restore the interconnection using them following a blackout. It also
requires operating personnel to be trained in these plans.
    621. In the NOPR, the Commission proposed to approve Reliability
Standard EOP-005-1 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 proposed to direct that NERC submit a modification to
EOP-005-1 that: (1) Includes Measures and (2) identifies time frames
for training and review of restoration plan requirements to simulate
contingencies and prepare operators for anticipated and unforeseen
events.
i. Comments
    622. APPA and EEI state that Reliability Standard EOP-005-1 is
sufficient for approval as a mandatory Reliability Standard and
requests that the Commission direct NERC to address missing Measures
and training requirements. In addition, APPA notes that the Reliability
Standard is applicable to both balancing authorities and transmission
operators but the Measures and Levels of Non-Compliance elements refer
only to transmission operators.
    623. ISO[dash]NE does not support adoption of the proposed
Reliability Standard because, while Requirement R1 requires
transmission operators to include applicable elements from Attachment 1
of EOP-005-1 in their restoration plans, Requirement R1 appears to
indicate that the elements in Attachment 1 are to be included in the
emergency plan only ``as applicable.'' ISO[dash]NE states that the
Reliability Standard should be clarified to indicate that the actual
emergency plan elements should be the basis for compliance.
    624. EEI and FirstEnergy note that the proposed modification to
identify time frames for training and review of restoration plan
requirements is being addressed in the proposed Reliability Standard
PER-005-1 and that including this requirement in EOP-005-1 would be
redundant. MISO also believes that the proposed modification is
unnecessary. It states that there are already requirements for
simulation-based training on emergencies and restoration and it is
unclear what is meant by conducting training to prepare operators for
unforeseen events.

    625. FirstEnergy states that Requirement R1 calls for a plan for a
partial shutdown of the system and that there is an infinite set of
events that can cause a partial shutdown. According to FirstEnergy,
because the borders of a partial shutdown are difficult, if not
impossible, to foresee, the Reliability Standard should specify some
boundaries for analysis of partial shutdowns including an appropriate
definition of the term ``partial shutdown.'' In addition, FirstEnergy
states that one uniform plan for all systems is not feasible; rather
the Reliability Standard should recognize that some companies already
have existing plans that could be used for analyzing events.
FirstEnergy also states that the Reliability Standard should provide a
uniform checklist of factors to analyze, developed on a company-
specific basis.
    626. NRC suggests that this Reliability Standard include: (1) A
requirement to record the time it takes to restore power to the
auxiliary power systems of nuclear power plants; (2) a provision
stating that the affected transmission operators shall give high
priority to restoration of off-site power to nuclear power plants
whether or not a nuclear power plant is being powered from the nuclear
power plant's onsite power supply and (3) a provision stating that
restoration shall not violate nuclear power plant minimum voltage and
frequency requirements.
    627. While not commenting on the substance of Reliability Standard
EOP-005-1, MRO states that EOP-005-1, EOP-006-1 and EOP-007-0 are
ordered in a confusing manner and should be renumbered. MRO reasons
that since the regional coordinator has oversight responsibility for
system restoration, EOP-006-1 should be first in the system restoration
sequence of Reliability Standards (i.e., EOP-006-1 should precede EOP-
005-1). Further, MRO recommends that EOP-005-1 follow EOP-006-1 because
transmission owners and balancing authorities are responsible for
submitting restoration plans to the regional coordinator. MRO requests
that if a reason exists for the current order, NERC should provide that
reason to the Commission.
ii. Commission Determination
    628. With regard to comments that the Commission's concerns are
being addressed in NERC's drafting of proposed PER-005-1 Reliability
Standard on operator training, we note PER-005-1 only includes
Requirements on the control room personnel and not those outside of the
control room. System restoration requires the participation of not only
control room personnel but also those outside of the control room.
These include blackstart unit operators and field switching operators
in situations where SCADA capability is unavailable. As such, the
Commission believes that inclusion of periodic system restoration
drills and training and review of restoration plans in a system
restoration Reliability Standard is the most effective way of achieving
the desired goal of ensuring that all participants are trained in
system restoration and that the restoration plans are up to date to
deal with system changes.
    629. Several commenters raise issues that should be addressed by
the ERO through the Reliability Standards development process.\252\ For
example: whether the Measures and Levels of Non-Compliance should refer
to balancing authorities; clarification of the elements that form the
basis for compliance with the requirements of Attachment 1; what
constitutes a partial shutdown for which restoration plans must be
developed and recognition that some companies already have existing
plans that could be used for analyzing events; and that the Reliability
Standard should provide a uniform checklist of factors to analyze,
developed on a company-specific basis. We find that consideration of
these issues could be helpful in meeting the objectives of the
Reliability Standard. Accordingly, the ERO should consider these
concerns in future revisions of the Reliability Standard through the
Reliability Standards development process.
---------------------------------------------------------------------------

    \252\ See APPA, ISO-NE, FirstEnergy and MRO.
---------------------------------------------------------------------------

    630. NRC raises several issues concerning the role and priority
that nuclear power plants should have in system restorations. The
Commission shares these concerns and directs the ERO to consider the
issues raised by NRC in future revisions of the Reliability Standard
through the Reliability Standards development process. In addition the
Commission directs the ERO to gather data, pursuant to Sec.  39.5(f) of
the Commission's regulations, from simulations and drills of system
restoration on the time it takes to restore power to the auxiliary
power systems of nuclear power plants under its data gathering
authority and report that information to the Commission on a quarterly
basis.
    631. We find that the Reliability Standard adequately addresses
operating personnel training and system restoration plans to ensure
that transmission operators, balancing authorities and reliability
coordinators are prepared to restore the Interconnection following a
blackout. Accordingly, the Commission approves Reliability Standard
EOP-005-1 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 EOP-005-1
through the Reliability Standards development process that identifies
time frames for training and review of restoration plan requirements to
simulate contingencies and prepare operators for anticipated and
unforeseen events and gathers the data from simulations and drills of
system restoration on the time it takes to restore power to the
auxiliary power systems of nuclear power plants under its data
gathering authority and report that information to the Commission on a
quarterly basis.
f. Reliability Coordination-System Restoration (EOP-006-1)
    632. Proposed Reliability Standard EOP-006-1 addresses reliability
coordination and system restoration.\253\ It establishes specific
requirements for reliability coordinators during system restoration,
and it states that reliability coordinators must have a coordinating
role in system restoration to ensure that reliability is maintained
during restoration and that priority is placed on restoring the
Interconnection.
---------------------------------------------------------------------------

    \253\ In its November 15, 2006, filing, NERC submitted EOP-006-
1, which supercedes the Version 0 Reliability Standard. EOP-006-1
adds Measures and Levels of Non-Compliance to the Version 0
Reliability Standard. In this Final Rule, we review the November
version, EOP-006-1.
---------------------------------------------------------------------------

    633. In the NOPR, the Commission proposed to approve the
Reliability Standard as mandatory and enforceable. In addition,
pursuant to section 215(d)(5) of the FPA and Sec.  39.5(f) of our
regulations, the Commission proposed to direct that NERC submit a
modification to the Reliability Standard that: (1) requires that the
reliability coordinator be involved in the development of and approves
restoration plans and (2) includes Measures and Levels of Non-
Compliance.
i. Comments
    634. APPA states that Reliability Standard EOP-006-1, which NERC
filed on November 15, 2006, includes the required Measures and Levels
of Non-Compliance and as such APPA agrees that EOP-006-1 should be
approved as mandatory and enforceable. In addition, APPA does not
oppose industry consideration of a requirement that reliability
coordinators be involved in the development and approval of restoration
plans.

    635. EEI states that Requirements R4 and R11 of EOP-005-1 already
address reliability coordinator involvement in the development and
approval of transmission operator system restoration plans. Further,
while EEI agrees that the reliability coordinator's role is
appropriate, it believes that the asset owner, as the entity that
ultimately bears responsibility for restoration capabilities, should
also have authority to develop and maintain the plans. MISO believes
that it is unnecessary to modify the Reliability Standard to involve
the reliability coordinator because there is already a requirement in
EOP-005-1 for balancing authorities and transmission operators to
coordinate their plans with the reliability coordinator.
    636. Xcel disagrees that the reliability coordinator should be
involved with the development of restoration plans because the
reliability coordinator typically does not have the knowledge of the
details necessary to develop the plans in contrast to the balancing
authorities and the transmission operators. Instead it proposes that
the reliability coordinator develop its own plans and coordinate that
with the balancing authority and transmission operator's plans.
ii. Commission Determination
    637. The reliability coordinator is the highest level of authority
that is responsible for the reliable operation of the Bulk-Power
System. Given the importance of this role in connection with matters
covered by EOP-006-1, the Commission believes that the reliability
coordinator must be involved in the development and approval of the
restoration plans. The current Reliability Standard only requires that
the reliability coordinator be aware of the restoration plan of each
transmission operator in its area. The Commission disagrees with EEI
and MISO, who contend that the reliability coordinator's role in the
transmission operator's restoration plan is covered in EOP-005-1. EOP-
005-1 only requires coordination with the reliability coordinator, and
during actual system restoration, EOP-005-1 requires approval from the
reliability coordinator to resynchronize isolated areas with other
isolated areas.
    638. In response to comments by Xcel, the Commission believes that
while the reliability coordinator may not have the level of detailed
knowledge that the balancing authorities and transmission operators may
have for setting-up the stable islands required under restoration
plans, the reliability coordinator is in the best position to determine
how those stable islands should be resynchronized with each other and
the rest of the interconnected system.
    639. The Commission finds that the Reliability Standard adequately
addresses the goals of effective and efficient reliability coordination
and system restoration. Accordingly, the Commission approves
Reliability Standard EOP-006-1 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 EOP-006-1 through the Reliability Standards development
process that ensures that the reliability coordinator, which is the
highest level of authority responsible for reliability of the Bulk-
Power System, is involved in the development and approval of system
restoration plans.
g. Establish, Maintain, and Document a Regional Blackstart Capability
Plan (EOP-007-0)
    640. EOP-007-0, which deals with establishing, maintaining and
documenting regional blackstart capability plans, ensures that the
quantity and location of system blackstart generators are sufficient
and that they can perform their expected functions as specified in the
overall coordinated regional system restoration plans.
    641. The NOPR did not propose to approve or remand EOP-007-0,
because it applies only to regional reliability organizations.
i. Comments
    642. APPA agrees that EOP-007-0 should not be approved as a
mandatory Reliability Standard and states that in the interim the
regional reliability organizations and Regional Entities should
continue to perform this function. In addition, APPA proposes that, in
the interim, an umbrella organization composed of representatives from
each regional reliability organization and Regional Entity should be
formed to establish operation planning rules, including blackstart
requirements, across the Eastern Interconnection. APPA suggests that
such an effort would go a long way in identifying critical facilities,
using consistent and transparent study assumptions and minimizing seams
during system emergencies throughout the Interconnection.
    643. TANC states that the number of blackstart units and their
locations depend heavily on regional characteristics and cannot be
prescribed in a uniform, continent-wide manner. It proposes that
regional flexibility be afforded to provide an appropriate mix of
facilities to achieve the reliability objectives. EEI suggests that
EOP-007-0 be rewritten so that compliance obligations are assigned
directly to those entities that provide the data and other information.
    644. FirstEnergy and MRO state that the reliability coordinator,
not the Regional Entity, should be responsible for the regional
blackstart plan for its area of responsibility. Further, FirstEnergy
states that the blackstart plan developed for a region should be
consistent with NRC requirements, should recognize that nuclear units
have no blackstart capability and should recognize that nuclear units
must have priority access to off-site power for safety reasons.
FirstEnergy requests that the Commission direct NERC to revise the
definition of a blackstart unit to mean a ``diesel, hydro, pump
storage, or the combustion turbine generating unit that is used to
provide cranking power to a larger steam generating unit designed to
restore load'' or to mean a ``larger steam generating unit designed to
restore load.'' \254\ MRO states that arrangements for coordination of
blackstart capability should be addressed in a contract between
appropriate entities.
---------------------------------------------------------------------------

    \254\ See FirstEnergy at 35.
---------------------------------------------------------------------------

ii. Commission Determination
    645. The Commission will not approve or remand EOP-007-0, because
it applies only to regional reliability organizations. However, the
Commission provides guidance for the ERO's future consideration.
    646. The Commission disagrees with APPA that an umbrella
organization is needed for the Eastern Interconnection while the
Reliability Standard is pending final approval. The Commission is
persuaded that FirstEnergy's and MRO's comments concerning the
reliability coordinator being responsible for regional blackstart plans
have merit. The Commission has directed that the reliability
coordinator approve the system restoration plans and this is a logical
extension of that direction. However, until such time as the
Reliability Standard has been revised and approved by the ERO and the
Commission, the regional reliability organization (or Regional Entity,
depending on the organization of a particular region) should continue
to perform this role as it has in the past.\255\
---------------------------------------------------------------------------

    \255\ See NOPR at P 328.
---------------------------------------------------------------------------

    647. With regard to TANC's request for regional flexibility in
determining the appropriate mix of facilities needed to achieve the
reliability objectives, it is

our understanding that the Reliability Standard provides for the number
and location of blackstart units to vary depending on the specific
requirements of each system. We believe that uniformity will be
required, however, in the criteria used to determine the number and
location of blackstart units and testing requirements.
    648. EEI, FirstEnergy and MRO offer suggestions for improving the
Reliability Standard. The Commission directs the ERO to consider these
suggestions in future revisions to improve EOP-007-0, through the
Reliability Standards development process.
    649. Accordingly, the Commission will not approve or remand EOP-
007-0 at this time.
h. Plans for Loss of Control Center Functionality (EOP-008-0)
    650. EOP-008-0 addresses plans for loss of control center
functionality. It requires each reliability coordinator, transmission
operator and balancing authority to have a plan to continue reliable
operations and to maintain situational awareness in the event its
control center is no longer operable.
    651. The Commission proposed five modifications to the Reliability
Standard and requested additional comments on other issues. We have
grouped the comments into two general categories: (1) Capabilities of
backup control centers and (2) which entities should have full backup
centers. Below, we address each topic separately, followed by an
overall conclusion and summary.
i. Capabilities of Backup Control Centers
    652. In the NOPR, the Commission proposed to approve Reliability
Standard EOP-008-0 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 proposed to direct that NERC submit a modification to
EOP-008-0 that includes a Requirement that provides for backup
capabilities that, at a minimum, must: (1) Be independent of the
primary control center; (2) be capable of operating for a prolonged
period of time and (3) provide for a minimum set of tools and
facilities to replicate the critical reliability functions of the
primary control center.\256\ In addition to these three capabilities
requirements, the Commission solicited comments concerning other
specific capabilities.
---------------------------------------------------------------------------

    \256\ The term ``facility'' in this context includes, but is not
limited to, telecommunications, backup power supplies, computer
systems and security systems. NOPR at P 335 & n.159.
---------------------------------------------------------------------------

(a) Comments
    653. EEI, Entergy, FirstEnergy and Northern Indiana support the
proposed modifications to EOP-008-0. Entergy agrees with the
Commission's proposed modifications to include more Requirements
regarding backup capabilities.
    654. APPA, Nevada Companies and TAPS caution that costs must be
considered and compared to possible benefits. APPA states that it would
take some time to implement the proposed modifications and therefore
specific requirements for backup control facilities and capabilities
should be left to the Reliability Standard development process. Nevada
Companies cautions that utilities that have invested millions of
dollars in back-up capabilities may find these facilities to be non-
compliant with the proposed Reliability Standard. It suggests that
cost/benefits analyses be conducted and that a grandfathering provision
be adopted to protect investments in backup systems that were made in a
good faith effort to comply with rules in place in the past, but which
may not comply with the Reliability Standard.
    655. MRO requests clarification of the term ``capability'' because
it is unsure if the term is intended to refer to a facility, what such
a facility should consist of and what operators should be capable of
doing from that facility.
    656. In response to the request for comments on backup
capabilities, NERC states that these are best addressed through the
Reliability Standards development process.
    657. SoCal Edison suggests that a risk-based assessment be
considered to determine the requirements for backup. MISO, TAPS and
International Transmission note that work is underway by NERC to
address the provisions for redundancy and backup control capabilities
via the Operating Committee Backup Control Task Force and that the
focus is on functionality rather than physical requirements. TAPS
states that, rather than directing NERC to adopt specific modifications
to the Reliability Standard that would inappropriately burden small
systems with the cost of dual facilities, the Commission should
identify objectives to the Task Force. TAPS also states that a small
balancing authority might be able to meet the functional requirements
for a backup control center with a contract with another entity while
larger entities might need a physical backup center.
    658. Northern Indiana states that the Commission's proposal appears
to eliminate an entity's opportunity to contract for backup
capabilities from others who already have full backup control centers.
FirstEnergy and Northern Indiana advocate for flexibility in the means
used to meet the backup requirements and request that the Commission
clarify that a ``full backup center'' can include providing full
redundancy by contract rather than physical backup center facilities.
SoCal Edison states that when entities utilize the services of another
entity for backup, they should be required to test the backup
capability a minimum number of times during the year and that all
system operators should be required to participate in such testing over
a specified time period.
    659. NRC suggests that this Reliability Standard require: (1) A
list of the nuclear power plants and their voltage, thermal, and/or
frequency limits and (2) provisions to notify nuclear power plants of
the loss of control center functionality.
(b) Commission Determination
    660. As we stated in the NOPR, the goal of the Reliability Standard
is the continuation of reliable operations and the maintenance of
situational awareness in the event that the primary control center is
no longer operational.\257\ Some commenters support the proposal to
require backup capabilities while others including APPA, Nevada
Companies and TAPS caution that the cost of the proposal may not be
justified. In addition, some commenters, including FirstEnergy and
Northern Indiana, advocate for flexibility in meeting the backup
requirements and suggest that entities should be able to contract for
full redundancy. MRO seeks clarification regarding the use of the term
``capability.''
---------------------------------------------------------------------------

    \257\ NOPR at P 329.
---------------------------------------------------------------------------

    661. In the NOPR, we found that the provision of backup
capabilities should be an explicit Requirement to meet the objectives
of the Reliability Standard. We chose to use the word ``capabilities''
to avoid defining particular facilities or preclude other options,
including arranging for backup capabilities by contracting with others.
We stated that the mechanism to provide these capabilities may include
building fully redundant physical backup control centers, contracting
for backup control services or using backup equipment within a separate
existing facility.\258\ In addition, regardless of the means used to
provide the backup capabilities, as we stated in the NOPR, the time
period for which backup capability is required

should correspond to the time it would take to replace the primary
control center.
---------------------------------------------------------------------------

    \258\ See Id. at P 336.
---------------------------------------------------------------------------

    662. On the issue of additional backup capabilities, NERC, MISO,
TAPS and International Transmission propose that the functional
requirements for backup capabilities be determined by the NERC Backup
Control Task Force. NRC offers requirements it believes should be added
to the Reliability Standard.
    663. The Commission disagrees with the Nevada Companies' proposal
for grandfathering. The Reliability Standards must define the minimum
functions that are necessary for the Reliable Operation of the Bulk-
Power System. The flexibility described above on how capabilities are
provided should mitigate any costs incurred to upgrade older centers.
    664. Given the importance to reliability of maintaining situational
awareness in the event of loss of the primary control center
operations, the Commission believes that, at a minimum, the three
requirements--independence from the primary control center, capability
to operate for a prolonged period corresponding to the time it would
take to replace the primary control center, and the provision of a
minimum set of tools and facilities to replicate the critical
reliability functions of the primary control center--must be included
as explicit requirements in the Reliability Standard. Other additional
Requirements may be developed by the Backup Control Task Force for
inclusion in the Reliability Standard. The Commission directs the ERO
to develop modifications to the requirements in future revisions to the
Reliability Standard through the Reliability Standards development
process.
ii. Which entities should have full backup centers
    665. In the NOPR , the Commission proposed to direct that NERC
submit a modification to EOP-008-0 that: (1) Provides that the extent
of the backup capability be consistent with the impact of the loss of
the entity's primary control center on the reliability of the Bulk-
Power System and (2) includes a Requirement that all reliability
coordinators have full backup control centers. The Commission also
requested comments on what other entities, such as balancing
authorities and large transmission operators, should have full backup
centers.
(a) Comments
    666. International Transmission, MISO and FirstEnergy state that in
addition to reliability coordinators, large balancing authorities and
transmission operators need full backup control centers. MISO states
that there are certain situations where large generation fleets that
are controlled centrally would also warrant full backup systems and
that small entities can operate reliably with less robust systems.
Further, it argues that the ERO needs latitude to decide from a
reliability standpoint how much redundancy is needed. FirstEnergy
states that in place of full backup control facilities it should be
acceptable to have standing contracts in place to provide backup
services in the event of a loss of a control center.
    667. NERC states that the proposed directive presumes that the only
way to achieve highly reliable and independent backup capability to
perform reliability coordinator functions in an emergency is to have a
redundant control center. NERC contends that while this may be an
option, it may not be the only one for achieving the necessary
reliability objective. NERC proposes that the Reliability Standard be
modified to define the performance results expected rather than how an
entity should meet the requirements.
    668. NERC, SoCal Edison and Otter Tail state that the question of
what other entities should have full backup centers is best addressed
through the Reliability Standards development process. Otter Tail
requests that the Commission not require all balancing authorities to
have full backup centers since the loss of a small balancing
authority's control center would not have a substantial impact on the
reliability of the Bulk-Power System. Northern Indiana states that
requiring transmission operators and balancing authorities to have full
backup centers would result in significant unnecessary facility
duplication, at great cost to consumers, and without a material
increase in reliability.
    669. FirstEnergy comments that the Reliability Standard should not
require a fully redundant SCADA system for the backup control center
for balancing authorities or transmission operators because the cost
would be prohibitive. It states that balancing authorities,
transmission operators and centrally-located generation owners should
be permitted to have a single distributed computer system in place to
diminish the probability of a complete system shutdown due to a natural
disaster or a single man-made physical act of sabotage.
    670. Nevada Companies also questions whether the significant cost
of full replication could ever be cost-effective, especially
considering the very high level of control center reliability achieved
now with the existing solution of a single control center plus backup
of critical systems.
(b) Commission Determination
    671. Several commenters agree with the Commission that reliability
coordinators at a minimum should have full backup control centers. They
also propose that this requirement be extended to large balancing
authorities, transmission operators and centrally dispatched generation
facilities. Others caution on the cost implications of requiring full
duplication given the very high level of control center reliability
achieved with the existing technology and backup of critical systems.
Having carefully considered all the issues raised by commenters and
taking into account the reliability impacts of loss of primary control
centers and the role of reliability coordinators as the highest level
of authority responsible for reliability of the Bulk-Power System, the
Commission is persuaded that all reliability coordinators must have
fully redundant independent backup control centers. In response to
NERC, any proposed modification that is independent from the primary
center, provides for continuous monitoring and has the full
functionality of the primary center would satisfy our concerns. Other
entities, including balancing authorities, transmission operators and
centrally dispatched generation control centers, must provide for the
minimum backup capabilities discussed above but may do so through other
means, such as contracting for these services instead of through
dedicated backup control centers.
    672. In addition, in response to FirstEnergy's concern regarding
balancing authorities and transmission operators having fully redundant
SCADA systems and distributed computer systems, the Commission requires
the primary and backup capabilities to replicate critical reliability
functionalities and be independent from the primary control center,
including telemetered data and control from remote terminal units. This
can be achieved through a variety of design alternatives, e.g.,
developing a SCADA management platform that will allow telemetered data
and control to be shared among SCADA systems so that data and control
is not lost during a SCADA or communications failure. The Commission's
focus is on function, not design.

iii. Summary of Commission Determination
    673. Accordingly, the Commission approves Reliability Standard EOP-
0081-0 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 EOP-008-0
through the Reliability Standards development process that includes a
Requirement that provides for backup capabilities that, at a minimum,
must: (1) Be independent of the primary control center; (2) be capable
of operating for a prolonged period of time, generally defined by the
time it takes to restore the primary control center; (3) provide for a
minimum functionality to replicate the critical reliability functions
of the primary control center; (4) provides that the extent of the
backup capability be consistent with the impact of the loss of the
entity's primary control center on the reliability of the Bulk-Power
System; (5) includes a Requirement that all reliability coordinators
have full backup control centers and (6) requires transmission
operators and balancing authorities that have operational control over
significant portions of generation and load to have minimum backup
capabilities discussed above but may do so through contracting for
these services instead of through dedicated backup control centers.
i. Documentation of Blackstart Generating Unit Tests Results (EOP-009-
0)
    674. Proposed Reliability Standard EOP-009-0 deals with
documentation of blackstart generating unit test results. In the NOPR,
the Commission proposed to approve EOP-009-0 as mandatory and
enforceable without modifications.
i. Comments
    675. APPA agrees that EOP-009-0 is sufficient for approval as a
mandatory and enforceable Reliability Standard. Xcel states that the
Reliability Standard should provide details on what constitutes a
blackstart test and FirstEnergy states that EOP-009-0 should be
consolidated with EOP-007-0 because the Requirements of EOP-009-0
already exist in EOP-007-0.
ii. Commission Determination
    676. The Commission believes that this Reliability Standard
sufficiently addresses documentation of blackstart generating unit test
results. Accordingly, the Commission approves Reliability Standard EOP-
009-0 as mandatory and enforceable.
    677. Two commenters made suggestions for improving the Reliability
Standard. The Commission directs the ERO to take these suggestions into
consideration when revising the Reliability Standard through the
Reliability Standards development process.
5. FAC: Facilities Design, Connections, Maintenance, and Transfer
Capabilities
    678. The nine Facility (FAC) Reliability Standards address topics
such as facility connection requirements, facility ratings, system
operating limits and transfer capabilities. The FAC Reliability
Standards also establish requirements for maintaining equipment and
rights-of-way, including vegetation management. The NOPR provided
direction for seven of the nine FAC Reliability Standards; NERC
withdrew two others, Reliability Standards FAC-004-0 and FAC-005-0.
NERC, in its November 15, 2006 filing requests approval of three
additional FAC Reliability Standards: FAC-010-0, FAC-011-0 and FAC-014-
0. These Reliability Standards are being addressed in a separate
docket.
a. Facility Connection Requirements (FAC-001-0)
    679. Proposed Reliability Standard FAC-001-0 is intended to ensure
that transmission owners establish facility connection and performance
requirements to avoid adverse impacts to the Bulk-Power System. In the
NOPR, the Commission proposed to approve FAC-001-0 as mandatory and
enforceable.
i. Comments
    680. APPA agrees with the Commission's proposal to approve FAC-001-
0 as mandatory and enforceable.
ii. Commission Determination
    681. As discussed in the NOPR, the Commission believes that
Reliability Standard FAC-001-0 is just, reasonable, not unduly
discriminatory or preferential and in the public interest and approves
it as mandatory and enforceable.
b. Coordination of Plans for New Generation, Transmission, and End-User
Facilities (FAC-002-0)
    682. Proposed Reliability Standard FAC-002-0 requires that each
generation owner, transmission owner, distribution provider, LSE,
transmission planner and planning authority assess the impact of
integrating generation, transmission and end-user facilities into the
interconnected transmission system.
    683. In the NOPR, the Commission proposed to approve Reliability
Standard FAC-002-0 as mandatory and enforceable. In addition, pursuant
to section 215(d)(5) of the FPA and Sec.  39.5(f) of our regulations,
the Commission proposed to direct that NERC submit a modification to
FAC-002-0 that amends Requirement R1.4 to require evaluation of system
performance under both normal and contingency conditions by referencing
TPL-001 through TPL-003.
i. Applicability and Assessment Responsibility
(a) Comments
    684. APPA, Xcel and FirstEnergy state that this Reliability
Standard is not clear about who will perform the required assessment
and how many assessments are required under this Reliability Standard.
APPA requests that the Reliability Standard be clarified to state that
the required assessment must be performed only by the transmission
planner and the planning authority. Xcel requests that the Commission
clarify that only one required assessment needs to be done when new
facilities are added, and that all the listed entities should
participate in that single assessment.
    685. FirstEnergy requests that NERC clarify what is considered a
new facility and asks if, for example, up-rates should be included as
new facilities. MRO is concerned that the impact of the Commission's
directive is too broad and may have a substantial affect on those
individual entities that are responsible for performing the studies;
MRO asks the Commission to clarify FAC-002-0 to the extent necessary,
but does not propose a specific change.
    686. Six Cities requests that this Reliability Standard clarify
that all applicable entities must make available data necessary for all
other responsible entities to perform the required assessment. Six
Cities also suggests that the transmission operator be added as an
entity to which this Reliability Standard is applicable, at least from
the perspective that it make necessary data available to all other
entities responsible for assessment. TAPS believes that this
Reliability Standard seems to assume that the LSE and distribution
provider actively participate in planning of new facilities in the
Bulk-Power System. TAPS states that very few LSEs or distribution
providers have the expertise to perform the tasks outlined in this
Reliability Standard and that these two entities provide only certain

data regarding certain new facilities to some or all of the other
entities identified in this Reliability Standard. TAPS therefore
believes that it would be unreasonable to require LSEs to provide the
transmission planning evaluations and assessments called for by R1.
California Cogeneration believes that the Reliability Standard implies
that generator owners will perform an independent assessment and if so,
it believes that such task is impossible, since generators do not have
the relevant information about the power system to perform such
evaluations. California Cogeneration believes that the Reliability
Standard should be clarified so that generator owners cooperate with
and provide input to the assessment performed by the transmission
operator and the balancing authority.
    687. FirstEnergy states that both MISO and PJM already have Large
Generator Interconnection Procedures (LGIP) in place that provide a
formal process that meets the requirements listed under R1, and asks
that the Commission state that complying with the interconnection
agreement and/or OATT satisfies this requirement. MISO states that
their procedures for coordinating plans for new generation,
transmission and end-user facilities includes modeling of normal system
and contingency conditions.
(b) Commission Determination
    688. All of the above commenters request clarification of
Requirement R1 in the Reliability Standard that states that various
functional entities ``shall each coordinate and cooperate on its
assessments with its transmission planner and planning authority.''
\259\ The Commission believes that all entities listed in the
Applicability section have a stake in the performance of the system and
should have the opportunity to provide input in the assessment under
R1. The Commission believes that commenters have raised valid concerns
that, if addressed, would make the Reliability Standard better. The
wording would allow a number of organizational approaches to achieving
the goal of performing an analysis. The Commission does not intend to
limit which organizational approach is used by the entities, only to
assure that a single competent and collaborative analysis is performed.
Therefore, the Commission directs the ERO to address these concerns in
the Reliability Standards development process.
---------------------------------------------------------------------------

    \259\ FAC-002-0.
---------------------------------------------------------------------------

    689. FirstEnergy asks the Commission to state that complying with
MISO's and PJM's interconnection agreements and/or OATT satisfies
requirement R1 under this Reliability Standard. We will not make that
determination here. If FirstEnergy believes that complying with the
MISO and PJM interconnection procedures meets the applicable
Reliability Standards, then it should follow those procedures, it
should not be concerned about violating the Reliability Standard.
ii. Standards of Conduct
(a) Comments
    690. Xcel and MidAmerican believe that the assessment required
under this Reliability Standard may conflict with the Commission's
Standards of Conduct \260\ since the assessment requires coordination
among several different functional groups within a vertically
integrated public utility. MidAmerican asserts that, since direct
communication between the generation and transmission entities would
result in more efficient overall planning, the Commission should
clarify its intended application of Standards of Conduct restrictions
on joint planning activities. Xcel asks the Commission to clarify that
actions taken to comply with this Reliability Standard will not result
in a transmission provider being in violation of the Standards of
Conduct.
---------------------------------------------------------------------------

    \260\ Standards of Conduct for Transmission Providers, Order No.
2004, FERC Stats. & Regs., Regulations Preambles ] 31,155 (2003),
order on reh'g, Order No. 2004-A, III FERC Stats. & Regs. ] 31,161
(2004), order on reh'g, Order No. 2004-B, III FERC Stats & Regs. ]
31,166 (2004).
---------------------------------------------------------------------------

(b) Commission Determination
    691. The Commission disagrees with MidAmerican and Xcel that this
Reliability Standard may conflict with the Standards of Conduct. This
type of system assessment is being performed today with the cooperation
of the entities listed in the Applicability section. Further, we note
that the Standards of Conduct were designed to address such
interactions. The entities participating in the assessment effort can
continue to contribute to this assessment and observe the Standards of
Conduct at the same time. If any entity finds an area where it believes
the Standards of Conduct prevent it from cooperating with the
assessment process, it may seek clarification from the Commission as to
whether that area of involvement is in conflict with the Standards of
Conduct.
iii. Reference to TPL Reliability Standards
(a) Comments
    692. While APPA and EEI agree with the Commission's proposal to
direct NERC to submit a modification to FAC-002-0 that amends
Requirement R1.4 to require evaluation of system performance under both
normal and contingency conditions by referencing TPL-001-0 through TPL-
003-0, Entergy disagrees and proposes that evaluation of system
performance under Reliability Standards TPL-001-0 and TPL-002-0 should
be sufficient. Entergy states that given the large number of small end-
user requests that transmission operators may receive, expanding the
scope of Requirement R1.4 may lead to additional work and documentation
that ultimately will not benefit reliability. First Entergy states that
the proposed reference to TPL Reliability Standards should be expanded
to include TPL-001-0 through TPL-004-0.
(b) Commission Determination
    693. The Commission notes that APPA and EEI agree with the
Commission's proposed directive to NERC to modify FAC-002-0 to require
evaluation of system performance under both normal and contingency
conditions by referencing TPL-001-0 through TPL-003-0. The Commission
also notes that NERC, in response to the Staff Preliminary Assessment,
has also agreed with the same proposal.\261\ These three TPL
Reliability Standards cover normal operation, first contingency
operation and multiple contingency operations respectively. The
Commission disagrees with Entergy that TPL-001-0 and TPL-002-0 are
sufficient because it is important to plan for new facilities taking
into account not only normal circumstances but also contingencies. In
addition, we note that including TPL-001-0 through TPL-003-0 will
result in the FAC-002 Reliability Standard being consistent with Order
No. 2003, which requires interconnecting entities to take into account
multiple contingencies in interconnection studies. With respect to
FirstEnergy's suggestion to also include a reference to Reliability
Standard TPL-004-0, we direct the ERO to consider it through the
Reliability Standards development process.
---------------------------------------------------------------------------

    \261\ NOPR at P 352.
---------------------------------------------------------------------------

    694. Accordingly, the Commission approves Reliability Standard FAC-
002-0 as mandatory and enforceable. In addition, pursuant to section
215(d)(5) of the FPA and Sec.  39.5(f) of our regulations, the
Commission directs the ERO to develop a modification to FAC-002-0
through the Reliability Standards development process that amends
Requirement R1.4 to require evaluation of system performance under both
normal and contingency conditions by referencing TPL-001 through TPL-
003.

Further, the Commission also directs the ERO to consider the above
commenters' concerns through the Reliability Standards development
process.
c. Transmission Vegetation Management Program (FAC-003-1)
    695. According to NERC, FAC-003-1 is designed to minimize
transmission outages from vegetation located on or near transmission
rights-of-way by maintaining safe clearances between transmission lines
and vegetation, and establishing a system for uniform reporting of
vegetation-related transmission outages. FAC-003-1 would apply to
transmission lines operated at 200 kV or higher voltage (and lower-
voltage transmission lines which have been deemed critical to
reliability by a regional reliability organization). It would require
each transmission owner to have a documented vegetation management
program in place, including records of its implementation. Each program
must be designed for the geographical area and specific design
configurations of the transmission owner's system.
    696. This Reliability Standard requires a transmission owner to
define a schedule for and the type (aerial or ground) of right-of-way
vegetation inspections. In addition, it requires a transmission owner
to determine and document the minimum allowable clearance between
energized conductors and vegetation before the next trimming, and it
specifically provides that ``Transmission-Owner-specific minimum
clearance distances shall be no less than those set forth in the IEEE
Standard 516-2003 (IEEE Guide for Maintenance Methods on Energized
Power Lines).'' \262\
---------------------------------------------------------------------------

    \262\ FAC-003-1 (Requirement R1.2.2).
---------------------------------------------------------------------------

    697. In the NOPR, the Commission proposed to approve Reliability
Standard FAC-003-1 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 proposed to direct NERC to submit a modification to FAC-
003-1 that: (1) Requires the ERO develop a minimum vegetation
inspection cycle that allows variation for physical differences and (2)
removes the general limitation on applicability to transmission lines
operated at 200 kV and above so that the Reliability Standard applies
to Bulk-Power System transmission lines that have an impact on
reliability as determined by the ERO.
i. Applicability
(a) Comments
    698. Entergy agrees with the Commission's proposal and supports
applying the Reliability Standard to only those lines that have an
impact on reliability as determined by the ERO, as supported by
reliability studies using consistent reliability contingency criteria.
    699. LPPC supports using an impact-based definition of the Bulk-
Power System to determine applicability and suggests that the
definition of significant adverse impact should be determined through
the NERC process. Further, LPPC asserts that actual facilities meeting
that criteria should be determined by Regional Entities, which best
understand the impacts of facilities on the regional system. LPPC notes
that Regional Entities can continue to use such tools as modeling and
power flow analyses to determine which facilities are critical to the
reliability of the Bulk-Power System.
    700. APPA and Avista believe that Regional Entities should
determine what transmission facilities this standard applies to, since
Regional Entities have detailed knowledge regarding the transmission
facilities within their regions. APPA would have the Regional Entities
create a regional Reliability Standard to do so, subject to ERO review
for reasonableness and consistency. Avista points out that WECC and the
other Regional Entities have already reviewed and designated critical
lower voltage transmission facilities, and the Reliability Standards
currently apply to such facilities.
    701. MISO asks for clarification with respect to the intent of
adding transmission lines below 200 kV ``that impact reliability'' and
whether the included lines are IROL-related facilities \263\ or some
other facilities. Progress and SERC suggest that it may be appropriate
to limit the applicability of the Reliability Standard to all lines
that are operated at 200 kV and above and to operationally significant
circuits between 100 kV and 200 kV that are elements of IROLs.
---------------------------------------------------------------------------

    \263\ An IROL-related facility is a facility whose outage would
result in an Interconnection Reliability Operating Limit (IROL)
violation.
---------------------------------------------------------------------------

    702. California PUC believes that discretion about determining
which lines are critical to the Bulk-Power System should be left to the
individual state (working in concert with RTOs and ISOs), which has
much greater knowledge of what is needed on the local level, rather
than to NERC or the Regional Reliability Organization.
    703. Progress, SERC, FirstEnergy and Avista argue that
automatically subjecting lines below 200 kV to Reliability Standard
FAC-003-1 would increase maintenance, documentation and reporting costs
and impacts to land owners, but would not necessarily increase the
reliability of the grid. LPPC does not object to eliminating the 200 kV
bright line threshold, but believes that extending vegetation
management practices to all facilities of 100 kV and above would
unnecessarily extend the scope of the vegetation management
requirements, creating large cost increases for many utilities without
creating a material increase in the reliability of the Bulk-Power
System. FirstEnergy recommends that if the voltage level is lowered,
implementation, especially for reporting requirements, should be spread
over at least one year. Similarly, Xcel asks the Commission to allow
flexibility in complying with this Reliability Standard for lower-
voltage facilities that previously were not subject to this Reliability
Standard.
    704. EEI maintains that not changing this Reliability Standard
would best maintain reliability, since removing the existing 200 kV
threshold requirement could inadvertently expose the Bulk-Power System
to a new set of risks. SoCal Edison argues that the Reliability
Standard already covers transmission lines rated less than 200 kV,
because Requirement 4.3 of FAC-003-1 states that this Reliability
Standard ``shall apply to all transmission lines operated at 200 kV and
above and to any lower voltage lines designated by the regional
reliability organization as critical to the reliability of the electric
system in the region.''
    705. APPA opposes the Commission's proposal to direct NERC to
change the applicability of this Reliability Standard. APPA argues that
the Commission should deal with this concern by having NERC reevaluate
the Reliability Standard. National Grid argues that expanding the
applicability of Reliability Standards would not be appropriate because
it could dramatically change the meaning of the Reliability Standards
and would undermine the Reliability Standard development process which
yielded the careful balances struck in developing the standards.
    706. NERC argues that the Commission's proposed modification should
be vetted through the Reliability Standards development process to
better understand what will be gained in terms of impacts to the
reliability of the Bulk-Power System. NERC notes that the current
applicability of the Reliability

Standard to 200 kV and above transmission lines was debated extensively
by the industry, and any change to this requirement should be vetted
again.
(b) Commission Determination
    707. We will not direct NERC to submit a modification to the
general limitation on applicability as proposed in the NOPR. However,
we will require the ERO to address the proposed modification through
its Reliability Standards development process. As explained in the
NOPR, the Commission is concerned that the bright-line applicability
threshold of 200 kV will exclude a significant number of transmission
lines that could impact Bulk-Power System reliability. Although the
regional reliability organizations are given discretion to designate
lower voltage lines under the proposed Reliability Standard, none have
designated any operationally significant lines even though there are
lower voltage lines involving IROL as suggested by Progress and SERC.
We continue to be concerned that this approach will not prospectively
result in the inclusion of all transmission lines that could impact
Bulk-Power System reliability. In proposing to require the ERO to
modify the Reliability Standard to apply to Bulk-Power System
transmission lines that have an impact on reliability as determined by
the ERO, we did not intend to make this Reliability Standard applicable
to fewer facilities than it currently is with the 200 kV bright line
applicability, but to extend the applicability to lower-voltage
facilities that have an impact on reliability. We support the
suggestions by Progress Energy, SERC and MISO to limit applicability to
lower voltage lines associated with IROL and these suggestions should
be part of the input to the Reliability Standards development process.
Similarly, the ERO should evaluate the suggestions proposed by LPPC,
APPA and Avista.
    708. California PUC suggests that states should have discretion
over what lines are critical to Bulk-Power System reliability. The
Commission has been given the responsibility to approve Reliability
Standards that assure the Reliable Operation of the Bulk-Power System,
including which facilities are covered by the Reliability Standards. We
cannot delegate that responsibility as proposed by California PUC.
Further, since many transmission facilities traverse multiple states,
we are concerned that this proposal could result in the Reliability
Standard applying to a section of a line in one state but not applying
to the same line in a neighboring state. Since a vegetation-related
outage affects all customers connected to that transmission line,
customers in both states could potentially have lower reliability as a
result of one state having a less stringent standard than another.
    709. Avista, LPPC, Progress and SERC raise concerns about the cost
of implementing this Reliability Standard if the applicability is
expanded to lower-voltage facilities. We recognize these concerns, and
this was one of the reasons we proposed to apply this Reliability
Standard to Bulk-Power System transmission lines that have an impact on
reliability as determined by the ERO. We recognize that many commenters
would like a more precise definition for the applicability of this
Reliability Standard, and we direct the ERO to develop an acceptable
definition that covers facilities that impact reliability but balances
extending the applicability of this standard against unreasonably
increasing the burden on transmission owners.
    710. FirstEnergy and Xcel suggest that if the applicability of this
Reliability Standard is expanded, the Commission should allow
flexibility in complying with this Reliability Standard for lower-
voltage facilities, or allow lower-voltage facilities one year before
the Reliability Standard is implemented. The ERO should consider these
comments when determining when it would request that the modification
of this Reliability Standard to go into effect.
    711. In response to EEI's concerns that removing the existing 200
kV threshold could expose the Bulk-Power System to a new set of risks,
we clarify that we are not immediately modifying this Reliability
Standard. Instead, it will go into effect as written and the ERO will
revise it through the Reliability Standards development process, with
the expectation that the applicability of this Reliability Standard
will expand to include additional facilities that impact reliability
that currently are not covered by this Reliability Standard. A
modification that reduces the applicability of this Reliability
Standard would not meet the Commission's directives. In response to
SoCal Edison's argument that the Reliability Standard already addresses
the Commission's concerns, the Commission agrees that while there
appears to be a mechanism for inclusion of additional lines, none have
been included. This lack of inclusion is in spite of the evidence that
some lower voltage lines can have significant impacts on the Bulk-Power
System, including IROLs and SOLs.
    712. In response to APPA, NRECA and NERC we agree that the proposed
modifications should be vetted through the Reliability Standards
development process. The Commission's goal is to promote the Reliable
Operation of the Bulk-Power System by including all of those entities
necessary to comply with this Reliability Standard. We believe that
requiring the Reliability Standard to include a greater number of
entities and exclude those that will not affect reliability will more
effectively sustain reliability than an overly exclusive list of
applicable entities.
ii. Inspection Cycles
    713. In the NOPR, the Commission proposed to direct NERC to submit
a modification to FAC-003-1 that requires the ERO to develop a minimum
vegetation inspection cycle that allows variation for physical
differences.
(a) Comments
    714. FirstEnergy states that a designation of a minimum annual
inspection cycle is appropriate and the method of inspection (aerial or
by ground) should be left to the transmission owner. Dominion cautions
that if there is a requirement for annual inspections, it should be
flexible and allow for different approaches to transmission line
inspections.
    715. APPA, Entergy, EEI, LPPC, Progress Energy, SERC and SoCal
Edison disagree with the Commission's proposal to require the ERO to
set minimum vegetation inspection cycles that allow for physical
differences. APPA, Entergy and LPPC say that, instead of proposing the
development of a Reliability Standard for minimum vegetation inspection
cycles, the Commission should permit the transmission system owner or
local utility to determine the inspection cycle best suited for its
system and adhere to that cycle, with compliance enforcement performed
by the Regional Entities and the ERO.
    716. Progress Energy and SERC believe that the Reliability Standard
as written provides flexibility regarding vegetation inspection cycles
and that the Commission should not impose requirements on the ERO to
develop minimum inspection intervals on a continent with such regional
diversity in climate and vegetation. In addition, Progress Energy
argues that, where a particular region is heavily forested and has
heavy rainfall along with extended or year round growing seasons, a
``back stop'' minimum inspection frequency could lead transmission
owners to conduct inspections less frequently than what the local
conditions require, which would lead to a lowest common denominator
Reliability Standard. This

could result in a transmission owner complying with the Reliability
Standard while not adequately protecting the reliability of that
region's transmission system.
    717. Progress Energy and SERC argue that, since the performance
metrics in FAC-003-1 require reporting of applicable transmission
interruptions caused by vegetation, the compliance process associated
with this Reliability Standard should appropriately identify
transmission owners' inspection cycles that are not adequate, and the
ERO can use its authority to remedy any vegetation-related outage that
is attributed to the transmission owner's inspection frequency.
    718. SoCal Edison states that transmission owners are already
obligated by Requirement R1.1 to establish a minimum vegetation
inspection schedule that allows adjustment for changing conditions.
SoCal Edison believes that the best measure of an effective
transmission vegetation management program is whether or not tree-to-
line contacts are occurring. SoCal Edison recommends the Commission
rescind the two proposed directives and order no further revisions to
FAC-003-1 until such time as Reliability Standard is deemed
unenforceable by the ERO or is not otherwise achieving its stated
goals.
    719. APPA and Progress Energy state that a minimum vegetation
inspection cycle could result in an undue financial burden for some
regions of the country, because they would be forced into a minimum
cycle that might be inappropriate for their own region. For example,
Progress Energy states that, where a particular region is arid,
sparsely forested or has a minimum growing season, a ``back stop''
minimum could require a more frequent interval than is realistically
needed. This would result in increased and unnecessary costs to the
transmission owner and its customers without providing a comparable
increase in reliability. EEI believes that a minimum inspection cycle
will add nothing to the strength of the existing practices and could
add a requirement that is not merited by actual circumstances in many
locations.
(b) Commission Determination
    720. The Commission is concerned about minimizing outages and
supports a realistic inspection cycle. In the NOPR, the Commission
proposed a minimum inspection cycle that takes account of physical
differences as one way to address this concern. However, we recognize
that there may be other options to achieve the same reliability goal.
For example, the ERO could determine whether a prepared company-
tailored inspection cycle is appropriate given the physical and
geographic factors and, through audits, inspect individual vegetation
management programs for compliance.
    721. While the Commission disagrees that incorporating a backstop
would lead to a lowest common denominator Reliability Standard, the
Commission is dissuaded from requiring the ERO to create a backstop
inspection cycle at this time. Instead, the Commission agrees that an
entity's vegetation management program should be tailored to
anticipated growth in the region and take into account other
environmental factors. The goal is to assure that transmission owners
conduct inspections at reasonable intervals. In the Commission's
Vegetation Management Report, we found that many entities performed
aerial or ground inspections less than every three years or even ``as
needed.'' \264\
---------------------------------------------------------------------------

    \264\ Utility Vegetation Management and Bulk Electric
Reliability Report at 10-11, available at http://www.ferc.gov/industries/electric/indus-act/reliability/2004.asp
 (Vegetation

Management Report).
---------------------------------------------------------------------------

    722. The Commission continues to be concerned with leaving complete
discretion to the transmission owners in determining inspection cycles,
which limits the effectiveness of the Reliability Standard.
Accordingly, the Commission directs the ERO to develop compliance audit
procedures, using relevant industry experts, which would identify
appropriate inspection cycles based on local factors. These inspection
cycles are to be used in compliance auditing of FAC-003-1 by the ERO or
Regional Entity to ensure such inspection cycles and vegetation
management requirements are properly met by the responsible entities.
iii. Minimum Clearances on National Forest Service Lands
    723. In the NOPR, the Commission did not propose to modify the
ERO's general approach with respect to clearances. However, the
Commission expressed its belief that any potential issues regarding
minimum clearances on National Forest Service (Forest Service) lands
should be dealt with on a case-by-case basis. The Commission requested
comments on whether another approach would be more appropriate to
address this issue.
(a) Comments
    724. APPA believes that a case-by-case approach may have to be
employed, since Forest Service lands are located all across the country
and have different regional characteristics. APPA notes that U.S. Fish
and Wildlife Service personnel have begun to take action regarding
vegetation management on non-federal lands, and reports that APPA
members have been told by U.S. Fish and Wildlife personnel to refrain
from cutting vegetation at certain times of the year in the absence of
an imminent reliability threat. APPA concludes that this information
conflicts with specifying minimum nationwide vegetation inspection/
cutting cycles and clearances. In addition, APPA requests clarification
of the Commission interpretation ``we interpret the FAC-003-1 to
require trimming that is sufficient to prevent outages due to
vegetation management practices under all applicable conditions.''
    725. Several commenters express concern about the Commission's
position that any potential issues regarding minimum clearances on
National Forest Service lands should be dealt with on a case-by-case
basis.\265\ EEI, Progress Energy and SERC believe that this approach is
inconsistent with the Reliability Standard's intent to use consistent
approaches in setting minimum vegetation clearance distances on both
private and public lands and the Commission's statement that this
Reliability Standard requires minimum clearances that are ``sufficient
to prevent outages due to vegetation management practices under all
applicable conditions.'' \266\ Therefore, International Transmission,
EEI, LPPC, Progress Energy and SERC assert that Reliability Standard
FAC-003-1 should be applicable to all responsible entities including
those with transmission on both private and public lands because
consistency is the only way to provide a uniform and reliable
electrical system. Dominion suggests the Commission defer to NERC and
the stakeholder process to develop specifications for clearances.
---------------------------------------------------------------------------

    \265\ See, e.g., EEI, Energy, International Transmission,
Progress Energy, SERC, LPPC and MISO.
    \266\ The NOPR states that ``Accordingly, we interpret the FAC-
003-1 to require trimming that is sufficient to prevent outages due
to vegetation management practices under all applicable conditions*
* *'' NOPR at P 380.
---------------------------------------------------------------------------

    726. Progress Energy and SERC note that EEI and certain federal
agencies \267\ have jointly addressed the issue of consistency in
vegetation management work on federal lands, and developed a memorandum
of understanding (Vegetation MOU) which sets the framework for managing
vegetation on transmission line rights-of-way under

Federal agency jurisdiction.\268\ Progress Energy and SERC recommend
using the EEI's Vegetation MOU framework for managing vegetation on
transmission line rights-of-way under federal agency jurisdiction
rather than the case-by-case approach proposed in the NOPR. LPPC
recommends creating a bright-line when it comes to utilities'
obligations (and rights) for trimming vegetation located on Forest
Service lands. Avista and Portland General ask that the Vegetation MOU
be affirmed by the Commission and permitted to govern transmission line
rights-of-ways located on lands managed by federal land management
agencies.
---------------------------------------------------------------------------

    \267\ Forest Service, Bureau of Land Management, Fish & Wildlife
Service, National Park Service, and U.S. Environmental Protection
Agency.
    \268\ The Vegetation MOU is available at http://www.eei.org/industry_issues/environment/land/vegetation_management/EEI_MOU_FINAL_5-25-06.pdf
.

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

    727. SoCal Edison believes that transmission owners should be
allowed the latitude to establish measures/procedures for less rigid
tree-to-line clearances in response to state and federal agency demands
or requests but is concerned that these measures/procedures will prove
to be of little or no value in the event of an ERO investigation into a
tree-to-line contact occurring within national/state forestry
boundaries or on private property.
    728. California PUC points out that California already has
requirements applicable to minimum vegetation clearance, and that the
Commission must take care to assure that any mandatory Reliability
Standard does not preempt the ability of California (and other states
with similar state standards) to impose stricter requirements that have
no adverse impacts on reliability.
    729. FirstEnergy states that the standard should define rights-of-
way to encompass the required clearance area instead of the
corresponding legal land rights. Some rights-of-way may be larger to
accommodate future needs and therefore may exceed clearances needed for
existing lines. FirstEnergy believes that Reliability Standards should
not require clearing entire rights-of-way when the required clearance
for existing lines does not take up the entire right-of-way.
(b) Commission Determination
    730. As proposed in the NOPR, the Commission approves Reliability
Standard FAC-003-1 with no proposed modification on the issue of
clearances. The Commission reaffirms its interpretation that FAC-003-1
requires sufficient clearances to prevent outages due to vegetation
management practices under all applicable conditions. As to APPA's
requests for clarification concerning the term ``under all applicable
conditions,'' the Reliability Standard already addresses this issue in
Requirement R3.2 by allowing for exceptions for natural disasters
(including wind shears and major storms) that cause vegetation to fall
into the transmission lines from outside the ROW. The Commission
therefore finds that no clarification is required in response to APPA.
    731. The Commission agrees that ownership of the land does not
change the impact of a vegetation-related outage on the Bulk-Power
System. However, the present Reliability Standard leaves the
determination and documentation of ``clearance 1'' to transmission
owners. As such, there are no specific clearances, or criteria/
procedures to develop clearances, before the Commission for approval.
What is in front of the Commission relative to ``locations on the
right-of-way where the Transmission Owner is restricted from attaining
the clearances specified in Requirement R1.2.1'' is addressed in
Requirement R1.4. Requirement R1.4 states that ``Each Transmission
Owner shall develop mitigation measures to achieve sufficient
clearances for the protection of the transmission facilities when it
identifies locations on the right-of-way where the Transmission Owner
is restricted from attaining the clearances specified in Requirement
R1.2.1.'' This Requirement addresses the instances when an entity
cannot attain the clearances that it needs on land that it controls.
Since there are multiple mitigation measures that the entity can employ
to achieve the goal of preventing outages due to vegetation management
practices, the Commission has stated that any potential issues
regarding minimum clearances on Forest Service lands should be dealt
with on a case-by-case basis.
    732. Avista and Portland General ask the Commission to endorse the
Vegetation MOU. The Commission reiterates its direction that the
minimum clearances must be sufficient to avoid any sustained
vegetation-related outages for all applicable conditions. The
Vegetation MOU references IEEE 516 as the only way to determine
applicable minimum clearances. The Commission declines to endorse the
use of IEEE 516 as the only minimum clearance because it is intended
for use as a guide by highly-trained maintenance personnel to carry out
live-line work using specialized tools under controlled environments
and operating conditions, not for those conditions necessary to safely
carry out vegetation management practices.\269\ Further, the allowable
clearances in the IEEE standard are significantly lower than those
specified by the relevant U.S. safety codes. As such, use of IEEE
clearance provision as a basis for minimum clearance prior to the next
tree trimming as a Requirement in vegetation management is not
appropriate for safety and reliability reasons. For example, the IEEE
Standard 516-2003 specifies a 2.45-foot clearance from a live conductor
for the 120 kV voltage class,\270\ whereas the ANSI Z-133 standard
specifies 12 feet, 4 inches as the approach distance for the 115 kV
voltage class.\271\
---------------------------------------------------------------------------

    \269\ Controlled environments and operating conditions include
clear days without precipitation, high winds or lightning.
    \270\ Institute of Electrical and Electronics Engineers, Inc.
(IEEE) Standard 516-2003, IEEE Guide for Maintenance Methods at 20.
    \271\ ANSI Z133, American National Standards Institute Standard
for Tree Care Operations--Pruning, Trimming, Repairing, Maintaining
and Removing Trees, and Cutting Brush--Safety Requirements.
---------------------------------------------------------------------------

    733. Accordingly, the Commission directs the ERO to develop a
Reliability Standard that defines the minimum clearance needed to avoid
sustained vegetation-related outages that would apply to transmission
lines crossing both federal land and non-federal land. While this
consensus is developed, the Commission directs the ERO to address any
potential issues regarding mitigation measures needed to assure these
minimum clearances on Forest Service lands are appropriate on a case-
by-case basis. The Commission also directs the ERO to collect outage
data for transmission outages of lines that cross both federal and non-
federal lands, analyze it, and use the results of this analysis and
information to develop a Reliability Standard that would apply to
transmission lines crossing both federal and non-federal land.
    734. In regard to California PUC's concern about its ability to
impose stricter requirements on vegetation clearances, the Commission
notes that section 215(i)(3) of the FPA states that nothing in section
215 shall be construed to preempt the authority of a state to take
action to ensure the reliability of electric service within that state,
as long as the action is not inconsistent with any Reliability
Standard. Therefore, the State of California may set its own vegetation
management requirements that are stricter than those set by the
Commission as long as they do not conflict with those set by the
Commission. Further, the Commission notes that once a Reliability
Standard is established, California PUC can develop stricter rules to
be applied within the

state of California, and if it wants them to be enforceable under
section 215 of the FPA, could submit those Reliability Standards to the
ERO and the Commission for approval as a regional difference.
    735. FirstEnergy suggests that rights-of-way be defined to
encompass the required clearance areas instead of the corresponding
legal rights, and that the standards should not require clearing the
entire right-of-way when the required clearance for an existing line
does not take up the entire right-of-way. The Commission believes this
suggestion is reasonable and should be addressed by the ERO.
Accordingly, the Commission directs the ERO to address this suggestion
in the Reliability Standards development process.
iv. Summary of Commission Determinations
    736. The Commission approves FAC-003-1 as mandatory as enforceable.
In addition, while we do not direct the ERO to submit a modification to
the general limitation on applicability as proposed in the NOPR, we
require the ERO to address the proposed modification through its
Reliability Standards development process as discussed above. Further,
while the Commission is dissuaded from requiring the ERO to create a
backstop inspection cycle at this time, it directs the ERO to develop
compliance audit procedures to identify appropriate inspection cycles
based on local factors. These inspection cycles are to be used in
compliance auditing of FAC-003-1 by the ERO or Regional Entity to
ensure such inspection cycles and vegetation management requirements
are properly met by the responsible entities. Finally, the Commission
directs the ERO to develop a Reliability Standard through the
Reliability Standard development process that defines the minimum
clearance needed to avoid sustained vegetation-related outages that
would apply to transmission lines crossing both federal land and non-
federal land. While this consensus is developed, the Commission directs
the ERO to address any potential issues regarding mitigation measures
needed to assure these minimum clearances on Forest Service lands are
appropriate on a case-by-case basis. The Commission also directs the
ERO to collect outage data for transmission outages of lines that cross
both federal and non-federal lands, analyze it, and use the results of
this analysis and information to develop a Reliability Standard that
would apply to transmission lines crossing both federal and non-federal
land.
d. Facility Ratings Methodology (FAC-008-1)
    737. FAC-008-1 requires each transmission owner and generation
owner to develop a facility rating methodology for its facilities,
which should consider manufacturing data, design criteria (such as
IEEE, ANSI or other industry methods), ambient conditions, operating
limitations and other assumptions. This methodology is to be made
available to reliability coordinators, transmission operators,
transmission planners and planning authorities who have responsibility
in the same areas where the facilities are located for inspection and
technical reviews.
    738. In the NOPR, the Commission proposed to approve Reliability
Standard FAC-008-1 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 proposed to direct NERC to develop a modification to
FAC-008-1 through the Reliability Standards development process that
requires transmission and generation facility owners to: (1) Document
underlying assumptions and methods used to determine normal and
emergency facility ratings; (2) develop facility ratings consistent
with industry standards developed through an open process such as IEEE
or CIGRE and (3) identify the limiting component(s) and define the
increase in rating based on the next limiting component(s) for all
critical facilities.
i. Methodology Used To Determine Facility Ratings and Documentation of
Underlying Assumptions
(a) Comments
    739. EEI, Valley Group, MidAmerican and TANC support the
Commission's proposal to require additional documentation as a
reasonable means to provide more transparency and consistency. EEI
suggests that this requirement could be accommodated with a provision
for the disclosure of such information upon request by a registered
user, owner or operator. TANC supports the Commission's proposal to not
require a uniform facility rating methodology and recommends that the
Commission adopt a policy that provides for each transmission owner and
generation owner to develop and document a facility rating methodology,
which is consistent with industry methodologies, for their facilities.
TANC also states that the methodology used for developing facility
ratings should include a description of and justification for all of
the assumptions. Valley Group states that it is extremely important
that the underlying assumptions and methods are documented and known to
all parties. Valley Group maintains that this will also ensure that the
rating assumptions used by operating and planning functions are
consistent with each other. Valley Group emphasizes that making these
assumptions open is important, especially regarding paths between
different transmission owners, to ensure that transmission owners
cannot exercise market power. It argues that open assumptions will also
provide rational grounds for dispute resolution.
(b) Commission Determination
    740. As EEI, TANC, Valley Group and MidAmerican discuss in their
comments, the Commission's proposal to modify FAC-008-1 to require
additional documentation supports the Commission's goals of improving
uniformity and transparency in the facility ratings process. EEI's
suggestion that having this information available for review upon
request of a registered user, owner or operator should be considered by
the ERO in its Reliability Standards development process. As proposed
in the NOPR, the Commission directs the ERO to submit a modification to
FAC-008-1 that requires transmission and generation facility owners to
document underlying assumptions and methods used to determine normal
and emergency facility ratings. As stated in the NOPR, the Commission
believes that this added transparency will allow customers, regulators
and other affected users, owners and operators of the Bulk-Power System
to understand how facility owners set facility ratings through
differing methods that provide equivalent results.
ii. Rating Facilities Consistent with Industry Standards Developed
Through an Open Process such as IEEE and CIGRE
(a) Comments
    741. The Valley Group states that the Commission correctly
identifies IEEE and CIGRE as examples of open process methodologies
suitable for overhead transmission line ratings calculations. It claims
that IEEE and CIGRE are the only methodologies which make their
algorithms available to everybody, and clearly document their
assumptions. Valley Group notes that both of these methodologies will
undergo a revision for accuracy regarding calculations for high
temperatures and high current densities in the next two years, which
may lead in some cases to slightly lower

line ratings, although the changes are not expected to be substantial.
    742. APPA suggests that the proposal to rate facilities consistent
with industry methodologies developed through an open process such as
IEEE and CIGRE should be considered in the ERO's Reliability Standards
development process rather than ordered by the Commission. LPPC asks
the Commission to require only that facility ratings be consistent with
good utility practice. According to LPPC, to the extent facility rating
methodologies need to be more prescriptive than good utility practice,
the details must be spelled out in the ERO Reliability Standards
themselves, not by reference to other unspecified industry
methodologies. LPPC believes that it would be poor policy for the
Commission to endorse these methodologies since it would be impossible
to police the processes by which such organizations develop their
methodologies. MidAmerican states that the Commission should recognize
that the proposal to require facility ratings be consistent with
industry methodologies developed through an open process is potentially
problematic, noting that certain aspects of the development of facility
ratings are based on industry standards that are not developed through
an open process, such as information provided by engineering textbooks
or manufacturer information that is not specifically referenced in any
current standard. MidAmerican recommends that the Commission delete the
requirement that facility ratings be ``developed through an open
process such as IEEE or CIGRE'' or add other sources that the
Commission would find appropriate, such as the results of accepted
scientific and engineering investigations and common sense. MRO
requests that the Commission clarify whether its directive to modify
FAC-008-1 to develop facility ratings consistent with industry
standards developed through an open process such as IEEE or CIGRE would
allow for legitimate regional differences such as climate, terrain or
population density.
(b) Commission Determination
    743. In the NOPR, the Commission stated, ``While not proposing to
mandate a particular methodology, we do propose that the methodology
chosen by a facility owner be consistent with industry standards
developed through an open process such as IEEE or CIGRE.'' \272\ These
processes have been validated through actual testing and have been
shown to provide appropriate results. Information from engineering
textbooks, common sense or manufacturer information would be part of
the underlying assumptions. The Commission's intent in the NOPR was to
require that FAC-008-1 be modified to require that facility ratings be
developed consistent with industry standards developed through an open,
transparent and validated process. The Commission agrees with Valley
Group that IEEE and CIGRE are two examples of such processes and
disagrees with LPPC that reference to industry standards is poor
policy. Industry standards that have been verified by actual testing
are appropriate. However, the Commission agrees with MidAmerican that
IEEE and CIGRE are just two examples of such bodies; any other open
process that has been technically validated for its provision of
accurate, consistent ratings is also acceptable. The ERO should
consider the concerns raised by LPPC and MRO in its Reliability
Standards development process, and is hereby directed to do so. The
Commission does not expect there to be any regional differences because
the only differences should be from different underlying assumptions
that are not defined by the Reliability Standard.
---------------------------------------------------------------------------

    \272\ NOPR at P 404.
---------------------------------------------------------------------------

iii. Identify the Limiting Component(s) and Define for All Critical
Facilities the Rating Based on the Next Limiting Component Within the
Same Facility
(a) Comments
    744. TANC maintains that the rating information provided by the
transmission owners and generator owners should include additional
information about all of the limiting components of the elements (e.g.,
transmission lines, transformers, etc.) for all critical facilities.
Access to such information will enable neighboring systems to
accurately study the effects of other facilities on their own systems
and determine the critical elements for increasing facility ratings.
    745. Valley Group states that identifying the limiting elements is
an excellent objective for reliability enhancement, but notes that its
granularity must be limited to major elements of the circuits, such as
transformers and breakers, while treating the transmission lines as
single elements. Valley Group also notes that, of the two examples
discussed in the NOPR, the example regarding relay settings is
technically well justified, whereas rating the line based on a single
limiting span is generally impractical because line design engineers
add to the National Electric Safety Code minimum requirements ``safety
buffers,'' which vary depending on their confidence in the accuracy of
design calculations.
    746. APPA is concerned about the possible ``unintended
consequences'' of this modification and questions whether this proposed
Requirement can be done as a practical matter; how many critical
facilities and limiting components would have to be modeled to meet
such a Requirement; and whether the cost of such modeling is justified
by the reliability benefits. Dynegy, MISO and Wisconsin Electric also
oppose this requirement because it is ambiguous, the additional work
required to identify the increase in rating based on the next limiting
component(s) is unwarranted and potentially costly, and the need for
any such specific information is questionable. Dynegy and Wisconsin
Electric do not believe there is a widespread need for this type of
information and recommend that the need for it be explored on a case-
by-case basis rather than including a global requirement in the
standards.
    747. Dynegy, FirstEnergy and MISO state that it is not clear what
specific criteria would be used to define ``critical facilities'' and
``limits.'' EEI also states that developing a practical definition of
``critical facilities'' presents a challenge, and that compliance would
require the analysis of possibly hundreds of thousands of ``limiting''
transmission elements to determine whether a limit is of primary
concern or is contingent on the status of other nearby elements or
system conditions at a particular time. EEI suggests that, rather than
requesting that the industry develop a definition, it may be more
useful for the Commission to recommend that the industry develop a set
of high-level criteria that could be used to identify those
transmission elements that create significant potential limits that are
independent of other factors and considerations.
    748. EEI and TVA assert this recommendation does not seem to be
intended to enhance reliability but to provide additional commercial
information to the market, and may not be appropriate to include in a
Reliability Standard. Portland General further points out that this
information can be obtained from a transmission provider by submitting
a transmission or interconnection request when ATC is not posted or not
available. TVA comments that, since the focus of this proceeding is the
Reliable Operation of the Bulk-Power System, changes to a proposed
Reliability Standard, such as FAC-008-1, that appear designed to
promote maximum commercial use of the grid are unwarranted in this

proceeding and could jeopardize, rather than further, reliable
transmission system operations.
    749. MRO seeks clarification about whether the proposed
modification will require that all limiting facilities elements be
published. MRO believes that serious confidentiality issues are raised
due to the security-sensitive nature of the information and urges the
Commission not to require the publication of such information.
    750. Dominion states that the Commission should exclude from this
requirement facilities that are covered under an open, regional
transmission expansion planning process, such as the Regional
Transmission Expansion Plan process in PJM, where any interested party
can be involved in the studies and determine what the limitations are
and what could be done to increase transmission capacity.
    751. International Transmission states that, if the Commission were
to require defining the increase in facility rating based on the next
limiting element, it should restrict such application to transmission
elements where the conductor itself is not the limiting element.
International Transmission explains that in cases where the line must
be completely rebuilt, it would not be feasible to estimate the
increase in facility rating, since the new line could be specified to
carry virtually any amount of power.
    752. MISO questions how a generator operator or generation owner
would identify the increase in rating based on the next most limiting
component(s) associated with generator output. FirstEnergy believes
that this modification should recognize that generators may need to
rely on transmission owners to point out facilities that are more
limiting than the generator facilities.
    753. Manitoba's technical experts disagree with the Preliminary
Staff Assessment regarding FAC-008-1. The Reliability Standard properly
places the responsibility of determining facility ratings with the
facility owners. Manitoba also states that, since this Reliability
Standard requires that the ``Facility Rating shall be equal to the most
limiting applicable Equipment Rating of the individual equipment that
comprises that Facility,'' information on the next limiting component
is already identified. Contrary to the Commission's view, Manitoba does
not believe it would be appropriate in this Reliability Standard to
identify the increase in rating for all critical facilities based on
the next limiting component. In a networked system, there may be other
limitations that set the current carrying capability of the critical
facility.
    754. Manitoba further notes that the Commission proposal may lead
to international conflicts in Reliability Standards. Manitoba states
that a mandated change to FAC-008-1, which forces an entity to accept
facility ratings beyond its risk tolerance, would be grounds for
Manitoba to recommend that the provincial government of Manitoba not
approve this Reliability Standard because it would degrade reliability.
    755. APPA suggests that the proposal to identify the limiting
component and define for all critical facilities the rating based on
the next limiting component be considered in the ERO's Reliability
Standards development process rather than ordered by the Commission.
(b) Commission Determination
    756. The Commission agrees with TANC that this modification would
provide useful information to neighboring systems and users, owners and
operators of the Bulk-Power System. The Commission also agrees with
Valley Group that identifying the limiting elements of facilities
enhances reliability by providing operators specific information about
the limiting elements and therefore allowing them to assess the risks
associated with circuit loadings.
    757. In response to the comments of APPA, Dynegy, EEI, MISO and
Wisconsin Electric, the Commission clarifies that this Reliability
Standard and the Commission's proposed modification apply to
facilities. As defined in the NERC glossary, a facility is ``a set of
electrical equipment that operates as a single Bulk Electric System
Element \273\ (e.g., a line, a generator, a shunt compensator,
transformer, etc.).'' The most limiting component in a facility
determines its rating, just like the rating of a chain is determined by
the weakest link. The Commission's proposed modification would require
identifying and documenting the limiting component for all facilities
and the increase in rating if that component were no longer the most
limiting component; in other words, the rating based on the second-most
limiting component. The Commission further clarifies that this
Reliability Standard will require this additional thermal rating
information only for those facilities for which thermal ratings cause
the following: (1) An IROL; (2) a limitation of TTC; (3) an impediment
to generation deliverability or (4) an impediment to service to major
cities or load pockets.
---------------------------------------------------------------------------

    \273\ An element is made up of one or more components.
---------------------------------------------------------------------------

    758. EEI and TVA raise concerns that this modification promotes
commercial use of the grid rather than ensuring Reliable Operation of
the Bulk-Power System, and relates more to transmission access than
reliable operations. The Commission disagrees that this modification
relates primarily to transmission access. When the transmission
operators know which component within the transmission element is
limiting they have more information to inform their decisions about how
to provide for the Reliable Operation of the Bulk-Power System. Our
proposed modification does not require any entity to invest in
equipment to increase ratings of any facility; it simply requires the
next limiting component of each facility to be identified in order to
understand what components are causing the limits that are to be used
in reliability mitigation assessments. The identification of the first
limiting component is already an inherent requirement in the existing
rating process. As clarified above, the modification to identify an
increase in rating of the transmission element that would result from
removing the first limitating component applies only to critical
facilities whose thermal ratings have been reached causing an SOL or
IROL condition. As Dominion highlights in its comments, this
information is already identified in the planning processes of some
RTOs and ISOs.
    759. In response to the concerns raised by EEI and MRO about
sharing confidential, market-sensitive information, the Commission
disagrees that ratings information is confidential or market-sensitive.
All users, owners and operators should have access to the facility
ratings in order to operate the system reliably. Section 215(a)(4) of
the FPA defines Reliable Operation, in part, as operating the elements
of the Bulk-Power System within equipment and electric system thermal
stability limits.\274\ Without knowing the ratings, it is not possible
to know whether this requirement is being met. As to the argument that
this information is confidential, the Commission clarifies that, as
with the other information required by this Reliability Standard, the
additional information required by this modification would be shared
only with users, owners and operators of the Bulk-Power System.
---------------------------------------------------------------------------

    \274\ 16 U.S.C. 824o(a)(4).
---------------------------------------------------------------------------

    760. In response to Dominion's comments, if the PJM Regional
Transmission Expansion Planning process meets the criteria, there is no

need to exclude facilities covered by that process from this
requirement.
    761. The Commission directs the ERO to consider International
Transmission's comments regarding requiring information about the
increase in facility rating based on the next limiting element only for
lines where the conductor itself is not the limiting element in its
Reliability Standards development process. Similarly, the ERO should
also consider the comments from MISO and FirstEnergy that generators
will have difficulty determining the increase in ratings due to the
next limiting element, since in most cases the generator itself would
be the most limiting element.
    762. We agree with Manitoba that this Reliability Standard properly
places the responsibility to determine facility ratings on the facility
owner. The Commission is not proposing to change this. We also agree
with Manitoba that the most limiting component is already identified
when facility ratings are determined. The Commission is only directing
transmission and generation owners to provide additional information on
the next limiting component within the facility so that facility
ratings are more transparent.
    763. In response to Manitoba's and APPA's concerns, we recognize
that this is an additional requirement with some complexities, and this
modification will go through the ERO Reliability Standards development
process. We do not intend to usurp the Reliability Standards
development process, where Manitoba may raise its concerns for the ERO
to consider.
iv. Applicability to Generator Owners
(a) Comments
    764. Xcel states that this Reliability Standard should not apply to
generator owners because capability testing, rather than using
mathematical calculations, is the preferred method of determining
generating unit capability. Capability testing clearly includes the
capability of all the supporting components behind the generator that
are required to produce a MW of capability. Xcel also states that this
proposed Reliability Standard, if applied to generating units, would
not improve system reliability and could result in conflicting and
confusing unit capability ratings. Xcel notes that generating units
already are required to be capability-tested on a periodic and seasonal
basis to demonstrate unit gross and net capability in accordance with
proposed standards MOD-024-1 and MOD-025-1.
    765. FirstEnergy also points out that facility ratings for nuclear
units are part of NRC license agreements and that the ratings
methodologies included in NRC license agreements are approved by NRC.
FirstEnergy proposes that compliance with NRC ratings methodology
requirements should be assumed to comply with this Reliability
Standard.
(b) Commission Determination
    766. The Commission agrees with Xcel that an actual test could be
used as a substitute for a mathematical calculation of capability, and
we ask the ERO to consider these comments in its Reliability Standards
development process. The Commission understands that NRC provides
ratings methodologies for nuclear power plants and not for the
transmission system. Capacity ratings of nuclear generators determined
using this methodology are acceptable for reliability purposes. We also
direct the ERO to consider FirstEnergy's comments in its Reliability
Standards development process.
 v. Compliance With Blackout Report Recommendation No. 27
(a) Comments
    767. Manitoba believes this Reliability Standard meets the
requirement of Blackout Report Recommendation No. 27 because the
recommendation does not require a uniform set of methodologies for
rating facilities, but instead only recommends that there be a clear,
unambiguous requirement to rate transmission lines.
    768. Valley Group notes that, while the Commission's proposal would
direct the ERO to respond to a part of Blackout Report Recommendation
No. 27, it does not address the important second part of the
Recommendation, namely dynamic ratings. Valley Group notes that dynamic
ratings offer a very powerful tool both for maximizing the capabilities
of transmission paths and for avoiding unnecessary transmission line
loading relief. Valley Group also notes that dynamic ratings, based
either on ambient-adjusted ratings or ratings generated by real-time
monitoring systems, are widely used in the PJM system, while broader
real-time ratings are applied on certain lines in SPP and ERCOT and at
several individual utilities. Valley Group states that controlling
unnecessary operator interventions with dynamic ratings both increases
the reliability of Bulk-Power System and improves its economy. Valley
Group concludes that it would be highly desirable for the ERO to
establish policies and procedures regarding dynamic ratings--as
recommended by the Blackout Report, and recommends that the Commission
include such guidance in its Final Rule.
(b) Commission Determination
    769. The Commission believes that implementation of the
modifications discussed earlier to Reliability Standard FAC-008-1 meets
our goal of implementing Blackout Report Recommendation No. 27, which
is to ``develop enforceable standards for transmission line ratings.''
\275\ To achieve a clear and unambiguous Requirement to rate
transmission lines, it is important to understand the underlying
assumptions and the methodologies that will be used to develop those
ratings. The Commission recognizes that dynamic line ratings are an
innovative application, and directs the ERO to consider the comments
from Valley Group in future revisions of this Reliability Standard.
---------------------------------------------------------------------------

    \275\ Blackout Report at 162.
---------------------------------------------------------------------------

vi. General Comments
    770. APPA notes that FAC-008-1 should be revised to replace Levels
of Non-Compliance with Violation Security Levels, and to include
Violation Risk Factors on all FAC-008-1 requirements.
(a) Commission Determination
    771. The Commission acknowledges that the Reliability Standards are
changing. In this Final Rule, we are ruling on the Reliability
Standards as they were filed, and these documents use the term Levels
of Non-Compliance. The ERO should address APPA's comments in its
Reliability Standards development process.
vii. Summary of Commission Determination
    772. Accordingly, as discussed in the responses to comments above,
the Commission approves FAC-008-1 as mandatory and enforceable. In
addition, we direct the ERO to develop modifications to FAC-008-1
through its Reliability Standards development process requiring
transmission and generation facility owners to: (1) Document underlying
assumptions and methods used to determine normal and emergency facility
ratings; (2) develop facility ratings consistent with industry
standards developed through an open, transparent and validated process
and (3) for each facility, identify the limiting component and, for
critical facilities, the resulting increase in rating if that component
is no longer limiting.

e. Establish and Communicate Facility Ratings (FAC-009-1)
    773. FAC-009-1 requires each transmission owner and generation
owner to establish facility ratings consistent with its associated
facility ratings methodology and provide those ratings to its
reliability coordinator, transmission operator, transmission planner
and planning authority. In the NOPR, the Commission proposed to approve
FAC-009-1 as mandatory and enforceable.
i. Comments
    774. APPA supports approval of FAC-009-1 as a mandatory and
enforceable Reliability Standard.
ii. Commission Determination
    775. FAC-009-1 serves an important reliability purpose of ensuring
that facility ratings are determined based on an established
methodology. Further, the proposed Requirements set forth in FAC-009-1
are sufficiently clear and objective to provide guidance for
compliance. Accordingly, the Commission approves Reliability Standard
FAC-009-1 as mandatory and enforceable.
f. Transfer Capability Methodology (FAC-012-1)
    776. Proposed Reliability Standard FAC-012-1 requires each
reliability coordinator and planning authority to document the
methodology used to develop its inter-regional and intra-regional
transfer capabilities. This methodology must describe how it addresses
transmission topology, system demand, generation dispatch and use of
projected and existing commitment of transmission.
    777. In the NOPR, the Commission explained that, because the
methodology to calculate transfer capability used by a reliability
coordinator or planning authority has not been submitted to the
Commission, it is not possible to determine at this time whether FAC-
012-1 satisfies the statutory requirement that a proposed Reliability
Standard be just, reasonable, not unduly discriminatory or
preferential, and in the public interest. Thus, the NOPR did not
propose to approve or remand this Reliability Standard until the
regional procedures are submitted.
    778. The NOPR explained that FAC-012-1 only requires that the
regional reliability organization provide documentation on transfer
capability methodology and provide it to entities such as the relevant
transmission planner, planning authority, reliability coordinator and
transmission operator. The Reliability Standard does not contain clear
requirements on how transfer capability should be calculated, which has
resulted in diverse interpretations of transfer capability and the
development of various calculation methodologies. The NOPR suggested
that FAC-012-1 should, as a minimum, provide a framework for the
transfer capability calculation methodology including data inputs and
modeling assumptions. In addition, the NOPR asked for comments on the
most efficient way to make the above information transparent for all
participants.
i. Methodology
(a) Comments
    779. APPA, International Transmission and MidAmerican agree that
the proposed FAC-012-1 is not sufficient and should not be accepted for
approval as a mandatory Reliability Standard. They suggest that, at a
minimum, this Reliability Standard should provide a framework for the
transfer capability calculation methodology, including data inputs and
modeling assumptions. APPA notes that, in the Western Interconnection
and ERCOT, the sets of rules for long-range and operational planning
studies are transparent to all users, owners and operators and suggests
that in the Eastern Interconnection, where multiple regions exist, the
Regional Entities should consider developing an umbrella organization
or process comprised of representatives from each of the Eastern
Interconnection's Regional Entities to establish the planning and
operational rules for the Interconnection. APPA suggests that this
approach would work well to identify critical facilities, by using
consistent and transparent study assumptions, and it would also
minimize seams issues when establishing facility rating and transfer
capabilities throughout the entire Interconnection. International
Transmission states that this Reliability Standard should identify the
performance that is required, that specifics of how transfer capability
should be calculated do not belong in this Reliability Standard, and
that a reference document could be developed for this purpose.
(b) Commission Determination
    780. Although we are not proposing to approve or remand this
Reliability Standard, because it is applicable to the regional
reliability organization, the Commission agrees with APPA,
International Transmission and MidAmerican that, at a minimum, this
Reliability Standard should provide a framework for the transfer
capability calculation methodology, including data inputs and modeling
assumptions. The Commission agrees with APPA that there should be an
umbrella organization to assure consistency within the Eastern
Interconnection and the other interconnections. We believe that the
best organization to do this would be the ERO, because it is the only
organization with knowledge of all of the individual Regional Entities
that can carry out this function. Therefore, we direct the ERO to
modify this Reliability Standard to provide such a framework.
ii. Transparency and Confidentiality
(a) Comments
    781. International Transmission cautions that, in making
information regarding the framework for calculating transfer capability
transparent to all participants, a balance must be maintained between
the need for transparency and the need to maintain the confidentiality
of sensitive critical energy infrastructure information (CEII). The
results of certain critical contingency analyses would not be
appropriate for public disclosure, but may be the basis for transfer
capability limits imposed on some interfaces.
    782. MidAmerican suggests that transparency could be provided in
the Eastern Interconnection by each reliability coordinator and each
planning authority posting the transfer capability calculations
performed pursuant to FAC-012-1, along with a document outlining how
they were determined and the purposes for which they are used on a
protected Web site. The protected site should be accessible only to
qualified entities. MidAmerican suggests that the Western
Interconnection's approach, the WECC message system used for certain
qualified paths, is an appropriately transparent system.
(b) Commission Determination
    783. Although we are not proposing to approve or remand this
proposed Reliability Standard, the Commission believes that it can be
improved. The Commission believes that the process used to determine
transfer capabilities should be transparent to the stakeholders, and
agrees with International Transmission and MidAmerican that the results
of those calculations should not be available for public disclosure but
only for qualified entities on a confidential basis. In addition, the
process and criteria used to determine transfer capabilities must be
consistent with the process and

criteria used for other users of the Bulk-Power System. Simply stated,
the criteria used to calculate transfer capabilities for use in
determining ATC must be identical to those used in planning and
operating the system. The Commission directs the ERO to take this into
account in its Reliability Standards development process, and to modify
the Reliability Standard consistent with Order No. 890 in Docket No.
RM05-25-000.
    784. Accordingly, the Commission affirms the NOPR proposal to not
approve or remand this Reliability Standard. We understand that the ERO
implemented its Reliability Standards development process to revise the
Reliability Standard and will be submitting it in accordance with the
schedule identified in Order No. 890.
g. Establish and Communicate Transfer Capability (FAC-013-1)
    785. FAC-013-1 requires either the reliability coordinator or the
planning authority, as determined by the regional reliability
organization, to calculate transfer capabilities consistent with its
transfer capability methodology and provide those capabilities to its
transmission operators, transmission service providers and planning
authorities.
    786. In the NOPR, the Commission proposed to approve Reliability
Standard FAC-013-1 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 proposed to direct NERC to develop a modification to
FAC-013-1 that: (1) Makes it applicable to all reliability coordinators
and (2) removes the regional reliability organization as the entity
that determines whether a planning authority has a role in determining
transfer capabilities.
i. Comments
    787. APPA supports the Commission's proposal to approve FAC-013-1
as a mandatory and enforceable Reliability Standard, but disagrees with
the Commission's proposed modification to remove the regional
reliability organization as the entity that determines whether a
planning authority has a role in determining transfer capabilities.
APPA believes that regional committee processes are essential to
determine, through their planning and operating committees, which
planning authorities and reliability coordinators are responsible for
determining and distributing each of the specific transfer capability
values within each regional footprint. APPA proposes that in the
Eastern Interconnection, where multiple regional reliability
organizations and Regional Entities exist, the Regional Entities should
consider developing an umbrella organization or process comprised of
representatives from each of the Eastern Interconnection's Regional
Entities, to establish the planning and operational planning rules for
the Interconnection. APPA believes that such a program would minimize
seams issues when establishing facility ratings and transfer
capabilities throughout the entire Interconnection.
    788. MidAmerican supports the Commission's proposal to make this
Reliability Standard applicable to all reliability coordinators and
planning authorities. MidAmerican believes in a clear separation of
responsibilities between the reliability coordinators and planning
authorities. MidAmerican believes that reliability coordinators should
calculate transfer capabilities in the operating horizon, while
planning authorities calculate transfer capabilities in the planning
horizon, and would support additional clarification of the standard by
explicitly stating the continued responsibility of planning authorities
to calculate transfer capabilities for the planning horizon.
    789. TANC is concerned that, if the transmission service provider
and the transmission operators are specifically named in Requirement
R2.1 of this Reliability Standard, but are not included in the
Applicability section, this will cause ambiguity. TANC questions
whether a transmission service provider or transmission operator that
does not receive the transfer capabilities from the reliability
coordinator will be held accountable and penalized for not producing
the transfer capabilities when the reliability coordinator never
provided them. If this is the case, TANC questions whether there will
be different penalties for the transmission service provider and
transmission operator, or whether they will be subject to the same
penalties as the entities listed in the Applicability section.
    790. EEI believes that the full range of issues discussed here are
currently under review under Docket No. RM05-25 and proposes that these
issues remain in a single forum to avoid confusion.
ii. Commission Determination
    791. The Commission does not believe that the regional reliability
organization should be able to decide the type of entity to which this
Reliability Standard applies. The Commission disagrees with APPA that
regional committee processes are essential to determine which planning
authorities and reliability coordinators are responsible for
determining and distributing each of the specific transfer capability
values. Reliability coordinators have a wider-area view of the
transmission system than planning authorities, which is important in
calculating inter- and intra-regional transfer capabilities. Therefore,
the Commission agrees with MidAmerican that reliability coordinators
should calculate transfer capabilities in the operating horizon. The
Commission will not address MidAmerican's proposal regarding
calculating transfer capabilities in the planning horizon because those
Reliability Standards are being considered in Docket No. RM07-3-000 and
are therefore beyond the scope of this proceeding.
    792. The Commission, as discussed elsewhere in this Final Rule, has
considered APPA's proposal concerning creating an umbrella organization
in regard to FAC-012-001.\276\
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    \276\ See supra P 780.
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    793. In regard to TANC's concern that transmission service
providers and transmission operators may be liable because they are
specifically named in Requirement R2.1, the Commission clarifies that,
because the Reliability Standard only provides that the transmission
service providers and transmission operators receive information
regarding transfer capabilities, and does not require an affirmative
action on the part of transmission service providers or transmission
operators, a transmission service provider or transmission operator
cannot be liable for violating the Reliability Standard.
    794. The Commission disagrees with EEI that these matters should be
evaluated only in the OATT Reform Proceeding. In Order No. 890, the
Commission directed transmission owners to use the ERO's Reliability
Standards development process to implement changes required in that
Final Rule.\277\
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    \277\ Order No. 890 at P 196.
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    795. Accordingly, the Commission approves Reliability Standard FAC-
013-1 as mandatory and enforceable, and, 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 FAC-013-1 through the Reliability
Standards development process that makes it applicable to reliability
coordinators.

6. INT: Interchange Scheduling and Coordination
    796. The Interchange Scheduling and Coordination (INT) group of
Reliability Standards addresses interchange transactions,\278\ which
occur when electricity is transmitted from a seller to a buyer across
the power grid. Specific information regarding each transaction must be
identified in an accompanying electronic label, known as a ``Tag'' or
``e-Tag'' which is used by affected reliability coordinators,
transmission service providers and balancing authorities to assess the
transaction for reliability impacts. Communication, submission,
assessment and approval of a Tag must be completed for reliability
consideration before implementation of the transaction.
---------------------------------------------------------------------------

    \278\ The NERC glossary defines ``interchange'' as ``Energy
transfers that cross Balancing Authority boundaries.'' NERC Glossary
at 9.
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a. Interchange Authority
    797. The Version 1 INT Reliability Standards submitted with NERC's
August 28, 2006 supplemental filing include a new entity, the
interchange authority, which oversees interchange transactions and is
included as an applicable entity or referenced in the Requirements
sections of INT-005-1, INT-006-1, INT-007-1, INT-008-1, INT-009-1 and
INT-010-1.\279\ The Commission requested in the NOPR that NERC provide
additional information regarding the role of the interchange authority
so that the Commission could determine whether the interchange
authority is a user, owner or operator of the Bulk-Power System
required to comply with mandatory Reliability Standards.
---------------------------------------------------------------------------

    \279\ The NERC Glossary defines an ``interchange authority'' as
``the responsible entity that authorizes implementation of valid and
balanced Interchange Schedules between Balancing Authority Areas,
and ensures communication of Interchange information for reliability
assessment purposes.'' Id.
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i. Comments
    798. ISO-NE states that it is unclear who the interchange authority
should be, how its tasks could be performed operationally and how the
interchange authority function relates to other reliability and market
functions. ISO-NE states that NERC has not yet fully incorporated the
concept of an interchange authority into its Functional Model and has
not provided a means for an entity to register as an interchange
authority under the Functional Model. Finally, ISO-NE states that NERC
must still create a process to allow the appropriate entities to
register as interchange authorities so that their status is clear to
all applicable entities, and it urges that approval of the Reliability
Standards that have the interchange authority as an applicable entity
be withheld until these issues are resolved.
    799. APPA agrees that applicability of the Reliability Standards to
the interchange authority is confusing. However, APPA suggests the best
approach to the problem is for NERC to identify the source and sink
balancing authorities as the applicable entity in these Reliability
Standards until the Functional Model is revised to better specify the
status and responsibility of interchange authorities.
    800. EEI observes that there is considerable confusion throughout
the industry regarding the registration process and the relationship
between registration and applicability of standards, with the
interchange authority being an example of that confusion. However, EEI
states it understands that the role of an interchange authority is
currently being addressed and revisions to the Functional Model are
currently moving through the approval process. If Version 3 of the
Functional Model is approved by the NERC Board, EEI believes it will
clarify that a sink balancing authority performing a Tag authority
service could serve as an interchange authority and this modification
would address the Commission's concern.
    801. The CAISO suggests that it is premature to place any INT
Reliability Standards involving an interchange authority into effect
until more information is provided concerning the interchange
authority's role.
ii. Commission Determination
    802. The NERC glossary definition of interchange authority
indicates that it is intended to provide essentially a quality control
function in verifying and approving interchange schedules and
communicating that information. Our understanding is that, in the
interim, sink and source balancing authorities will serve as
interchange authorities until the ERO has further clarified an
interchange authority's role and responsibility in the modification of
the Functional Model and in the registration process. The new
interchange authority function allows an entity other than a balancing
authority to perform this function in the future; the pre-existing INT-
001-1 Reliability Standard identified the balancing authority as the