SOL or IROL violation.\209\ Staff stated that, in light of the
procedures involved, including submission, assessment and approval, the
total time necessary to implement an interchange transaction
modification is expected to exceed significantly the 30 minute time-
frame established in other Reliability Standards, i.e., the requirement
that the system be returned from a SOL/IROL violation to a secure
operating state as soon as possible, but no more than 30 minutes after
the violation.\210\ INT-004-0 (now INT-010-1) does not contain a clear
reference to this potential

[[Continued on page 64819]]

]

[[pp. 64819-64868]] Mandatory Reliability Standards for the Bulk-Power System

[[Continued from page 64818]]

limitation, and staff observed that it could lead to the inappropriate
use of transaction modification by reliability entities to deal with
actual SOL/IROL violations. Staff expressed concern that such actions
could lead to the loss of valuable time that would be needed to
readjust the system effectively using other operational corrective
actions.
---------------------------------------------------------------------------

    \209\ NERC defines IROL as ``[t]he value (such as MW, MVar,
Amperes, Frequency or Volts) derived from, or a subset of the System
Operating Limits, which if exceeded, could expose a widespread area
of the Bulk Electric System to instability, uncontrolled
separation(s) or cascading outages.'' NERC glossary at 8.
    \210\ Reliability Standard IRO-005-0, Requirement R3, states in
part ``[i]f a potential or actual IROL violation cannot be avoided
through proactive intervention, the Reliability Coordinator shall
initiate control actions or emergency procedures to relieve the
violation without delay, and no longer than 30 minutes.''
---------------------------------------------------------------------------

iii. Comments
    493. There were no comments submitted regarding the use of
transaction modification to address actual IROL violations in INT-010-
1.
iv. Commission Proposal
    494. The Commission believes that it is generally ineffective to
use transaction modifications to mitigate an actual IROL violation or
other system condition that calls for expeditious return to a secure
system state. Transaction modifications are even less effective than
the use of transmission load relief (TLR) procedures to mitigate an
actual IROL violation. We note that the Blackout Report specified that
NERC should ``clarify that the [TLR] process should not be used in
situations involving an actual violation of an Operating Security
Limit.'' The Blackout Report stated that ``the TLR procedure is often
too slow for use in situations in which an affected system is already
in violation of an Operating Security Limit.'' \211\ We believe these
same concerns articulated in the Blackout Report apply all the more so
to a transaction modification to address an actual IROL violation.
---------------------------------------------------------------------------

    \211\ Blackout Report at 163.
---------------------------------------------------------------------------

    495. Reliability Standard INT-010-1 includes provisions that allow
modification to an existing interchange schedule or submission of a new
interchange schedule that is directed by a reliability coordinator to
address current or imminent reliability-related reasons. We interpret
that these current or imminent reliability-related reasons do not
include actual IROL violations as they require immediate control
actions so that the system can be returned to a secure operating state
as soon as possible and no longer than 30 minutes--a period that is
much shorter than the time that is expected to require for new or
modified transactions to be implemented.
    496. Accordingly, with the above interpretation, the Commission
therefore proposes to approve INT-010-1 as mandatory and enforceable.
We believe that the proposed Reliability Standard is just, reasonable,
not unduly discriminatory or preferential, and in the public interest.
7. IRO: Interconnection Reliability Operations and Coordination
a. Overview
    497. The Interconnection Reliability Operations and Coordination
(IRO) group of Reliability Standards detail the responsibilities and
authorities of a reliability coordinator.\212\ The proposed IRO
Reliability Standards establish requirements for data, tools and wide
area view, all of which are intended to facilitate a reliability
coordinator's ability to perform its responsibilities and ensure the
reliable operation of the interconnected grid.
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    \212\ According to the NERC glossary, at 13, a reliability
coordinator is ``the entity with the highest level of authority who
is responsible for the reliable operation of the Bulk Electric
System, has the Wide Area view of the Bulk Electric System, and has
the operating tools, processes and procedures, including the
authority to prevent or mitigate emergency operating situations in
both next-day analysis and real-time operations * * *''
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b. General Comments
    498. CenterPoint believes that the IRO series of Reliability
Standards are largely unnecessary as they are process-oriented. It
proposes the consolidation of the IRO series of Reliability Standards
to replace the process based Requirements with performance metrics. If,
after some time, these do not achieve their reliability goal, they
should be rejected.
    499. The Commission believes that performance metrics will
generally complement and improve the proposed Reliability Standards.
However, we do not believe that a Reliability Standard based solely on
performance metrics can replace the proposed IRO Reliability Standards.
This is because performance metrics, in general, are lagging
indicators, and therefore, could only serve as reactive tools in
improving the Reliability Standards. Additionally, we do not agree with
CenterPoint's statement that the IRO series of Reliability Standards
are largely unnecessary and can be replaced with performance standards.
On the contrary, we believe that the proposed IRO series of Reliability
Standards establish requirements for data, tools, and wide area view
and other real-time operating activities that must be performed by a
reliability coordinator to ensure the reliable operation of the
interconnected grid.
c. Reliability Coordination--Responsibilities and Authorities (IRO-001-
0)
i. NERC Proposal
    500. IRO-001-0 requires that a reliability coordinator have
reliability plans, coordination agreements and the authority to act and
direct reliability entities to maintain reliable system operations
under normal, contingency and emergency conditions. This Reliability
Standard would apply to reliability coordinators and regional
reliability organizations.
ii. Staff Preliminary Assessment
    501. The Staff Preliminary Assessment noted that IRO-001-0 does not
explicitly assign responsibilities to reliability coordinators in its
Purpose or Requirements. Responsibilities can only be inferred from the
definition of reliability coordinator in the NERC glossary.
iii. Comments
    502. NERC comments that virtually every Requirement in IRO-001-0
applies to reliability coordinators, so it does not understand the
Staff Preliminary Assessment's concern regarding the assignment of a
reliability coordinator's responsibilities. It also states that the
compliance registry will include reliability coordinators.
    503. MRO and ReliabilityFirst agree with the Staff Preliminary
Assessment. MRO believes that a clarification of the ``Purpose''
section of IRO-001-0 is warranted to better identify a reliability
coordinator's responsibilities.
    504. The ISO/RTO Council does not share the Staff Preliminary
Assessment's concern because each reliability coordinator's
``reliability plan'' is approved by the NERC Operating Committee. It
states that this process is intended to ensure that a reliability
coordinator's peers validate that there is an appropriate entity
authorized to carry out a reliability coordinator's plans.
iv. Commission Proposal
    505. The stated Purpose of IRO-001-0 is ``[r]eliability
[c]oordinators must have the authority, plans and agreements in place
to immediately direct reliability entities within their Reliability
Coordinator Areas to re-dispatch generation, reconfigure transmission,
or reduce load to mitigate critical conditions to return the system to
a reliable state.'' As noted by NERC, IRO-001-0 includes eight
Requirements that set forth reliability coordinator responsibilities.
However, these Requirements do not comprehensively match the
responsibilities described in the Purpose statement of this Reliability
Standard. Nonetheless, the Commission observes that the IRO group of
Reliability Standards, taken as a whole, together with the NERC
glossary definition of reliability coordinator, provides an adequate
understanding of

the role and responsibilities of a reliability coordinator. Thus, while
IRO-001-0 could be improved by comprehensively defining the overall
responsibility of a reliability coordinator, as suggested in the title
of the Reliability Standard (Reliability Coordination--Responsibilities
and Authorities), we will not propose to direct NERC to do so.
    506. Requirement R1 of IRO-001-0 provides that each regional
reliability organization, ``subregion'' or ``interregional coordinating
group'' shall establish one or more reliability coordinators to
continuously assess transmission reliability and coordinate emergency
operations. Sections 502 and 503 of NERC's Rules of Procedure indicate
that the ERO and Regional Entities are responsible for registering,
certifying and verifying entities pursuant to NERC's compliance
registry, including reliability coordinators. The Commission proposes
that NERC modify Requirement R1 to reflect the process set forth in the
NERC Rules of Procedures, including the substitution of Regional Entity
for regional reliability organization.
    507. Accordingly, giving due weight to the technical expertise of
the ERO and with the expectation that the Reliability Standard will
accomplish the purpose represented to the Commission by the ERO and
that it will improve the reliability of the nation's Bulk-Power System,
the Commission proposes to approve Reliability Standard IRO-001-0 as
mandatory and enforceable. In addition, pursuant to section 215(d)(5)
of the FPA and Sec.  39.5(f) of our regulations, the Commission
proposes to direct that NERC submit a modification to Requirement R1 of
IRO-001-0 that: (1) Reflects the process set forth in the NERC Rules of
Procedures; and (2) eliminates the regional reliability organization as
an applicable entity.
d. Reliability Coordination--Facilities (IRO-002-0)
i. NERC Proposal
    508. The proposed Reliability Standard, IRO-002-0, establishes the
requirements for data, information, monitoring and analytical tools and
communication facilities to enable a reliability coordinator to meet
the reliability needs of the Interconnection, act in addressing real-
time emergency conditions and control analysis tools. NERC indicates
that it plans to modify IRO-002-0 to address the lack of Measures and
Levels of Non-Compliance and resubmit it for Commission approval in
November 2006.
ii. Staff Preliminary Assessment
    509. The Staff Preliminary Assessment did not identify any
substantive issues other than noting the absence of Measures and Levels
of Non-Compliance.
iii. Comments
    510. MISO contends that the proposed Reliability Standard does not
clearly require all reliability coordinators to demonstrate a
functioning state estimation, real-time contingency analysis or a
defined ``wide area view'' that includes visibility into neighboring
regions. According to MISO, the requirement that a reliability
coordinator have ``adequate analysis tools'' is a ``loophole that
belies the term `standard.' ''\213\ ReliabilityFirst asserts that NERC
should expedite the development of missing compliance elements within
IRO-002-0.
---------------------------------------------------------------------------

    \213\ MISO Comments at 13, n.13, quoting IRO-002-0, Requirement
R7, which states, ``[e]ach Reliability Coordinator shall have
adequate analysis tools such as state estimation, pre- and post-
contingency analysis capabilities (thermal, stability, and voltage),
and wide-area overview displays.''
---------------------------------------------------------------------------

iv. Commission Proposal
    511. Requirement R7 currently does not specifically require the
reliability coordinators to have specific tools because it includes the
phrase ``such as.'' Requirement R7 should be modified to explicitly
require a minimum set of tools that should be made available to the
reliability coordinator. We share ReliabilityFirst's concern that IRO-
002-0 lacks Measures and Levels of Non-Compliance and direct NERC to
add these compliance elements in its modification of the proposed
Reliability Standard. While the Commission has identified concerns with
regard to IRO-002-0, we believe that the proposal serves an important
purpose in ensuring that reliability coordinators have the information,
tools and capabilities to perform their functions. NERC should provide
Measures and Levels of Non-Compliance for this proposed Reliability
Standard. Nonetheless, the proposed Requirements set forth in this
Reliability Standard are sufficiently clear and objective to provide
guidance for compliance.
    512. Accordingly, giving due weight to the technical expertise of
the ERO and with the expectation that the Reliability Standard will
accomplish the purpose represented to the Commission by the ERO and
that it will improve the reliability of the nation's Bulk-Power System,
the Commission proposes to approve Reliability Standard IRO-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
proposes to direct that NERC submit, a modification to IRO-002-0 that:
(1) Includes Measures and Levels of Non-Compliance and (2) modifies
Requirement R7 to explicitly require a minimum set of tools for the
reliability coordinator.
e. Reliability Coordination--Wide Area View (IRO-003-1)
i. NERC Proposal
    513. The stated purpose of the proposed Reliability Standard is
that a reliability coordinator must have a wide area view of its own
and adjacent areas to maintain situational awareness. Wide area view
also facilitates a reliability coordinator's ability to calculate SOL
and IROL as well as determine potential violations in its own area.
NERC indicates that it plans to modify IRO-003-1 to address the absence
of Measures and Levels of Non-Compliance and will resubmit it for
Commission approval in November 2006.
ii. Staff Preliminary Assessment
    514. The Staff Preliminary Assessment indicated that IRO-003-1 does
not specify the criteria for defining critical facilities in adjacent
systems whose status and loading could affect the reliability of
neighboring systems.
iii. Comments
    515. NERC responds that IRO-003-1 provides that ``critical
facilities'' are those that, if they fail, would result in an SOL or
IROL violation. According to NERC, this means that critical facilities
can only be determined by contingency analysis and change through time,
and therefore, ``may or may not exist.'' Because an SOL or IRO
violation is an operating state that can only be determined by running
a series of ``what if'' analyses, IRO-003-1 defines a ``critical
facility'' as the facility that, if it fails, places the transmission
system in a state ``such that the failure of some other element will
result in facility overloads, instability, or uncontrolled cascading
outages.'' \214\ NERC states that the Commission should approve the
Reliability Standard and adds that it will consider revising it to
clarify the definition of ``critical facility.''
---------------------------------------------------------------------------

    \214\ NERC Comments at 126.
---------------------------------------------------------------------------

    516. MRO agrees with the Staff Preliminary Assessment that this
Reliability Standard should be revised to specify the criteria for
defining ``critical facilities'' in adjacent systems. MISO contends
that the proposed Reliability Standard does not clearly

define the term ``wide area view'' that includes visibility into
neighboring regions.
iv. Commission Proposal
    517. The Blackout Report emphasized that a principal cause of the
August 2003 blackout was a lack of situational awareness, which was in
turn the result of inadequate reliability tools and backup
capabilities.\215\ It pointed out that the need for improved
visualization capabilities over a wide geographic area has been a
recurrent theme in blackout investigations. The Blackout Report also
explained that the Task Force investigation of the August 2003 blackout
revealed that ``there has been no consistent means across the Eastern
Interconnection to provide an understanding of the status of the power
grid outside of a control area,'' and improved visibility of grid
status would aid an operator in making adjustments in operations to
mitigate potential problems.\216\ The Commission believes that this
issue is applicable to the entire country and not just the Eastern
Interconnection. IRO-003-1 addresses these important concerns of the
Blackout Report by requiring that a reliability coordinator monitor its
own and adjacent areas to have a wide area view that is ``necessary to
ensure that, at any time, regardless of prior planned or unplanned
events, the Reliability Coordinator is able to determine any potential
System Operating Limit and Interconnection Reliability Operating Limit
violations within its Reliability Coordination Area.'' \217\
---------------------------------------------------------------------------

    \215\ Blackout Report at 159.
    \216\ Id.
    \217\ IRO-003-1, Requirement R1.
---------------------------------------------------------------------------

    518. The Commission notes that Requirement R2 of the Reliability
Standard requires that each reliability coordinator know the current
status of all ``critical facilities'' whose ``failure, degradation or
disconnection'' could result in an SOL or IROL violation. However, IRO-
003-1 does not specify the criteria for defining critical facilities.
NERC explains that specifying such criteria is very difficult because
critical facilities can only be determined by contingency analysis and
change through time. While NERC acknowledges the absence of such
criteria, it requests that the Reliability Standard be approved. In
addition, NERC indicates that it will consider a modification to
clarify the definition of ``critical facility.''
    519. IRO-003-1 serves an important reliability goal of requiring
reliability coordinators to have a wide area view and maintain
situational awareness. The Commission proposes to direct NERC to
provide Measures and Compliance elements for the proposed Reliability
Standard, and include criteria to define ``critical facilities'' in a
reliability coordinator's area and its adjacent systems. Nonetheless,
the Requirements set forth in IRO-003-1 are sufficiently clear and
objective to provide guidance for compliance and a basis for
enforcement.
    520. Accordingly, giving due weight to the technical expertise of
the ERO and with the expectation that the Reliability Standard will
accomplish the purpose represented to the Commission by the ERO and
that it will improve the reliability of the nation's Bulk-Power System,
the Commission proposes to approve Reliability Standard IRO-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
proposes to direct that NERC submit a modification to IRO-003-1 that
includes: (1) Measures and Levels of Non-Compliance; and (2) criteria
to define the term ``critical facilities'' in a reliability
coordinator's area and its adjacent systems.
f. Reliability Coordination--Operations Planning (IRO-004-1)
i. NERC Proposal
    521. The stated purpose of IRO-004-1 is to require that each
reliability coordinator conduct next-day operations reliability
analyses to ensure that the system can be operated reliably in
anticipated normal and contingency system conditions. Operations plans
must be developed to return the system to a secure operating state
after contingencies and shared with other operating entities.
ii. Staff Preliminary Assessment
    522. The Staff Preliminary Assessment noted that, while IRO-004-1
requires Reliability Coordinators to conduct next-day reliability
analyses to ensure reliable operations in anticipated normal and
contingency event conditions, it ``does not require that the system be
assessed in the next-day planning analysis to identify the control
actions needed to bring the system back to a stable state, with an
effective implementation time of within 30 minutes, so that the system
will be able to withstand the next contingency without cascading.''
\218\
---------------------------------------------------------------------------

    \218\ Staff Preliminary Assessment at 71.
---------------------------------------------------------------------------

iii. Comments
    523. NERC asserts that Requirement R1 of IRO-004-1 does require
next-day operations planning studies and does not require
modification.\219\ Similarly, ISO-RTO Council comments that the
proposed Reliability Standard contains the appropriate requirements for
ensuring reliable operations because there are other tools available to
meet the needs identified with a next-day analysis. These alternative
tools are adequate for conducting next-day analysis.
---------------------------------------------------------------------------

    \219\ Requirement R1 requires that ``Each Reliability
Coordinator shall conduct next-day reliability analyses for its
reliability coordinator area to ensure that the Bulk Electric System
can be operated reliably in anticipated normal and contingency event
conditions. The reliability coordinator shall conduct contingency
analysis studies to identify potential interface and other SOL and
IROL violations, including overloaded transmission lines and
transformers, voltage and stability limits, etc.''
---------------------------------------------------------------------------

    524. MRO suggests that the next-day reliability analyses do not
need to include the control actions that would be implemented to bring
the system back to a stable state. MRO argues that, in most cases, the
actual dispatch and condition of the system during real-time is not
representative of the dispatch used in the model for performing the
next-day analyses and, thus, mitigation action needed during real-time
will differ.
    525. ReliabilityFirst agrees in general with the Staff Preliminary
Assessment's comments, but cautions that the proposal to identify and
study all possibilities for alleviating SOL and IROL may be impractical
and unachievable.
iv. Commission Proposal
    526. The Commission agrees with NERC that the proposed Reliability
Standard requires next day operations planning. While the Staff
Preliminary Assessment mentions the next-day planning analysis and the
need to study events that would result in cascading for the first
contingency, this was not the intended focus of staff's observations.
Rather, the thrust of staff's concern was that the control actions
necessary to return the system to a stable state after the first
contingency must do so effectively within the specified implementation
time of less than 30 minutes.\220\ To assure that an operator has
either sufficient generation resources, transmission modifications, or
load shedding capability to avoid a cascading outage after the first
contingency, the control actions should be identified in the next-day
analyses to better prepare system operators to deal

with system contingencies or emergencies in real-time operations.
---------------------------------------------------------------------------

    \220\ IRO-005-1, Requirement R3 states, in relevant part, ``* *
* the [r]eliability [c]oordinator shall initiate control actions or
emergency procedures to relieve the violations without delay, and no
longer than 30 minutes.''
---------------------------------------------------------------------------

    527. The Commission believes that identification of potential
control actions will aid system operators in performance of their
duties. While MRO is correct that control actions identified in a next-
day analysis may not always be useful in a real-time scenario,
nonetheless, the control actions identified in the next-day analysis
may quite often be relevant and having the system operators aware of
options earlier on would be helpful.
    528. The Commission agrees with NERC regarding the applicability of
this Reliability Standard. While most Requirements pertain to
reliability coordinators, they also require each balancing authority,
transmission operator, transmission owner, generator operator, and
load-serving entity to provide information to its reliability
coordinator for system studies. It also requires that each transmission
operator, balancing authority and transmission service provider to
comply with the directive of its reliability coordinator based on next-
day assessments.
    529. While the Commission has identified one concern with regard to
IRO-004-1, the proposed Reliability Standard serves an important
purpose by requiring that each reliability coordinator conduct next-day
operations reliability analyses to ensure that the system can be
operated reliably in anticipated normal and contingency system
conditions. Further, the Requirements set forth in IRO-004-1 are
sufficiently clear and objective to provide guidance for compliance and
a basis for enforcement.
    530. Accordingly, giving due weight to the technical expertise of
the ERO and with the expectation that the Reliability Standard will
accomplish the purpose represented to the Commission by the ERO and
that it will improve the reliability of the nation's Bulk-Power System,
the Commission proposes to approve Reliability Standard IRO-004-1 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
proposes to direct that NERC submit a modification to IRO-004-1 that
requires the next-day analysis to identify effective control actions
that can be implemented within 30 minutes during contingency
conditions.
g. Reliability Coordination--Current Day Operations (IRO-005-1)
    531. IRO-005-1 ensures energy balance and transmission reliability
for the current day by identifying tasks that reliability coordinators
must perform throughout the day. The stated purposed of the proposed
Reliability Standard is that a reliability coordinator must be
continuously aware of conditions within its area and include this
information in its reliability assessments. Additionally, a reliability
coordinator must monitor the parameters of the system that may have a
significant impact upon its area and neighboring reliability
coordinator areas. NERC indicates that it plans to modify IRO-005-0 to
address the lack of Measures and Levels of Non-Compliance and resubmit
it for Commission approval in November 2006.
i. Staff Preliminary Assessment
    532. Requirement R3 of IRO-005-1 provides that: ``[i]f a potential
or actual IROL violation cannot be avoided through proactive
intervention, the Reliability Coordinator shall initiate control
actions or emergency procedures to relieve the violation without delay,
and no longer than 30 minutes. The Reliability Coordinator shall ensure
all resources, including load shedding, are available to address a
potential or actual IROL violation.'' The Staff Preliminary Assessment
pointed out that this Requirement may be interpreted in either of two
ways: (1) a less conservative interpretation in which an IROL is
allowed to be exceeded during normal operations, i.e., prior to a
contingency, provided that corrective actions are taken within 30
minutes; and (2) a more conservative interpretation that an IROL should
only be exceeded after a contingency and the system must subsequently
be returned to a secure condition as soon as possible, but no longer
than 30 minutes. Therefore, IRO-005-1 creates the situation in which
the system may be one contingency away from potential cascading failure
if operated under the less conservative interpretation or two
contingencies away from potential cascading failure if the more
conservative interpretation is adopted.
ii. Comments
    533. NERC acknowledges that the SOLs and IROLs are among the most
important operating measures contained in the proposed Reliability
Standards and that it continues to refine the definitions of both these
terms. NERC explains that SOL and IROL violations do not necessarily
result from an event or ``contingency.'' It asserts that the
transmission system may ``drift'' into an SOL or IROL violation without
any triggering event and with every element of the transmission system
operation within its own safe limit.\221\ NERC states that the point of
these limits is not whether a particular transmission facility is
operating within its normal limits, but to determine what happens if
the transmission element fails regardless of how much power is flowing
through it.
---------------------------------------------------------------------------

    \221\ See NERC Comments at 43-48.
---------------------------------------------------------------------------

    534. NERC states that it will consider clarifying those Reliability
Standards that indicate a contingency is not required and, as a
corollary, that a Reliability Standard should not allow a system
operator to ``drift'' in and out of an SOL or IROL violation. Further,
NERC will continue to refine its definition of SOL and IROL violations.
The Operating Committee has commissioned an Operating Limits Definition
Task Force to work on this matter, and the Task Force will bring its
final suggestions to the Operating Committee by the end of 2006. NERC
indicates that it will review proposed Reliability Standards IRO-003-0
and IRO-005-1 and address SOL and IROL violation mitigation.
    535. According to NERC, the 30-minute limit for mitigating IROL
violations is one of many reliability standards gleaned from decades of
interconnected systems operation experience, and represents a tradeoff
between: (1) sufficient time to allow the transmission operator or
reliability coordinator to mitigate the violation without having to
shed load or disconnect transmission system components; and (2) the
risk that some event will occur before the mitigating action is taken.
NERC explains that action is required ``as soon as possible'' or
``without delay,'' however, exceeding an SOL or IROL for no more than
30 minutes is not a violation. It contends that this approach is
reasonable because it allows the system operator to decide on what
course of action to take. Operating options that are less severe than
shedding load are often available, but it explains that these actions
may require more time for implementation. NERC asserts that its
committees and subcommittees have debated the phrase, ``as soon as
possible'' for years and have not found a better way to articulate a
requirement that allows the system operator the leeway to decide the
best course of action.
    536. MRO and NYSRC agree with the Staff Preliminary Assessment that
IRO-005-1 allows varying interpretations with respect to IROL limits
under normal and contingency conditions and should be revised to
clarify how IROL events are addressed. ReliabilityFirst believes that a
methodology to address

SOLs and IROLs must be developed. It argues that this will aid in
clarifying that exceeding limits is not acceptable operating practice.
According to ReliabilityFirst, proposed Reliability Standards are being
developed that will provide more definition and detail in this area. It
urges the acceleration of this development.
    537. MidAmerican believes that staff's ``more conservative''
interpretation may be overly conservative and should not be adopted. It
contends that, in an interconnected transmission network, it is
difficult to operate prior to a contingency so that potential IROL
violations are avoided at all times. It believes that to adopt the more
conservative interpretation could require an operator to scale back the
operation of its system pre-contingency by an inordinate amount to
provide a safety margin so as not to risk a potential IROL violation
even for only very short periods of time. MidAmerican maintains that
such an operation would result in slightly more reliable operation at
an unjustifiably high price.
iii. Commission Proposal
    538. The Commission proposes to approve IRO-005-1 as mandatory and
enforceable. In addition, we propose to direct that NERC develop
modifications to the Reliability Standard and perform a survey of
present operating practices and actual operating experience concerning
drifting in and out of IROL violations.
    539. The Commission believes that one of the fundamental principles
in operating the Bulk-Power System reliably is that the system must be
capable of supplying firm demand and supporting firm transactions while
retaining the capability to withstand a critical contingency without
resulting in instability, uncontrolled separation or cascading
failures. This is affirmed by the term, Reliable Operation, as set
forth in section 215(a)(4) of the FPA \222\ and the technical
requirement as stated in Table 1 of Reliability Standard TPL-002-
0.\223\ Therefore, in order to achieve the reliability goal stated in
the definition of Reliable Operation, the Bulk-Power System must be
operated to respect all applicable IROLs during normal conditions, i.e.
prior to a contingency, so that the system is capable of withstanding a
critical contingency without resulting in instability, uncontrolled
separation or cascading outages.
---------------------------------------------------------------------------

    \222\ Reliable operation: Operating the elements of the Bulk-
Power System within equipment and electric system thermal, voltage
and stability limits so that instability, uncontrolled separation,
or cascading failures of such system will not occur as a result of
sudden disturbance, including a Cybersecurity Incident, or
unanticipated failure of system elements.
    \223\ TPL-002-0 System Performance Following Loss of a Single
Bulk Electric System Element, Table 1: For Category B events
resulting in loss of a single element, the system remains stable and
both thermal and voltage limits are within applicable ratings with
no loss of demand or curtailment of firm transfers and no cascading
outages.
---------------------------------------------------------------------------

    540. IRO-005-1 allows a system operation to respect IROLs in two
possible ways: (1) allowing IROL to be exceeded during normal
operations, i.e., prior to a contingency, provided that corrective
actions are taken within 30 minutes or (2) exceeding IROL only after a
contingency and subsequently returning the system to a secure condition
as soon as possible, but no longer than 30 minutes. Thus, the system
can be one contingency away from potential cascading failure if
operated under the first interpretation and two contingencies away from
cascading failure under the second interpretation.
    541. The Commission notes that the proposed Reliability Standards
(e.g. TOP-007-0) do not consider operation exceeding IROL for less than
30 minutes as a compliance violation. This, in addition to the less
conservative interpretation that IROL violation is permissible during
normal operations, opens up a significant reliability gap that allows
operations with IROL violations for less than 30 minutes at a time.
Under the mandatory reliability construct, there would be no
enforcement provision to sanction against such actions even they
resulted in cascading outages.
    542. The Commission believes a proactive standard, that clearly
defines that reliable operations means operating the system within
IROLs and requires such operating practice be reinforced by periodic
reporting of the frequency, duration and causes of IROL violations, is
needed to prevent or mitigate the risk of blackouts. This is because,
by definition, when the system is operating in violation of IROLs and
if a critical contingency occurs, cascading outages will result.
    543. Operating the system during normal system conditions with IROL
violations is also known in the industry as ``drifting in and out'' of
an IROL violation. This is the first and less conservative
interpretation of the proposed Reliability Standard as stated above and
one contingency away from cascading failure. We particularly note that
the NERC Operating Committee recommended that the proposed Reliability
Standards should not allow a system operator to ``drift'' in and out of
an SOL or IROL violation.
    544. The Commission agrees with ReliabilityFirst's comments that
exceeding any limit is not acceptable operating practice. The system
should strive to operate in a secure state that respects all IROLs
under normal conditions at all times, except for infrequent and
unanticipated changing conditions that are beyond the control of
reliability coordinators and operating entities under their
jurisdiction. Furthermore, these unanticipated factors should be
limited and should not include load pick-up and drop-off as changes in
load demand or coordinated generation dispatches and transactions, all
of which would have obtained prior assessments and approvals.
    545. In contrast to MidAmerican's comments, the Commission does not
believe that respecting IROL under normal system conditions requires an
inordinate amount of operating margin which may result in an
unjustifiably high price. However, we propose to direct NERC to perform
a survey of present operating practices and actual operating experience
concerning drifting in and out of IROL violations. As part of the
survey, we will require all reliability coordinators to report any
violations of IROLs, their causes, the date and time of the violation,
and the duration in which actual operations exceeded IROL to the ERO on
a monthly basis for one year beginning two months after the effective
date of the final rule.
    546. The Commission also finds that well-designed Levels of Non-
Compliance should duly recognize the magnitude, frequency and duration
of IROL violations under normal system conditions and differentiate
those caused by system contingencies. The former, if not severe,
frequent, of extended duration or willfully deployed, should not incur
heavy penalties. Nevertheless, these occurrences and causes should be
recorded and reported. We understand that most reliability coordinators
and transmission operators already keep records of power flows on
transmission interfaces, transmission paths or flowgates versus their
respective IROLs as a part of their operating and management tools. We
believe that the practice of separately recording and reporting IROL
violations and durations occurring under normal and contingency system
conditions serves several purposes, including: (1) Reinforcing the
sound principles of reliable system operations; (2) serving as a
performance metric to gauge the effectiveness of Reliability Standards,
coordinated Interconnection operations,

and the health of the Bulk-Power System; and (3) proactively improving
system reliability over time.
    547. It is important to keep in mind that, while the Commission has
concerns regarding Requirement R3, the proposed Reliability Standard
contains 17 Requirements relating to current day operations. With this
perspective, while the Commission has identified a number of concerns
with regard to IRO-005-1, we believe that the proposed Reliability
Standard adequately addresses the important reliability goal of
requiring a reliability coordinator to be continuously aware of
conditions within its reliability coordinator area and include this
information in its reliability assessments. Further, NERC should
provide Measures and Levels of Non-Compliance elements for this
proposed Reliability Standard. Nonetheless, the proposed Requirements
set forth in this Reliability Standard are sufficiently clear and
objective to provide guidance for compliance.
    548. Accordingly, giving due weight to the technical expertise of
the ERO and with the expectation that the Reliability Standard will
accomplish the purpose represented to the Commission by the ERO and
that it will improve the reliability of the nation's Bulk-Power System,
the Commission proposes to approve Reliability Standard IRO-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
proposes to direct that NERC submit a modification to IRO-005-1 that
includes Measures and Levels of Non-Compliance. We propose that the
Measures and Levels of Non-Compliance specific to IROL violations
should be commensurate with the magnitude, duration, frequency and
causes of the violation. Further, as discussed above, we propose that
the ERO conduct a survey on IROL practices and experiences. The
Commission may propose further modifications to IRO-005-1 based on the
survey results.
h. Reliability Coordination--Transmission Loading Relief (IRO-006-3)
i. NERC Proposal
    549. IRO-006-3 ensures that a reliability coordinator has a
coordinated method to alleviate loadings on the transmission system if
it becomes congested to avoid limit violations. IRO-006-3 establishes a
detailed Transmission Loading Relief (TLR) process for use in the
Eastern Interconnection to alleviate loadings on the system by
curtailing or changing transactions based on their priorities and
according to different levels of TLR procedures.\224\ The proposed
Reliability Standard includes a regional difference for reporting
market flow information to the Interchange Distribution Calculator
rather than tagged transaction information for the MISO and PJM
areas.\225\ It also references the equivalent Interconnection-wide
congestion management methods used in the WECC and ERCOT regions.
---------------------------------------------------------------------------

    \224\ The equivalent Interconnection-wide transmission loading
relief procedures for use in WECC and ERCOT are known as ``WSCC
Unscheduled Flow Mitigation Plan'' and Section 7 of the ``ERCOT
Protocols,'' respectively.
    \225\ The NERC glossary defines Interchange Distribution
Calculator as ``The mechanism used by reliability coordinators in
the Eastern Interconnection to calculate the distribution of
Interchange Transactions over specific Flowgates. It includes a
database of all Interchange Transactions and a matrix of the
Distribution Factors for the Eastern Interconnection.'' NERC
glossary at 6.
---------------------------------------------------------------------------

    550. On August 28, NERC submitted IRO-006-3 for approval, which
replaces IRO-006-1. The new proposal would extend the PJM/MISO regional
difference to SPP and contains some additional changes to the
Attachment to the Reliability Standard. The comments submitted in
response to the Preliminary Staff Assessment on IRO-006-1 apply equally
to IRO-006-3.\226\
---------------------------------------------------------------------------

    \226\ We note that on September 29, 2006, NERC submitted Version
2 of the same Reliability Standard (ERO-006-2) in Docket No. ER06-
1545-000, seeking approval of its TLR procedure pursuant to section
205 of the FPA.
---------------------------------------------------------------------------

ii. Staff Preliminary Assessment
    551. The Staff Preliminary Assessment noted that IRO-006-1 does not
address concerns expressed in the Blackout Report that call for
``clarify[ing] that the transmission loading relief (TLR) process
should not be used in situations involving an actual violation of an
Operating Security Limit [SOL].'' \227\ It also noted that Requirement
R2, which provides that a reliability coordinator experiencing a
potential or actual SOL or IROL violation shall select from either a
local or Interconnection-wide transmission loading relief procedure,
could lead a reliability system operator to ``inappropriately use
transmission loading relief procedures to mitigate actual IROL
violations'' and, ``in doing so, valuable time that could be utilized
to re-adjust the system by other, more effective, operating measures
would be lost.'' \228\
---------------------------------------------------------------------------

    \227\ Blackout Report, Recommendation No. 31 at 163.
    \228\ Staff Preliminary Assessment at 69.
---------------------------------------------------------------------------

iii. Comments
    552. NERC explains that the TLR procedure is a method of addressing
the impacts of bilateral transactions causing parallel flows. The
procedure curtails bilateral transactions, which causes generation to
be re-dispatched, which in turn changes the flow patterns on the
transmission system. The curtailments are based on a power flow model
of the Eastern Interconnection, and have the effect of reducing the
loading on those lines over which the transactions are actually
flowing.
    553. NERC agrees that the TLR procedure alone is usually not
effective as a control measure to mitigate an IROL violation and
explains that the TLR procedure was not intended to be effective in
this manner.\229\ It states that, while TLR procedures can be effective
as a preventive tool to adjust and manage bilateral transactions so
that limit violations do not occur, other options such as local or
market area re-dispatch and transmission reconfiguration are more
precise for a system operator to stay within SOLs and IROLs.
---------------------------------------------------------------------------

    \229\ NERC Comments at 49.
---------------------------------------------------------------------------

    554. NERC believes that transmission operators and reliability
coordinators understand that the TLR procedure is not the only method
for mitigating an SOL or IROL violation and that the proposed
Reliability Standard--as one tool among many--is adequate and necessary
to protect Bulk-Power System reliability. NERC states that ``it does
not believe the recommendation of the Blackout Report that ``the [TLR]
process should not be used in situations involving an actual violation
of an Operating Security Limit [SOL]'' needs further discussion to
determine possible changes to standard.'' \230\
---------------------------------------------------------------------------

    \230\ Id. at 50.
---------------------------------------------------------------------------

    555. ISO/RTO Council states that, although TLR should not be
considered an emergency procedure,\231\ Requirement R1 of IRO-006-3
does not require use of TLR procedures and permits the implementation
of existing policies and procedures to correct transmission
loading.\232\ It further states that Requirement R1 appropriately
identifies a reliability coordinator as being responsible for actions
related to transmission loading. As a result,

because Requirement R1 clearly does not specify the use of TLR, and
instead explicitly calls for the use of appropriate tools available to
the reliability coordinator, the ISO/RTO Council believes that IRO-006-
3 allows entities sufficient flexibility to ensure reliability.
---------------------------------------------------------------------------

    \231\ In its comments on EOP-002-0 regarding Capacity and Energy
Emergencies, ISO/RTO Council elaborates that it ``agrees with FERC
Staff's concerns that TLRs are not appropriate for addressing actual
transmission emergencies, because TLRs are not a method that can be
used quickly or predictably enough in situations where an operating
security limit is close to, or actually being violated.''
    \232\ IRO-006-1, Requirement R1 states, ``[a] [r]eliability
[c]oordinator shall take appropriate actions in accordance with
established policies, procedures, authority, and expectations to
relieve transmission loading.''
---------------------------------------------------------------------------

    556. However, ISO/RTO Council explains the limitations of TLR in
EOP-002-0 that most ISOs and RTOs use re-dispatch to correct SOL and
IROL violations instead of TLR procedures because re-dispatch is
superior to TLR procedures for the purposes of ensuring system
reliability. It further states that as a result, the applicability to
an ISO or RTO region of any Reliability Standard that provides for the
use of TLR procedures is not clear, and if applied, could actually be
detrimental to reliability.
    557. ReliabilityFirst agrees in general with the Staff Preliminary
Assessment. NYSRC comments that the concerns articulated by staff are
not significant enough to prevent approval of the proposed Reliability
Standard. MRO believes that IRO-006-3 should be modified to clarify the
use of TLR as proposed by the Staff Preliminary Assessment due to the
identified interpretation issue.
    558. CenterPoint contends that the ERCOT region should be
explicitly exempted from these [IRO] Reliability Standards since ERCOT
does not use TLR procedures. Instead, it manages congestion using
procedures relevant to ERCOT market rules.
iv. Commission Proposal
    559. The Commission proposes to approve IRO-006-3 as mandatory and
enforceable. In addition, we propose to direct that NERC develop
modifications to the Reliability Standard as discussed below.
    560. The Commission notes that NERC agrees that the TLR procedure
is usually not effective by itself as a control measure to mitigate an
IROL violation, the procedure is not intended to be effective in this
manner and that it be combined with other effective methods such as
reconfiguration, re-dispatch or load shedding until relief requested by
the TLR process is achieved.\233\ The Commission is concerned, however,
that the Requirements in IRO-006-3 do not sufficiently convey the
availability of alternatives, nor highlight the inefficiency of TLR
procedure which requires a lead time for implementation much longer
than the allowable 30 minutes to return the system from IROL violation
to a secure state. This could potentially mislead a transmission
operator or reliability coordinator that is attempting to mitigate an
IROL violation to first deploy the TLR procedure only to find out later
that other more effective operating measures should have been used. In
addition, we duly note ISO/RTO Council's comment that the applicability
to an ISO or RTO region of any Reliability Standard that provides for
the use of TLR procedures is not clear, and if applied, could actually
be detrimental to reliability. Since the system is subject to cascading
outages when it is in IROL violation, we have particular concern
regarding the use of TLR to mitigate IROL violations and less so on its
use on SOLs since the latter would not result in cascading outages.
---------------------------------------------------------------------------

    \233\ NERC Comments at 49.
---------------------------------------------------------------------------

    561. While NERC suggests that transmission operators and
reliability coordinators understand that the TLR procedure is not the
sole method for mitigating an SOL or IROL violation, the Commission
notes that the Blackout Report suggests otherwise with regard to the
causes of the August 2003 cascading blackout since the operator was
first attempting to use TLR to mitigate an IROL violation only to find
out it was ineffective.\234\ This led the Blackout Task Force to
recommend that NERC ``clarify that the [TLR] process should not be used
in situations involving an actual violation of an Operating Security
Limit.'' \235\
---------------------------------------------------------------------------

    \234\ See Blackout Report at 63.
    \235\ Id. at 163.
---------------------------------------------------------------------------

    562. We propose that the Reliability Standard should also clearly
provide the flexibility for ISOs and RTOs to rely on re-dispatch, as
suggested by ISO/RTO Council. Accordingly, we propose to direct that
NERC modify IRO-006-3 to (1) include a clear warning that TLR procedure
is an inappropriate and ineffective tool to mitigate IROL violation and
(2) to identify effective alternatives to use of the TLR procedure in
situations involving an IROL violation.
    563. With regard to CenterPoint suggestion that the ERCOT region be
explicitly exempted from compliance with IRO-006-3, we note that our
regulations require that any such proposal must be developed through an
open, stakeholder process and submitted to the Commission by the ERO.
    564. The Commission notes that Requirement R2.2 identifies the
``WSCC Unscheduled Flow Mitigation Plan'' \236\ as an equivalent load
relief procedure for use in the Western Interconnection. The referenced
document contains governance, compensation, charges for use of the
procedure and limitations on applicable facilities which are unusual in
a Reliability Standard. The Commission believes that these issues are
part of the transition to mandatory Reliability Standards and are
mainly administrative in nature. The Commission believes that the WECC
approach is superior to the national standard because it uses phase
angle regulators, series capacitors and back-to-back DC lines to
mitigate contingencies without curtailing transactions. The Commission
proposes to approve its use.
---------------------------------------------------------------------------

    \236\ WSCC is an old reference to WECC.
---------------------------------------------------------------------------

    565. The Commission notes that Requirement R2.3 identifies section
7 of the ERCOT Protocols as an equivalent load relief procedure for use
in the Texas Interconnection. The Protocol contains significant details
about the ERCOT market that are unusual in a Reliability Standard. The
Commission believes that these issues are part of the transition to
mandatory Reliability Standards and are mainly administrative in
nature. The Commission believes that the ERCOT zonal LMP approach is
superior to the national standard in that it uses generation re-
dispatch and pricing to mitigate congestion without curtailing
transactions. The Commission proposes to approve its use.
    566. While the Commission has identified concerns with regard to
IRO-006-3, we believe that the proposal serves an important purpose in
ensuring reliability coordinators have a coordinated method for
alleviating loadings on the transmission system when it becomes too
congested to avoid potential SOL and IROL violations. It also includes
a regional difference for reporting market flow information to the
Interchange Distribution Calculator. The Commission believes that it is
important for NERC to clarify that the TLR process is not the only, and
perhaps not even the preferred, method to mitigate an SOL and
especially IROL violation. The proposed Requirements set forth in IRO-
006-3 are sufficiently clear and objective to provide guidance for
compliance.
    567. Accordingly, giving due weight to the technical expertise of
the ERO and with the expectation that the Reliability Standard will
accomplish the purpose represented to the Commission by the ERO and
that it will improve the reliability of the nation's Bulk-Power System,
the Commission proposes to approve Reliability Standard IRO-006-3 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
proposes to direct that NERC submit a modification

to IRO-006-3 that: (1) Includes a clear warning that TLR procedure is
an inappropriate and ineffective tool to mitigate IROL violations; (2)
identifies in a Requirement the available alternatives to use of the
TLR procedure to mitigate an IROL violation; and (3) includes Measures
and Levels of Non-Compliance that address each Requirement.
i. Regional Difference to IRO-006-3: PJM/MISO/SPP Enhanced Congestion
Management (Curtailment/Reload/Reallocation)
i. NERC Proposal
    568. IRO-006-003 provides for a regional difference for MISO, PJM
and SPP. NERC explains that this regional difference is needed to allow
RTO market practices, simplify transaction information requirements for
market participants, and provide reliability coordinators with
appropriate information for security analysis and curtailments,
reloads, reallocations and redispatch requirements.
ii. Staff Preliminary Assessment
    569. This regional difference was not addressed in the Staff
Preliminary Assessment.
iii. Comments
    570. MISO and PJM, in a joint filing, contend that there is unduly
discriminatory treatment of the market flows of MISO and PJM versus the
generation-to-load impacts of non-market entities in the application of
the TLR standard. They argue that NERC should modify IRO-006-3 and the
MISO/PJM regional difference to require: (1) Netting of generation-to-
load impacts; (2) reporting to the Interchange Distribution Calculator
all net generation-to-load impacts for both market and non-market
transmission providers; and (3) modifying the curtailment threshold to
a standard percentage for all impacts thus reported to the Interchange
Distribution Calculator to a level that is technically feasible to
implement and on a non-discriminatory basis. MISO and PJM also note
that they, as well as SPP, have been working through various groups to
achieve a consensus on these changes. According to MISO and PJM, these
efforts were fruitful, but they were unable to complete the changes
prior to NERC's April 6, 2006 submission of its Version 0 reliability
standards for Commission approval. The Commission believes that SPP
could experience the same problems identified by MISO and PJM.
iv. Commission Proposal
    571. The Commission believes that the comments and information
presented by MISO and PJM are persuasive. However, before acting on
this regional difference, the Commission invites comments to assure
that we have a full and complete record on which to base our decision.
    572. The Commission notes that MISO and PJM indicate that their
competition concerns are being addressed in discussions with NERC and
other relevant entities. The Commission prefers that PJM, MISO and
others continue to pursue a negotiated resolution rather than having
the Commission impose a solution on market participants. Accordingly,
the Commission will not propose to approve or remand this regional
difference.
j. Procedures, Processes, or Plans to Support Coordination Between
Reliability Coordinators (IRO-014-1)
i. NERC Proposal
    573. The stated purpose of IRO-014-1 is to ensure that each
reliability coordinator's operations are coordinated such that they
will not have an adverse reliability impact on other reliability
coordinator areas and to preserve the reliability benefits of
interconnected operation. Specifically, IRO-014-1 ensures energy
balance and transmission by requiring a reliability coordinator to have
operating procedures, processes or plans for the (1) exchange of
operating information and (2) coordination of operating plans.
ii. Staff Preliminary Assessment
    574. No substantive issues were identified for IRO-014-1.
iii. Comments
    575. No comments were submitted regarding IRO-014-1.
iv. Commission Proposal
    576. The Commission believes that IRO-014-1 contains sufficient
details in the specification of the required procedures, processes or
plans for a reliability coordinator to support coordination among it
neighbors, and agreements that all reliability coordinators, as the
only applicable entity, must take the indicated actions to ensure
coordinated and reliable operations.
    577. For the reasons discussed above, the Commission proposes to
approve Reliability Standard IRO-014-1 as just, reasonable, not unduly
discriminatory or preferential, and in the public interest.
k. Notifications and Information Exchange Between Reliability
Coordinators (IRO-015-1)
i. NERC Proposal
    578. Proposed Reliability Standard IRO-015-1 establishes
Requirements for a reliability coordinator to share and exchange
reliability-related information among its neighbors and participate in
agreed-upon conference calls and other communication forums with
adjacent reliability coordinators. This exchange of reliability-related
information among reliability coordinators facilitates situation
awareness.
ii. Staff Preliminary Assessment
    579. No substantive issues were identified for IRO-015-1.
iii. Comments
    580. No comments were submitted regarding IRO-015-1.
iv. Commission Proposal
    581. The Commission believes that IRO-015-1 contains sufficient
Requirements to ensure that reliability coordinators inform and
exchange information with other reliability coordinators, as the only
applicable entity, to ensure coordinated operations.
    582. For the reasons discussed above, the Commission proposes to
approve Reliability Standard IRO-015-1 as just, reasonable, not unduly
discriminatory or preferential, and in the public interest.
l. Coordination of Real-Time Activities Between Reliability
Coordinators (IRO-016-1)
i. NERC Proposal
    583. IRO-016-1 establishes Requirements for coordinated real-time
operations, including: (1) Notification of problems to neighboring
reliability coordinators and (2) discussions and decisions for agreed-
upon solutions for implementation. It also requires a reliability
coordinator to maintain records of its actions. Where a disagreement
arises, IRO-016-1 requires that reliability coordinators work with one
another until a system problem is resolved or implement the more
conservative solution.
ii. Staff Preliminary Assessment
    584. No substantive issues were identified for IRO-016-1.
iii. Comments
    585. No comments were submitted regarding IRO-016-1.
iv. Commission Proposal
    586. The Commission believes that IRO-016-1 contains sufficient

requirements for a reliability coordinator to inform, discuss and
identify a solution with other reliability coordinators to prevent or
resolve a problem that requires joint actions from all affected
reliability coordinators as the only applicable entity. It also clearly
articulates binding and conservative corrective actions to be taken in
the event that an agreement cannot be reached among them.
    587. For the reasons discussed above, the Commission proposes to
approve Reliability Standard IRO-016-1 as just, reasonable, not unduly
discriminatory or preferential, and in the public interest.
8. MOD: Modeling, Data, and Analysis
a. Overview
    588. The Modeling, Data, and Analysis group of Reliability
Standards are intended to standardize methodologies and system data
needed for traditional transmission system operation and expansion
planning, reliability assessment, and the calculation of available
transmission capacity (ATC) in an open access environment. The 23
standards may be grouped into four distinct categories. The first
category covers methodology and associated documentation, review, and
validation of Total Transfer Capability (TTC), ATC, Capacity Benefit
Margin (CBM), and Transmission Reliability Margin (TRM)
calculations.\237\ The second category covers steady-state and dynamics
data and models.\238\ The third category covers actual and forecast
demand data.\239\ The fourth category covers the verification of
generator real and reactive power capability.\240\
---------------------------------------------------------------------------

    \237\ MOD-001-0 through MOD-009-0.
    \238\ MOD-010-0 through MOD-015-0.
    \239\ MOD-016-0 through MOD-021-0.
    \240\ MOD-024-1 through MOD-025-1.
---------------------------------------------------------------------------

OATT Reform NOPR and the MOD Standards
    589. The Commission has been considering ATC, TTC, CBM and TRM
calculation issues in Docket Nos. RM05-17-000 and RM05-25-000, and is
addressing them in the OATT Reform NOPR.\241\ Among other things, the
OATT Reform NOPR discusses the need for consistency and transparency of
ATC, TTC, CBM, and TRM. It proposes that public utilities, working
through NERC/NAESB, would use the guidelines in the OATT Reform NOPR to
revise the relevant standards and business practices, and asks for
comments on certain proposals. It also recognizes that there are still
many unspecified elements in the calculation processes and development
of modeling assumptions, and deficiencies in data exchange that may
have a negative impact on both transmission system reliability and
competition.\242\
---------------------------------------------------------------------------

    \241\ OATT Reform NOPR, 71 FR 32636 at 32658.
    \242\ Id., 71 FR at 32654 and 32667.
---------------------------------------------------------------------------

    590. The industry also acknowledged this problem and has taken
steps to address the lack of consistency and transparency in the way
ATC is calculated. NERC formed a Long-Term Available Flowgate Capacity
\243\ (AFC)/ATC Task Force to review NERC's standards on ATC, which
issued a final report in 2005.\244\ Based on the recommendations in the
NERC Report, NERC has begun two Standards Authorization Request (SAR)
proceedings to revise the standards on ATC.\245\ NAESB has also begun a
proceeding to develop business practice standards to enhance the
processing of transmission service requests, which affects the ATC
calculation.
---------------------------------------------------------------------------

    \243\ AFC is a methodology that first calculates available
capacity on a flowgate-AFC, and transfers that value into ATC by
dividing AFC with the associated flowgate distribution factor. After
ATC is determined, TTC is calculated from ATC for posting on OASIS.
This method is different from NERC's original ATC calculation, where
TTC is calculated in a first step and then used to determine ATC by
reducing TTC with capacity needed for existing commitments and
reserve margins.
    \244\ The NERC Report made recommendations for greater
consistency and greater clarity in the calculation of ATC/AFC. The
task force also recommended greater communication and coordination
of ATC/AFC information to ensure that neighboring entities exchange
relevant information. See NERC, Long-Term AFC/ATC Task Force Final
Report (2005) (NERC Report) at 2, available at: ftp://www.nerc.com/pub/sys/all_updl/mc/ltatf/LTATF_Final_Report_Revised.pdf
.

    \245\ The first SAR proceeding proposes changes to the existing
standards on ATC to, among other things, further establish
consistency in the calculation of ATC and to increase the clarity of
each transmission provider's ATC calculation methodology. The second
SAR proceeding proposes certain changes to NERC's existing CBM and
TRM standards and calls for greater regional consistency and
transparency in how CBM and TRM are treated in transmission
providers' ATC calculations.
---------------------------------------------------------------------------

Staff Preliminary Assessment
    591. Staff expressed concerned that fourteen of the twenty-three
Reliability Standards in this group apply to regional reliability
organization, which is not a user, owner, or operator of the Bulk-Power
System.
General Comments
    592. NERC comments that it has a team in place to address the
regional reliability organization applicability issue and will submit
an action plan and schedule in November 2006 for completing the fill-
in-the-blank standards. NERC expects that it will take approximately
three years to complete the process, and will prioritize standards that
require the most immediate revision.
    593. CenterPoint advocates eliminating many of the MOD Reliability
Standards or consolidating them into planning or operating standards.
CenterPoint reasons that, to the extent the process-oriented
Reliability Standards are necessary, the ``fill-in-the-blank''
standards are necessary; however, it is impractical to require that
each region use identical practices in building and validating its
models. CenterPoint adds that, should the Reliability Standards be
approved by the Commission, ERCOT should be exempt from those that
address transfer capability because ERCOT does not have any inter-
control area transfers and does not use the NERC methodologies.
Commission Proposal
    594. As we discussed in the Common Issues section above describing
fill-in-the-blank Reliability Standards, we propose to seek additional
information before acting on the Reliability Standards that require the
regional reliability organization to provide criteria on procedures.
    595. While we agree with CenterPoint that some of the MOD
Reliability Standards could be grouped into planning or operating
standards, we will not propose any such modification, but rather, leave
it to the discretion of the ERO. Regarding CenterPoint's suggestion
that ERCOT should be exempt from Reliability Standards that address
available transfer capability, the Commission will consider any
regional difference at the time it is submitted by NERC for Commission
review. Therefore, if ERCOT wishes to request a regional difference it
must do so through the ERO process.
b. Documentation of Total Transfer Capability and Available Transfer
Capability Calculation Methodologies (MOD-001-0)
i. NERC Proposal
    596. NERC states that the purpose of MOD-001-0 is to promote the
consistent and uniform application of transfer capability calculations
among transmission system users. The Reliability Standard requires the
regional reliability organizations to develop their respective methods
for determining TTC and ATC and to make those methodologies available
to others for review. The Reliability Standard contains two
Requirements directing each regional reliability organization to: (1)
Develop and document a regional TTC and ATC methodology in conjunction
with its members; and (2)

post the most recent version of its TTC and ATC methodology at a Web
site accessible by NERC, the regional reliability organizations, and
transmission users.
    597. The first Requirement specifies nine items that the regional
reliability organization must include in its methodology for
determining its TTC and ATC values. Most of these items call for
descriptions on how TTC and ATC values are determined and what
assumptions are used. Two items require the regional reliability
organization to take into account the reservations and schedules for
transactions occurring inside and outside the transmission provider's
system. One item specifies a time and frequency for calculating and
posting TTC and ATC values.
ii. Staff Preliminary Assessment
    598. Staff identified MOD-001-0 as a ``fill-in-the-blank'' standard
that applies to the regional reliability organization. Staff expressed
concern that industry historically used inconsistent calculation
methodologies and stated that this inconsistency could have an undue
negative impact on competition.
iii. Comments
    599. Although NERC acknowledges that proposed Reliability Standard
MOD-001-0 needs improvement, it urges that the Commission approve it.
NERC explains that the final version of the ATC/TTC/AFC Revision SAR
proposes a method for calculating ATC and requires that specific
reliability practices be incorporated into the ATC calculation and
coordination methodologies. Further, NERC advises that a requirement
will be added to enhance documentation of the calculation.
    600. MRO acknowledges that, because TTC and ATC values must satisfy
certain principles, which balance both technical and commercial issues
from each of the regions, there may be differences in the calculation
of these values from the different regions. However, MRO adds that the
parties in the Eastern Interconnection must agree to the values,
calculations, and methodologies which flow across the borders of
various regions and system operators. MRO states that these should be
transparent and agreements should be based on rational, technical
requirements.
    601. ReliabilityFirst submits that it generally agrees with staff's
evaluation that, to ensure consistency, procedures developed by the
individual regions need to be combined. Similarly, TAPS advises that
there are significant flaws and undue competitive impacts in the way
the Reliability Standard is currently proposed. TAPS urges the
Commission to make the calculations related to this Reliability
Standard transparent, consistent, and regionally-based.
iv. Commission Proposal
    602. MOD-001-0 is a ``fill-in-the-blank'' standard that requires
each regional reliability organization to develop its respective
methods for determining TTC and ATC and to make those methodologies
available to others for review. Because the regional procedures have
not been submitted to the Commission, it is not possible to determine
at this time whether MOD-001-0 satisfies the statutory requirement that
a proposed Reliability Standard be ``just, reasonable, not unduly
discriminatory or preferential, and in the public interest.''
Accordingly, the Commission will not propose to accept or remand this
Reliability Standard until the ERO submits additional information. In
the interim, compliance with MOD-001-0 should continue on its current
basis, and the Commission considers compliance with the Reliability
Standard to be a matter of good utility practice. Although we do not
propose any action with regard to MOD-001-0 at this time, we address
our concerns regarding this Reliability Standard below. The concerns we
discuss below are consistent with the OATT Reform NOPR.\246\
---------------------------------------------------------------------------

    \246\ OATT Reform NOPR at ] 155-70.
---------------------------------------------------------------------------

    603. The Reliability Standard only requires that the regional
reliability organization document its ATC and TTC methodology and post
that documentation. The Reliability Standard does not contain clear
Requirements on how ATC and TTC should be calculated, which has
resulted in diverse interpretations of ATC, TTC, and the development of
various calculation methodologies, modeling assumptions, and data
exchange protocols by various entities.\247\ This creates potential
reliability issues and an opportunity to unduly discriminate against
competitors.
---------------------------------------------------------------------------

    \247\ For example, there are two primary ATC calculation
methodologies: the contract path approach and the flowgate approach.
However, the ATC values that result from application of either
method should largely be the same if consistent data inputs and
modeling assumptions are used. See OATT Reform NOPR, 71 FR 32653.
---------------------------------------------------------------------------

    604. Further, the different approaches in calculation of ATC/
AFC,\248\ TTC, and lack of clear requirements for calculation of
existing transmission commitments (ETC) \249\ could also create an
undue negative impact on competition. For example, NERC has not
proposed either a definition or Reliability Standard on how ETC should
be determined. This could allow transmission providers to set aside
more capacity for native load than is needed, and ultimately block
capacity that would otherwise be available to unaffiliated transmission
customers. This also gives broad discretion to a transmission provider
to determine how to model power transfers and associated loop flows
that impact the neighboring systems reliability. We believe that this
Reliability Standard should, at a minimum, provide a framework for the
ATC, TTC, and ETC calculation.
---------------------------------------------------------------------------

    \248\ Available Flowgate Capability is a method widely used in
the Eastern Interconnection but there is no NERC definition for that
term.
    \249\ ETC includes transmission capacity set aside for both
native load and transmission reservations.
---------------------------------------------------------------------------

    605. MOD-001-0 requires that the regional reliability organization
develop and post its methodology on TTC and ATC, but only requires a
narrative description of a few elements of the TTC and ATC calculation.
We believe that this Reliability Standard should include a requirement
that applicable entities make available a comprehensive list of
assumptions and contingencies underlying ATC and TTC calculations. We
believe that such documentation should include mathematical algorithms,
process flow diagrams, data inputs, identification of flowgates, and
modeling assumptions used to perform the TTC and ATC calculations,
consistent with those proposed in the OATT Reform NOPR.
    606. We are further concerned that the Reliability Standard does
not clearly define the data to be shared among transmission service
providers. We believe that MOD-001-0 could be improved by identifying a
detailed list of information to be shared. This is consistent with the
OATT Reform NOPR, which proposes that, at a minimum, the following data
should be exchanged among transmission providers for the purposes of
ATC modeling: (1) Load levels; (2) transmission planned and contingency
outages; (3) generation planned and contingency outages; (4) base
generation dispatch; (5) existing transmission reservations, including
counterflows; (6) ATC calculation frequency; and (7) source/sink
modeling identification.
    607. In addition, the Commission notes that MOD-001-0
inappropriately combines the requirements for TTC and ATC methodology
into one Reliability Standard. TTC and ATC serve two different purposes
and are calculated through different calculation processes. We believe
that MOD-001-0 should

address only the ATC and AFC requirements while the TTC requirements
should be addressed in a separate Reliability Standard such as FAC-012-
1, as discussed below.
    608. The NERC glossary does not substantially differentiate between
the definition of TTC (as used in MOD-001-0) \250\ and transfer
capability (as used in FAC-012-1).\251\ Thus, there are two Reliability
Standards to measure essentially the same thing: One Reliability
Standard calculates TTC using one set of data and modeling assumptions
presumably for use in evaluating transmission service requests, and
another Reliability Standard calculates transfer capability for in-
house use in planning and operations studies. This will not only cause
confusion, but also opportunities for discrimination against
transmission customers. We believe that the TTC calculation methodology
should be addressed under FAC-012-1, which standardizes transfer
capability methodology.
---------------------------------------------------------------------------

    \250\ Total Transfer Capability is defined in the NERC glossary
as ``[t]he amount of electric power that can be moved or transferred
reliably from one area to another area of the interconnected
transmission systems by way of all transmission lines (or paths)
between those areas under specified system conditions.'' NERC
glossary at 14.
    \251\ Transfer Capability is defined in NERC glossary as ``[t]he
measure of the ability of interconnected electric systems to move or
transfer power in a reliable manner from one area to another over
all transmission lines (or paths) between those areas under
specified system conditions. The units of transfer capability are in
terms of electric power, generally expressed in megawatts (MW). The
transfer capability from `Area A' to `Area B' is not generally equal
to the transfer capability from `Area B' to `Area A.' '' NERC
glossary at 15.
---------------------------------------------------------------------------

    609. We reiterate our concern expressed in the OATT Reform NOPR
that modeling assumptions are a crucial element in the calculation of
ATC.\252\ We believe that NERC should develop a set of consistent
assumptions as a part of MOD-001-0 for use in ATC and AFC
determinations. Consistent with the OATT Reform NOPR, we believe that
the assumptions in the calculation of ATC and AFC should be used
consistently among transmission providers to the maximum extent
practicable. In general, the Commission believes that the assumptions
used in the determination of ATC and AFC should be consistent with
those used for planning the expansion or operation of the Bulk-Power
System. Consequently, the models for short- and long-term ATC and AFC
calculation should be developed using consistent assumptions regarding
the load level, generation dispatch, transmission and generation
facilities maintenance schedules, contingency outages and topology as
those used for expansion planning and operations. Consistent with the
OATT Reform NOPR, we believe that the long-term ATC and AFC models
should rely to the maximum extent possible on the same assumptions
regarding new transmission and generation facility additions and
retirements as those used in the planning for expansion. Specifically,
MOD-001-0 should contain a Requirement that long-term ATC (one year and
longer) be based on the calculation that uses the same power flow
models, assumptions regarding load, generation dispatch, special
protection systems, post contingency switching, and transmission and
generation facility additions and retirements as those used in the
expansion planning for the same time frame.
---------------------------------------------------------------------------

    \252\ OATT Reform NOPR at P 166.
---------------------------------------------------------------------------

    610. Finally, the applicability section identifies that the
Reliability Standard applies to regional reliability organizations.
Consistent with our discussion above, we believe that NERC should
identify the applicable entities in terms of users, owners, and
operators of the Bulk-Power System.\253\
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    \253\ We note that our observation here also applies to MOD-002,
MOD-003, MOD-004, MOD-005, MOD-008, MOD-009, MOD-011, MOD-013, MOD-
014, MOD-015, MOD-016, MOD-024, and MOD-025.
---------------------------------------------------------------------------

c. Review of Transmission Service Provider Total Transfer Capability
and Available Transfer Capability Calculations and Results (MOD-002-0)
i. NERC Proposal
    611. MOD-002-0 concerns the review of transmission service
providers' compliance with the regional methodologies for calculating
TTC and ATC. It requires that the regional reliability organization:
(1) Develop and implement a procedure to periodically review and ensure
that the TTC and ATC calculations and resulting values developed by
transmission service providers comply with the regional TTC and ATC
methodology and applicable regional criteria; (2) document the results
of its periodic review of TTC and ATC; and (3) provide the results of
its most current reviews to NERC on request within 30 calendar days.
ii. Staff Preliminary Assessment
    612. Staff identified no substantive issues other than the fact
that MOD-002-0 is a ``fill-in-the-blank'' standard and that the
standard applies to the regional reliability organization.
iii. Comments
    613. The Commission received no specific comments regarding MOD-
002-0.
iv. Commission Proposal
    614. MOD-002-0 is a ``fill-in-the-blank'' Reliability Standard that
requires each regional reliability organization to develop and
implement a procedure to periodically review and ensure that a
transmission service provider's TTC and ATC calculations comply with
regional TTC and ATC methodologies and criteria. Because the regional
procedures have not been submitted to the Commission, it is not
possible to determine at this time whether MOD-002-0 satisfies the
statutory requirement that a proposed Reliability Standard be ``just,
reasonable, not unduly discriminatory or preferential, and in the
public interest.'' Accordingly, the Commission will not propose to
approve or remand this Reliability Standard until the regional
procedures are submitted. In the interim, compliance with MOD-002-0
should continue on a voluntary basis, and the Commission considers
compliance with the Reliability Standard to be a matter of good utility
practice.
d. Regional Procedure for Input on Total Transfer Capability and
Available Transfer Capability Methodologies and Values (MOD-003-0)
i. NERC Proposal
    615. MOD-003-0 defines how a transmission user can submit its
concerns regarding ATC/TTC calculation methodologies and values. It
requires each regional reliability organization to: (1) Develop and
document a procedure on how a transmission user can input their
concerns or questions regarding TTC and ATC calculations including the
TTC and ATC values, and how these concerns will be addressed; and (2)
make its procedure for receiving and addressing these concerns
available to other regional reliability organizations, NERC and
transmission users on its Web site.
ii. Staff Preliminary Assessment
    616. The Staff Preliminary Assessment noted that MOD-003-0 is a
``fill-in-the-blank'' standard. It also raised concern that MOD-003-0
does not provide a consistent procedure for transmission users to input
concerns or questions regarding the methodology for calculation of TTC
and ATC and resulting TTC and ATC values, nor does it provide a
consistent procedure for

how these questions or concerns will be addressed.
iii. Comments
    617. The Commission received no comments regarding MOD-003-0.
iv. Commission Proposal
    618. MOD-003-0 is a ``fill-in-the-blank'' standard that requires
each regional reliability organization to develop and document a
procedure to on how a transmission user can input its concerns
regarding the TTC and ATC methodologies of a transmission service
provider. Because the regional procedures have not been submitted to
the Commission, it is not possible to determine at this time whether
MOD-003-0 satisfies the statutory requirement that a proposed
Reliability Standard be ``just, reasonable, not unduly discriminatory
or preferential, and in the public interest.'' Accordingly, the
Commission will not propose to accept or remand this Reliability
Standard until the regional procedures are submitted. In the interim,
compliance with MOD-003-0 should continue on a voluntary basis, and the
Commission considers compliance with the Reliability Standard to be a
matter of good utility practice.
e. Documentation of Regional Reliability Organization Capacity Benefit
Margin Methodologies (MOD-004-0)
i. NERC Proposal
    619. NERC states that the purpose of MOD-004-0 is to promote the
consistent and uniform application of transmission transfer capability
margin. MOD-004-0 addresses the development of a regional methodology
for CBM.\254\ The Reliability Standard requires each regional
reliability organization to: (1) Develop and document a regional CBM
methodology in conjunction with its members; and (2) post the most
recent version of its CBM methodology on a Web site accessible by NERC,
regional reliability organizations, and transmission users.
---------------------------------------------------------------------------

    \254\ The NERC glossary defines ``capacity benefit margin'' or
``CBM'' as the amount of firm transmission transfer capability
preserved by a transmission provider for load serving entities whose
loads are located on the transmission service provider's system, to
enable access by the load serving entity to generation from
interconnected systems to meet generation reliability requirements.
NERC glossary at 2.
---------------------------------------------------------------------------

    620. The first Requirement specifies ten items that the regional
reliability organization must include and explain in its CBM
calculation method. In addition, the Reliability Standard requires that
other regional reliability organization-specific items be explained
along with their use in determining CBM values. These requirements
specify that calculation of CBM be consistent with the generation
planning criteria, and that generation outages simulated in a
transmission provider's CBM calculation be restricted to those
generators located within the transmission provider's system. It is
also required that CBM should be preserved only for the load within the
control area. The allocation process of the CBM should be identified.
In addition, it requires that the sum of the CBM values allocated to
all interfaces at one control area shall not exceed the portion of the
generation reliability requirement that is to be provided from outside
resources. The remaining items require a description of the rationale
regarding the assumptions used for CBM calculation. Finally, it
requires a description of the formal process and rational for the
regional reliability organization to grant any variances to individual
transmission providers from the regional reliability organization's CBM
methodology.
ii. Staff Preliminary Assessment
    621. The Staff Preliminary Assessment noted that MOD-004-0 is a
``fill-in-the-blank'' standard. Further, while MOD-004-0 requires each
regional reliability organization to develop and document a regional
CBM methodology, it does not specify how CBM is determined and
allocated across transmission paths. Staff expressed concern that the
Reliability Standard does not address the effect of associated
transmission service requirements and curtailment provisions on
transmission customers nor does it specify the criteria used in
determining whether or not to include generation resources, reserves,
and loads in its methodology as described in four of the Requirements
(R1.5, R1.6, R1.9, and R1.10).
iii. Comments
    622. NERC points out that the CBM/TRM Revisions Standard
Authorization Request (SAR) proposes requiring crisp and clear
calculation documentation and making various components of the
methodology mandatory to ensure consistency.
    623. TAPS agrees with staff's evaluation of MOD-004-0. TAPS states
that the proposed Reliability Standard has significant flaws and will
harm competition if accepted in its current form. For example, TAPS
refers to the significant potential for abuse because transmission
providers have flexibility in the calculation of CBM. Further, TAPS
questions how CBM can be viewed as a Reliability Standard if it is
optional to the transmission provider. TAPS urges the Commission to
make the calculations related to this standard transparent, consistent,
and regionally-based.
iv. Commission Proposal
    624. MOD-004-0 is a ``fill-in-the-blank'' Reliability Standard that
requires each regional reliability organization to develop and document
a regional CBM methodology. Because the regional CBM methodologies have
not been submitted to the Commission, it is not possible for determine
at this time whether MOD-004-0 satisfies the statutory requirement that
a proposed Reliability Standard be ``just, reasonable, not unduly
discriminatory or preferential, and in the public interest.''
Accordingly, the Commission will not propose to accept or remand this
Reliability Standard until the regional procedures are submitted. In
the interim, compliance with MOD-004-0 should continue on a voluntary
basis, and the Commission considers compliance with the Reliability
Standard to be a matter of good utility practice.
    625. Although we do not propose any action with regard to MOD-004-0
at this time, we address our concerns regarding the Reliability
Standard below.
    626. We share TAPS' concern that MOD-004-0 may contain significant
flaws and may unduly impact competition. The Commission expressed
similar concerns with the CBM calculation in the OATT Reform NOPR. The
lack of consistent criteria and clarity with regard to the entity on
whose behalf CBM has been set aside has the potential to result in the
transmission provider setting aside capacity that it might not
otherwise need to, thus increasing costs for native load customers and
blocking third party uses of the transmission system.\255 \
---------------------------------------------------------------------------

    \255\ The Commission has explained that the pro forma OATT
requires both transmission customers and transmission providers
using the transmission system to serve network load (including
bundled retail native load) to designate their resources and loads
so that the transmission customers and transmission providers would
have no incentive to designate network resources above their needs
and, in so doing, tie up valuable transmission capacity. Aquila
Power Corp. v. Entergy Services, Inc., 90 FERC ] 61,260, reh'g
denied, 92 FERC ] 61,064 (2000), reh'g denied, 101 FERC] 61,328
(2002), aff'd sub nom. Entergy Services, Inc. v. FERC, 375 F.3d 1204
(D.C. Cir. 2004).
---------------------------------------------------------------------------

    627. We also share TAPS' concern that the calculations related to
this Reliability Standard must be transparent and consistent. We are
concerned with the latitude that transmission providers have when
preserving a portion of transfer capability for CBM. There are

no consistent industry-wide standards for determining how much transfer
capability should be set aside as CBM and how that amount should be
allocated to interfaces. Therefore, we believe that MOD-004-0 could be
improved by providing more specific Requirements on how CBM should be
determined and allocated to interfaces.
    628. In response to TAPS's question about how CBM can be viewed as
a Reliability Standard if it is optional to the Transmission Provider,
our understanding is that transmission providers that opt not to use
CBM could instead set aside transmission margin (needed to meet the
generation Reliability Standard) either through ETC or TRM. Obviously,
CBM is not the only way to preserve transmission margin. However, if
the Reliability Standard is not clear regarding the method to calculate
transmission margin, it may cause double-counting of transmission
margins and reduction of ATC. Therefore, we believe that MOD-004-0
could be improved by including a provision ensuring that CBM, TRM, and
ETC cannot be used for the same purpose, such as the loss of the
identical generation unit. Without a clear requirement against double-
counting of margins causing ATC decrease, there is a possibility that
such double-counting may be used to prevent the non-affiliated third
party's access to the transmission system.
f. Procedure for Verifying Capacity Benefit Margin Values (MOD-005-0)
i. NERC Proposal
    629. The Reliability Standard specifies the requirements regarding
the periodic review of a transmission service provider's adherence to
the regional reliability organization's CBM methodology. This
Reliability Standard has three Requirements. The first Requirement
calls for each regional reliability organization to develop and
implement a procedure to review at least annually the CBM calculations
and the resulting values determined by member transmission service
providers. The second Requirement mandates that the regional
reliability organization document its CBM review procedure and make it
available to NERC on request within 30 calendar days. The third
Requirement specifies that the regional reliability organization must
make the results of the most current CBM review available to NERC on
request, within 30 calendar days. There are several sub-requirements
specifying the regional reliability organization's CBM review process,
including an assurance that the transmission provider's CBM components
are calculated consistently with its planning criteria, and a
Requirement that CBM values are at least annually updated and made
available to the regional reliability organization, NERC, and
transmission users.
ii. Staff Preliminary Assessment
    630. Staff Preliminary Assessment noted that although MOD-005-0
requires each regional reliability organization to review the CBM
calculations and the resulting values, it does not require a consistent
and uniform calculation of CBM.
iii. Comments
    631. The Commission received no comments regarding MOD-005-0.
iv. Commission Proposal
    632. MOD-005-0 is a ``fill-in-the-blank'' standard that requires
the regional reliability organization to develop and implement a
procedure to review the CBM calculations and the resulting values and
to make the documentation of the results of the CBM review available to
NERC and others. Because the regional procedures have not been
submitted to the Commission, it is not possible to determine at this
time whether MOD-005-0 satisfies the statutory requirement that a
proposed Reliability Standard be ``just, reasonable, not unduly
discriminatory or preferential, and in the public interest.''
Accordingly, the Commission will not propose to accept or remand this
Reliability Standard until the ERO submits additional information. In
the interim, compliance with MOD-005-0 should continue on a voluntary
basis, and the Commission considers compliance with the Reliability
Standard to be a matter of good utility practice.
g. Procedure for the Use of Capacity Benefit Margin Values (MOD-006-0)
i. NERC Proposal
    633. NERC states that the purpose of MOD-006-0 is to promote the
consistent and uniform use of transmission transfer capability margins
calculations among transmission system users. MOD-006-0 requires a
transmission service provider to document and post its procedures on
the use of CBM. Specifically, the Reliability Standard requires that
each transmission service provider document its procedure explaining
scheduling of energy against CBM. It also requires the transmission
service provider to make that procedure available on a Web site
accessible by the regional reliability organization, NERC, and
transmission users.
ii. Staff Preliminary Assessment
    634. Staff stated that it was concerned that proposed Reliability
Standard MOD-006-0 does not require a consistent and uniform
calculation of CBM.
iii. Comments
    635. The Commission received no comments regarding MOD-006-0.
iv. Commission Proposal
    636. The Commission proposes to approve MOD-006-0 as mandatory and
enforceable. In addition, we propose to direct NERC to modify the
Reliability Standard, as discussed below.
    637. As discussed above regarding MOD-004-0, we are concerned that
there is an opportunity to double-count transmission margins CBM and
TRM, which will result in lower ATC values. Without a clear requirement
against double-counting margins, this may be used to prevent non-
affiliated third party access to the transmission system. Therefore, we
propose to direct the ERO to modify this Reliability Standard to
include a provision that will ensure that CBM and TRM cannot be used
for the same purpose.
    638. Requirement R1.2 of MOD-006-0 calls for CBM to be used by a
load-serving entity that experiences a generation deficiency only when
its transmission provider simultaneously experiences ``transmission
constraints relative to imports of energy on its transmission system.''
It is our understanding that a load-serving entity can experience a
generation deficiency without the simultaneous transmission constraint
on its transmission service provider's system. Therefore, we propose
that the ERO modify Requirement R1.2 so that concurrent occurrence of
transmission constraints is not a required condition for CBM usage.
    639. Moreover, the Reliability Standard does not specify how the
generation deficiency is identified. We propose to direct that the ERO
define ``generation deficiency'' based on a specific energy emergency
alert level (specified in the EOP Reliability Standards) that triggers
CBM usage.
    640. The Commission believes that CBM should be used only when the
load-serving entity's local generation capacity is insufficient to meet
balancing Reliability Standards. Moreover, a load-serving entity that
has sufficient generation resources within its balancing authority to
meet the balancing Reliability Standards should

not need to preserve capacity for CBM at all. In addition, we believe
that CBM should have a zero value in the calculation of non-firm ATC.
Based on this guidance, we propose that NERC should clarify the
Requirements to address when and how CBM can be used to reduce
transmission provider discretion with regard to CBM usage.
    641. Requirement R1.2 of MOD-006-0 provides that CBM shall only be
used if the load-serving entity calling for its use is experiencing a
generation deficiency. The applicability section, however, applies to
only transmission service providers and not load-serving entities. The
Commission believes that the applicability section should be expanded
to include the entities that actually use CBM, such as load serving
entities.
    642. Accordingly, giving due weight to the technical expertise of
the ERO and with the expectation that the Reliability Standard will
accomplish the purpose represented to the Commission by the ERO and
that it will improve the reliability of the nation's Bulk-Power System,
the Commission proposes to approve Reliability Standard MOD-006-0 as
mandatory and enforceable. In addition, pursuant to section 215(d)(5)
of the FPA and Sec.  39.5(f) of our regulations, we propose directing
that NERC submit a modification to MOD-006-0 that: (1) Includes a
provision that will ensure that CBM and TRM are not used for the same
purpose; (2) modifies Requirement R1.2 so that concurrent occurrence of
generation deficiency and transmission constraints is not a required
condition for CBM usage; (3) modifies Requirement R1.2 to define
``generation deficiency'' based on a specific energy emergency alert
level; and (4) expands the applicability section to include the
entities that actually use CBM, such as load serving entities.
h. Documentation of the Use of Capacity Benefit Margin (MOD-007-0)
i. NERC Proposal
    643. NERC states that the purpose of MOD-007-0 is to promote the
consistent use of transmission transfer capability margin calculations
among transmission system users. MOD-007-0 requires transmission
service providers that use CBM to report and post its use. This
Reliability Standard has two Requirements. The first Requirement calls
for each transmission provider that uses CBM, at the request of a load-
serving entity, to report that use to the regional reliability
organization, NERC and the transmission users. The transmission service
provider is not required to report the occasions when CBM is sold on a
non-firm basis. The second Requirement is that, for any use of CBM
concurrent with an energy emergency situation, the transmission service
provider must disclose and post circumstances, duration, and the amount
of CBM used on a Web site accessible by the regional reliability
organization, NERC, and transmission users.
ii. Staff Preliminary Assessment
    644. Staff noted that MOD-007-0 does not specify how CBM should be
preserved, which is important to allow both transmission providers and
transmission customers to meet their respective generation reliability
criteria.
iii. Comments
    645. The Commission received no comments regarding MOD-007-0.
iv. Commission Proposal
    646. The Commission proposes to approve MOD-007-0 as mandatory and
enforceable. In addition, we propose to direct that NERC develop
modifications to the Reliability Standard, as discussed below.
    647. Requirement R1 of MOD-007-0 provides that the use of CBM by
the load-serving entity shall be documented. However, the applicability
section of MOD-007-0 applies to only transmission service providers and
not load-serving entities. The Commission believes that the
applicability section should be expanded to include the entities that
actually use CBM, such as load-serving entities.
    648. Accordingly, giving due weight to the technical expertise of
the ERO and with the expectation that the Reliability Standard will
accomplish the purpose represented to the Commission by the ERO and
that it will improve the reliability of the nation's Bulk-Power System,
the Commission proposes to approve Reliability Standard MOD-007-0 as
mandatory and enforceable. In addition, pursuant to section 215(d)(5)
of the FPA and Sec.  39.5(f) of our regulations, we propose directing
that NERC to submit a modification to MOD-007-0 that expands the
applicability section to include the entities that actually use CBM,
such as load-serving entities.
i. Documentation and Content of Each Regional Transmission Reliability
Margin Methodology (MOD-008-0)
i. NERC Proposal
    649. NERC notes that the purpose of MOD-008-0 is to promote the
consistent application of transmission transfer capability margin
calculations among transmission service providers and transmission
owners. MOD-008-0 requires the development and posting of a regional
methodology for TRM, a transmission capacity that is preserved to
provide reasonable assurance that the interconnected transmission
network will remain secure under various system conditions. The
Reliability Standard specifies two Requirements for the regional
reliability organization to: (1) Develop and document a regional TRM
methodology in conjunction with its members, and (2) post the most
recent version of its TRM methodology on a Web site accessible by NERC,
the regional reliability organizations, and transmission users.
    650. The first Requirement specifies five items that the regional
reliability organization must include and explain in its TRM
calculation method. In addition, the Reliability Standard allows other
items specific to a regional reliability organization to be explained
along with their use in determining TRM values, if such items exist.
Some of these items require the regional reliability organization to
specify TRM update frequency, describe how TRM values are accounted for
in ATC calculations, and detail which uncertainties are accounted for
in TRM. The regional reliability organization must also describe how
transmission capacity preserved for TRM can be sold for non-firm
services.
ii. Staff Preliminary Assessment
    651. Staff noted that although MOD-008-0 requires each regional
reliability organization to develop and document a Regional TRM
methodology, it does not specify how TRM is determined and allocated
across transmission paths. Staff also stated that the Requirement R1.5
does not specify the criteria for granting variances from the regional
TRM methodology.
iii. Comments
    652. NERC points out that a Reliability Standard is under
development that will make various components of the methodology
mandatory to ensure consistency.
    653. MRO advocates that MOD-008-0 should specify the criteria for
granting variances.
iv. Commission Proposal
    654. MOD-008-0 is a ``fill-in-the-blank'' Reliability Standard that
requires each regional reliability organization to develop a
methodology for determining TRM and to make the methodology available
to others for review. Because the regional methodologies have not been
submitted to the Commission, it is

not possible to determine at this time whether MOD-008-0 satisfies the
statutory requirement that a proposed Reliability Standard be ``just,
reasonable, not unduly discriminatory or preferential, and in the
public interest.'' Accordingly, the Commission will not propose to
accept or remand this Reliability Standard until the ERO submits
additional information. In the interim, compliance with MOD-008-0
should continue on its current basis, and the Commission considers
compliance with the Reliability Standard to be a matter of good utility
practice.
    655. Although we do not propose any action with regard to MOD-008-0
at this time, we address our concerns regarding this Reliability
Standard below.
    656. We are concerned about the lack of clear requirements on how
TRM should be calculated and allocated across the paths. In addition,
the lack of consistent criteria and clarity with regard to the entity
on whose behalf TRM has been set aside may result in the transmission
provider setting aside excess capacity, thus increasing costs for
native load customers, and blocking third party uses of the
transmission system. We seek comments on how TRM is currently
calculated and allocated across the paths, and what would be a
recommended approach for the future.
j. Procedure for Verifying Transmission Reliability Margin Values (MOD-
009-0)
i. NERC Proposal
    657. MOD-009-0 specifies the Requirements for establishing a
procedure for periodic review of a transmission provider's adherence to
the relevant regional reliability organization's TRM methodology. This
Reliability Standard has three Requirements. The first Requirement
calls for each regional reliability organization to develop and
implement a procedure to review TRM calculations and the resulting
values determined by member transmission providers to ensure compliance
with the regional TRM methodology. The second Requirement is that the
regional reliability organization documents its TRM review procedure
and makes that available to NERC on request within 30 calendar days.
The third Requirement specifies that the reliability regional
organization must make the documentation of the results of the most
current TRM review available to NERC on request, within 30 calendar
days.
ii. Staff Preliminary Assessment
    658. Staff noted that MOD-009-0 does not provide a consistent
procedure for review of TRM calculations and the resulting values.
iii. Comments
    659. The Commission received no specific comments regarding MOD-
009-0.
iv. Commission Proposal
    660. MOD-009-0 is a ``fill-in-the-blank'' Reliability Standard that
requires each regional reliability organization to develop its
procedure for review of TRM calculations and the resulting values.
Because the regional procedures have not been submitted to the
Commission, it is not possible to determine at this time whether MOD-
009-0 satisfies the statutory requirement that a proposed Reliability
Standard be ``just, reasonable, not unduly discriminatory or
preferential, and in the public interest.'' Accordingly, the Commission
will not propose to accept or remand this Reliability Standard until
the ERO submits additional information. In the interim, compliance with
MOD-009-0 should continue on its current basis, and the Commission
considers compliance with the Reliability Standard to be a matter of
good utility practice.
k. Steady-State Data for Modeling and Simulation of Interconnected
Transmission System (MOD-010-0)
i. NERC Proposal
    661. The purpose of this Reliability Standard is to establish
consistent data requirements, reporting procedures, and system models
to be used in the reliability analysis. MOD-010-0 requires the
transmission owner, transmission planner, generator owner, and resource
planner to provide steady-state data, such as equipment
characteristics, system data, and existing and future interchange
schedules, to the regional reliability organization, NERC, and entities
specified in Requirement R1 of MOD-011-0. Data is to be provided within
the determined time schedule or upon request if no time schedule
exists.
ii. Staff Preliminary Assessment
    662. Staff noted that MOD-010-0 does not include the planning
authority as an applicable entity. The inclusion of the planning
authority is necessary in the applicability section of the Reliability
Standard because the planning authority is the entity responsible for
the coordination and integration of transmission facilities and
resource plans, as well as one of the entities responsible for the
integrity and consistency of the data.
iii. Comments
    663. MRO and ReliabilityFirst state that they generally agree with
staff's evaluation of MOD-010-0. However, in response to the staff
comment regarding inappropriate exclusion of the planning authority
from the Reliability Standard's applicability, ReliabilityFirst points
out that the information required by the Reliability Standard
originates with the transmission planner and resource planner who,
ultimately, provide such information to the planning authority.
Similarly, PG&E states that a planning authority does not develop, and
cannot provide such information and is rightly not included in the
applicability section of the standard. PG&E explains that MOD-010-0
requires transmission owners, transmission planners, generator owners,
and resource planners to provide appropriate equipment characteristics,
system data, and existing and future interchange schedules in
compliance with Interconnection regional steady-state or dynamic
modeling and simulation data requirements and reporting procedures.
iv. Commission Proposal
    664. The Commission proposes to approve MOD-010-0 as mandatory and
enforceable. In addition, we propose to direct that NERC develop
modifications to the Reliability Standard, as discussed below.
    665. We propose that MOD-010-0 should add a new requirement to have
the transmission owners also provide the list of the contingencies they
use in performing system operation and planning studies. We believe
that access to such information will enable neighboring systems to
accurately study their effects on their own systems.
    666. In addition, we propose that the Reliability Standard should
be modified to apply to the planning authority. The planning authority
is the entity responsible for coordination and integration of
transmission facilities and resource plans, as well as one of the
entities responsible for the integrity and consistency of the data. We
disagree with commenters that the planning authority should be omitted
from the applicability section because it merely gets the data from the
others. We believe that the planning authority plays a significant role
in integration of the data.
    667. Accordingly, giving due weight to the technical expertise of
the ERO and with the expectation that the Reliability Standard will
accomplish the

purpose represented to the Commission by the ERO and that it will
improve the reliability of the nation's Bulk-Power System, the
Commission proposes to approve Reliability Standard MOD-010-0 as
mandatory and enforceable. In addition, pursuant to section 215(d)(5)
of the FPA and Sec.  39.5(f) of our regulations, we propose to direct
that NERC to submit a modification to MOD-010-0 that: (1) Adds a new
requirement for transmission owners to provide the list of
contingencies they use in performing system operation and planning
studies; and (2) expands the applicability section to include the
planning authority.
l. Maintenance and Distribution of Steady-State Data Requirements and
Reporting Procedures (MOD-011-0)
i. NERC Proposal
    668. The purpose of MOD-011-0 is to establish consistent data
requirements, reporting procedures, and system models to be used in the
reliability analysis. MOD-011-0 requires the regional reliability
organization within an Interconnection to develop comprehensive steady-
state data requirements and reporting procedures needed to model and
analyze the steady-state conditions for each of the three NERC
Interconnections. The regional reliability organizations within an
Interconnection are required to:
    (1) Document their Interconnection's data requirements and
reporting procedures;
    (2) Review the data requirements and reporting procedures at least
every five years; and
    (3) Make the data requirements and reporting procedures available
on request to the regional reliability organizations, NERC, and all
users of the interconnected transmission system.
ii. Staff Preliminary Assessment
    669. Staff noted that MOD-011-0, identified as a ``fill-in-the-
blank'' standard, does not include the planning authority in the
Requirements section. The planning authority is the entity responsible
for coordination and integration of transmission facilities and
resource plans, as well as one of the entities responsible for the
integrity and consistency of the data.
iii. Comments
    670. PG&E comments that MOD-011-0 does not need to be modified
because the appropriate planning authority will be a part of the
regional reliability organization.
iv. Commission Proposal
    671. As mentioned above, MOD-011-0 is a ``fill-in-the-blank''
standard that requires the regional reliability organizations within an
Interconnection to develop comprehensive steady-state data requirements
and reporting procedures needed to model and analyze the steady-state
conditions for each of the three NERC Interconnections. Because the
regional methodologies have not been submitted to the Commission, it is
not possible to determine at this time whether MOD-011-0 satisfies the
statutory requirement that a proposed Reliability Standard be ``just,
reasonable, not unduly discriminatory or preferential, and in the
public interest.'' Accordingly, the Commission will not propose to
accept or remand this Reliability Standard until the ERO submits
additional information. In the interim, compliance with MOD-011-0
should continue on its current basis, and the Commission considers
compliance with the Reliability Standard to be a matter of good utility
practice.
    672. As we noted in the discussion of MOD-010-0, we believe that
the planning authority plays a significant role in integration of data
and should also be included in the applicability section of MOD-011-0.
m. Dynamics Data for Modeling and Simulation of the Interconnected
Transmission System (MOD-012-0)
i. NERC Proposal
    673. The purpose of MOD-012-0 is to establish consistent data
requirements, reporting procedures, and system models to be used in the
reliability analysis. MOD-012-0 requires transmission owners,
transmission planners, generator owners, and resource planners to
provide dynamic system modeling and simulation data, such as equipment
characteristics and system data, to the regional reliability
organization, NERC, and entities specified in MOD-013-0, Requirement
R1, within a pre-determined time schedule or upon request if no time
schedule exists.
ii. Staff Preliminary Assessment
    674. Staff stated that proposed Reliability Standard MOD-012-0 does
not apply to the planning authority. However, the planning authority is
the entity responsible for the coordination and integration of
transmission facilities and resource plans, as well as one of the
entities responsible for the integrity and consistency of the data.
iii. Comments
    675. MRO agrees with staff that the planning authority should be
included in MOD-012-0. In contrast, PG&E comments that MOD-012-0 does
not need to be modified, as found by staff's evaluation. Since the
appropriate planning authority is already a part of the regional
reliability organization, specific inclusion of the planning authority
within the Reliability Standard is unnecessary. PG&E explains that,
because MOD-012-0 requires the regional reliability organization within
an Interconnection to develop data requirements and reporting
procedures needed to model and analyze the conditions for each
Interconnection, it already provides for appropriate participation by
the planning authority.
iv. Commission Proposal
    676. We propose that MOD-012-0 add a new requirement for
transmission owners to provide the list of faults or disturbances they
use in performing dynamic stability analysis. We believe that access to
such information will enable neighboring systems to accurately study
their effects on their own systems. As we noted in the discussions of
MOD-010-0 and MOD-11-0, we believe that the planning authority plays a
significant role in integration of data and should also be included in
the applicability section of MOD-012-0.
    677. Accordingly, giving due weight to the technical expertise of
the ERO and with the expectation that the Reliability Standard will
accomplish the purpose represented to the Commission by the ERO and
that it will improve the reliability of the nation's Bulk-Power System,
the Commission proposes to approve Reliability Standard MOD-012-0 as
mandatory and enforceable. In addition, pursuant to section 215(d)(5)
of the FPA and Sec.  39.5(f) of our regulations, we propose directing
that NERC submit a modification to MOD-012-0 that: (1) adds a new
requirement for transmission owners to provide the list of faults or
disturbances they use in performing dynamic stability analysis; and (2)
expands the applicability section to include the planning authority.
n. Maintenance and Distribution of Dynamics Data Requirements and
Reporting Procedures (MOD-013-1)
i. NERC Proposal
    678. The purpose of MOD-013-1 is to establish consistent data
requirements, reporting procedures, and system models to be used in
reliability analysis. MOD-013-1 requires the regional

reliability organizations within an Interconnection to develop
comprehensive dynamics data requirements and reporting procedures
needed to model and analyze the dynamic behavior and response of each
of the three NERC Interconnections. More specifically, the regional
reliability organization, in coordination with its transmission owners,
transmission planners, generator owners, and resource planners within
an Interconnection, is required to: (1) Participate in development of
documentation for their Interconnection data requirements and reporting
procedures; (2) participate in the review of those data requirements
and reporting procedures (at least every five years); and (3) make the
data requirements and reporting procedures available on request to the
regional reliability organizations, NERC, and all users of the
interconnected transmission system on request.
    679. The proposed Reliability Standard specifies the types of
dynamic data that should be included. For example, it specifies that
dynamics data pertaining to generating units, synchronous condensers,
other devices that dynamically respond during disturbances, and
dynamics data representing load characteristics should be provided. In
addition, the Reliability Standard requires that dynamics data be
consistent with the steady state data supplied according to MOD-010-0,
Requirement R1.
    680. NERC's August 28, 2006 Supplemental Filing includes a revised
version of MOD-013, designated MOD-013-1. MOD-013-1 has an additional
Requirement to provide design data for the new or refurbished
excitation systems.
ii. Staff Preliminary Assessment
    681. Staff stated that proposed Reliability Standard does not
include the planning authority in the applicability section. The
inclusion of the planning authority is necessary in the applicability
section of the Reliability Standard because the planning authority is
the entity responsible for coordinating and integrating transmission
facilities and resource plans, as well as one of the entities
responsible for the integrity and consistency of the data.\256\
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    \256\ Although the Staff Preliminary Assessment addresses
concerns regarding the MOD-013-0, many of the same concerns apply to
MOD-013-1 as well.
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iii. Comments
    682. NERC acknowledges that planning authorities also have
responsibilities under the Reliability Standard and the applicability
section should be revised to reflect that. PG&E, on the other hand,
asserts that the proposed Reliability Standard does not need to be
modified, because the appropriate planning authority is a part of the
regional reliability organization, specific inclusion of the planning
authority within the Reliability Standard is unnecessary.
    683. PG&E adds that Requirement R1.1.1, which allows for the use of
estimated or typical manufacturer's data on pre-1990 units to model
dynamic behavior when unit-specific data is unavailable, is arbitrary
in imposing the 1990 cut-off. PG&E asserts that difficulty in obtaining
unit specific data is not limited to the age of the unit but also unit
configuration. As a result, PG&E recommends that the 1990 cut-off be
removed from the proposed Reliability Standard and that the Reliability
Standard be revised to allow the use of estimated or typical
manufacturer data where unit specific data is impractical to obtain.
iv. Commission Proposal
    684. MOD-013-1 is a ``fill-in-the-blank'' Reliability Standard that
requires the regional reliability organizations within an
Interconnection to develop comprehensive dynamics data requirements and
reporting procedures needed to model and analyze the dynamic behavior
or response for each of the three NERC Interconnections. Because the
regional methodologies have not been submitted to the Commission, it is
not possible to determine at this time whether the proposed Reliability
Standard satisfies the statutory requirement that it be ``just,
reasonable, not unduly discriminatory or preferential, and in the
public interest.'' Accordingly, the Commission will not propose to
accept or remand this Reliability Standard until the ERO submits
additional information. In the interim, compliance with the proposed
Reliability Standard should continue, and the Commission considers
compliance with the Reliability Standard to be a matter of good utility
practice. Although we do not propose any action with regard to MOD-013-
1 at this time, we address our concerns regarding this Reliability
Standard below.
    685. We share PG&E's concern regarding the 1990 cut off date that
the difficulty in obtaining unit-specific data is not limited to the
age, but may also be due to other factors such as unit configuration.