clarification should be provided for the thresholds of normal and
emergency ratings. There are potential inconsistencies with respect to
whether or not an entity can plan to operate above normal ratings, but
below emergency ratings, and for how long.
    1781. Northern Indiana also takes issue with the NOPR proposal that
no load or transactions be interrupted except for consequential load
loss. Attempting to reduce the probability of load loss to zero would
greatly increase capital spending, and therefore increase rates to
customers, and all in the name of achieving an unattainable goal. PG&E
disputes that the Reliability Standard should provide limits on the
magnitude and duration of consequential load loss. Determining the
magnitude and consequences of load loss is a factor in the economic
evaluation during the development of transmission expansion plans. This
economic evaluation is not an appropriate subject for this Reliability
Standard. Northern Indiana urges the Commission to acknowledge that
planning studies by nature must balance infrastructure improvement and
expansion against site-specific and regional load projections, using
available resources. It questions whether the NOPR reflects a proper
balance between the many costs involved and the benefits, if any, that
would be realized.
    1782. Entergy opposes the Commission's proposed guidance concerning
footnote (b) to Table 1 for two reasons. First, Entergy believes the
Commission should give due weight to the technical expertise of NERC
and permit NERC to address these matters through Reliability Standards
development process. Second, the Commission's guidance suggests that it
views all transmission outages as having the same level of importance
to and impact on the interconnected transmission grid. Entergy states
that the Commission should recognize that the effect of transmission
outages can be local in nature and have no impact on the reliability of
the Bulk Power System. Removing the transmission operator's ability to
shed load or enact other system adjustments as appropriate for a single
contingency would result in significant facility upgrade costs simply
to avoid the consequence of a local outage. Entergy requests that the
Commission clarify that its guidance does not constrain the
transmission operator's ability to determine the best course of action
to take to address any reliability constraint that may result from
these local outages.
    1783. PG&E disagrees with the Commission's proposal to delete from
footnote (b) of this Reliability Standard the phrase ``to prepare for
the next contingency, system adjustments are permitted, including
curtailments of contracted Firm (non-recallable reserved) electric
power transfers.'' \455\ PG&E states that this phrase permits critical
system adjustments to reduce the potential for and impact of future
contingencies. It would allow re-scheduling power (but not load
shedding) as part of manual system adjustment after the first Category
B contingency (first N-1) to bring the system back to a safe operating
point before the next Category B contingency (second N-1). This phrase
is consistent with the manual system adjustment allowed in Category
C.3.\456\ PG&E states that, contrary to the Commission's
interpretation, footnote (c) does not capture this phrase. The
difference between footnote (b) as part of Category B and Category C.3
is that footnote (b) applies before the second N-1, whereas Category
C.3 applies after the second N-1. Without this phrase in footnote (b),
no manual system adjustment would be

allowed after a Category B contingency, which would be inconsistent
with Category C.3.
---------------------------------------------------------------------------

    \455\ Id. at P 1084.
    \456\ From TPL Standards Table 1, Category C.3 is Category B
(B1, B2, B3 or B4) contingency, manual system adjustments, followed
by another Category B (B1, B2, B3 or B4) contingency.
---------------------------------------------------------------------------

    1784. APPA and LPPC recommend that changes to the footnotes of
Table 1 be subject to the NERC 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 affect Table 1 and have a direct impact on the
determination of the severity of consequences that were approved along
with the original standard. APPA also states that consideration of
reliability impacts of spare equipment strategies and obligations of
all generators to have the same voltage ride through capabilities are
important changes that should not be made by Commission fiat.
ii. Commission Determination
    1785. The Commission approves TPL-002-0 as a mandatory and
enforceable Reliability Standard. In addition, we direct the ERO to
develop modifications to TPL-002-0 through the Reliability Standards
development process, as discussed below.
    1786. The Commission notes that, like Requirement R1.3.1 of TPL-
001-0, R1.3.2 of TPL-002-0 requires an entity assessing system
performance to cover ``critical system conditions and study years'' as
deemed appropriate by the entity performing the study, but it does not
specify the rationale for determining critical system conditions and
study years. The Commission directs the ERO to modify TPL-002-0 to
require that critical system conditions and study years be determined
in the same manner as it directed with regard to TPL-001-0. The
Commission's explanation of the need for that change applies equally
here.
    1787. With regard to Northern Indiana's concerns, we disagree that
the proposal to address situations in which critical equipment may be
unavailable for a prolonged period requires planned and forced outage
schedules for the next ten years. Reliability Standard TPL-002-0
requires consideration of planned outages at those demand levels for
which planned outages are performed but does not address situations in
which critical long lead time equipment, such as a transformer or phase
angle regulator, may be unavailable for a prolonged period that could
extend into periods where planned outages of such equipment would not
normally be performed. Assessments of these situations do not require
outage schedules for the next ten years but rather identification of
which facilities are deemed to be critical that have long lead times
for repair or replacement. Given that planned outage considerations of
such long lead time equipment are inexorably linked to spare equipment
strategy, consistent with our discussion of the issue above in
connection with spare equipment strategy, the Commission directs the
ERO to modify the Reliability Standard to require assessments of
planned outages of long lead time critical equipment consistent with
the entity's spare equipment strategy.
    1788. In the NOPR, the Commission identified an implicit assumption
in the TPL Reliability Standards that all generators are required to
ride through the same types of voltage disturbances and remain in
service after the fault is cleared. This implicit assumption should be
made explicit. Commenters agree with the proposed requirement for all
generators to ride through the same set of Category B and C events as
required for wind generators. The Commission understands that NRC has
both degraded voltage and loss of voltage requirements. The degraded
voltage requirement allows the voltage at the auxiliary power system
busses to go below the minimum value for a time frame that is usually
much longer than normal fault clearing time.\457\ If a specific nuclear
power plant has an NRC requirement that would force it to trip off-line
if its auxiliary power system voltage was depressed below some minimum
voltage, the simulation should include the tripping of the plant in
addition to the faulted facilities. In this regard, the Commission
agrees that NRC requirements should be used when implementing the
Reliability Standards. Using NRC requirements as input will assure that
there is consistency between the Reliability Standards and the NRC
requirement that the system is accurately modeled. Accordingly, the
Commission directs the ERO to modify the Reliability Standard to
explicitly require either that all generators are capable of riding
through the same set of Category B and C contingencies, as required by
wind generators in Order No. 661, or that those generators that cannot
ride through be simulated as tripping. If a generator trips due to low
voltage from a single contingency, the initial trip of the faulted
element and the resulting trip of the generator would be governed by
Category B contingencies and performance criteria.
---------------------------------------------------------------------------

    \457\ 10 CFR 50, Appendix a, GDC17.
---------------------------------------------------------------------------

    1789. The Commission agrees with NRC that for operations purposes
the N-1 condition is always analyzed from the conditions being
experienced. In other words, allowing for the 30 minute system
adjustment period, the system must be capable of withstanding an N-1
contingency, with load shedding available to system operators as a
measure of last resort to prevent cascading failures. However, for
planning purposes, a different analysis applies. The N-1 condition is a
Category B event under TPL-002-0, and, following the N-1 contingency,
the system must be stable and thermal loading and voltages be within
applicable limits. Some adjustment of generation or other controls is
permitted to return loadings to within continuous ratings, provided the
loadings before adjustments are within the emergency or short-term
ratings. Under TPL-002-0 the system is not required to be able to
withstand another N-1 contingency. That N-1 requirement is a Category C
contingency which is addressed by TPL-003-0. The Commission has
addressed NRC's comment concerning N-1 contingencies in real-time
operation in TOP-002. In regard to the specific revisions proposed by
NRC, the Commission directs the ERO to consider these as part of the
Reliability Standards development process.
    1790. In regard to Northern Indiana's comment concerning the load
modeling statement made in the NOPR, it should be clear that the
context of the discussion is system performance during simulations.
Load models used in simulations clearly should, to the extent feasible,
represent the actual performance of the aggregate mix of industrial,
commercial and residential loads. If the load model representations
used in simulations do not mirror the actual performance of loads,
especially during dynamic simulations, but also when carrying out
voltage stability studies, the simulation results will not be accurate.
Because load representation in simulations has a significant impact on
simulation results and often load models are not well known, it is
common practice for planners to perform sensitivity studies with a
range of load models. Accordingly, as proposed in the NOPR, the
Commission directs the ERO to modify the Reliability Standard to
require documentation of load models used in system studies and the
supporting rationale for their use.
    1791. In the NOPR, the Commission set forth its rationale for
proposing that the ERO clarify the phrase ``permit operating steps
necessary to maintain system control'' in footnote (a) to Table 1.\458\
Specifically, the Commission stated that the operating steps required

to relieve emergency loadings and return the system to a normal state
should not include firm load shedding. MidAmerican agrees with the
Commission. International Transmission states clarification is required
on the thresholds for normal and emergency ratings and, in particular,
on whether an entity can plan to operate above normal ratings but below
emergency ratings and for how long. The Commission agrees that this
issue requires clarification and therefore directs the ERO to modify
the standard to clarify the phrase of footnote (a) that states ``permit
operating steps necessary to maintain system control'' to clarify the
use of emergency ratings.
---------------------------------------------------------------------------

    \458\ NOPR at P 1083.
---------------------------------------------------------------------------

    1792. The Commission stated in the NOPR that footnote (b) raises
three issues that need to be addressed.\459\ Two relate to the use of
planned or controlled load interruption under certain circumstances,
and the third relates to the use of system adjustments including
curtailment of firm transfers to prepare for the next contingency.
Northern Indiana and Entergy disagree with the Commission's proposal to
modify footnote (b) to state that load shedding for a single
contingency is not permitted except in very special circumstances where
such interruption is limited to the firm load associated with the
failure (consequential load loss). The commenters argue that the impact
of transmission outages can be local in nature and have no impact on
the reliability of the Bulk-Power System and that removing the option
to shed load in a local area for a single contingency would result in
significant facility upgrade costs and therefore increased rates to
customers simply to avoid a local outage. Entergy seeks clarification
that the Commission does not intend to constrain the transmission
operator's ability to determine the best course of action to address
local reliability constraints.
---------------------------------------------------------------------------

    \459\ Id. at P 1084.
---------------------------------------------------------------------------

    1793. The NOPR proposed a modification that would clarify footnote
(b) as disallowing loss of such firm load or the curtailment of firm
transactions after a first contingency of the bulk electric system. In
its comments to the Staff Preliminary Assessment, NERC agreed with this
interpretation, representing that a practice that permits the planned
interruption of ``firm transmission service'' is a misapplication of
the Reliability Standard.\460\ Some commenters now argue otherwise, and
in some cases cite examples where, based on a balance of economic and
reliability considerations, it may be preferable to plan the bulk
electric system in such a manner that contemplates the interruption of
some firm load customers in the event of a N-1 contingency. We view
these arguments as based largely on the matter of economics, not
reliability, with the underlying premise that it is not economically
feasible to invest in the bulk electric system to the point that it can
continue service to all firm load customers under some specific N-1
scenarios. Therefore, they argue, the ambiguities of footnote (b)
should be interpreted to allow that an entity plan for some amount of
load loss to avoid costly infrastructure investments.
---------------------------------------------------------------------------

    \460\ ``NERC standards, including footnote (b), are not intended
to endorse or approve planning the interconnection using radial
configurations as a preferred method for reliably serving load, nor
do NERC standards consider load shedding acceptable for a single
contingency.'' NERC comments to the Staff Preliminary Assessment at
57-58.
---------------------------------------------------------------------------

    1794. The Commission considers this matter to be a fundamental
issue of transmission service. Indeed, the ERO's definition of ``firm
transmission service'' specifically states that it is the ``highest
quality (priority) service offered to customers under a filed rate
schedule that anticipates no planned interruption.''
    1795. Based on the record before us, we believe that the
transmission planning Reliability Standard should not allow an entity
to plan for the loss of non-consequential load in the event of a single
contingency.\461\ The Commission directs the ERO to clarify the
Reliability Standard. Regarding the comments of Entergy and Northern
Indiana that the Reliability Standard should allow entities to plan for
the loss of firm service for a single contingency, the Commission finds
that their comments may be considered through the Reliability Standards
development process. However, we strongly discourage an approach that
reflects the lowest common denominator.\462\ The Commission also
clarifies that an entity may seek a regional difference to the
Reliability Standard from the ERO for case-specific circumstances.
---------------------------------------------------------------------------

    \461\ Consequential load is the load that is directly served by
the elements that are removed from service as a result of the
contingency.
    \462\ See Order No. 672 at P 329.
---------------------------------------------------------------------------

    1796. PG&E disputes that the Reliability Standard should provide
limits on the magnitude and duration of consequential load loss, as
this is an economic evaluation and is not an appropriate goal for this
Reliability Standard. The Commission disagrees. Indeed in its comments
to the Staff Preliminary Assessment, the ERO raised the issue of what
is an acceptable magnitude and duration of consequential load
loss.\463\ The Commission notes that most utilities have guidelines for
the magnitude and duration of load loss that is acceptable on radial
facilities before the facilities are looped to provide a second source
of supply to accommodate load growth. NERC also stated that it
recognizes that looped configurations are key to the reliable operation
of the Interconnection and to meet reasonable expectations for reliable
service to loads.\464\ The Commission, therefore, suggests that the ERO
consider developing a ceiling on the amount and duration of
consequential load loss that will be acceptable. If the ERO determines
that such a ceiling is appropriate, it should be developed through the
ERO's Reliability Standards development process. Further, we note that
the DOE thresholds for reporting disturbances on Form EIA-417 would be
one example of an appropriate starting point for developing such a
ceiling. These thresholds for load loss are 300 MW for 15 minutes or
50,000 customers for one hour, whichever is greater.
---------------------------------------------------------------------------

    \463\ NERC Comments to Staff Preliminary Assessment at 56-57.
    \464\ ``NERC recognizes that looped configurations are key to
the reliable operation of the interconnection, and to meet
reasonable expectations for reliable service to loads.'' Id. at 57.
---------------------------------------------------------------------------

    1797. The third issue with footnote (b) relates to the Commission's
proposal in the NOPR to delete the footnote's second sentence, which
states ``[t]o prepare for the next contingency, system adjustments are
permitted, including curtailments of contracted Firm (non-recallable
reserved) electric power transfers.'' \465\ PG&E disagrees with the
Commission's proposal because it allows re-scheduling power (but not
load shedding) as part of manual adjustment after the first Category B
contingency to bring the system back to a safe operating point. The
Commission agrees that footnote (b) should permit manual adjustments
including generation redispatch and transmission reconfiguration, but
not load shedding, to return the system to a normal operating state
within the time period permitted by the emergency or short term
ratings. The Commission understands that this is the normal practice
used by most transmission planners. However, the system adjustments
permitted in the statement above includes curtailments of contracted
firm, non-recallable reserved and electric power transfers and this is
not acceptable for Category B single contingencies. Therefore, the ERO
should modify the sentence to indicate that manual system adjustments,
except

for shedding firm load or curtailment of firm transfers, are permitted
after the first contingency to bring the system back to a normal
operating state. The Commission disagrees with PG&E's statement that
the difference between footnote (b) as part of Category B and Category
C.3 is that footnote (b) applies before the second N-1 contingency,
whereas Category C.3 applies after the second N-1 contingency. Rather,
manual adjustments referred to in both cases apply after the first N-1
contingency. The Commission, therefore, directs the ERO to modify the
second sentence of footnote (b) to clarify that manual system
adjustments other than shedding of firm load or curtailment of firm
transfers are permitted to return the system to a normal operating
state after the first contingency, provided these adjustment can be
accomplished within the time period allowed by the short term or
emergency ratings.
---------------------------------------------------------------------------

    \465\ NOPR at P 1083.
---------------------------------------------------------------------------

    1798. Accordingly, the Commission approves Reliability Standard
TPL-002-0 as mandatory and enforceable. In addition, the Commission
directs the ERO to develop a modification to TPL-002-0 through the
Reliability Standards development process that: (1) Requires that
critical system conditions be determined in the same manner as we
propose to require for TPL-001-0; (2) requires assessments of planned
outages of long lead time critical equipment consistent with the
entity's spare equipment strategy; (3) requires all generators to ride
through the same set of Category B and C contingencies as required by
wind generators in Order No. 661, or to simulate those generators that
cannot ride through as tripping; (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'' in footnote (a) and the use of emergency ratings and
(6) clarifies footnote (b) in regard to load loss following a single
contingency, specifying the amount and duration of consequential load
loss and system adjustments permitted after the first contingency to
return the system to a normal operating state, as discussed above.
d. System Performance Following Loss of Two or More Elements (TPL-003-
0)
    1799. Reliability Standard TPL-003-0 seeks to ensure that the
future Bulk-Power System is planned to meet the system performance
requirements of a system with the loss of multiple elements. It does
this by requiring that the transmission planner and the planning
authority annually evaluate and document the ability of its
transmission system to meet the performance requirements of Category C
contingencies specified in Table 1 (i.e., events resulting in the loss
of two or more elements) for both the near-term and the longer-term
planning horizons. TPL-003-0 requires the preparation of a documented
plan to achieve the necessary performance requirements if the system is
unable to meet the Category C performance criteria.
    1800. TPL-003-0 applies to each planning authority and transmission
planner. They must demonstrate annually through valid assessments that
their portion of the interconnected transmission system is planned to
meet the performance requirements of Category C with all transmission
facilities in service over a planning horizon that takes into account
lead times for corrective plans. The Reliability Standard also requires
the applicable entities to consider planned outages of transmission
equipment for those demand levels for which they perform such outages.
The Reliability Standard defines various categories of conditions to be
simulated. The specific study elements selected from each of the
categories for assessments, including the subset of Category C
contingencies to be evaluated, require approval by the associated
regional reliability organization.
    1801. The Commission proposed in the NOPR to approve Reliability
Standard TPL-003-0 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-003-0 that:
(1) Requires that critical system conditions be determined by
conducting sensitivity studies (as elaborated in our discussion of TPL-
001-0); (2) makes certain clarifications to footnote (c) to Table 1;
(3) requires the applicable entities to define and document the proxies
necessary to simulate cascading outages and (4) tailors the purpose
statement to reflect the specific goal of the Reliability Standard.
    1802. The Commission also sought comments on one potential addition
to TPL-003-0. It noted that Category C3 of this Reliability Standard
involves a situation in which two single contingencies occur, with
manual system adjustments permitted after the first contingency to
prepare for the next one (generally referred to as N-1-1). However, the
Commission also noted that should the second contingency occur before
the manual system adjustments can be completed, the local area and
potentially the system would be exposed to risk of cascading outages.
For that reason some entities plan and operate their systems so that
they are able to withstand the simultaneous occurrence of the two
contingencies (normally referred to as N-2) for major load pockets. The
Commission sought comments on the value and appropriateness of
including such a requirement in TPL-003-0.
i. Comments
    1803. LPPC recommends that changes to footnotes of Table 1 be
subject to the NERC Reliability Standards development process. It
states 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 which should be given
due weight by the Commission. 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.
    1804. FirstEnergy supports the proposed requirement to document
proxies of subsequent line trips due to thermal overload and low
voltage generation trips to evaluate potential cascading conditions.
FirstEnergy states it currently is required to account for these items
in its planning process.
    1805. EEI questions the value of providing proxies when planners
conduct thousands of studies based on combinations of contingencies
under a broad range of circumstances and conditions, especially in
longer-term planning horizons where the uncertainty around the value of
any one variable is already very high. SoCal Edison states that one can
determine the cascading outages in load flow studies. In transient
stability studies, if the outage is severe, then the thermal overload
relays and undervoltage relays, if modeled, will trip the load. If the
load tripped was not planned to be tripped for this outage, then the
planning authority should take the necessary steps to avoid this
situation, as cascading is not allowed.
    1806. LPPC and Northern Indiana oppose the proposal to require
proxies necessary to simulate cascading outages be defined and
documented. Northern Indiana states that there is no consensus on what
these proxies should be. LPPC states that utility planners have
traditionally used their engineering judgment to simulate a
conservative estimate of the level of thermal overload or low voltage
that will cause the likelihood of subsequent line or generator trips
and cascading events. LPPC states that this approach has been

successful, and NERC should not be asked to second-guess the decisions
of operators in this area. That could result in the adoption of less
conservative, least common denominator, design assumptions across all
regions and reduce modeling flexibility and use of engineering
judgment. Proxies are typically tailored to specific systems because
the development of proxies is highly dependent on regional differences
and localized knowledge. If the Commission determines that independent
review of utility outage simulation proxies is necessary, Regional
Entities should conduct that review, because they better understand the
regional and localized factors that influence the proxies.
    1807. EEI requests that the Commission clarify the meaning of the
term ``controlled load interruption'' and the meaning of its statement
that ``to avoid undue negative impact on competition, third party
studies could be permitted to implement the same or less controlled
load interruption as used by the transmission owner.'' \466\
---------------------------------------------------------------------------

    \466\ Id. at P 1097.
---------------------------------------------------------------------------

    1808. NRC states that this Reliability Standard should be clarified
in regard to the N-1-1 condition. In addition, it recommends specific
changes to Requirements R1.6, R.1.2 and R2.2.
    1809. A number of commenters respond to the Commission's request
for comments on the value and appropriateness of including the ability
of the system to withstand two simultaneous contingencies for major
load pockets. NERC states that this issue has been recognized as
needing clarification, and it welcomes comments in the development of
these revisions in accordance with its Reliability Standards
development process. NERC states that it is developing a proposal for a
transmission availability data system that will provide a quantitative
(probabilistic) basis for judging the likelihood of various multi-
element contingencies which will be helpful in determining the value of
this proposal.
    1810. APPA, LPPC and National Grid state that imposing N-2 planning
may be difficult to administer since there is no consensus on what
constitutes a ``major load pocket.'' LPPC states that the definition of
major load pockets has been, and is still being debated. As there is no
nation-wide consensus on the term's definition, no list of major load
pockets exists. Because load pockets and their boundaries change with
the dynamically changing system and load patterns, it is difficult to
establish or administer a rule that encompasses the particular sub-
region to which such an N-2 requirement would apply.
    1811. APPA and EEI believe such provisions would significantly
expand planning requirements for extremely unlikely events that in most
cases are not cost effective to build into system planning decisions.
They explain that the Reliability Standard currently includes the more
likely situation, i.e., where two events occur in a time frame that
allows some time to adjust in response to the first event. APPA and EEI
state that various planning entities may, of course, study much more
extreme events, including the hypothetical the Commission poses,
especially if formal state or regional planning requires such studies,
and actual preparation for extreme events is viewed as cost-effective
in a particular area. However, this level of planning sensitivity is
simply unnecessary for many regions of the country. They ask that if
the Commission envisions changes to provide for N-2 service to load
pockets, a dialogue must first be initiated within the industry and
with state public utility commissions to identify such load pockets,
target the required transmission investments (which could be very
substantial) and develop plans for allocating the costs of such
investments.
    1812. FirstEnergy comments that, although simultaneous C.3
independent contingencies may pose potentially high risk, they are most
likely extremely low in probability. FirstEnergy states that it
nevertheless routinely evaluates these contingencies across its system
for facilities 200 kV and higher and suggests that if this analysis is
made a requirement, it should be limited to an extra high voltage
subset of the Bulk-Power System.
    1813. MISO believes that evaluation of multiple contingency events
should only reside in the planning arena and not in the operations
environment. It states that the current Reliability Standard provides a
reasonable and time tested methodology.
    1814. National Grid opposes applying this N-2 criterion across the
board. It states that N-2 planning is usually relied upon when a
particular area does not have the resources or flexibility to adopt the
N-1-1 approach. The Bulk-Power System is designed differently in every
region, and there is no need to impose N-2 planning where regions are
satisfactorily implementing the N-1-1 methodology.
    1815. SDG&E states that the N-2 consideration for major load
pockets is neither of value nor appropriate for transmission planning
entities at large. The probability of such a contingency for a major
load pocket is very low, and the costs for addressing such a remote
contingency would be significant. SoCal Edison states the potential
number of multi-contingency events that could be studied under TPL-003-
0 is staggering. Planners should be given flexibility to select
generation and transmission elements that reflect a broad range of
potential combinations without having to commit resources to conduct
potentially hundreds or thousands of contingency studies. Northern
Indiana contends that this requirement is in effect a third back-up
capability, that it would be prohibitive in terms of time and cost, and
that it would take many years to put the infrastructure it would
require into place.
    1816. PG&E believes there is no need for a general requirement to
withstand the simultaneous occurrence of any two contingencies for
major load pockets. It states that IRO-005 provides for contingencies
that are credible when operating below IROL in current day operations.
The TPL group of Reliability Standards already require provisions for
specific circumstances based on evaluations that take into account the
probability of an outage occurring and the associated consequences when
transmission plans are developed. PG&E states that TPL-003-0, Category
C.5 contingency already addresses the more probable simultaneous
outages (due to common-mode failure) that could occur. PG&E maintains
that simultaneous occurrence of other contingencies is not credible.
The principles incorporated in the Reliability Standards require that
evaluations of credibility be balanced against potential impact, and
investing resources to prevent improbable events diverts attention and
focus from more critical Reliability Standards and more probable
conditions.
ii. Commission Determination
    1817. The Commission approves proposed Reliability Standard TPL-
003-0 as a mandatory and enforceable Reliability Standard. In addition,
we direct the ERO to develop modifications to TPL-003-0 through the
Reliability Standards development process, as discussed below.
    1818. The Commission notes that, like Requirement R1.3.1 of TPL-
001-0, Requirement R1.3.2 of TPL-003-0 requires an entity assessing
system performance to cover ``critical system conditions and study
years'' as deemed appropriate by the entity performing the study, but
that the Requirement does not specify the rationale for determining
critical system conditions and study years. The Commission directs the
ERO to modify TPL-003-0 to require that

critical system conditions and study years be determined in the same
manner as we directed with regard to TPL-001-0, for the reasons as set
forth in our discussion of TPL-001-0.
    1819. The intent underlying the statement that ``to avoid undue
negative impact on competition, third party studies should be permitted
to implement the same or less controlled load interruption as used by
the transmission owner'' is to ensure that third parties have access to
the same options that the transmission owner uses to alleviate
reliability constraints including those related to controlled load
shedding. For example, if a transmission owner designs its system to
result in a controlled load shedding of 300 MW for Category C
contingencies, designs proposed for third parties requesting
interconnections to that system must also be permitted, but not
required, to have 300 MW of controlled load shedding for the same
Category C contingencies. The Commission directs the ERO to modify
footnote (c) of Table 1 to the Reliability Standard to clarify the term
``controlled load interruption.'' In response to LPPC's comments on
modification procedures, the Commission agrees that changes to the
footnotes of Table 1 should be addressed through the ERO's Reliability
Standards development process.
    1820. The Commission stated in the NOPR that the concern involved
relates to the use of thermal overloads or low voltage proxies to judge
the likelihood of subsequent line or generator trips leading to a
cascading outage.\467\ The Commission agrees with SoCal Edison that, if
an entity models overload relays, undervoltage relays, all remedial
action schemes including those of neighboring systems and has a good
load representation, then proxies are not required. However, due to
modeling and simulation limitations this is often not the case and
planners invariably use proxies.\468\ Recognizing this and the range of
proxies currently in use, the Transmission Issues Subcommittee of the
NERC Planning Committee recommended that proxies used in simulations be
defined until such time as improved analytical tools and models are
available to simulate cascading events.
---------------------------------------------------------------------------

    \467\ Id. at P 1098.
    \468\ See WECC Disturbance Performance Table W-1 and Figure W-1
of Allowable Effects on other Systems, NERC/WECC Planning Standards
April 10, 2003.
---------------------------------------------------------------------------

    1821. The Commission disagrees with LPPC that defining and
documenting proxies will result in the adoption of less conservative,
least common denominator design assumptions across all regions and
reduce modeling flexibility and engineering judgment. To the contrary,
the Commission believes that such sharing of information will improve
knowledge and understanding and promote a more rigorous approach to
analyzing cascading outages. The Commission agrees with LPPC that it
may be preferable for the Regional Entities to conduct the review of
proxies, because they better understand the regional and localized
factors that influence the proxies. However, we expect the ERO to
coordinate between regions to assure that best practices are shared
among the Regional Entities. Accordingly, the Commission directs the
ERO to modify the Reliability Standard to require definition and
documentation of proxies necessary to simulate cascading outages.
    1822. No comments were received on the Commission's proposal that
the purpose statement of TPL-003-0 be tailored to reflect the specific
goal of the Reliability Standard. The Commission directs that this
modification be made. Reliability Standards should be clear and
unambiguous, and a clear statement of a Reliability Standard's purpose
and goal is one of the features necessary to achieve this end.
    1823. The NRC's comments on TPL-003-0 parallel its comments on TPL-
002-0. The Commission discussed those comments above, and its
conclusions there apply equally here. The Commission, for the same
reasons set forth in our discussion of TPL-002-0, directs the ERO to
address NRC concerns through its Reliability Standards development
process.
    1824. The Commission received numerous comments on its request for
comments on the appropriateness and value of including the ability of
the system to withstand two simultaneous Category B contingencies for
major load pockets. The Commission stated that it was aware that
several entities currently apply this approach and notes that one
entity was actually commended by NERC for doing so as part of its
readiness review. FirstEnergy states that it routinely evaluates these
contingencies across its system for 200 kV and higher. NERC states that
this issue has been recognized as requiring clarification, and it
welcomes comments on these revisions in accordance with the Reliability
Standards development process.
    1825. Many commenters state that, without a consensus on what
constitutes a major load pocket, little progress can be made in this
regard. LPPC states that the definition of major load pockets has been
and is still being debated. National Grid states that N-2 planning is
usually relied upon when a particular area does not have the resources
and flexibility to adopt the N-1-1 approach. The Commission agrees with
National Grid but notes that this is more applicable to the operating
domain, something that MISO opposes. PG&E states that this approach is
not necessary because Category C5 already addresses more probable
simultaneous outages due to common mode failure. The Commission
disagrees since Category C5 only deals with a loss of any two circuits
on a multi-circuit tower line and not a simultaneous loss of a line and
a generator which was envisaged by the request for comments. Many
commenters indicated that this was a very low probability event and the
costs for addressing such an event would be significant. As a result,
EEI states that a dialogue must first be initiated within the industry
and with state public utility commissions to identify such load
pockets, to target the required potentially significant transmission
investments and to develop plans for allocating the costs of such
investments. In light of these comments, the Commission does not intend
to recommend action on this issue at this time and, instead, directs
the ERO to consider the comments in possible future revisions to the
Reliability Standard.
    1826. Accordingly, the Commission approves Reliability Standard
TPL-003-0 as mandatory and enforceable. In addition, the Commission
directs the ERO to develop a modification to TPL-003-0 through the
Reliability Standards development process that: (1) Requires that
critical system conditions be determined in the same manner as we
propose to require for TPL-001-0; (2) modifies footnote (c) to Table 1
to clarify the term ``controlled load interruption;'' (3) requires
applicable entities to define and document the proxies necessary to
simulate cascading outages and (4) tailors the purpose statement to
reflect the specific goal of the Reliability Standard.
e. System Performance Following Extreme Events (TPL-004-0)
    1827. The goal of Reliability Standard TPL-004-0 is to ensure that
the future Bulk-Power System is evaluated to assess the risks and
consequences of an extreme event involving the loss of multiple
elements. It seeks to do this by requiring the transmission planner and
the planning authority to evaluate and document annually the risks and
consequences of Category D contingencies (i.e., extreme events

resulting in loss of two or more elements or cascading) for the near-
term (five-year) planning horizon.
    1828. TPL-004-0 applies to each planning authority and transmission
planner. Each must demonstrate annually through valid assessments that
its portion of the interconnected transmission system is evaluated for
the risks and consequences of a number of each of the extreme
contingencies of Category D with all transmission facilities in service
over a planning horizon that takes into account lead times for
corrective plans. TPL-004-0 also requires that planned outages of
transmission equipment be considered for those demand levels for which
planned outages are performed. It defines various categories of
conditions to be simulated. The associated regional reliability
organization must approve the specific study elements selected from
each of the categories for assessment, including the subset of Category
D contingencies to be evaluated.
    1829. The Commission proposed in the NOPR to approve Reliability
Standard TPL-004-0 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-004-0 that:
(1) Requires that critical system conditions be determined in the same
manner as proposed for TPL-001-0; (2) requires the identification of
options for reducing the probability or impacts of extreme events that
cause cascading; (3) requires that, in determining the range of extreme
events to be assessed, the contingency list of Category D be expanded
to include recent events and (4) tailors the purpose statement to
reflect the specific goal of the Reliability Standard.
i. Comments
    1830. MidAmerican supports the Commission's proposed modifications
to the Reliability Standard as reasonable and agrees with the
Commission that the Reliability Standard should not require
improvements for low probability events that cannot be justified.\469\
MidAmerican supports developing options for any events listed in TPL-
004-0 that result in cascading outages and suggests use of
probabilistic estimates to determine which, if any, of the TPL-004
extreme events options should be estimated to reduce their probability
or impacts.
---------------------------------------------------------------------------

    \469\ See NOPR at P 1112.
---------------------------------------------------------------------------

    1831. FirstEnergy, EEI, APPA, TVA and Northern Indiana all oppose
the expansion of the list of extreme contingencies to include natural
disasters such as hurricanes and ice storms. They state that the
potential contingencies resulting from this expansion are endless and
therefore impractical to consider through engineering studies. As a
result, additional requirements in this Reliability Standard are
unnecessary. EEI and APPA state that to the extent that such events
will happen, entities historically have put heavy emphasis on emergency
planning and procedures, which are addressed by the EOP group of
Reliability Standards.
ii. Commission Determination
    1832. The Commission approves proposed Reliability Standard TPL-
004-0 as mandatory and enforceable. In addition, we direct the ERO to
develop modifications to TPL-004-0 through the Reliability Standards
development process, as discussed below.
    1833. The Commission notes that, like Requirement R1.3.1 of TPL-
001-0, Requirement R1.3.2 of TPL-004-0 requires an entity assessing
system performance to cover ``critical system conditions and study
years'' as deemed appropriate by the entity performing the study, but
it does not specify the rationale for determining critical system
conditions and study years. The Commission directs the ERO to modify
TPL-004-0 to require that critical system conditions and study years be
determined in the same manner as we directed with regard to TPL-001-0
and for the reasons stated there.
    1834. MidAmerican states that it supports the proposal to modify
TPL-004-0 to require identification of options for reducing the
probability or impacts of extreme events that cause cascading.
Accordingly, for the reasons cited in the NOPR, the Commission directs
the ERO to modify the Reliability Standard to make this modification to
the Reliability Standard.
    1835. All commenters that responded on the issue opposed the
Commission's proposal to modify TPL-004-0 to require that, in
determining the range of the extreme events to be assessed, the
contingency list of Category D be expanded to include recent events
such as hurricanes and ice storms. The Commission is not persuaded by
the commenters' contention that expansion of the extreme events list
will lead to an endless list of possibilities. The two that the
Commission used are examples from the general news media. While the
NOPR referred to two recent events, other examples include: (1) Loss of
a large gas pipeline into a region or multiple regions that have
significant gas-fired generation; (2) a successful cyber attack; (3)
regulation that restricts or eliminates the use of a river or lake or
other body of water as the cooling source for generation; (4) shutdown
of a nuclear power plant and other facilities a day or more prior to a
hurricane, tornado or wildfire, or other event and (5) the loss of
older transmission lines, which may not be constructed to meet an
entity's present radial ice loading requirements, while the newer or
stronger transmission lines remain in service. The above examples are
not an exhaustive list, however, the Commission would not expect the
range of scenarios to be much more extensive than this, either. Thus,
we are not expecting an endless list of scenarios and infinite number
of combinations in directing this modification. Each event is
identifiable for each entity based on its topology, facilities and
generation mix. Accordingly, the Commission directs the ERO to expand
the list of events with examples of such events identified above.
    1836. The Commission received no comments on its proposal to modify
the purpose statement of TPL-004-0 to reflect the specific goal of the
Reliability Standard. The Commission directs that this modification be
made.
    1837. Accordingly, the Commission approves Reliability Standard
TPL-004-0 as mandatory and enforceable. In addition, the Commission
directs the ERO to develop a modification to TPL-004-0 through the
Reliability Standards development process that: (1) Requires that
critical system conditions be determined in the same manner as proposed
for TPL-001-0; (2) requires the identification of options for reducing
the probability or impacts of extreme events that cause cascading; (3)
requires that, in determining the range of extreme events to be
assessed, the contingency list of Category D be expanded to include
recent events and (4) tailors the purpose statement to reflect the
specific goal of the Reliability Standard.
f. Regional and Interregional Self-Assessment Reliability Reports (TPL-
005-0)
    1838. Reliability Standard TPL-005-0 seeks to ensure that each
regional reliability organization conducts reliability assessments of
its existing and planned regional bulk electric system annually by
requiring it to assess and document the performance of its power system
for the current year, the next five years, and to analyze trends for
the longer-term planning horizons.
    1839. The Commission proposed in the NOPR not to approve or remand

TPL-005-0, as it applies only to regional reliability organizations.
i. Comments
    1840. EEI comments that TPL-005-0 should be revised to remove the
regional reliability organizations.
ii. Commission Determination
    1841. Consistent with our discussion in the Common Issues section
above, we will not approve or remand TPL-005-0 until we receive
additional information from the ERO.
    1842. In Order No. 890, the Commission stated that there will be a
series of technical conferences and regional meetings to obtain
industry input to achieving the goal of regional planning.\470\ The
Commission encourages the ERO to monitor those proceedings and use the
results as input to the Reliability Standards development process in
revising Reliability Standard TPL-005-0 to address regional planning
and related processes.
---------------------------------------------------------------------------

    \470\ Order No. 890 at P 443.
---------------------------------------------------------------------------

g. Assessment Data From Regional Reliability Organizations (TPL-006-0)
    1843. Reliability Standard TPL-006-0 seeks to ensure that the data
necessary to conduct reliability assessments is available by requiring
the regional reliability organization to provide NERC with Bulk-Power
System data, reports, demand and energy forecasts, and other
information necessary to assess reliability and compliance with NERC
Reliability Standards and relevant regional planning criteria.
    1844. The Commission proposed in the NOPR not to approve or remand
TPL-006-0, as it applies only to regional reliability organizations.
i. Comments
    1845. EEI agrees that TPL-006-0 should be revised to remove the
regional reliability organizations.
ii. Commission Determination
    1846. Consistent with our discussion in the Common Issues section
above, the Commission will not approve or remand TPL-006-0.
13. VAR: Voltage and Reactive Control
    1847. The Version 0 Voltage and Reactive Control (VAR) Reliability
Standard VAR-001-0 is intended to maintain Bulk-Power System facilities
within voltage and reactive power limits, thereby protecting
transmission, generation, distribution, and customer equipment and the
reliable operation of the Interconnection. The Voltage and Reactive
Control group of Reliability Standards is intended to replace the
existing VAR-001-0 and consists of two proposed Reliability Standards,
VAR-001-1 and VAR-002-1, with new Requirements. These two new proposed
Reliability Standards have been submitted by NERC as part of the August
28, 2006 Supplemental Filing for Commission review. NERC requested an
effective date of February 2, 2007 for VAR-001-1, and August 2, 2007
for VAR-002-1.
a. VAR-001-1 Voltage and Reactive Control
    1848. Reliability Standard VAR-001-1 requires transmission
operators to implement formal policies for monitoring and controlling
voltage levels, acquire sufficient reactive resources, specify criteria
for generator voltage schedules, know the status of all transmission
reactive power resources, operate or direct the operation of devices
that regulate voltage and correct IROL or SOL violations resulting from
reactive resource deficiencies. VAR-001-1 also requires purchasing-
selling entities to arrange for reactive resources to satisfy their
reactive requirements.
    1849. In the NOPR, the Commission proposed to approve VAR-001-1 as
mandatory and enforceable. In addition, the Commission proposed to
direct NERC to submit a modification to VAR-001-1 that: (1) Expands the
applicability to include reliability coordinators and LSEs; (2)
includes detailed and definitive requirements on ``established limits''
and ``sufficient reactive resources,'' and identifies acceptable
margins above the voltage instability points; (3) includes Requirements
to perform voltage stability assessments periodically during real-time
operations and (4) includes controllable load among the reactive
resources to satisfy reactive requirements. The Commission also
requested comments concerning NERC's assertion that all LSEs are also
purchasing-selling entities, and on the acceptable ranges of net power
factor range at the interface at which the LSEs receive service from
the Bulk-Power System during normal and extreme load conditions.
    1850. Most comments address the specific modifications and concerns
raised by the Commission in the NOPR. Below, we address each topic
separately, followed by an overall conclusion and summary.
i. Applicability to Load-Serving Entities and Reliability Coordinators
(a) Comments
    1851. EEI agrees with the Commission that the applicability of VAR-
001-1 should be expanded to include reliability coordinators and LSEs.
    1852. MISO contends that the view and role of generator operators,
transmission operators and reliability coordinators are different, and
reliability coordinators' monitoring and response requirements are
addressed elsewhere in the Reliability Standards.
    1853. In response to the Commission's request in the NOPR for
comments concerning whether all LSEs are also purchasing-selling
entities, SoCal Edison believes they are distinguishable. It states
that a purchasing-selling entity, according to the functional model,
makes financial deals across balancing authorities (from source to
sink). Within the area of a large balancing authority, such as the
CAISO, an LSE can serve load from a resource within the balancing
authority, so that there is no requirement to tag this transaction, and
technically there is no purchasing-selling entity involved.
    1854. APPA is concerned that requiring VAR-001-1 to be applicable
to LSEs would require LSEs to conduct various studies and perform
reliability functions that have been assigned to other functional
entities. The role of LSEs in voltage stability assessments should be
limited to coordination and the provision of data. TAPS also questions
the need to expand applicability of these Reliability Standards to
LSEs. TAPS maintains that purchasing and selling utilities are already
subject to the Reliability Standards, and are required to satisfy any
reactive requirements through purchasing Ancillary Service No. 2 under
the OATT (or self-supply). TAPS believes that the addition of LSEs as
an additional applicable entity serves no reliability purpose.
(b) Commission Determination
    1855. In a complex power grid such as the one that exists in North
America, reliable operations can only be ensured by coordinated efforts
from all operating entities in long-term planning, operational planning
and real-time operations. To that end, the Staff Preliminary Assessment
recommended and the NOPR proposed that the applicability of VAR-001-1
extend to reliability coordinators and LSEs.
    1856. Since a reliability coordinator is the highest level of
authority overseeing the reliability of the Bulk-Power System, the
Commission believes that it is

important to include the reliability coordinator as an applicable
entity to assure that adequate voltage and reactive resources are being
maintained. As MISO points out, other Reliability Standards address
responsibilities of reliability coordinators, but we agree with EEI
that it is important to include reliability coordinators in VAR-001-1
as well. Reliability coordinators have responsibilities in the IRO and
TOP Reliability Standards, but not the specific responsibilities for
voltage levels and reactive resources addressed by VAR-001-1, which
have a great impact on system reliability. For example, voltage levels
and reactive resources are important factors to ensure that IROLs are
valid and operating voltages are within limits, and that reliability
coordinators should have responsibilities in VAR-001-1 to monitor that
sufficient reactive resources are available for reliable system
operations. Accordingly, the ERO should modify VAR-001-1 to include
reliability coordinators as applicable entities and include a new
requirement(s) that identifies the reliability coordinator's monitoring
responsibilities.
    1857. The Commission agrees with SoCal Edison that not all LSEs are
purchasing-selling entities, because not all LSEs purchase or sell
power from outside of their balancing authority area. This
understanding is consistent with the NERC functional model and NERC
glossary. Both LSEs and purchasing-selling entities should have some
requirements to provide reactive power to appropriately compensate for
the demand they are meeting for their customers. Neither a purchasing-
selling entity nor a LSE should depend on the transmission operator to
supply reactive power for their loads during normal or emergency
conditions.
    1858. VAR-001-1 recognizes that energy purchases of purchasing-
selling entities can increase reactive power consumption on the Bulk-
Power System and the purchasing-selling entities must supply what they
consume. The Commission agrees with APPA that LSEs would provide data
for voltage stability assessments. However, the Commission also
believes that LSEs have an active role in voltage and reactive control,
since LSEs are responsible for maintaining an agreed-to power factor at
the interface with the Bulk-Power System.
    1859. While the Commission recognizes the point made by TAPS, that
purchasing-selling entities are required to satisfy any reactive
requirements through purchasing Ancillary Service 2 under the
OATT or self-supply, the Commission disagrees that adding LSEs to this
Reliability Standard serves no reliability purpose. As discussed in the
NOPR and the Staff Preliminary Assessment, LSEs are responsible for
significantly more load than purchasing-selling entities.\471\ The
reactive power requirements can have significant impact on the
reliability of the system and LSEs should be accountable for that
impact in the same ways that purchasing-selling entities are
accountable, by providing reactive resources, and also by providing
information to transmission operators to allow transmission operators
to accurately study the reactive power needs for both the LSEs' and
purchasing-selling entities' load characteristics.\472\ The Commission
recognizes that all transmission customers of public utilities are
required to purchase Ancillary Service No. 2 under the OATT or self-
supply, but the OATT does not require them to provide information to
transmission operators needed to accurately study reactive power needs.
The Commission directs the ERO to address the reactive power
requirements for LSEs on a comparable basis with purchasing-selling
entities.
ii. Acceptable Ranges of Net Power Factor Range
---------------------------------------------------------------------------

    \471\ NOPR at P 1134.
    \472\ Purchasing selling entities provide information concerning
their load through the INT series of Reliability Standards. Load
serving entities would need to provide similar information through
this Reliability Standard.
---------------------------------------------------------------------------

(a) Comments
    1860. SoCal Edison states that its Bulk-Power System facilities are
designed and operated to provide a unity power factor during normal
load conditions, and that during extreme load conditions, this power
factor could be in the range of 0.95 to 1.0.
    1861. APPA contends that it may be difficult to reach an agreement
on acceptable ranges of net power factors at the interfaces where LSEs
receive service from the Bulk-Power System because the acceptable range
of power factors at any particular point on the electrical system
varies based on many location-specific factors. APPA further states
that system power factors will be affected by the transmission
infrastructure used to supply the load. As an example, APPA states that
an overhead circuit may operate at a higher power factor than an
underground cable due to a substantial amount of reactive line
charging, and that a transmission circuit carrying low levels of real
power will tend to provide more reactive power, which will affect the
need to switch off capacitor banks at the delivery point to manage
delivery power factors.
(b) Commission Determination
    1862. In the NOPR, the Commission asked for comments on acceptable
ranges of net power factor at the interface at which the LSEs receive
service from the Bulk-Power System during normal and extreme load
conditions. The Commission asked for these comments in response to
concerns that during high loads, if the power factor at the interface
between many LSEs and the Bulk-Power System is so low as to result in
low voltages at key busses on the Bulk-Power System, then there is risk
for voltage collapse. The Commission believes that Reliability Standard
VAR-001-1 is an appropriate place for the ERO to take steps to address
these concerns by setting out requirements for transmission owners and
LSEs to maintain an appropriate power factor range at their interface.
We direct the ERO to develop appropriate modifications to this
Reliability Standard to address the power factor range at the interface
between LSEs and the Bulk-Power System.
    1863. We direct the ERO to include APPA's concern in the
Reliability Standards development process. We note that transmission
operators currently have access to data through their energy management
systems to determine a range of power factors at which load operates
during various conditions, and we suggest that the ERO use this type of
data as a starting point for developing this modification.
    1864. The Commission expects that the appropriate power factor
range developed for the interface between the bulk electric system and
the LSE from VAR-001-1 would be used as an input to the transmission
and operations planning Reliability Standards. The range of power
factors developed in this Reliability Standard provides the input to
the range of power factors identified in the modifications to the TPL
Reliability Standards. In the NOPR, the Commission suggested that
sensitivity studies for the TPL Reliability Standards should consider
the range of load power factors.\473\
---------------------------------------------------------------------------

    \473\ NOPR at P 1047.
---------------------------------------------------------------------------

iii. Requirements on ``established limits'' and ``sufficient reactive
resources''
(a) Comments
    1865. Dynegy supports the Commission's proposal to include more
definitive requirements on ``established

limits'' and ``sufficient reactive resources.'' It recommends that VAR-
001-1 be further modified to require the transmission operator to have
more detailed and definitive requirements when setting the voltage
schedule and associated tolerance band that is to be maintained by the
generator operator. Dynegy states that the transmission operator should
not be allowed to arbitrarily set these values, but rather should be
required to have a technical basis for setting the required voltage
schedule and tolerance band that takes into account system needs and
any limitations of the specific generator. Dynegy believes that such a
requirement would eliminate the potential for undue discrimination, as
well as the possibility of imposing overly conservative and burdensome
voltage schedules and tolerance bands on generator operators that could
be detrimental to grid reliability, or conversely, the imposition of
too low a voltage schedule and too wide a tolerance band that could
also be detrimental to grid reliability.
    1866. While MISO supports the concept of including more detailed
requirements, it believes that there needs to be a definitive reason
for establishing voltage schedules and tolerances, and that any
situations monitored in this Reliability Standard need to be limited to
core reliability requirements.
    1867. EEI seeks clarification about whether the Commission is
suggesting that reactive requirements should aim for significantly
greater precision, especially in terms of planning for various
emergency conditions. If so, EEI cautions the Commission against ``
`putting too many eggs' '' in the reactive power `basket.' '' \474\ To
the extent compliance takes place pursuant to all other modeling and
planning assessments under the other Reliability Standards, EEI
strongly believes that the Commission should have some high level of
confidence that the system's reactive power needs can be met
satisfactorily across a broad range of contingencies that planners
might reasonably anticipate. Moreover, EEI believes that requirements
to successfully predict reactive power requirements in conditions of
near-system collapse would require significantly more creative
guesswork than solid analysis and contingency planning. For example,
EEI notes that the combinations and permutations of how a voltage
collapse could occur on a system as large as the eastern
Interconnection are numerous.
---------------------------------------------------------------------------

    \474\ EEI at 99.
---------------------------------------------------------------------------

    1868. EEI suggests that, alternatively, the Commission should
consider that reactive power evaluations should be conducted within a
process that is documented in detail and includes a range of
contingencies that might be reasonably anticipated, because this would
avoid the `one size fits all' problem, where a prescriptive analytical
methodology does not fit with a particular system configuration. EEI
believes that this flexible approach would provide a more effective
planning tool for the industry, while satisfying the Commission's
concerns over potentially inadequate reactive reserves. MRO notes that
the need for, and method of providing for, reactive resources varies
greatly, and if this Reliability Standard is expanded it must be done
carefully. MRO believes that all entities should not be required to
follow the same methodology to accomplish the goal of a reliable
system.
(b) Commission Determination
    1869. In the NOPR, the Commission expressed concern that the
technical requirements containing terms such as ``established limits''
or ``sufficient reactive resources'' are not definitive enough to
address voltage instability and ensure reliable operations.\475\ To
address this concern, the NOPR proposed directing the ERO to modify
VAR-001-1 to include more detailed and definitive requirements on
``established limits'' and ``sufficient reactive resources'' and
identify acceptable margins (i.e. voltage and/or reactive power
margins) above voltage instability points to prevent voltage
instability and to ensure reliable operations. We will keep this
direction, and direct the ERO to include this modification in this
Reliability Standard.
---------------------------------------------------------------------------

    \475\ See NOPR at P 1140.
---------------------------------------------------------------------------

    1870. We recognize that our proposed modification does not identify
what definitive requirements the Reliability Standard should use for
``established limits'' and ``sufficient reactive resources.'' Rather,
the ERO should develop appropriate requirements that address the
Commission's concerns through the ERO Reliability Standards development
process. The Commission believes that the concerns of Dynegy, EEI and
MISO are best addressed by the ERO in the Reliability Standards
development process.
    1871. In response to EEI's concerns about a prescriptive analytical
methodology, we clarify that the Commission is not asking that the
Reliability Standard dictate what methodology must be used to determine
reactive power needs. Rather, the Commission believes that the
Reliability Standard would benefit from having more defined
requirements that clearly define what voltage limits are used and how
much reactive resources are needed to ensure voltage instability will
not occur under normal and emergency conditions. For example, in the
NOPR, the Commission suggested that NERC consider WECC's Reliability
Criteria, which contain specific and definitive technical requirements
on voltage and margin application. While we are not directing that the
WECC reliability criteria be adopted, we believe they represent a good
example of clearly-defined requirements for voltage and reactive
margins.
    1872. In sum, the Commission believes that minimum requirements for
voltage levels and reactive resources should be clearly defined by
placing more detailed requirements on the terms ``established limits''
and ``sufficient reactive resources'' in the Reliability Standard as
discussed in the NOPR and the Staff Preliminary Assessment. As
mentioned above, EEI's concerns should be considered in the ERO's
Reliability Standards development process.
iv. Periodic Voltage Stability Analysis in Real-Time Operations
(a) Comments
    1873. SDG&E supports the NOPR recommendation that a more effective
requirement could be based on WECC's reliability criteria, which
contain specific and definitive technical requirements on voltage and
margin application. MidAmerican and PacifiCorp recommend that the
``WECC Methods to address voltage stability and settling margins''
should be consulted when designing corresponding NERC requirements.
    1874. Xcel Energy recommends that this proposed modification
instead address requirements to measure reactive power margin for a
variety of topology conditions. MidAmerican recommends that the
Commission's proposal be modified to require real-time checks for
voltage stability assessments only in areas susceptible to voltage
instability. Alternatively, MidAmerican suggests that the Commission
``should exempt from these requirements areas that can demonstrate they
are not susceptible to voltage instability.''
    1875. APPA, SDG&E and EEI all state that they are not aware of
commercially-available tools to provide real-time transient stability
assessments as part of an integrated energy management system for
operators. APPA notes that

premature reliance on various tools that are now under development but
not yet operational may jeopardize reliability by providing operators
with a false sense of security and recommends leaving the decision to
use such tools to NERC. EEI points out that any tools to conduct the
analyses recommended by the Commission will require adjustments and
modifications to improve their capabilities. Therefore, EEI recommends
that the Commission consider its proposals regarding these standards as
long-term industry objectives and of a lower priority than other
Reliability Standards. In addition, it is unclear to EEI whether the
proposed voltage stability assessments apply to steady-state or dynamic
analyses, or whether these assessments are of a general nature. Since
these analyses are technically complex and involve a broad range of
assumptions regarding system configurations, EEI suggests that the
Commission provide further guidance.
(b) Commission Determination
    1876. In response to the concerns of APPA, SDG&E and EEI on the
availability of tools, the Commission recognizes that transient voltage
stability analysis is often conducted as an offline study, and that
steady-state voltage stability analysis can be done online. The
Commission clarifies that it does not wish to require anyone to use
tools that are not validated for real-time operations. Taking these
comments into consideration, the Commission clarifies its proposed
modification from the NOPR. For the Final Rule, we direct the ERO,
through its Reliability Standards development process, to modify
Reliability Standard VAR-001-1 to include Requirements to perform
voltage stability analysis periodically, using online techniques where
commercially-available, and offline simulation tools where online tools
are not available, to assist real-time operations. The ERO should
consider the available technologies and software as it develops this
modification to VAR-001-1 and identify a process to assure that the
Reliability Standard is not limiting the application of validated
software or other tools.
    1877. With respect to MidAmerican's suggestion of exempting areas
that are not susceptible to voltage instability from the requirement to
perform voltage stability analysis, the Commission notes that such
exemption is not appropriate. We draw an analogy between transient
stability limits and voltage stability limits. The requirement to
perform voltage stability analysis is similar to existing operating
practices for IROLs that are dictated by transient stability. Transient
stability IROLs are determined using the results of off-line simulation
studies, and no areas are exempt. In real-time operations, these IROLs
are monitored to ensure that they are not violated. Similarly, voltage
stability is conducted in the same manner, determining limits with off-
line tools and monitoring limits in real-time operations. Areas that
are susceptible to voltage instability are expected to run studies
frequently, and areas that have not been susceptible to voltage
instability are expected to periodically update their study results to
ensure that these limits are not encountered during real-time
operations.
v. Controllable Load
(a) Comments
    1878. SMA supports adoption of the proposal to include controllable
load as a reactive resource. SMA notes that its members' facilities
often include significant capacitor banks, and further, reducing load
can reduce local reactive requirements.
    1879. SoCal Edison suggests caution regarding the Commission's
proposal to include controllable load as a reactive resource. It agrees
that, when load is reduced, voltage will increase and for that reason
controllable load can lessen the need for reactive power. However,
SoCal Edison believes that controllable load is typically an energy
product and there are other impacts not considered by the Commission's
proposal to include controllable load as a reactive resource. For
example, activating controllable load for system voltage control
lessens system demand, requiring generation to be backed down. It is
not clear to SoCal Edison whether any consideration has been given to
the potential reliability or commercial impacts of the Commission's
proposal.
(b) Commission Determination
    1880. The Commission noted in the NOPR that in many cases, load
response and demand-side investment can reduce the need for reactive
power capability in the system.\476\ Based on this assertion, the
Commission proposed to direct the ERO to include controllable load
among the reactive resources to satisfy reactive requirements for
incorporation into Reliability Standard VAR-001-1. While we affirm this
requirement, we expect the ERO to consider the comments of SoCal Edison
with regard to reliability and SMA in its process for developing the
technical capability requirements for using controllable load as a
reactive resource in the applicable Reliability Standards.
---------------------------------------------------------------------------

    \476\ See FERC Staff Report, Principles of Efficient and
Reliable Reactive Power Supply and Consumption (2005), available at
http://www.ferc.gov/legal/staff-reports.asp.

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

vi. Summary of Commission Determination
    1881. Accordingly, the Commission approves Reliability Standard
VAR-001-1 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 VAR-001-1
through the Reliability Standards development process that: (1) Expands
the applicability to include reliability coordinators and LSEs; (2)
includes detailed and definitive requirements on ``established limits''
and ``sufficient reactive resources'' as discussed above, and
identifies acceptable margins above the voltage instability points; (3)
includes Requirements to perform voltage stability analysis
periodically, using online techniques where commercially available and
offline techniques where online techniques are not available, to assist
real-time operations, for areas susceptible to voltage instability; (4)
includes controllable load among the reactive resources to satisfy
reactive requirements and (5) addresses the power factor range at the
interface between LSEs and the transmission grid.
b. VAR-002-1
    1882. Reliability Standard VAR-002-1 requires generator operators
to operate in automatic voltage control mode, to maintain generator
voltage or reactive power output as directed by the transmission
operator, and to notify the transmission operator of a change in status
or capability of any generator reactive power resource. The Reliability
Standard requires generator owners to provide transmission operators
with settings and data for generator step-up transformers. In the NOPR,
the Commission stated its belief that Reliability Standard VAR-002-1 is
just, reasonable, not unduly discriminatory or preferential and in the
public interest; and proposed to approve it as mandatory and
enforceable.
i. Comments
    1883. APPA and SDG&E agree that VAR-002-1 is sufficient for
approval as a mandatory and enforceable Reliability Standard.
    1884. Dynegy believes that VAR-002-1 should be modified to require
more detailed and definitive requirements when defining the time frame
associated with an ``incident'' of non compliance (i.e., each 4-second
scan, 10-minute

integrated value, hourly integrated value). Dynegy states that, as
written, this Reliability Standard does not define the time frame
associated with an ``incident'' of non-compliance, but apparently
leaves this decision to the transmission operator. Dynegy believes that
either more detail should be added to the Reliability Standard to cure
this omission, or the Reliability Standard should require the
transmission operator to have a technical basis for setting the time
frame that takes into account system needs and any limitations of the
generator. Dynegy believes that this approach will eliminate the
potential for undue discrimination and the imposition of overly
conservative or excessively wide time frame requirements, both of which
could be detrimental to grid reliability.
ii. Commission Determination
    1885. In the NOPR, the Commission commended NERC and industry for
its efforts in expanding on the Requirements of VAR-002-1 from the
predecessor standard, and noted that the submitted Reliability Standard
includes Measures and Levels of Non-Compliance to ensure appropriate
generation operation to maintain network voltage schedules.
Accordingly, the Commission approves Reliability Standard VAR-002-1 as
mandatory and enforceable.
    1886. Dynegy has suggested an improvement to Reliability Standard
VAR-002-1, and NERC should consider this in its Reliability Standards
development process.
14. Glossary of Terms Used in Reliability Standards
    1887. NERC's glossary is updated whenever a new or revised
Reliability Standard is approved that includes a new defined term. The
glossary may also be approved by a separate action using NERC's
Reliability Standards development process. NERC updated the glossary in
its August 28, 2006 Supplemental Filing.
    1888. In the NOPR, the Commission proposed to approve the glossary.
In addition, the Commission proposed to direct NERC to submit a
modification to the glossary that: (1) Includes the statutory
definitions of Bulk-Power System, Reliable Operation, and Reliability
Standard, as set forth in section 215(a) of the FPA; (2) modifies the
definitions of ``transmission operator'' and ``generator operator'' to
include aspects unique to ISOs, RTOs and pooled resource organizations;
(3) modifies the definition of ``bulk electric system'' consistent with
discussion in the NOPR Common Issues section \477\ and (4) modifies the
definition of terms concerning reserves (such as operating reserves) to
include DSM, including controllable load.
---------------------------------------------------------------------------

    \477\ NOPR at P 42-43.
---------------------------------------------------------------------------

a. Comments
    1889. NERC supports the Commission's proposal to approve the
glossary. APPA supports the Commission's proposal to have NERC
incorporate the statutory definitions of the terms Bulk-Power System,
Reliable Operation and Reliability Standard into the NERC glossary, as
an aide to the development of future NERC Reliability Standards.
    1890. APPA suggests that the Commission permit NERC and industry to
consider whether any modifications to the terms ``transmission
operator'' and ``generation operator'' are needed, rather than
directing NERC to modify these terms. APPA's initial reaction is that
the existing terms are adequate and accommodate most elements of ISO,
RTO and pooled resource organization operations. APPA believes that a
broader and continuing inquiry is required to address such situations.
APPA anticipates that many such concerns will arise as NERC and the
Regional Entities implement the initial compliance program in June
2007, and states that any additional changes to the glossary should be
driven by that experience.
    1891. APPA's concerns regarding the Commission proposal to modify
the definition of terms concerning reserves to include DSM (including
controllable load) are discussed above in reference to the BAL
Reliability Standards.
    1892. NERC supports the Commission's proposal to direct NERC to
complete the necessary improvements to the proposed Reliability
Standards through the established NERC Reliability Standards
development process.
    1893. Santa Clara submits that, to eliminate any ambiguity about
when these definitions of these commonly-used terms apply, a footnote
should be added to the glossary that states that the definitions
contained in the glossary are not intended to supersede any definitions
in a tariff or contract approved or accepted by the Commission.
 b. Commission Conclusion
    1894. The Commission approves the glossary. The terms defined in
the glossary have an important role in establishing consistent
understanding of the Reliability Standards Requirements and
implementation. The approval of the glossary will provide continuity in
application of the glossary definitions industry-wide, and will
eliminate multiple interpretations of the same term or function, which
may otherwise create miscommunication and jeopardize Bulk-Power System
reliability. The glossary should be updated through the Reliability
Standards development process whenever a new or revised Reliability
Standard that includes a new defined term is approved, or as needed to
clarify compliance activities. For example, the ERO will need to update
the glossary to reflect modifications required by the Commission in
this Final Rule.\478\
---------------------------------------------------------------------------

    \478\ See, e.g., MOD-001-0, TOP-002-1 and the INT Reliability
Standards.
---------------------------------------------------------------------------

    1895. The Commission directs the ERO to modify the glossary through
the Reliability Standards development process to include the statutory
definitions of the terms Bulk-Power System, Reliable Operation and
Reliability Standard. However, this determination does not negate our
discussion in the Applicability section of the Final Rule. While the
glossary should be revised to include the stautory definition of Bulk-
Power System, the Reliability Standards refer to the bulk electric
system, which is also defined in the glossary.
    1896. The Commission directs the ERO to submit a modification to
the glossary that enhances the definitions of ``transmission operator''
and ``generator operator'' to reflect concerns of the commenters and
the direction provided by the Commission in other sections of this
Final Rule. The Commission is concerned that there not be any gaps or
unecessary overlaps of responsibilities concerning any of the
Requirements in the Reliability Standards that are applicable to
transmission operators and generator operators.
    1897. Further, we adopt the NOPR proposal to require the ERO to
submit a modification to the glossary that updates the definition of
``operating reserves,'' as required in our discussion of BAL-002-0 and
BAL-005-0.
    1898. Regarding Santa Clara's concern about terms in the glossary
differing from definitions in tariffs, we clarify that the glossary
governs Reliability Standards, while tariff definitions govern tariff
issues. We recognize that many items have different tariff definitions
from those in the NERC glossary. However, we expect most of these terms
to be consistent. If the glossary definition creates a conflict between
the Reliability Standards and a Transmission Organization's function,

rule, order, tariff, rate schedule, or agreement accepted, approved, or
ordered by the Commission, then the Transmission Organization shall
expeditiously notify the Commission, the Electric Reliability
Organization and the relevant Regional Entity of the possible conflict
pursuant to Sec.  39.6 of the Commission's regulations.\479\
---------------------------------------------------------------------------

    \479\ 18 CFR 39.6 (2006).
---------------------------------------------------------------------------

    1899. In conclusion, the Commission approves the glossary. Further,
pursuant to section 215(d)(5) of the FPA and Sec.  39.5(f) of our
regulations, the Commission directs ERO to modify the glossary through
the Reliability Standards development process to: (1) Include the
statutory definitions of the terms Bulk-Power System, Reliable
Operation and Reliability Standard; (2) modify the definition of
``transmission operator'' and ``generator operator'' to include aspects
unique to ISO, RTO and pooled resource organizations and (3) modify the
definition of ``operating reserves'' as discussed in BAL-002-0 and BAL-
005-0.

III. Information Collection Statement

    1900. The Office of Management and Budget (OMB) regulations require
that OMB approve certain reporting and recordkeeping (collections of
information) imposed by an agency.\480\ The information collection
requirements in this Final Rule are identified under the Commission
data collection, FERC-725A ``Bulk Power System Mandatory Reliability
Standards.'' Under section 3507(d) of the Paperwork Reduction Act of
1995,\481\ the proposed reporting requirements in the subject
rulemaking will be submitted to OMB for review. Interested persons may
obtain information on the reporting requirements by contacting the
Federal Energy Regulatory Commission, 888 First Street, NE, Washington,
DC 20426 (Attention: Michael Miller, Office of the Executive Director,
202-502-8415) or from the Office of Management and Budget (Attention:
Desk Officer for the Federal Energy Regulatory Commission, fax: 202-
395-7285, e-mail: oira_submission@omb.eop.gov).
---------------------------------------------------------------------------

    \480\ 5 CFR 1320.11.
    \481\ 44 U.S.C. 3507(d) (2000).
---------------------------------------------------------------------------

    1901. The ``public protection'' provisions of the Paperwork
Reduction Act of 1995 requires each agency to display a currently valid
control number and inform respondents that a response is not required
unless the information collection displays a valid OMB control number
on each information collection or provides a justification as to why
the information collection number cannot be displayed. In the case of
information collections published in regulations, the control number is
to be published in the Federal Register.
    1902. Public Reporting Burden: In the NOPR, the Commission based
its initial estimates on the premise that the proposed Reliability
Standards have already been in effect for a substantial period of time
on a voluntary basis and consequently entities would have already put
them into practice. Seventy of the 125 commenters express concern with
the burden to be imposed by the NOPR's requirements. The majority of
these comments address the potential impact the requirements would have
on small entities but did not provide specific estimates on this
impact. Because these comments are also the subject of the analysis
performed under the Regulatory Flexibility Act, the Commission has
provided a response under that section of this rulemaking. Commenters
also raise concerns about the impact of specific Reliability Standards,
and the Commission has addressed those concerns in the discussion of
each Reliability Standard. Five commenters, Reliant, TAPS, Wisconsin
Electric, Portland General and WECC questioned the Commission's initial
burden estimates as contained in the NOPR.
    1903. By Reliant's estimate, it would take at least four employees
to prepare and submit compliance filings and to monitor compliance on
an on-going basis. TAPS, while not providing a specific estimate on the
burden, believes that the NOPR's proposed application of mandatory
Reliability Standards is overly-broad and would encompass several
thousand municipal systems. Wisconsin Electric states that the NOPR
significantly understated the impact that would be imposed by mandatory
Reliability Standards. Wisconsin Electric believes that a ``typical
control area utility with its multiple functional entity
responsibilities'' will need far more than the 100 hours estimated by
the Commission to manage a quality compliance program as discussed in
the ERO's Sanction Guidelines.\482\
---------------------------------------------------------------------------

    \482\ Wisconsin Electric at 9.
---------------------------------------------------------------------------

    1904. Portland General believes that meeting the Requirements of
mandatory Reliability Standards will place an additional burden for
documentation, over and above compliance with the substance of the
Requirements. It claims that the NOPR failed to take this additional
burden into account in its cost estimate for compliance. WECC disagrees
with the Commission's estimate that compliance cost would be $40
million annually on an aggregate basis. It also disagrees with the
Commission's assumption that there would be no increased reporting
burden or additional information requirements because the Reliability
Standards impose new documentation requirements that will create
additional costs.
    1905. In response to the comments and upon further review we have
revised our initial estimates as reflected in the table below. While
the ERO has submitted several new Reliability Standards and included
additional Measures for documenting compliance with 20 existing
Reliability Standards, we continue to believe that the reporting
requirements embedded in the Reliability Standards that are approved in
the Final Rule have been implemented on a voluntary basis for many
years in most instances.\483\ This would not apply, however, to
entities that are new to reliability oversight. We encourage entities
that are responsible for compliance with mandatory Reliability
Standards to develop a quality compliance program as discussed in the
ERO's Sanction Guidelines. However, we believe that the costs of such a
program are distinct from the reporting burdens that are estimated
below.
---------------------------------------------------------------------------

    \483\ NOPR at P 1157.
---------------------------------------------------------------------------

    1906. Further, our estimates below reflect a revision in the number
of respondents, based on our determinations regarding
``applicability,'' as discussed in section II.C above.
    1907. Total Annual Hours for Collection:

----------------------------------------------------------------------------------------------------------------
                                                     Number of       Number of       Hours per     Total annual
                 Data collection                    respondents      responses       response          hours
----------------------------------------------------------------------------------------------------------------
FERC-725A
    Investor Owned Utilities....................             170               1           2,080         353,600
    Municipals and Cooperatives--Large..........              80               1           1,420         113,600
    Municipals and Cooperatives--Small..........             670               1             710         475,700
    Generator Operators.........................             360               1             500         180,000

    Power Marketers.............................             159               1             100          15,900
    Recordkeeping...............................     Investor Owned Utilities     ..............          35,360
                                                        Munis/Coops (Large)       ..............          11,360
                                                        Munis/Coops (Small)       ..............          47,570
                                                       Generator Owner/Ops.       ..............          18,000
                                                          Power Marketers         ..............           1,590
        Totals..................................  ..............  ..............  ..............      1,252,680
----------------------------------------------------------------------------------------------------------------
(FTE=Full Time Equivalent or 2,080 hours)

    Total Hours = 1,138,800 (reporting) + 113,880 (recordkeeping) =
1,252,680 hours. This estimated reporting burden will be significantly
reduced once joint action agencies are established, which will reduce
the number of small entities that will be responsible for compliance
with Reliability Standards.
    1908. Information Collection Costs: The Commission sought comments
about the costs needed to comply with these requirements. As noted
above, a number of commenters state that the NOPR underestimated the
burden of the rulemaking in terms of hours required to comply. However,
no comments were received regarding the Commission's estimate of the
projected cost of $200/hour to comply with these requirements. In
further consideration, the Commission believes that the $200/hour
projection is too high, and the calculations below reflect an adjusted
hourly figure.
    Cost to Comply:
hour), consultant ($150), technical ($80) and administrative support
($25)).
    Total Costs: Reporting ($129,823,200) + Recordkeeping ($1,935,960)
= $131,759,160.
    Sources: ``NERC Compliance Update: What it might cost to comply'',
Herb Schrayshuen, NARUC-Electric Reliability Staff Subcommittee,
November 12, 2006.
    Janco Associates, Inc., 2005 Information Technology Compensation
Study, January 2005.
    Bureau of Labor Statistics, Department of Labor, Occupational
Outlook Handbook, http://www.bls.gov/oco/ocos268.htm.

    Titles: FERC-725A ``Mandatory Reliability Standards for the Bulk-
Power System''.
    Action: Proposed Collection of Information.
    OMB Control Nos: To be determined.
    Respondents: Business or other for profit, not for profit
institutions, state, local or tribal government and Federal Government.
    Frequency of Responses: On occasion.
    Necessity of Information: The Final Rule approves 83 Reliability
Standards. Compliance with such Reliability Standards will be mandatory
and enforceable for the applicable categories of entities identified in
each Reliability Standard. These Reliability Standards are approved by
the Commission pursuant to its authority under section 215 of the FPA,
which authorizes the Commission to approve a Reliability Standard
proposed by the ERO if the Commission determines that it is just and
reasonable, not unduly discriminatory or preferential and in the public
interest. The Reliability Standards approved in this Final Rule are
necessary for the reliable operation of the nation's interconnected
Bulk-Power System.
    For information on the requirements, submitting comments on the
collection of information and the associated burden estimates including
suggestions for reducing this burden, please send your comments to the
Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426 (Attention: Michael Miller, Office of the
Executive Director,<PHONE_NUMBER>) or send comments to the Office of
Management and Budget (Attention: Desk Officer for the Federal Energy
Regulatory Commission, fax:<PHONE_NUMBER>, e-mail
oira_submission@omb.eop.gov).

IV. Environmental Analysis

    1909. The Commission is required to prepare an Environmental
Assessment or an Environmental Impact Statement for any action that may
have a significant adverse effect on the human environment.\484\ The
actions taken here fall within the categorical exclusion in the
Commission's regulations for rules that are clarifying, corrective or
procedural, for information gathering, analysis, and
dissemination.\485\
---------------------------------------------------------------------------

    \484\ Regulations Implementing the National Environmental Policy
Act, Order No. 486, 52 FR 47,897 (Dec. 17, 1987), FERC Stats. &
Regs., Regulations Preambles 1986-1990 ] 30,783 (1987).
    \485\ 18 CFR 380.4(a)(5).
---------------------------------------------------------------------------

V. Regulatory Flexibility Act

    1910. The Regulatory Flexibility Act of 1980 (RFA)\486\ generally
requires a description and analysis of Final Rules that will have
significant economic impact on a substantial number of small entities.
The RFA does not mandate any particular outcome in a rulemaking. It
only requires consideration of alternatives that are less burdensome to
small entities and an agency explanation of why alternatives were
rejected.
---------------------------------------------------------------------------

    \486\ 5 U.S.C. 601-612 (2006).
---------------------------------------------------------------------------

    1911. In drafting a rule an agency is required to: (1) Assess the
effect that its regulation will have on small entities; (2) analyze
effective alternatives that may minimize a regulation's impact and (3)
make the analyses available for public comment.\487\ In its NOPR, the
agency must either include an initial regulatory flexibility analysis
(initial RFA) \488\ or certify that the proposed rule will not have a
``significant impact on a substantial number of small entities.'' \489\
---------------------------------------------------------------------------

    \487\ 5 U.S.C. 601-604.
    \488\ 5 U.S.C. 603(a).
    \489\ 5 U.S.C. 605(b).
---------------------------------------------------------------------------

    1912. If in preparing the NOPR an agency determines that the
proposal could have a significant impact on a substantial number of
small entities, the agency shall ensure that small entities will have
an opportunity to participate in the rulemaking procedure.\490\
---------------------------------------------------------------------------

    \490\ 5 U.S.C. 609(a).
---------------------------------------------------------------------------

    1913. In its Final Rule, the agency must also either prepare a
Final Regulatory Flexibility Analysis (Final RFA) or make the requisite
certification. Based on the comments the agency receives on the NOPR,
it can alter its original position as expressed in the NOPR but it is
not required to make any substantive changes to the proposed
regulation.
    1914. The statute provides for judicial review of an agency's final
certification or Final RFA.\491\ An agency must file a

Final RFA demonstrating a ``reasonable, good-faith effort'' to carry
out the RFA mandate.\492\ However, the RFA is a procedural, not a
substantive, mandate. An agency is only required to demonstrate a
reasonable, good faith effort to review the impact the proposed rule
would place on small entities, any alternatives that would address the
agency's and small entities' concerns and their impact, provide small
entities the opportunity to comment on the proposals, and review and
address comments. An agency is not required to adopt the least
burdensome rule. Further, the RFA does not require an agency to assess
the impact of a rule on all small entities that may be affected by the
rule, only on those entities that the agency directly regulates and
that will be directly impacted by the rule.\493\
---------------------------------------------------------------------------

    \491\ 5 U.S.C. 611.
    \492\ United Cellular Corp. v. FCC, 254 F.3d 78, 88 (D.C. Cir.
2001); Alenco Commuications, Inc. v. FCC, 201 F.3d 608, 625 (5th
Cir. 2000).
    \493\ Mid-Tex Electric Coop., Inc. v. FERC, 773 F.2d 327 (D.C.
Cir 1985).
---------------------------------------------------------------------------

A. Notice of Proposed Rulemaking

    1915. In the NOPR, the Commission stated that the proposed
Reliability Standards ``may cause some small entities to experience
significant economic impact.'' \494\ In response to the ERO's proposal
to develop limits on the applicability of specific Reliability
Standards, the Commission stated that, while it could not rule on the
merits until a specific proposal is submitted, the Commission stated
that it believed that reasonable limits based on size may be an
acceptable alternative to ``lessen the economic impact on the proposed
rule on small entities.'' \495\ The Commission emphasized that any such
limits must not weaken Bulk-Power System reliability.
---------------------------------------------------------------------------

    \494\ NOPR at P 1175.
    \495\ Id. at 1176.
---------------------------------------------------------------------------

    1916. Further, under the Applicability Issues section of the NOPR,
we devoted an entire subsection to the issues facing small
entities.\496\ The Commission stated that there may be instances in
which small entity compliance with a particular Reliability Standard
may be critical to reliability. It explained that, in such
circumstances, it may be appropriate to differentiate among subsets of
users, owners and operators. As an example, the NOPR provided that
``the requirement to have adequate communications capabilities to
address real-time emergency conditions * * * may be necessary for all
applicable entities regardless of size or role, although we understand
that the implementation of these requirements for applicable entities
may vary based on size or role.'' \497\ Additionally, in the NOPR, the
Commission supported the ERO's proposal to permit the registration of
``joint action agencies,'' a concept designed to ease the burden of
small entities by allowing one organization to perform reliability-
related activities for multiple entities. The Commission proposed to
direct the ERO to develop procedures that would permit a joint action
agency or similar organization to accept compliance responsibility on
behalf of its members.
---------------------------------------------------------------------------

    \496\ Id. at 49-53 (Section B.3 ``Applicability to Small
Entities'').
    \497\ Id. at 51.
---------------------------------------------------------------------------

    1917. Thus, in the NOPR, the Commission discussed the potential
disparate impact on small entities, considered the implications and
potential alternatives and solicited comments on the limiting the
application of the Reliability Standards to small entities. Further,
the Information Collection Statement discussed the difficulty
estimating the number of small entities that would be affected by the
Reliability Standards. As such, the Commission was aware of the
potential impacts on small entities and was actively considering
alternatives that would lessen the impact on them while still ensuring
reliability of the Bulk-Power System.
1. Comments
    1918. APPA and NRECA, in their joint comments, provide data about
their membership. APPA states that, based on 2005 data, 1,971 public
utilities or 98 percent of the public utilities in the United States
had less than 4 million MW hours in sales which would qualify them as
small entities. Of these, 90 percent--or 1,775--are distribution-only
utilities, 48 are wholesale-only, and 148 make both wholesale and
retail sales.\498\ NRECA states that its membership includes 930 rural
cooperatives most of which are distribution utilities and almost all of
which would qualify as small entities. Additionally, according to
NRECA, 40 of its 65 generation and transmission cooperatives also
qualify as small entities.\499\
---------------------------------------------------------------------------

    \498\ APPA/NRECA comments at 2.
    \499\ Id.
---------------------------------------------------------------------------

    1919. APPA/NRECA contends that the Commission did not include a
complete initial RFA analysis as required and, without a full initial
RFA, the Commission cannot lay a proper foundation for eliciting public
comments on the impacts of the rule on small entities. Specifically,
APPA/NRECA contends that the NOPR failed to include proposals that
would minimize the impact on small entities. They assert that, instead,
the Commission's proposed definition of bulk electric system in the
NOPR exceeds NERC's definition and thereby sweeps in many small
facilities that are unnecessary to the Reliable Operation of the Bulk-
Power System. APPA/NRECA argue that, if the Commission adopts this
definition, many small transmission owners and operators of lower
voltage transmission systems will be unnecessarily required to bear the
increased training costs to comply with Reliability Standards, yet the
NOPR never considered these additional burdens. APPA/NRECA also asserts
that, under this definition, many small distribution providers would
also be required to comply with the communication-related (COM)
Reliability Standards at additional costs that were never discussed.
They request that the Commission address these shortcomings.
    1920. APPA/NRECA also claims that the Commission substantially
underestimated the number of small entities that would be impacted by
the application of the Reliability Standards as proposed in the NOPR.
APPA/NRECA asserts that 98 percent of public utilities and 99 percent
of public cooperatives, along with numerous small industrial
facilities, small qualifying facilities and small generators would
qualify under the small entity definition and would be impacted by the
rule. According to APPA/NRECA, most of these small entities would not
have a material impact on the reliability of the Bulk-Power System but,
under the NOPR's definition of Bulk-Power System, would be required to
comply with the Reliability Standards.
    1921. APPA/NRECA suggests that the Commission can significantly
reduce the impact on small entities by ``focusing on materiality.''
They contend that an overly-expansive reliability regime would violate
the FPA by imposing unnecessary regulatory burdens on small entities
and divert the ERO's and the Commission's resources away from those
entities that are crucial to Bulk-Power System reliability. APPA/NRECA
asserts that the Commission can ensure reliability without
unnecessarily burdening small entities by considering two alternatives.
First, they urge the Commission to adopt NERC's current definition of
bulk electric system. Second, they ask the Commission to reconsider the
standard-by-standard approach to defining owners, users and operators
of the Bulk-Power System and, instead, accept the NERC compliance
registry to identify the entities that will be responsible for
compliance with Reliability Standards. APPA/NRECA, TAPS, and numerous

other commenters discuss these proposals in their comments, which the
Commission addresses in the Applicability Issues section of the Final
Rule.\500\
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    \500\ See Applicability Issues: Bulk-Power System v. Bulk
Electric System and Applicability to Small Entities, supra sections
II.C.1-2.
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    1922. TAPS asserts that the Commission should apply the ERO's
registration thresholds and, ``absent such limits, the Commission
cannot satisfy its obligations under the [RFA].'' \501\ Georgia Cities
asserts that the Commission should adopt reasonable limits on the
application of the Reliability Standards to small entities, as it
promised in its RFA statement.
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    \501\ TAPS at 13.
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2. Commission Response
    1923. The Commission believes that the NOPR provided a meaningful
discussion of the impact that the Reliability Standards could have on
small entities and discussed several potential alternatives. In fact,
the NOPR contained an entire section on the applicability of the
proposed standards on small entities.\502\ In that section, the
Commission discussed various alternatives to lessen the acknowledged
potential impact on small entities. The Commission indicated its
receptiveness to the ERO's proposal to develop threshold limits
regarding the applicability of specific Reliability Standards. The
Commission also suggested that, where it is necessary for reliability
that a Reliability Standard apply to small entities, implementation of
the requirements of such Reliability Standards may vary based on size
or role. In the NOPR, the Commission set forth another alternative to
address the potential burden on small entities when it proposed to
direct the ERO to develop procedures permitting a joint action agency
or similar organization to accept compliance responsibility on behalf
of its members.
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    \502\ NOPR at P 49-53.
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    1924. As previously stated, the purpose of the RFA is to ensure
that agencies consider the impact a proposed rule would have on small
entities and any potential alternatives that would minimize that
impact. The initial RFA analysis is designed to elicit informed
comments on the impacts to small entities and alternatives. The
Commission believes the NOPR achieved this goal. After the NOPR was
issued, the Commission received over 125 comments and a majority of
those addressed small entity issues. Further, almost all of the
commenters addressed the NOPR's proposed interpretation of the
definition of the bulk electric system, which as APPA/NRECA states
would have had the greatest impact on small entities.
    1925. In addition to the comments received addressing these issues,
Commission staff has met with representatives of small entities,
including APPA and NRECA, and listened to their concerns on the
potential impacts of the Final Rule and discussed possible
alternatives.
    1926. Since receiving APPA/NRECA's comments on the RFA, the
Commission has compiled and reviewed available data on small entities
and the impact of the Final Rule on such entities. Therefore, the
Commission believes that any inadequacy that may have existed in the
NOPR's initial RFA analysis has now been corrected. This Final RFA and
the alternative proposals adopted herein demonstrate the Commission's
consideration of the potential burdens that the rulemaking could place
on small entities.
    1927. As discussed in the Applicability section above, the
Commission adopts in the Final Rule the current definition of bulk
electric system. Any possible change to the definition would occur in a
future Commission proceeding. Further, the Commission has endorsed the
ERO's compliance registry process to identify the entities that must
comply with mandatory Reliability Standards.\503\ By adopting these
alternative proposals, the Commission has been responsive to small
entity concerns and greatly reduced the number of small entities that
will be affected by the Final Rule.
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    \503\ As noted previously, APPA, NRECA and TAPs submitted
supplemental comments supporting the ERO's compliance registry
process.
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B. Final RFA

1. Description of the Reasons Why Action by the Agency Is Being
Considered
    1928. On April 4, 2006, as later modified and supplemented, NERC--
the ERO--submitted 107 Reliability Standards for Commission approval
pursuant to section 215(d) of the FPA. The ERO's submission includes
the ``Version 0'' standards with which the electric industry has
complied on a voluntary basis as well as several new Reliability
Standards approved by NERC since its certification as the ERO.
    1929. As set forth in section 215(a) of the FPA, the term
``Reliability Standard'' means a requirement, approved by the
Commission to provide for the Reliable Operation of the Bulk-Power
System. The term ``Reliable Operation'' means ``operating the elements
of the bulk-power system within equipment and electric system, thermal,
voltage, and stability limits so that instability, uncontrolled, or
cascaded failures of such system will not occur as a result of a sudden
disturbance * * * or unanticipated failure of system elements.'' \504\
Thus, the purpose of each Reliability Standard approved by the
Commission in this Final Rule is to provide for the Reliable Operation
of the Bulk-Power System and thereby minimize the risk of instability,
uncontrolled or cascading failure on the Bulk-Power System.
---------------------------------------------------------------------------

    \504\ 16 U.S.C. 824o(a)(4) (2006).
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    1930. The Commission is approving 83 of the proposed Reliability
Standards. Upon the effective date of the Final Rule, compliance with
these Reliability Standards will be mandatory and enforceable for
applicable users, owners and operators of the Bulk-Power System. The
Commission believes that these Reliability Standards form a solid
foundation on which to develop and maintain the reliability of the
North American Bulk-Power System.
2. Objectives of and the Legal Basis for the Final Rule
    1931. This Final Rule requires applicable users, owners and
operators of the Bulk-Power System to comply with mandatory and
enforceable Reliability Standards. As discussed above, these
Reliability Standards are necessary to ensure the reliable operation of
the North American Bulk-Power System.
    1932. EPAct 2005 added a new section 215 to the FPA, which provides
for a system of mandatory and enforceable Reliability Standards.
Section 215(d)(1) of the FPA provides that the ERO must file each
Reliability Standard or modification to a Reliability Standard that it
proposes to be made effective, i.e., mandatory and enforceable, with
the Commission. As mentioned above, on April 4, 2006, and as later
modified and supplemented, the ERO submitted 107 Reliability Standards
for Commission approval pursuant to section 215(d) of the FPA.
    1933. Section 215(d)(2) of the FPA provides that the Commission may
approve, by rule or order, a proposed Reliability Standard or
modification to a proposed Reliability Standard if it meets the
statutory standard for approval, giving due weight to the technical
expertise of the ERO. Alternatively, the Commission may remand a
Reliability Standard pursuant to section 215(d)(4) of the FPA. Further,
the Commission may order the ERO to submit to the

Commission a proposed Reliability Standard or a modification to a
Reliability Standard that addresses a specific matter if the Commission
considers such a new or modified Reliability Standard appropriate to
``carry out'' section 215 of the FPA.\505\ The Commission's action in
this Final Rule is based on its authority pursuant to section 215 of
the FPA.
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    \505\ See 16 U.S.C. 824o(d)(5) (2006).
---------------------------------------------------------------------------

3. Significant Issues Raised by Comments, Agency Assessment of the
Comments and a Statement of Any Changes Made in the Proposed Rule as a
Result of the Comments
    1934. Numerous small entity commenters oppose the NOPR
interpretation of bulk electric system and urge the Commission to adopt
the ERO's current definition of that term. Further, small entity
commenters oppose the NOPR's proposal to address applicability on a
standard-by-standard basis and, instead, ask that the Commission rely
on the ERO's compliance registry process as the means to identify
entities responsible for complying with mandatory and enforceable
Reliability Standards. Commenters assert that the Commission's proposed
changes would greatly increase the number of small entities that would
be significantly impacted by the Final Rule.
    1935. As discussed above, the Commission is not adopting its
proposed interpretation of bulk electric system contained in the NOPR.
Rather, the Commission adopts the NERC definition of bulk electric
system. Further, the Commission is relying on NERC's registration
process to provide as much certainty as possible regarding the
applicability and responsibility of specific entities in the start-up
phase of the mandatory Reliability Standards regime. Any change in
these approaches would be addressed in a separate Commission
proceeding.
    1936. A complete summary of these comments and the Commission's
response has been previously addressed in the Applicability section.
4. Description and Estimate of the Number of Small Entities To Which
the Final Rule Will Apply
    1937. According to the SBA, a small electric utility is defined as
one that has a total electric output of less than four million MWh in
the preceeding year.
    1938. According to the DOE's Energy Information Administration
(EIA), there were 3,284 electric utility companies in the United States
in 2005,\506\ and 3,029 of these electric utilities qualify as small
entities under the SBA definition. Of these 3,284 electric utility
companies, the EIA subdivides them as follows: (1) 883 cooperatives of
which 852 are small entity cooperatives; (2) 1,862 municipal utilities,
of which 1842 are small entity municipal utilities; (3) 127 political
subdivisions, of which 114 are small entity political subdivisions; (4)
159 power marketers, of which 97 individually could be considered small
entity power marketers; \507\ (5) 219 privately owned utilities, of
which 104 could be considered small entity private utilities; (6) 25
state organizations, of which 16 are small entity state organizations
and (7) nine federal organizations of which four are small entity
federal organizations.
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    \506\ See Energy Information Administration Database, Form EIA-
861, Dept. of Energy (2005), available at http://www.eia.doe.gov/cneaf/electricity/page/eia861.html
.

    \507\ Most of these small entity power marketers and private
utilities are affiliated with others and, therefore, do not qualify
as small entities under the SBA definition.
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    1939. As discussed above, the Commission is relying on the ERO's
compliance registry process to identify which entities must comply with
mandatory and enforceable Reliability Standards. The ERO's Compliance
Registry Criteria describe how NERC will identify organizations that
may be candidates for registration and assign them to the compliance
registry.\508\ According to this document, the ERO will register
transmission owners and operators with an integrated element associated
with the Bulk-Power System of 100 kV and above, or lower voltage as
defined by a Regional Entity. The ERO plans to register only those
distribution providers or LSEs that have a peak load of 25 MW or
greater and are directly connected to the bulk electric system or are
designated as a responsible entity as part of a required underfrequency
load shedding program or a required undervoltage load shedding program.
For generators, the ERO plans to register individual units of 20 MVA or
greater that are directly connected to the bulk electric system,
generating plants with an aggregate rating of 75 MVA or greater, any
blackstart unit material to a restoration plan, or any generator
``regardless of size, that is material to the reliability of the Bulk-
Power System.'' Further, the ERO will not register an entity that meets
the above criteria if it has transferred responsibility for compliance
with mandatory Reliability Standards to a joint action agency or other
organization.
---------------------------------------------------------------------------

    \508\ See NERC Statement of Compliance Registry Criteria
(Revision 3) at 6-8.
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    1940. As mentioned above, the SBA defines a small electric utility
as one that has a total electric output of less than four million MWh
in the proceeding year. Thus, the set of small entities that must
comply with mandatory Reliability Standards would be those that exceed
the ERO registry criteria but still meet the SBA definition. The
Commission has reviewed data compiled by EIA in Form EIA-861, NERC's
pre-registry data, and information submitted by commenters, and
determined an estimate of the number of small entities to which the
Final Rule will apply.
    1941. The Commission estimates that the Reliability Standards
approved in the Final Rule will apply to approximately 682 small
entities (excluding entities in Alaska and Hawaii) as follows: 670
small municipal utilities and cooperatives and 12 small investor-owned
utilities.
    1942. As discussed above, the ERO's Compliance Registry Criteria
allows for a joint action agency, G&T cooperative or similar
organization to accept compliance responsibility on behalf of its
members. Once such organizations register with the ERO, the number of
small entities registered with the ERO will diminish and, thus,
significantly reduce the impact of the Final Rule on small entities.
    1943. To be included in the compliance registry, the ERO will have
made a determination that a specific small entity has a material impact
on the Bulk-Power System. Consequently, the compliance of such small
entities is justifiable as necessary for Bulk-Power System reliability.
5. Description of the Projected Reporting, Recordkeeping and Other
Compliance Requirements for Small Entities
    1944. A complete summary of comments and the Commission's response
has been previously addressed in the Information Collection Statement
section.
6. Duplication of Other Federal Rules
    1945. There are no relevant Federal rules which may duplicate,
overlap or conflict with the Final Rule.
7. Description of Any Significant Alternatives to the Final Rule
    1946. In the Final Rule, the Commission adopts several significant
alternatives that will minimize the burden on small entities. The
Commission approves the current ERO definition of bulk electric system,
which

will reduce significantly the number of small entities responsible for
complying with the Final Rule. The Commission also approves the ERO
compliance registry process to identify the entities responsible for
compliance with mandatory and enforceable Reliability Standards.
Further, the Commission directs the ERO to submit a procedure to permit