify system performance under contingency conditions involving the
failure of a single element with or without a fault. The Reliability
Standard requires that planned outages of transmission equipment be
considered for those demand levels for which planned outages are
performed. When system simulations indicate that the system cannot meet
the performance requirements stipulated in the Reliability Standard, a
documented plan to achieve system performance requirements must be
prepared. The specific study elements selected from each of the
categories for assessments are subject to approval by the associated
regional reliability organization.
    1774. The Commission proposed in the NOPR to approve Reliability
Standard TPL-002-0 as mandatory and

enforceable. In addition, pursuant to section 215(d)(5) of the FPA and
Sec.  39.5(f) of our regulations, we proposed to direct NERC to submit
a modification to TPL-002-0 that: (1) Requires that critical system
conditions be determined in the same manner as proposed for TPL-001-0;
(2) requires the inclusion of the reliability impact of the entity's
existing spare equipment strategy; (3) explicitly requires all
generators to ride through the same set of Category B and C
contingencies as required for wind generators in Order No. 661; (4)
requires documentation of load models used in system studies and
supporting rationale for their use; (5) clarifies the phrase ``permit
operating steps necessary to maintain system control'' and (6)
clarifies footnote (b) to Table 1 to allow no firm load or firm
transactions to be interrupted except for consequential load loss.
i. Comments
    1775. APPA agrees that TPL-002-0 is sufficient for approval as a
mandatory and enforceable reliability standard.
    1776. In response to the Commission's proposal \454\ that NERC
modify TPL-002-0, in part, because it does not address situations in
which critical equipment may be unavailable for a prolonged period,
Northern Indiana states that systems depicted in planning studies
cannot possibly contain complete planned and forced outage schedules
for the next ten years. For this reason TPL-003-0 deals with double
contingencies, i.e., contingencies that allow operator intervention
after the first outage, and then capture system response to an
additional outage. Operator intervention includes coordination of
contingency plans and may impact strategies for spare equipment,
particularly for critical equipment.
---------------------------------------------------------------------------

    \454\ NOPR at P 1081.
---------------------------------------------------------------------------

    1777. EEI and MidAmerican support requiring all generators to ride
through the same contingencies as required for wind generators.
Constellation notes that while it supports the Commission's proposed
modifications to TPL-002-0, an explicit requirement that all generators
stay online during the same set of Category B and C events, as is
required for wind generators, is too broad. Constellation requests that
the Commission modify this requirement to recognize that NRC has
specific requirements for how nuclear generation must respond to
disturbances on the Bulk-Power System, and that those NRC rules should
apply. Moreover, Constellation generally recommends that the
Reliability Standards applied to nuclear generation should be
consistent with NRC requirements and that NRC rules should control in
the event of conflict.
    1778. NRC notes that there appears to be significant variation in
the interpretation of this Reliability Standard. It states that some of
its licensees interpret the TPL-002-0 Reliability Standard to state
that if a licensee is operating in an N-1 condition another single
contingency does not need to be considered. NRC states that its
interpretation has been that the N-1 condition is always analyzed from
the conditions being experienced. They state that this Reliability
Standard should be clarified and recommend specific revisions to
Requirements R1.6, R2.1, R2.2 and Levels of Non-Compliance.
    1779. Northern Indiana expresses concern about the statement in P
1062 of the NOPR that ``load models used in system studies have a
significant impact on system performance * * *.'' Northern Indiana
believes the opposite is true, i.e., system performance has a
significant impact on load models. The goal of the models is to attempt
to capture system performance.
    1780. MidAmerican supports the proposed clarifications to operating
steps and to footnote (b). International Transmission states that more