[Federal Register Volume 80, Number 228 (Friday, November 27, 2015)]
[Rules and Regulations]
[Pages 73977-73991]
[FR Doc No: 2015-30110]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 40

[Docket No. RM15-16-000, Order No. 817]

Transmission Operations Reliability Standards and Interconnection
Reliability Operations and Coordination Reliability Standards

AGENCY:  Federal Energy Regulatory Commission, Energy.

ACTION:  Final rule.

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SUMMARY:  The Commission approves revisions to the Transmission
Operations and Interconnection Reliability Operations and Coordination
Reliability Standards, developed by the North American Electric
Reliability Corporation, which the Commission has certified as the
Electric Reliability Organization responsible for developing and
enforcing mandatory Reliability Standards. The Commission also directs
NERC to make three modifications to the standards within 18 months of
the effective date of the final rule.

DATES:  This rule will become effective January 26, 2016.

FOR FURTHER INFORMATION CONTACT:
Robert T. Stroh (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street NE., Washington,
DC

20426, Telephone:<PHONE_NUMBER><EMAIL_ADDRESS>Eugene Blick (Technical Information), Office of Electric Reliability,
Federal Energy Regulatory Commission, 888 First Street NE., Washington,
DC 20426, Telephone:<PHONE_NUMBER><EMAIL_ADDRESS>Darrell G. Piatt, PE (Technical Information), Office of Electric
Reliability, Federal Energy Regulatory Commission, 888 First Street
NE., Washington, DC 20426, Telephone:<PHONE_NUMBER>,
<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION:

Order No. 817

Final Rule

(Issued November 19, 2015)
    1. Pursuant to section 215 of the Federal Power Act (FPA),\1\ the
Commission approves revisions to the Transmission Operations (TOP) and
Interconnection Reliability Operations and Coordination (IRO)
Reliability Standards, developed by the North American Electric
Reliability Corporation (NERC), the Commission-certified Electric
Reliability Organization (ERO). The TOP and IRO Reliability Standards
improve on the currently-effective standards by providing a more
precise set of Reliability Standards addressing operating
responsibilities and improving the delineation of responsibilities
between applicable entities. The revised TOP Reliability Standards
eliminate gaps and ambiguities in the currently-effective TOP
requirements and improve efficiency by incorporating the necessary
requirements from the eight currently-effective TOP Reliability
Standards into three comprehensive Reliability Standards. Further, the
standards clarify and improve upon the currently-effective TOP and IRO
Reliability Standards by designating requirements in the proposed
standards that apply to transmission operators for the TOP standards
and reliability coordinators for the IRO standards. Thus, we conclude
that there are benefits to clarifying and bringing efficiencies to the
TOP and IRO Reliability Standards, consistent with the Commission's
policy promoting increased efficiencies in Reliability Standards and
reducing requirements that are either redundant with other currently-
effective requirements or have little reliability benefit.\2\
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    \1\ 16 U.S.C. 824o (2012).
    \2\ Electric Reliability Organization Proposal to Retire
Requirements in Reliability Standards, Order No. 788, 145 FERC ]
61,147 (2013).
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    2. The Commission also finds that NERC has adequately addressed the
concerns raised by the Commission in the Notice of Proposed Rulemaking
issued in November 2013 concerning the proposed treatment of system
operating limits (SOLs) and interconnection reliability operating
limits (IROLs) and concerns about outage coordination.\3\ Further, the
Commission approves the definitions for operational planning analysis
and real-time assessment, the implementation plans and the violation
severity level and violation risk factor assignments. However, the
Commission directs NERC to make three modifications to the standards as
discussed below within 18 months of the effective date of this Final
Rule.
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    \3\ Monitoring System Conditions--Transmission Operations
Reliability Standard, Transmission Operations Reliability Standards,
Interconnection Reliability Operations and Coordination Reliability
Standards, Notice of Proposed Rulemaking, 145 FERC ] 61,158 (2013)
(Remand NOPR). Concurrent with filing the proposed TOP/IRO standards
in the immediate proceeding, NERC submitted a motion to withdraw the
earlier petition that was the subject of the Remand NOPR. No
protests to the motion were filed and the petition was withdrawn
pursuant to 18 CFR 385.216(b).
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    3. We also address below the four issues for which we sought
clarifying comments in the June 18, 2015, Notice of Proposed Rulemaking
(NOPR) proposing to approve the TOP and IRO Reliability Standards: (A)
Possible inconsistencies in identifying IROLs; (B) monitoring of non-
bulk electric system facilities; (C) removal of the load-serving entity
as an applicable entity for proposed Reliability Standard TOP-001-3;
and (D) data exchange capabilities. In addition we address other issues
raised by commenters.

I. Background

A. Regulatory Background

    4. Section 215 of the FPA requires a Commission-certified ERO to
develop mandatory and enforceable Reliability Standards, subject to
Commission review and approval.\4\ Once approved, the Reliability
Standards may be enforced by the ERO subject to Commission oversight,
or by the Commission independently.\5\ In 2006, the Commission
certified NERC as the ERO pursuant to FPA section 215.\6\
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    \4\ 16 U.S.C. 824o(c) and (d).
    \5\ See id. 16 U.S.C. 824o(e).
    \6\ North American Electric Reliability Corp., 116 FERC ]
61,062, order on reh'g and compliance, 117 FERC ] 61,126 (2006),
aff'd sub nom. Alcoa Inc. v. FERC, 564 F.3d 1342 (D.C. Cir. 2009).
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    5. The Commission approved the initial TOP and IRO Reliability
Standards in Order No. 693.\7\ On April 16, 2013, in Docket No. RM13-
14-000, NERC submitted for Commission approval three revised TOP
Reliability Standards to replace the eight currently-effective TOP
standards.\8\ Additionally, on April 16, 2013, in Docket No. RM13-15-
000, NERC submitted for Commission approval four revised IRO
Reliability Standards to replace six currently-effective IRO
Reliability Standards. On November 21, 2013, the Commission issued the
Remand NOPR in which the Commission expressed concern that NERC had
``removed critical reliability aspects that are included in the
currently-effective standards without adequately addressing these
aspects in the proposed standards.'' \9\ The Commission identified two
main concerns and asked for clarification and comment on a number of
other issues. Among other things, the Commission expressed concern that
the proposed TOP Reliability Standards did not require transmission
operators to plan and operate within all SOLs, which is a requirement
in the currently-effective standards. In addition, the Commission
expressed concern that the proposed IRO Reliability Standards did not
require outage coordination.
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    \7\ See Mandatory Reliability Standards for the Bulk-Power
System, Order No. 693, FERC Stats. & Regs. ] 31,242, at P 508, order
on reh'g, Order No. 693-A, 120 FERC ] 61,053 (2007). In addition, in
Order No. 748, the Commission approved revisions to the IRO
Reliability Standards. Mandatory Reliability Standards for
Interconnection Reliability Operating Limits, Order No. 748, 134
FERC ] 61,213 (2011).
    \8\ On April 5, 2013, in Docket No. RM13-12-000, NERC proposed
revisions to Reliability Standard TOP-006-3 to clarify that
transmission operators are responsible for monitoring and reporting
available transmission resources and that balancing authorities are
responsible for monitoring and reporting available generation
resources.
    \9\ Remand NOPR, 145 FERC ] 61,158 at P 4.
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B. NERC Petition

    6. On March 18, 2015, NERC filed a petition with the Commission for
approval of the proposed TOP and IRO Reliability Standards.\10\ As
explained in the Petition, the proposed Reliability Standards
consolidate many of the currently-effective TOP and IRO Reliability
Standards and also replace the TOP and IRO Reliability Standards that
were the subject of the Remand NOPR. NERC stated that the proposed
Reliability Standards include

improvements over the currently-effective TOP and IRO Reliability
Standards in (1) operating within SOLs and IROLs; (2) outage
coordination; (3) situational awareness; (4) improved clarity and
content in foundational definitions; and (5) requirements for
operational reliability data. NERC stated that the proposed TOP and IRO
Reliability Standards address outstanding Commission directives
relevant to the proposed TOP and IRO Reliability Standards. NERC stated
that the proposed Reliability Standards provide a comprehensive
framework for reliable operations, with important improvements to
ensure the bulk electric system is operated within pre-established
limits while enhancing situational awareness and strengthening
operations planning. NERC explained that the proposed Reliability
Standards establish or revise requirements for operations planning,
system monitoring, real-time actions, coordination between applicable
entities, and operational reliability data. NERC contended that the
proposed Reliability Standards help to ensure that reliability
coordinators and transmission operators work together, and with other
functional entities, to operate the bulk electric system within SOLs
and IROLs.\11\ NERC also provided explanations of how the proposed
Reliability Standards address the reliability issues identified in the
report on the Arizona-Southern California Outages on September 8, 2011,
Causes and Recommendations (``2011 Southwest Outage Blackout Report'').
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    \10\ The TOP and IRO Reliability Standards are not attached to
the Final Rule. The complete text of the Reliability Standards is
available on the Commission's eLibrary document retrieval system in
Docket No. RM15-16 and is posted on the ERO's Web site, available
at: http://www.nerc.com.
    \11\ The NERC Glossary of Terms defines IROL as ``[a] System
Operating Limit that, if violated, could lead to instability,
uncontrolled separation, or Cascading outages that adversely impact
the reliability of the Bulk Electric System.'' In turn, NERC defines
SOL as ``[t]he value (such as MW, MVar, Amperes, Frequency or Volts)
that satisfies the most limiting of the prescribed operating
criteria for a specified system configuration to ensure operation
within acceptable reliability criteria. . . .''
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    7. NERC proposed three TOP Reliability Standards to replace the
existing suite of TOP standards. The proposed TOP Reliability Standards
generally address real-time operations and planning for next-day
operations, and apply primarily to the responsibilities and authorities
of transmission operators, with certain requirements applying to the
roles and responsibilities of the balancing authority. Among other
things, NERC stated that the proposed revisions to the TOP Reliability
Standards help ensure that transmission operators plan and operate
within all SOLs. The proposed IRO Reliability Standards, which
complement the proposed TOP Standards, are designed to ensure that the
bulk electric system is planned and operated in a coordinated manner to
perform reliably under normal and abnormal conditions. The proposed IRO
Reliability Standards set forth the responsibility and authority of
reliability coordinators to provide for reliable operations. NERC
stated that, in the proposed IRO Reliability Standards, reliability
coordinators must continue to monitor SOLs in addition to their
obligation in the currently effective Reliability Standards to monitor
and analyze IROLs. These obligations require reliability coordinators
to have the wide-area view necessary for situational awareness and
provide them the ability to respond to system conditions that have the
potential to negatively affect reliable operations.
    8. NERC also proposed revised definitions for ``operational
planning analysis'' and ``real-time assessment.'' For all standards
except proposed Reliability Standards TOP-003-3 and IRO-010-2, NERC
proposed the effective date to be the first day of the first calendar
quarter twelve months after Commission approval. According to NERC's
implementation plan, for proposed TOP-003-3, all requirements except
Requirement R5 will become effective on the first day of the first
calendar quarter nine months after the date that the standard is
approved. For proposed IRO-010-2, Requirements R1 and R2 would become
effective on the first day of the first calendar quarter that is nine
months after the date that the standard is approved. Proposed TOP-003-
3, Requirement R5 and IRO-010-2, Requirement R3 would become effective
on the first day of the first calendar quarter twelve months after the
date that the standard is approved. The reason for the difference in
effective dates for proposed TOP-003-3 and IRO-010-2 is to allow
applicable entities to have time to properly respond to the data
specification requests from their reliability coordinators,
transmission operators, and/or balancing authorities.

C. Notice of Proposed Rulemaking

    9. On June 18, 2015, the Commission issued a Notice of Proposed
Rulemaking proposing to approve the TOP and IRO Reliability Standards
pursuant to FPA section 215(d)(2), along with the two new definitions
referenced in the proposed standards, the assigned violation risk
factors and violation severity levels, and the proposed implementation
plan for each standard.\12\
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    \12\ Transmission Operations Reliability Standards and
Interconnection Reliability Operations and Coordination Reliability
Standards, 151 FERC ] 61,236 (2015) (NOPR).
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    10. In the NOPR, the Commission explained that the proposed TOP and
IRO Reliability Standards improve on the currently-effective standards
by providing a more precise set of Reliability Standards addressing
operating responsibilities and improving the delineation of
responsibilities between applicable entities. The Commission also
proposed to find that NERC has adequately addressed the concerns raised
by the Remand NOPR issued in November 2013.
    11. In the NOPR, the Commission also discussed the following
specific matters and asked for further comment: (A) Possible
inconsistencies in identifying IROLs; (B) monitoring of non-bulk
electric system facilities; (C) removal of the load-serving entity as
an applicable entity for proposed Reliability Standard TOP-001-3; and
(D) data exchange capabilities.
    12. Timely comments on the NOPR were filed by: NERC; Arizona Public
Service Company (APS), Bonneville Power Administration (BPA), Dominion
Resources Services, Inc. (Dominion), the Edison Electric Institute
(EEI); Electric Reliability Council of Texas, Inc. (ERCOT), Independent
Electricity System Operator (IESO), ISO/RTOs,\13\ International
Transmission Company (ITC); Midcontinent Independent System Operator,
Inc., Northern Indiana Public Service Company (NIPSCO), Occidental
Energy Ventures, LLC (Occidental), Peak Reliability (Peak), and
Transmission Access Policy Study Group (TAPS).
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    \13\ ISO/RTOs include Independent Electricity System Operator,
ISO New England Inc., Midcontinent Independent System Operator, New
York Independent System Operator, Inc., PJM Interconnection LLC, and
Southwest Power Pool, Inc.
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II. Discussion

    13. Pursuant to section 215(d) of the FPA, we adopt our NOPR
proposal and approve NERC's revisions to the TOP and IRO Reliability
Standards, including the associated definitions, violation risk
factors, violation severity levels, and implementation plans, as just,
reasonable, not unduly discriminatory or preferential and in the public
interest. We note that all of the commenters that address the matter
support, or do not oppose, approval of the revised suite of TOP and IRO
Reliability Standards. We determine that NERC's approach of
consolidating requirements and removing redundancies generally has
merit and is consistent with Commission policy

promoting increased efficiencies in Reliability Standards and reducing
requirements that are either redundant with other currently-effective
requirements or have little reliability benefit.\14\
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    \14\ See Order No. 788, 145 FERC ] 61,147.
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    14. We also determine that the proposed TOP and IRO Reliability
Standards should improve reliability by defining an appropriate
division of responsibilities between reliability coordinators and
transmission operators.\15\ The proposed TOP Reliability Standards will
eliminate multiple TOP standards, resulting in a more concise set of
standards, reducing redundancy and more clearly delineating
responsibilities between applicable entities. In addition, we find that
the proposed Reliability Standards provide a comprehensive framework as
well as important improvements to ensure that the bulk electric system
is operated within pre-established limits while enhancing situational
awareness and strengthening operations planning. The TOP and IRO
Reliability Standards address the coordinated efforts to plan and
reliably operate the bulk electric system under both normal and
abnormal conditions.
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    \15\ See, e.g., Order No. 748, 134 FERC ] 61,213, at PP 39-40.
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    15. In the NOPR, the Commission proposed to find that NERC
adequately addressed the concerns raised by the Commission in the
Remand NOPR with respect to (1) the treatment of SOLs in the proposed
TOP Reliability Standards, and (2) the IRO standards regarding planned
outage coordination, both of which we address below.

Operational Responsibilities and Actions of SOLs and IROLs

    16. In the Remand NOPR, the Commission expressed concern that the
initially proposed (now withdrawn) TOP standards did not have a
requirement for transmission operators to plan and operate within all
SOLs. The Commission finds that the TOP Reliability Standards that NERC
subsequently proposed address the Commission's Remand NOPR concerns by
requiring transmission operators to plan and operate within all SOLs,
and to monitor and assess SOL conditions within and outside a
transmission operator's area. Further, the TOP/IRO Standards approved
herein address the possibility that additional SOLs could develop or
occur in the same-day or real-time operational time horizon and,
therefore, would pose an operational risk to the interconnected
transmission network if not addressed. Likewise, the Reliability
Standards give reliability coordinators the authority to direct actions
to prevent or mitigate instances of exceeding IROLs because the primary
decision-making authority for mitigating IROL exceedances is assigned
to reliability coordinators while transmission operators have the
primary responsibility for mitigating SOL exceedances.\16\
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    \16\ See Remand NOPR, 145 FERC ] 61,158 at P 85. Further,
currently-effective Reliability Standard IRO-009-1, Requirement R4
states that ``[w]hen actual system conditions show that there is an
instance of exceeding an IROL in its Reliability Coordinator Area,
the Reliability Coordinator shall, without delay, act or direct
others to act to mitigate the magnitude and duration of the instance
of exceeding that IROL within the IROL's Tv.''
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    17. Furthermore, the revised definitions of operational planning
analysis and real-time assessment are critical components of the
proposed TOP and IRO Reliability Standards and, together with the
definitions of SOLs, IROLs and operating plans, work to ensure that
reliability coordinators, transmission operators and balancing
authorities plan and operate the bulk electric system within all SOLs
and IROLs to prevent instability, uncontrolled separation, or
cascading. In addition, the revised definitions of operational planning
analysis and real-time assessment address other concerns raised in the
Remand NOPR as well as multiple recommendations in the 2011 Southwest
Outage Blackout Report.\17\
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    \17\ NERC Petition at 17-18.
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Outage Coordination

    18. In the NOPR, the Commission explained that NERC had addressed
concerns raised in the Remand NOPR with respect to the IRO standards
regarding planned outage coordination. In the Remand NOPR, the
Commission expressed concern with NERC's proposal because Reliability
Standards IRO-008-1, Requirement R3 and IRO-010-1a (subjects of the
proposed remand and now withdrawn by NERC) did not require the
coordination of outages, noting that outage coordination is a critical
reliability function that should be performed by the reliability
coordinator.\18\
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    \18\ Remand NOPR, 145 FERC ] 61,158 at P 90.
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    19. In the NOPR, the Commission noted that Reliability Standard
IRO-017-1, Requirement R1 requires each reliability coordinator to
develop, implement and maintain an outage coordination process for
generation and transmission outages within its reliability coordinator
area. Additionally, Reliability Standard IRO-014-3, Requirement R1,
Part 1.4 requires reliability coordinators to include the exchange of
planned and unplanned outage information to support operational
planning analyses and real-time assessments in the operating
procedures, processes, and plans for activities that require
coordination with adjacent reliability coordinators. We believe that
these proposed standards adequately address our concerns with respect
to outage coordination as outlined in the Remand NOPR. However, as we
discuss below we direct NERC to modify the standards to include
transmission operator monitoring of non-BES facilities, and to specify
that data exchange capabilities include redundancy and diverse routing;
as well as testing of the alternate or less frequently used data
exchange capability, within 18 months of the effective date of this
Final Rule.
    20. Below we discuss the following matters: (A) Possible
inconsistencies of identifying IROLs; (B) monitoring of non-bulk
electric system facilities; (C) removal of the load-serving entity
function from proposed Reliability Standard TOP-001-3; (D) data
exchange capabilities, and (E) other issues raised by commenters.

A. Possible Inconsistences in IROLs Across Regions

NOPR
    21. In the NOPR, the Commission noted that in Exhibit E (SOL White
Paper) of NERC's petition, NERC stated that, with regard to the SOL
concept, the SOL White Paper brings ``clarity and consistency to the
notion of establishing SOLs, exceeding SOLs, and implementing Operating
Plans to mitigate SOL exceedances.'' \19\ The Commission further noted
that IROLs, as defined by NERC, are a subset of SOLs that, if violated,
could lead to instability, uncontrolled separation, or cascading
outages that adversely impact the reliability of the bulk electric
system. The Commission agreed with NERC that clarity and consistency
are important with respect to establishing and implementing operating
plans to mitigate SOL and IROL exceedances. However, the Commission
noted that NERC, in its 2015 State of Reliability report, had stated
that the Western Interconnection reliability coordinator definition of
an IROL has additional criteria that may not exist in other reliability
coordinator areas.\20\ The

Commission stated that it is unclear whether NERC regions apply a
consistent approach to identifying IROLs. The Commission, therefore,
sought comment on (1) identification of all regional differences or
variances in the formulation of IROLs; (2) the potential reliability
impacts of such differences or variations, and (3) the value of
providing a uniform approach or methodology to defining and identifying
IROLs.
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    \19\ NERC Petition, Exhibit E, ``White Paper on System Operating
Limit Definition and Exceedance Clarification'' at 1.
    \20\ NOPR, 151 FERC ] 61,236 at P 51, citing NERC 2015 State of
Reliability report at 44, available at www.nerc.com. See also WECC
Reliability Coordination System Operating Limits Methodology for the
Operations Horizon, Rev. 7.0 (effective March 3, 2014) at 18
(stating that ``SOLs qualify as IROLs when . . . studies indicate
that instability, Cascading, or uncontrolled separation may occur
resulting in uncontrolled interruption of load equal to or greater
than 1000 MW''), available at https://www.wecc.biz/Reliability/PhaseII%20WECC%20RC%20SOL%20Methodology%20FINAL.pdf.
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Comments
    22. Commenters generally agree that there are variations in IROL
formulation but maintain that the flexibility is needed due to
different system topographies and configurations. EEI and other
commenters, also suggest that, to the extent there are variations, such
resolution should be addressed by NERC and the Regional Entities in a
standard development process rather than by a Commission directive.
NERC requests that the Commission refrain from addressing these issues
in this proceeding. NERC contends that the TOP and IRO Reliability
Standards do not address the methods for the development and
identification of SOLs and IROLs and that requirements governing the
development and identification of SOLs and IROLs are included in the
Facilities Design, Connections and Maintenance (FAC) Reliability
Standards. NERC states that the current FAC Reliability Standards
provide reliability coordinators flexibility in the manner in which
they identify IROLs.\21\ NERC adds that it recently initiated a
standards development project (Project 2015-09 Establish and
Communicate System Operating Limits) to evaluate and modify the FAC
Reliability Standards that address the development and identification
of SOLs and IROLs. NERC explains that the Project 2015-09 standard
drafting team will address the clarity and consistency of the
requirements for establishing both SOLs and IROLs. According to NERC,
it would be premature for NERC or the Commission to address issues
regarding the identification of IROLs in this proceeding without the
benefit of the complete analysis of the Project 2015-09 standard
drafting team. NERC commits to working with stakeholders and Commission
staff during the Project 2015-09 standards development process to
address the issues raised in the NOPR.
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    \21\ See also Peak Comments at 4-5. Peak points to Reliability
Standards FAC-011-2 and FAC-014-2 as support for regional variation
in establishing IROLs.
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    23. ERCOT comments that the existing Reliability Standards provide
a consistent but flexible structure for IROL identification that
provides maximum benefit to interconnected transmission network. ERCOT
believes that the Reliability Standards should continue to permit
regional variations that will encourage flexibility for consideration
of system-specific topology and characteristics as well as the
application of operational experience and engineering judgment. ERCOT
states that regional differences exist in terms of the specific
processes and methodologies utilized to identify IROLs. However,
according to ERCOT, appropriate consistency in IROL identification is
driven by the definition of an IROL, the Reliability Standards
associated with the identification of SOLs, and the communication and
coordination among responsible entities. Further, ERCOT argues that
allowing regional IROL differences benefits the bulk electric system by
allowing the entities with the most operating experience to recognize
the topology and operating characteristics of their areas, and to
incorporate their experience and judgment into IROL identification.
    24. Peak supports allowing regions to vary in their interpretation
and identification of IROLs based on the level of risk determined by
that region, as long as that interpretation is transparent and
consistent within that region. Peak understands the definition of IROL
to recognize regional differences and variances in the formulation of
IROLs. Peak contends that such regional variation is necessary due to
certain physical system differences. Thus, according to Peak, a
consistent approach from region to region is not required, and may not
enhance the overall reliability of the system. Peak explains that, in
the Western United States, the evaluation of operating limits and
stability must take into account the long transmission lines and
greater distance between population centers, a situation quite
different than the dense, interwoven systems found in much of the
Eastern Interconnection. Peak adds that the Western Interconnection
more frequently encounters localized instability because of the
sparsity of the transmission system and the numerous small load centers
supplied by few transmission lines, and these localized instances of
instability have little to no impact on the overall reliability of the
bulk electric system. Peak encourages the Commission to recognize that
differences among the regions may require flexibility to determine,
through its SOL methodology, the extent and severity of instability and
cascading that warrant the establishment of an IROL.
    25. While Peak supports retaining the flexibility of a region by
region application of the IROL definition, Peak notes that the current
definition is not without some confusing ambiguity in the application
of IROL that should be addressed, including ambiguity and confusion
around the term ``instability,'' the phrase ``that adversely impact the
reliability of the Bulk Electric System'' and ``cascading.'' Peak
suggests that one method to eliminate confusion on the definition and
application of IROLs would be to expand NERC's whitepaper to address
concerns more specific to IROLs. Peak contends that further guidance
from NERC in the whitepaper may remedy the confusion on the limits on
the application of IROLs for widespread versus localized instability.
    26. Peak requests that, if the Commission or NERC determines that a
one-size-fits all approach is necessary for the identification of IROLs
and eliminates the current flexibility for regional differences, that
the Commission recognizes the limitations this will place on
reliability coordinators to evaluate the specific conditions within
their reliability coordinator area. The Commission should require that
any standardized application of the IROL definition would need to
address specific thresholds and implementation triggers for IROLs based
on the risk profile and challenges facing specific regions, to avoid
the downfalls of inaccurate or overbroad application, as discussed
above.
Commission Determination
    27. While it appears that regional discrepancies exist regarding
the manner for calculating IROLs, we accept NERC's explanation that
this issue is more appropriately addressed in NERC's Facilities Design,
Connections and Maintenance or ``FAC'' Reliability Standards. NERC
indicates that an ongoing FAC-related standards development project--
NERC Project 2015-09 (Establish and Communicate System Operating
Limits)--will address the development and identification of SOLs and
IROLs. We conclude that NERC's explanation, that the Project 2015-09
standard drafting team will address the clarity and consistency of the
requirements for establishing both SOLs and IROLs, is reasonable.

Therefore, we will not direct further action on IROLs in the immediate
TOP and IRO standard-related rulemaking. However, when this issue is
considered in Project 2015-19, the specific regional difference of
WECC's 1,000 MW threshold in IROLs should be evaluated in light of the
Commission's directive in Order No. 802 (approving Reliability Standard
CIP-014) to eliminate or clarify the ``widespread'' qualifier on
``instability'' as well as our statement in the Remand NOPR that
``operators do not always foresee the consequences of exceeding such
SOLs and thus cannot be sure of preventing harm to reliability.'' \22\
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    \22\ Physical Security Reliability Standard, Order No. 802, 149
FERC ] 61,140 (2014) and Remand NOPR, 145 FERC ] 61,158 at P 52. See
also FPA section 215(a)(4) defining Reliable Operation as
``operating the elements of the bulk-power system within equipment
and electric system thermal, voltage, and stability limits so that
instability, uncontrolled separation, or cascading failures of such
system will not occur as a result of a sudden disturbance, including
a cybersecurity incident, or unanticipated failure of system
elements.''
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B. Monitoring of Non-Bulk Electric System Facilities

NOPR
    28. In the NOPR the Commission proposed to find that the proposed
Reliability Standards adequately address the 2011 Southwest Outage
Blackout Report recommendation regarding monitoring sub-100 kV
facilities, primarily because of the responsibility of the reliability
coordinator under proposed Reliability Standard IRO-002-4, Requirement
R3 to monitor non-bulk electric system facilities to the extent
necessary. The Commission noted, however, that ``the transmission
operator may have a more granular perspective than the reliability
coordinator of its necessary non-bulk electric system facilities to
monitor,'' and it is not clear whether or how the transmission operator
would provide information to the reliability coordinator regarding
which non-BES facilities should be monitored.\23\ The Commission sought
comment on how NERC will ensure that the reliability coordinator will
receive such information.
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    \23\ NOPR, 151 FERC ] 61,236 at P 58.
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    29. The Commission stated that including such non-bulk electric
system facilities in the definition of bulk electric system through the
NERC Rules of Procedure exception process could be an option to address
any potential gaps for monitoring facilities but notes that there may
be potential efficiencies gained by using a more expedited method to
include non-bulk electric system facilities that requires monitoring.
The Commission sought comment on whether the BES exception process
should be used exclusively in all cases. Alternatively, the Commission
sought comment on whether this concern can be addressed through a
review process of the transmission operators' systems to determine if
there are important non-bulk electric system facilities that require
monitoring.
Comments
    30. Nearly all commenters support the Reliability Standards as
proposed as sufficient for identifying and monitoring non-bulk electric
system facilities, and do not support the alternatives offered by the
Commission in the NOPR.\24\ NERC submits that the proposed data
specification and collection Reliability Standards IRO-010-2 and TOP-
003-3, in addition to the exceptions process will help ensure that the
reliability coordinator can work with transmission operators, and other
functional entities, to obtain sufficient information to identify the
necessary non-bulk electric system facilities to monitor. In support,
NERC points to Reliability Standard IRO-010-2, which provides a
mechanism for the reliability coordinator to obtain the information and
data it needs for reliable operations and to help prevent instability,
uncontrolled separation, or cascading outages. Further, NERC cites
Reliability Standard TOP-003-3, which allows transmission operators to
obtain data on non-bulk electric system facilities, necessary to
perform their operational planning analyses, real[hyphen]time
monitoring, and real[hyphen]time assessments from applicable entities.
NERC explains that any data that the transmission operator obtains
regarding non-bulk electric system facilities under Reliability
Standard TOP-003-3 can be passed on to the reliability coordinator
pursuant to a request under proposed Reliability Standard IRO-010-2.
Accordingly, NERC states that it would be premature to develop an
alternative process before the data specification and bulk electric
system exception process are allowed to work.
---------------------------------------------------------------------------

    \24\ E.g. NERC, EEI, TAPS, Occidental, and NIPSCO.
---------------------------------------------------------------------------

    31. EEI states that this issue has been thoroughly studied by NERC
through Project 2010-17 Phase 2 (Revisions to the Definition of Bulk
Electric System) that led to modification of the definition of bulk
electric system. EEI believes that the current process provides all of
the necessary tools and processes to ensure that insights by TOPs are
fully captured and integrated into existing monitoring systems that
would ensure that all non-BES elements that might impact BES
reliability are fully monitored. EEI does not support the alternative
process proposed by the Commission. EEI warns that an alternative,
parallel review process of the transmission operators' systems to
determine if there are important non-bulk electric system facilities
that require monitoring would either circumvent the revised bulk
electric system definition process or arbitrarily impose NERC
requirements (i.e., monitoring) onto non-bulk electric system elements.
    32. APS agrees with the Commission that there would be a
reliability benefit for the reliability coordinator to be able to
identify facilities within the transmission operators' areas that may
have a material impact on reliability. APS believes this benefit can be
achieved using the method deployed in the Western Interconnection by
the Western Electricity Coordinating Council (WECC). APS explains that
the WECC planning coordination committee has published a bulk electric
system inclusion guideline that categorizes non-bulk electric system
facilities that are to be identified by each planning authority and
transmission planner when performing their system planning and
operations reliability assessments, and the identified facilities are
then reported to NERC. APS proposes a similar exception process be used
in all cases. According to APS, each reliability coordinator would
publish a guideline on how to identify non-bulk electric system
facilities critical to reliability appropriate for their reliability
coordinator area, and each planning coordinator and transmission
planner would run studies according to the reliability coordinator
guideline at least once every three years.
    33. ERCOT states that performance of sufficient studies and
evaluations of reliability coordinator areas occurs in cooperation and
coordination with associated transmission operators, rending an
additional review process unnecessary. However, to avoid any potential
gaps in monitoring non-bulk electric system facilities and ensure that
existing agreements and monitoring processes are respected, ERCOT
states that the Commission should direct NERC to modify the TOP and IRO
Reliability Standards to refer not only to sub-100 kV facilities
identified as part of the bulk electric system through the Rules of
Procedure exception process, but also to other sub-100 kV facilities as
requested or agreed by the responsible entities.\25\ ERCOT also states
that

because ``non-bulk electric system facilities'' fall outside the scope
of the NERC Reliability Standards, use of this terminology should be
avoided. ERCOT advocates for the Commission to permit monitoring of
other sub-100 kV facilities to be undertaken as agreed to between the
reliability coordinator and the transmission operator. ERCOT and ISO/
RTOs suggest that the phrase ``non-BES facilities'' in Reliability
Standard IRO-002-4, Requirement R3 should be replaced with ``sub-100 kV
facilities identified as part of the BES through the BES exception
process or as otherwise agreed to between the Reliability Coordinator
and Transmission Operator'' and the phrase ``non-BES data'' in
Reliability Standards IRO-010-2 (Requirement R1.1) and TOP-003-3
(Requirement R1.1) should be replaced with ``data from sub-100 kV
facilities identified as part of the BES through the BES exception
process, as otherwise requested by the Responsible Entity, or as agreed
to between the Transmission Operator and the Responsible Entity.'' \26\
---------------------------------------------------------------------------

    \25\ See also ISO/RTOs Comments at 3.
    \26\ See also ISO/RTOs Comments at 4-6.
---------------------------------------------------------------------------

    34. ITC does not support the Commission's proposal. ITC states that
transmission operators are required to incorporate any non-bulk
electric system data into operational planning analysis and real-time
assessments and monitoring, which therefore requires transmission
operators to regularly review their models to identify impacting non-
bulk electric system facilities. Conversely, ITC explains that
conducting a one-time or periodic review and analysis of a transmission
operator's model ignores the fact that changes in system conditions can
cause the list of impacting non-bulk electric system facilities to
change frequently.
Commission Determination
    35. We agree with NERC, TAPS, and EEI that the BES exception
process can be a mechanism for identifying non-BES facilities to be
included in the BES definition.\27\ Indeed, once a non-BES facility is
included in the BES definition under the BES exception process, the
``non-BES facility'' becomes a BES ``Facility'' under TOP-001-3,
Requirement R10, and real-time monitoring is required of
``Facilities.'' \28\ However, we are concerned that in some instances
the absence of real-time monitoring of non-BES facilities by the
transmission operator within and outside its TOP area as necessary for
determining SOL exceedances in proposed TOP-001-3, Requirement R10
creates a reliability gap. As the 2011 Southwest Outage Report
indicates, the Regional Entity ``should lead other entities, including
TOPs and BAs, to ensure that all facilities that can adversely impact
BPS reliability are either designated as part of the BES or otherwise
incorporated into planning and operations studies and actively
monitored and alarmed in [real-time contingency analysis] systems.''
\29\ Such monitoring of non-BES facilities could provide a ``stop gap''
during the period where a sub-100 kV facility undergoes analysis as a
possible BES facility, allowing for monitoring in the interim until
such time the non-bulk electric system facilities become ``BES
Facilities'' or the transmission operator determines that a non-bulk
electric system facility is no longer needed for monitoring to
determine a system operating limit exceedance in its area.\30\ We
believe that the operational planning analyses and real-time
assessments performed by the transmission operators as well as the
reliability coordinators will serve as the basis for determining which
``non-BES facilities'' require monitoring to determine system operating
limit and interconnection reliability operating limit exceedances. In
addition, we believe that monitoring of certain non-BES facilities that
are occasional system operating limit exceedance performers may not
qualify as a candidate for inclusion in the BES definition, yet should
be monitored for reliability purposes.\31\ Accordingly, pursuant to
section 215(d)(5) of the FPA, we direct NERC to revise Reliability
Standard TOP-001-3, Requirement R10 to require real-time monitoring of
non-BES facilities. We believe this is best accomplished by adopting
language similar to Reliability Standard IRO-002-4, Requirement R3,
which requires reliability coordinators to monitor non-bulk electric
system facilities to the extent necessary. NERC can develop an equally
efficient and effective alternative that addresses our concerns.\32\
---------------------------------------------------------------------------

    \27\ NERC TOP/IRO Petition, Exh. G at 9 states in response to
the 2011 Southwest Outage Recommendation 17, ``If a non-BES
facility impacts the BES, such as by contributing to an SOL or IROL,
then the SDT expects that facility to be incorporated into the BES
through the official BES Exception Process and it would be covered
in proposed TOP-001-3, Requirement R10, Parts 10.1 and 10.2 by use
of the defined term `Facilities.' ''
    \28\ NERC Glossary of Terms defines Facility as: ``A set of
electrical equipment that operates as a single Bulk Electric System
Element (e.g., a line, a generator, a shunt compensator,
transformer, etc.)''
    \29\ NOPR, 151 FERC ] 61,236 at P 55, citing Recommendation 17
of the 2011 Southwest Outage Blackout Report (emphasis added).
    \30\ NERC's BES Frequently Asked Questions, Version 1.6,
February 25, 2015, Section 5.6. ``How long will the process take?''
at page 14 states: ``In general, assuming a complete application, no
appeals, and taking the allotted time for each subtask, the process
could take up to 11.5 months, but is anticipated to be shorter for
less complicated Exception Requests. If the Exception Request is
appealed to the NERC Board of Trustees Compliance Committee pursuant
to Section 1703 of the NERC Rules of Procedure, the process could
take an additional 8.5 months, totaling 20 months. This does not
include timing related to an appeal to the applicable legal
authority or Applicable Governmental Authority. A Regional Entity,
upon consultation with NERC, may extend the time frame of the
substantive review process. . . .'' http://www.nerc.com/pa/RAPA/BES%20DL/BES%20FAQs.pdf.
    \31\ See, e.g., NERC TOP/IRO Petition at 18 and 27-28.
    \32\ Reliability Standard IRO-002-4, Requirement R3 states: Each
Reliability Coordinator shall monitor Facilities, the status of
Special Protection Systems, and non-BES facilities identified as
necessary by the Reliability Coordinator, within its Reliability
Coordinator Area and neighboring Reliability Coordinator Areas to
identify any System Operating Limit exceedances and to determine any
Interconnection Reliability Operating Limit exceedances within its
Reliability Coordinator Area.
---------------------------------------------------------------------------

    36. To be clear, we are not directing that all current ``non-BES''
facilities that a transmission operator considers worthy of monitoring
also be included in the bulk electric system. We believe that such
monitoring may result in some facilities becoming part of the bulk
electric system through the exception process; however it is
conceivable that others may remain non-BES because they are occasional
system operating limit exceedance performers that may not qualify as a
candidate for inclusion in the BES definition.

C. Removal of Load-Serving Entity Function From TOP-001-3

NOPR
    37. NERC proposed the removal of the load-serving entity function
from proposed Reliability Standard, TOP-001-3, Requirements R3 through
R6, as a recipient of an operating instruction from a transmission
operator or balancing authority. NERC supplemented its initial petition
with additional explanation for the removal of the load-serving entity
function from proposed Reliability Standard TOP-001-3.\33\ NERC
explained that the proposed standard gives transmission operators and
balancing authorities the authority to direct the actions of certain
other functional entities by issuing an operating instruction to
maintain reliability during real-time operations.
---------------------------------------------------------------------------

    \33\ The Commission also notes that Reliability Standards TOP-
003-3 and IRO-010-2 also include ``load-serving entity'' as an
applicable entity.
---------------------------------------------------------------------------

    38. In the NOPR, the Commission noted that NERC was required to
make a compliance filing in Docket No. RR15-4-000, regarding NERC's
Risk-Based Registration initiative, and that the Commission's decision
on that filing

will guide any action in this proceeding. On March 19, 2015, the
Commission approved, in part, NERC's Risk-Based Registration
initiative, but denied, without prejudice, NERC's proposal to eliminate
the load-serving entity function from the registry process, finding
that NERC had not adequately justified its proposal.\34\ In doing so,
the Commission directed NERC to provide additional information to
support this aspect of its proposal to address the Commission's
concerns. On July 17, 2015, NERC submitted a compliance filing in
response to the March 19 Order.
---------------------------------------------------------------------------

    \34\ North American Electric Reliability Corp. 150 FERC ] 61,213
(2015) (March 19 Order).
---------------------------------------------------------------------------

Comments
    39. NERC states that while load-serving entities play a role in
facilitating interruptible (or voluntary) load curtailments, that role
is to simply communicate requests for voluntary load curtailments and
does not necessitate requiring load-serving entities to comply with a
transmission operator's or balancing authority's operating instructions
issued pursuant to Reliability Standard TOP-001-3. In short, the load-
serving entity's role in carrying out interruptible load curtailment is
not the type of activity that rises to the level of requiring an
operating instruction. EEI and TAPS contend it is appropriate to omit
the load-serving entity function from TOP-001-3 applicability. TAPS
explains that because the load-serving entity function does not own or
operate equipment, the load-serving entity function cannot curtail load
or perform other corrective actions subject to reliability standards.
Dominion asserts that a load-serving entity does not own or operate
bulk electric system facilities or equipment or the facilities or
equipment used to serve end-use customers and is not aware of any
entity, registered solely as a load-serving entity, which is
responsible for operating one or more elements or facilities.
Commission Determination
    40. In an October 15, 2015 order in Docket No. RR15-4-001, the
Commission accepted a NERC compliance filing, finding that NERC
complied with the March 17 Order with respect to providing additional
information justifying the removal of the load-serving entity
function.\35\ The Commission also found that NERC addressed the
concerns expressed regarding an accurate estimate of the load-serving
entities to be deregistered and the reliability impact of doing so, and
how load data will continue to be available and reliability activities
will continue to be performed even after load-serving entities would no
longer be registered.\36\ Because the load-serving entity category is
no longer a NERC registration function, no further action is required
in this proceeding.\37\
---------------------------------------------------------------------------

    \35\ North American Electric Reliability Corp, 153 FERC ] 61,024
(2015).
    \36\ Id.
    \37\ In its response to comments in Docket No. RR15-4-000, NERC
stated that, once the Commission approved the proposed deactivation
of the load-serving entity registration function, it would make any
needed changes to the Reliability Standards through the Reliability
Standard Development Process. See January 26, 2016, NERC Motion to
File Limited Answer at 6 in Docket No. RR15-4-000.
---------------------------------------------------------------------------

D. Data Exchange Capabilities

    41. The Commission approved Reliability Standards COM-001-2
(Communications) and COM-002-4 (Operating Personnel Communications
Protocols) in Order No. 808, and noted that in the NOPR underlying that
order (COM NOPR) it had raised concerns as to whether Reliability
Standard COM-001-2 addresses facilities that directly exchange or
transfer data.\38\ In response to that concern in the COM NOPR, NERC
clarified that Reliability Standard COM-001-2 did not need to include
requirements regarding data exchange capability because such capability
is covered under other existing and proposed standards. Based on that
explanation, the Commission decided not to make any determinations in
Order No. 808 and stated that it would address the issue in this TOP
and IRO rulemaking proceeding.\39\
---------------------------------------------------------------------------

    \38\ See NOPR, 151 FERC ] 61,236 at P 67, citing Communications
Reliability Standards, Order No. 808, 151 FERC ] 61,039 (2015).
    \39\ Id. citing Order No. 808, 151 FERC ] 61,039 at P 54.
---------------------------------------------------------------------------

NOPR
    42. In the NOPR, the Commission stated that facilities for data
exchange capabilities appear to be addressed in NERC's TOP/IRO
petition. However, the Commission sought additional explanation from
NERC regarding how it addresses data exchange capabilities in the TOP
and IRO Standards in the following areas: (a) Redundancy and diverse
routing; and (b) testing of the alternate or less frequently used data
exchange capability.
1. Redundancy and Diverse Routing of Data Exchange Capabilities
NOPR
    43. In the NOPR, the Commission agreed that proposed Reliability
Standard TOP-001-3, Requirements R19 and R20 require some form of
``data exchange capabilities'' for the transmission operator and
balancing authority and that proposed Reliability Standard TOP-003-3
addresses the operational data itself needed by the transmission
operator and balancing authority. In addition, the Commission agreed
that Reliability Standard IRO-002-4, Requirement R1 requires ``data
exchange capabilities'' for the reliability coordinator and that
proposed Reliability Standard IRO-010-2 addresses the operational data
needed by the reliability coordinator and that proposed Reliability
Standard IRO-002-4 Requirement R4 requires a redundant infrastructure
for system monitoring. However, the Commission was concerned that it is
not clear whether redundancy and diverse routing of data exchange
capabilities were adequately addressed in proposed Reliability
Standards TOP-001-3 and IRO-002-4 for the reliability coordinator,
transmission operator, and balancing authority and sought explanation
or clarification on how the standards address redundancy and diverse
routing or an equally effective alternative. The Commission also stated
that, if NERC or others believe that redundancy and diverse routing are
not addressed, they should address whether there are associated
reliability risks of the interconnected transmission network for any
failure of data exchange capabilities that are not redundant and
diversely routed.
Comments
    44. NERC and EEI state that the requirements in the TOP and IRO
Reliability Standards covering data exchange are results-based,
articulating a performance objective without dictating the manner in
which it is met. NERC adds that, in connection with their compliance
monitoring activities, NERC and the Regional Entities will review
whether applicable entities have met that objective, and will consider
whether the applicable entity has redundancy and diverse routing, and
whether the applicable entity tests these capabilities. EEI also argues
that Reliability Standard EOP-008-1, Requirements R1, R1.2, R1.2.2, R7,
and EOP-001-2.1b, Requirements R6 and R6.1 provide specific
requirements for maintaining or specifying reliable back-up data
exchange capability necessary to ensure BES Reliability and the testing
of those capabilities.
    45. ERCOT asserts that the Reliability Standards already
appropriately provide for redundancy and diversity of routing of data
exchange capabilities, as both the existing and proposed standards

either explicitly or implicitly require responsible entities to ensure
availability of data and data exchange capabilities. ERCOT states that,
should the Commission seek to provide further clarification on this
issue, such clarification should be consistent with existing explicit
requirements regarding the redundancy of data exchange capabilities,
such as Requirement R4 of Reliability Standard IRO-002-4.
    46. ISOs/RTOs and ERCOT explain the suite of currently-effective
standards and the proposed TOP and IRO standards establish performance-
based requirements for reliability coordinators, balancing authorities,
and transmission operators, that create the need for those entities to
have diverse and redundantly routed data communication systems. In the
event of a failure of data communications, ISOs/RTOs explain that the
functional entity should be able to rely on the redundant and diversely
routed voice capabilities required in the COM standards.
Commission Determination
    47. We agree with NERC and other commenters that there is a
reliability need for the reliability coordinator, transmission operator
and balancing authority to have data exchange capabilities that are
redundant and diversely routed. However, we are concerned that the TOP
and IRO Standards do not clearly address redundancy and diverse routing
so that registered entities will unambiguously recognize that they have
an obligation to address redundancy and diverse routing as part of
their TOP and IRO compliance obligations. NERC's comprehensive approach
to establishing communications capabilities necessary to maintain
reliability in the COM standards is applicable to data exchange
capabilities at issue here.\40\ Therefore, pursuant to section
215(d)(5) of the FPA, we direct NERC to modify Reliability Standards
TOP-001-3, Requirements R19 and R20 to include the requirement that the
data exchange capabilities of the transmission operators and balancing
authorities require redundancy and diverse routing. In addition, we
direct NERC to clarify that ``redundant infrastructure'' for system
monitoring in Reliability Standards IRO-002-4, Requirement R4 is
equivalent to redundant and diversely routed data exchange
capabilities.
---------------------------------------------------------------------------

    \40\ See, e.g, Order No. 808, 151 FERC ] 61,039 at P 8: ``NERC
stated in its [COM] petition that Reliability Standard COM-001-2
establishes requirements for Interpersonal Communication
capabilities necessary to maintain reliability. NERC explained that
proposed Reliability Standard COM-001-2 applies to reliability
coordinators, balancing authorities, transmission operators,
generator operators, and distribution providers. The proposed
Reliability Standard includes eleven requirements and two new
defined terms, ``Interpersonal Communication'' and ``Alternative
Interpersonal Communication,'' that, according to NERC, collectively
provide a comprehensive approach to establishing communications
capabilities necessary to maintain reliability.''
---------------------------------------------------------------------------

    48. Further, we disagree with commenter arguments that Reliability
Standard EOP-008-1 provides alternatives to data exchange redundancy
and diverse routing. The NERC standard drafting team that developed the
COM standards addressed this issue in the standards development
process, responding to a commenter seeking clarification on the
relationship between communication capabilities, alternative
communication capabilities, primary control center functionality and
backup control center functionality. The standard drafting team
responded that ``Interpersonal Communication and Alternative
Interpersonal Communication are not related to EOP-008,'' even though
Reliability Standard EOP-008-1 Requirement R1 applies equally to data
communications and voice communications.\41\ To the extent the standard
drafting team asserted that Reliability Standard EOP-008 did not
supplant the redundancy requirements of the COM Reliability Standards,
we believe the same is true for data communications. Redundancy for
data communications is no less important than the redundancy explicitly
required in the COM standards for voice communications.
---------------------------------------------------------------------------

    \41\ See NERC COM Petition, Exh. M, (Consideration of Comments
on Initial Ballot, February 25-March 7, 2011) at 30 (emphasis
added).
---------------------------------------------------------------------------

2. Testing of the Alternate or Less Frequently Used Data Exchange
Capability
NOPR
    49. In the NOPR, the Commission expressed concern that the proposed
TOP and IRO Reliability Standards do not appear to address testing
requirements for alternative or less frequently used mediums for data
exchange to ensure they would properly function in the event that the
primary or more frequently used data exchange capabilities failed.
Accordingly, the Commission sought comment on whether and how the TOP
and IRO Reliability Standards address the testing of alternative or
less frequently used data exchange capabilities for the transmission
operator, balancing authority and reliability coordinator.
Comments
    50. Commenters assert that the existing standards have sufficient
testing requirements. NERC points to Reliability Standard EOP-008-1,
Requirement R7, which requires that applicable entities conduct annual
tests of their operating plan that demonstrates, among other things,
backup functionality. Similarly, EEI cites EOP-008-1 Requirements R1,
R1.2, R1.2.2, R7 and EOP-001-2.1b Requirements R6 and R6.1 as providing
specific requirements for maintaining and testing of data exchange
capabilities. ITC suggests that NERC's proposed Standard TOP-001-3
provides ample assurance that the data exchange capabilities are
regularly tested and also points to Reliability Standards EOP-001-2.1b
and EOP-008-1 which require entities, including those covered by TOP-
001-3, to maintain reliable back-up data exchange capability as
necessary to ensure reliable BES operations, and require that such
capabilities be thoroughly and regularly tested.
Commission Determination
    51. We agree with NERC and other commenters that there is a
reliability need for the reliability coordinator, transmission operator
and balancing authority to test alternate data exchange capabilities.
However, we are not persuaded by the commenters' assertions that the
need to test is implied in the TOP and IRO Standards. Rather, we
determine that testing of alternative data exchange capabilities is
important to reliability and should not be left to what may or may not
be implied in the standards.\42\ Therefore, pursuant to section
215(d)(5) of the FPA, we direct NERC to develop a modification to the
TOP and IRO standards that addresses a data exchange capability testing
framework for the data exchange capabilities used in the primary
control centers to test the alternate or less frequently used data
exchange capabilities of the reliability coordinator, transmission
operator and balancing authority. We believe that the structure of
Reliability Standard COM-001-2, Requirement R9 could be a

model for use in the TOP and IRO Standards.\43\
---------------------------------------------------------------------------

    \42\ In NERC's COM Petition, Exh. M, (Consideration of Comments,
Index to Questions, Comments and Responses) at 35, the standard
drafting team stated that the ``requirement [COM-001-2, Requirement
R9 which addresses testing of alternative interpersonal
communication] applies to the primary control center'' and ``EOP-008
applies to the back up control center.''
    \43\ 43 COM-001-2, Requirement R9 states: ``Each Reliability
Coordinator, Transmission Operator, and Balancing Authority shall
test its Alternative Interpersonal Communication capability at least
once each calendar month. If the test is unsuccessful, the
responsible entity shall initiate action to repair or designate a
replacement Alternative Interpersonal Communication capability
within 2 hours.''
---------------------------------------------------------------------------

E. Other Issues Raised by Commenters

1. Emergencies and Emergency Assistance Under Reliability Standard TOP-
001-3
    52. Reliability Standard TOP-001-3, Requirement R7 requires each
transmission operator to assist other transmission operators within its
reliability coordinator area, if requested and able, provided that the
requesting transmission operator has implemented its comparable
emergency procedures. NIPSCO contends that this requirement limits the
ability of an adjacent transmission operator that is located along the
seam in another reliability coordinator area from rendering assistance
in an emergency because Requirement R7 only requires each transmission
operator to assist other transmission operators within its reliability
coordinator area. NIPSCO points to Reliability Standard IRO-014-3,
Requirement R7 which requires each reliability coordinator to assist
other reliability coordinators and, according to NIPSCO, a similar
requirement in Reliability Standard TOP-001-3 will make the two sets of
requirements consistent with each other.
    53. In addition, Reliability Standard TOP-001-3, Requirement R8
states:

Each Transmission Operator shall inform its Reliability Coordinator,
known impacted Balancing Authorities, and known impacted
Transmission Operators of its actual or expected operations that
result in, or could result in, an Emergency.

BPA contends that the phrase ``could result in'' in Requirement R8 of
TOP-001-3 is overly broad and suggests corrective language underscored
below:

Each Transmission Operator shall inform its Reliability Coordinator,
known impacted Balancing Authorities, and known impacted
Transmission Operators of its actual or expected operations that
result in an Emergency, or could result in an Emergency if a
credible Contingency were to occur.

As an alternative to changing the language of the requirement, BPA asks
the Commission to clarify that it is in the transmission operator's
discretion to determine what ``could result'' in an emergency, based on
the transmission operator's experience and judgment.
Commission Determination
    54. With regard to NIPSCO's concern, we do not believe that the
requirements as written limit the ability of an adjacent transmission
operator located along the seam in another reliability coordinator area
from rendering assistance in an emergency. We agree with NIPSCO that
proposed Reliability Standard TOP-001-3, Requirement R7 requires each
transmission operator to assist other transmission operators within its
reliability coordinator area and further agree with NIPSCO that
proposed Reliability Standard IRO-014-3, Requirement R7 requires each
reliability coordinator to assist other reliability coordinators.\44\
In addition, we understand that an adjacent transmission operator in
another reliability coordinator area can render assistance when
directed to do so by its own reliability coordinator.\45\ Having a
similar requirement in Reliability Standard TOP-001-3 compared to
Reliability Standard IRO-014-3, Requirement R7 is unnecessary and could
complicate the clear decision-making authority NERC developed in the
TOP and IRO Reliability Standards. Thus, we determine that no further
action is required.
---------------------------------------------------------------------------

    \44\ See Reliability Standards TOP-001-3 and IRO-014-3.
    \45\ See Reliability Standard IRO-001-4, Requirement R2.
---------------------------------------------------------------------------

    55. With regard to clarification of emergencies in Reliability
Standard TOP-001-3, Requirement R8, we do not see a need to modify the
language as suggested by BPA. The requirement as written implies that
the transmission operator has discretion to determine what could result
in an emergency, based on its experience and judgment. In addition, we
note that the transmission operators' required next-day operational
planning analysis, real-time assessments and real-time monitoring under
the TOP Reliability Standards provide evaluation, assessment and input
in determining what ``could result'' in an emergency.
2. Reliability Coordinator Authority in Next-Day Operating Plans
    56. Reliability Standard TOP-002-4, Requirements R2 and R4 require
transmission operators and balancing authorities to have operating
plans. Reliability Standard TOP-002-4, Requirements R6 and R7 require
transmission operators and balancing authorities to provide their
operating plans to their reliability coordinators and Reliability
Standard IRO-008-2, Requirement R2 requires reliability coordinators to
develop a coordinated operating plan that considers the operating plans
provided by the transmission operators and balancing authorities.
    57. NIPSCO is concerned about the absence of any required direct
coordination between transmission operators and balancing authorities
as well as the absence of any guidance regarding the resolution of
potential conflicts between the transmission operator and balancing
authority operating plans. NIPSCO contends that the Reliability
Standards provide only a limited coordination process in which
reliability coordinators are required to notify those entities
identified with its coordinated operating plan of their roles. NIPSCO
argues that there is no provision for modifications to operating plans
based on the reliability coordinator's coordinated operating plan or
based on potential conflicts between the transmission operator and
balancing authority operating plans. NIPSCO is concerned that a
potential disconnect between operating plans could lead to confusion or
a failure of coordination of reliable operations.
Commission Determination
    58. We believe that proposed Reliability Standards TOP-002-4 and
IRO-008-2 along with NERC's definition of reliability coordinator
address NIPSCO's concern.\46\ Although the transmission operator and
balancing authority develop their own operating plans for next-day
operations, both the transmission operator and balancing authority
notify entities identified in the operating plans as to their role in
those plans. Further, each transmission operator and balancing
authority must provide its operating plan for next-day operations to
its reliability coordinator.\47\ In Reliability Standard IRO-008-2,
Requirement R2, the reliability coordinator must have a coordinated
operating plan for next-day operations to address potential SOL and
IROL exceedances while considering the operating plans for the next-day
provided by its transmission operators

and balancing authorities. Also, Reliability Standard IRO-008-2,
Requirement R3 requires that the reliability coordinator notify
impacted entities identified in its operating plan as to their role in
such plan. Based on the notification and coordination processes of
Reliability Standards TOP-002-4 (for the transmission operator and
balancing authority) and IRO-008-2 (for the reliability coordinator)
for next-day operating plans, as well as the fact that the reliability
coordinator is the entity that is the highest level of authority who is
responsible for the reliable operation of the bulk electric system, we
believe that the reliability coordinator has the authority and
necessary next-day operational information to resolve any next-day
operational issues within its reliability coordinator area.
Accordingly, we deny NIPSCO's request.
---------------------------------------------------------------------------

    \46\ NERC Glossary of Terms defines the Reliability Coordinator
as ``The entity that is 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. The Reliability Coordinator
has the purview that is broad enough to enable the calculation of
Interconnection Reliability Operating Limits, which may be based on
the operating parameters of transmission systems beyond any
Transmission Operator's vision.''
    \47\ Reliability Standard TOP-002-4 (Operations Planning).
---------------------------------------------------------------------------

3. Reliability Coordinator Authority in Next-Day Operations and the
Issuance of Operating Instructions
    59. NIPSCO is concerned with the elimination of the explicit
requirement in currently-effective Reliability Standard IRO-004-2 that
each transmission operator, balancing authority, and transmission
provider comply with the directives of a reliability coordinator based
on next-day assessment in the same manner as would be required in real-
time operating conditions. NIPSCO claims that, while the Reliability
Standards appear to address the Commission's concerns regarding
directives issued in other than emergency conditions through the
integration of the term ``operating instruction,'' the standards only
allow for the issuance of directives in real-time. NIPSCO points to
Reliability Standard TOP-001-3, Requirements R1 and R2, and IRO-001-4,
Requirement R1, where transmission operators, balancing authorities,
and reliability coordinators are explicitly given authority and
responsibility to issue operating instructions to address reliability
in their respective areas. NIPSCO states that ``operating instruction''
is ``clearly limited to real-time operations'' as it underscored below:

A command by operating personnel responsible for the Real-time
operation of the interconnected Bulk Electric System to change or
preserve the state, status, output, or input of an Element of the
Bulk Electric System or Facility of the Bulk Electric System. (A
discussion of general information and of potential options or
alternatives to resolve Bulk Electric System operating concerns is
not a command and is not considered an Operating Instruction.)

NIPSCO contends that there are no clear requirements addressing
potential conflicts between operating plans, no clear requirements
authorizing the issuance of a directive to address issues identified in
next-day planning, and no clear requirement to comply with any
directive so issued. NIPSCO is concerned that this raises the
possibility that potential next-day problems identified in the
operational planning analyses may not get resolved in the next-day
planning period because the reliability coordinator's authority to
issue operating instructions is limited to real-time operation.
According to NIPSCO, this limitation undermines some of the usefulness
of the next-day planning and the performance of operational planning
analyses.
Commission Determination
    60. We do not share NIPSCO's concern. Rather, we believe that,
because the reliability coordinator is required to have a coordinated
operating plan for the next-day operations, the reliability coordinator
will perform its task of developing a coordinated operating plan in
good faith, with inputs not only from its transmission operators and
balancing authorities, but also from its neighboring reliability
coordinators.\48\ A reliability coordinator has a wide-area view and
bears the ultimate responsibility to maintain the reliability within
its footprint, ``including the authority to prevent or mitigate
emergency operating situations in both next-day analysis and real-time
operations.'' \49\
---------------------------------------------------------------------------

    \48\ See Reliability Standards IRO-008-2, Requirements R1 and
R2, and IRO-014-3, Requirement R1.
    \49\ See supra n. 46.
---------------------------------------------------------------------------

    61. In addition, we do not agree with NIPSCO's claim that operating
instructions are ``clearly limited to real-time operations.'' The
phrase ``real-time operation'' in the definition of operating
instruction as emphasized by NIPSCO applies to the entity that issues
the operating instruction which is ``operating personnel responsible
for the Real-time operation.'' The definition of operating instruction
is ``[a] command by operating personnel responsible for the Real-time
operation of the interconnected Bulk Electric System. . . .'' In
addition, the time horizons associated with the issuance of or
compliance with an operating instruction are not found in the
definition of operating instructions, but found in the individual
requirement(s) applicable to issuing an operating instruction. For
example, Reliability Standard TOP-001-3, Requirements R1 through R6 and
IRO-001-4, Requirements R1 through R3 are all requirements associated
with the issuance or compliance of operating instructions. In all nine
requirements, the defined time horizon is ``same-day operations'' and
``real-time operations.'' \50\ Accordingly, we deny NIPSCO's request on
this issue.
---------------------------------------------------------------------------

    \50\ NERC's ``Time Horizons'' document defines ``Same-Day
Operations'' time horizon as ``routine actions required within the
timeframe of a day, but not real-time'' and defines ``Real-Time
Operations'' time horizon as ``actions required within one hour or
less to preserve the reliability of the bulk electric system.'' See
http://www.nerc.com/files/Time_Horizons.pdf.
---------------------------------------------------------------------------

4. Updating Operational Planning Analyses and Real-Time Assessments
    62. NIPSCO is concerned that the proposed Reliability Standards are
not clear as to whether updates or additional analyses are required.
NIPSCO points to Reliability Standards IRO-008-2 and TOP-002-4, which
require reliability coordinators to perform--and transmission operators
and balancing authorities to have--an operational analysis for the
next-day, but do not specify when such analysis must be performed or if
it needs to be updated in next-day planning based on any change in
inputs. Similarly, NIPSCO asserts that the proposed Reliability
Standards require the performance of a real-time assessment every 30
minutes but do not address the need to potentially update operating
plans based on changes in system conditions (including unplanned
outages of protection system degradation) and do not require the
performance of additional real-time assessments or other studies with
more frequency based on changes in system conditions. NIPSCO explains
that it is not clear if or when, based on the operational planning
analysis results, some type of additional study or analysis would need
to be undertaken prior to the development of an operating plan.
According to NIPSCO, the text of the requirements and the definition do
not specifically require additional studies; however, it seems that
when issues associated with protection system degradation or outages
are identified, further study of these issues would be required and/or
additional analyses required to update results as protection system
status or transmission or generation outages change.
Commission Determination
    63. We do not share NIPSCO's concern. Reliability Standards IRO-
008-2 and TOP-002-4 require reliability coordinators to perform and

transmission operators to have an operational planning analysis to
assess whether its planned operations for next-day will exceed any of
its SOLs (for the transmission operator) and SOLs/IROLs (for the
reliability coordinator). Both are required to have an operating
plan(s) to address potential SOL and/or IROL exceedances based on its
operational planning analysis results. We believe that, if the
applicable inputs of the operational planning analysis change from one
operating day to the next operating day, and because an operational
planning analysis is an ``evaluation of projected system conditions,''
a new operational planning analysis must be performed to include the
change in applicable inputs. Based on the results of the new
operational planning analysis for next-day, operating plans may need
updating to reflect the results of the new operational planning
analysis. Likewise with the real-time assessment, as system conditions
change and the applicable inputs to the real-time assessment change, a
new assessment would be needed to accurately reflect applicable inputs,
as stated in the real-time assessment definition.\51\
---------------------------------------------------------------------------

    \51\ Real-time assessment is defined as ``An evaluation of
system conditions using Real-time data to assess existing (pre-
Contingency) and potential (post-Contingency) operating conditions.
The assessment shall reflect applicable inputs including, but not
limited to: Load, generation output levels, known Protection System
and Special Protection System status or degradation, Transmission
outages, generator outages, Interchange, Facility Ratings, and
identified phase angle and equipment limitations. (Real-time
Assessment may be provided through internal systems or through
third-party services.).''
---------------------------------------------------------------------------

5. Performing a Real-Time Assessment When Real-Time Contingency
Analysis Is Unavailable
    64. Reliability Standard TOP-001-3, Requirement R13 requires
transmission operators to ensure a real-time assessment is performed at
least every 30 minutes. NIPSCO states that NERC's definition of real-
time assessment anticipates that real-time assessments must be
performed through the use of either an internal tool or third-party
service.\52\ NIPSCO believes that compliance with the requirement to
perform a real-time assessment should not be dependent on the
availability of a system or tool. According to NIPSCO, if a
transmission operators' tools are unavailable for 30 minutes or more,
they should be permitted to meet the requirement to assess existing
conditions through other means.
---------------------------------------------------------------------------

    \52\ See supra n. 48.
---------------------------------------------------------------------------

Commission Determination
    65. Reliability Standard TOP-001-3, Requirement R13 requires the
transmission operator to ensure the assessment is performed at least
once every 30 minutes, but does not state that the transmission
operator on its own must perform the assessment and does not specify a
system or tool. This gives the transmission operator flexibility to
perform its real-time assessment. Further supporting this flexibility,
NERC's definition of real-time assessment states that a real-time
assessment ``may be provided through internal systems or through third-
party services.'' \53\ Therefore, we believe that Reliability Standard
TOP-001-3, Requirement R13 does not specify the system or tool a
transmission operator must use to perform a real-time assessment. In
addition, NERC explains that Reliability Standard TOP-001-3,
Requirement R13 and the definition of real-time assessment ``do not
specify the manner in which an assessment is performed nor do they
preclude Reliability Coordinators and Transmission Operators from
taking `alternative actions' and developing procedures or off-normal
processes to mitigate analysis tool (RTCA) outages and perform the
required assessment of their systems. As an example, the Transmission
Operator could rely on its Reliability Coordinator to perform a Real-
time Assessment or even review its Reliability Coordinator's
Contingency analysis results when its capabilities are unavailable and
vice-versa.'' \54\ Accordingly, we conclude that TOP-001-3 adequately
addresses NIPSCO's concern, namely, if a transmission operators' tools
are unavailable for 30 minutes or more, the transmission operator has
the flexibility to meet the requirement to assess system conditions
through other means.
---------------------------------------------------------------------------

    \53\ NERC TOP/IRO Petition at 18.
    \54\ NERC TOP/IRO Petition, Exh. K (Summary of Development
History and Complete Record of Development), Consideration of
Comments May 19, 2014 through July 2, 2014) at 61.
---------------------------------------------------------------------------

6. Valid Operating Limits
    66. IESO is concerned that the revised TOP standards do not compel
an entity to verify existing limits or re-establish limits following an
event that results in conditions not previously assessed within an
acceptable time frame as is specified in the currently-effective
Reliability Standard TOP-004-2 Requirement R4.\55\ IESO disagrees that
this is sufficient because there is no requirement in the Reliability
Standard TOP-001-3 standard to derive a new set of limits, particularly
transient stability limits, or verify that an existing set of limits
continue to be valid for the prevailing conditions within an
established timeframe. IESO contends that a real-time assessment is
useful only if the system conditions are assessed against a valid set
of limits and is unable to verify or re-establish stability-restricted
SOLs with which to assess system conditions to address reliability
concerns. IESO believes that an explicit requirement to verify or re-
establish SOLs when entering into an unstudied state must therefore be
imposed to fill this reliability gap.
---------------------------------------------------------------------------

    \55\ Requirement R4 states: ``If a Transmission Operator enters
an unknown operating state (i.e. any state for which valid operating
limits have not been determined), it will be considered to be in an
emergency and shall restore operations to respect proven reliable
power system limits within 30 minutes.''
---------------------------------------------------------------------------

    67. Further, IESO asserts that implementing operating plans to
mitigate an SOL exceedance does not require transmission operators to
determine a valid set of limits with which to compare the prevailing
system conditions (i.e. whether or not the limits are exceeded). While
the IESO supports performing a real-time assessment every 30 minutes,
it asserts that performing an assessment without first validating the
current set of limits or re-establishing a new set of limits as the
boundary conditions leaves a reliability gap.
Commission Determination
    68. We agree with IESO that valid operating limits, including
transient stability limits, are essential to the reliable operation of
the interconnected transmission network and that a transmission
operator must not enter into an unknown operating state. Further, we
agree with IESO that Reliability Standard TOP-001-3 has no requirements
to derive a new set of limits or verify an existing set of limits for
prevailing operating conditions within an established timeframe.
However, IESO's concerns regarding the establishment of transient
stability operating limits are addressed collectively through proposed
Reliability Standard TOP-001-3, certain currently-effective Facilities
Design, Connections, and Maintenance (FAC) Reliability Standards and
NERC's Glossary of Terms definition of SOLs.
    69. In its SOL White Paper, NERC stated that the intent of the SOL
concept is to bring clarity and consistency for establishing SOLs,
exceeding SOLs, and implementing operating plans to mitigate SOL
exceedances.\56\ In

addition, ``transient stability ratings'' are included in the SOL
definition. Further, in the SOL White Paper, NERC states that the
``concept of SOL determination is not complete without looking at the
approved NERC FAC standards FAC-008-3, FAC-011-2 and FAC-014-2.'' \57\
Specific to IESO's concerns of establishing transient stability limits,
we agree with NERC that approved Reliability Standard FAC-011-2,
Requirement R2 requires that the reliability coordinator's SOL
methodology include a requirement that SOLs provide a certain level of
bulk electric system performance including among other things, that the
``BES shall demonstrate transient, dynamic and voltage stability'' and
that ``all Facilities shall be within their . . . stability limits''
for both pre- and post-contingency conditions.\58\ In addition, we note
that currently-effective Reliability Standard FAC-011-2, Requirement
R2.1 states that ``[i]n the determination of SOLs, the BES condition
used shall reflect current or expected system conditions and shall
reflect changes to system topology such as Facility outages.'' \59\
---------------------------------------------------------------------------

    \56\ NERC Petition, Exh. E (White Paper on System Operating
Limit Definition and Exceedance Clarification) at 1. NIPSCO requests
clarification as to how NERC's SOL White Paper can be used in
determining compliance. NIPSCO requests that any substantive content
that is treated as containing enforceable compliance requirements be
filed with the Commission for approval. NERC developed the SOL White
Paper as a guidance document which provides links between relevant
reliability standards and reliability concepts to establish a common
understanding necessary for developing effective operating plans to
mitigate SOL exceedances. Guidelines are illustrative but not
mandatory and enforceable compliance requirements. See, e.g. North
American Electric Reliability Corp., 143 FERC ] 61,271, at P 15
(2013). Accordingly, we see no need for further revisions to the
Reliability Standards to incorporate the SOL White Paper as
requested by NIPSCO.
    \57\ NERC Petition, Exh. E at 1.
    \58\ Id. at 2. See also Reliability Standard FAC-011-2,
Requirement R2.
    \59\ Reliability Standard FAC-011-1, Requirement R2.1 (emphasis
added).
---------------------------------------------------------------------------

    70. With respect to Reliability Standard TOP-001-3, we agree with
NERC that Requirement R13 specifies that transmission operators must
perform a real-time assessment at least once every 30 minutes, which by
definition is an evaluation of system conditions to assess existing and
potential operating conditions. The real-time assessment provides the
transmission operator with the necessary knowledge of the system
operating state to initiate an operating plan, as specified in
Requirement R14, when necessary to mitigate an exceedance of SOLs. In
addition, the SOL White Paper provides technical guidance for including
timelines in the required operating plans to return the system to
within prescribed ratings and limits.\60\ Accordingly, we conclude that
the establishment of transient stability operating limits is adequately
addressed collectively through proposed Reliability Standard TOP-001-3,
currently-effective Reliability Standards FAC-011-2 and FAC-014-2 and
NERC's Glossary of Terms definition of SOLs.\61\
---------------------------------------------------------------------------

    \60\ NERC Petition at 57-58.
    \61\ See Reliability Standard FAC-014-2, Requirement R2.
---------------------------------------------------------------------------

III. Information Collection Statement

    71. The collection of information contained in this Final Rule is
subject to review by the Office of Management and Budget (OMB)
regulations under section 3507(d) of the Paperwork Reduction Act of
1995 (PRA).\62\ OMB's regulations require approval of certain
informational collection requirements imposed by agency rules.\63\ Upon
approval of a collection(s) of information, OMB will assign an OMB
control number and an expiration date. Respondents subject to the
filing requirements of a rule will not be penalized for failing to
respond to these collections of information unless the collections of
information display a valid OMB control number.
---------------------------------------------------------------------------

    \62\ 44 U.S.C. 3507(d) (2012).
    \63\ 5 CFR 1320.11.
---------------------------------------------------------------------------

    Public Reporting Burden: The number of respondents below is based
on an estimate of the NERC compliance registry for the balancing
authority, transmission operator, generator operator, distribution
provider, generator owner, load-serving entity, purchasing-selling
entity, transmission service provider, interchange authority,
transmission owner, reliability coordinator, planning coordinator, and
transmission planner functions. The Commission based its paperwork
burden estimates on the NERC compliance registry as of May 15, 2015.
According to the registry, there are 11 reliability coordinators, 99
balancing authorities, 450 distribution providers, 839 generator
operators, 80 purchasing-selling entities, 446 load-serving entities,
886 generator owners, 320 transmission owners, 24 interchange
authorities, 75 transmission service providers, 68 planning
coordinators, 175 transmission planners and 171 transmission operators.
The estimates are based on the change in burden from the current
standards to the standards approved in this Final Rule. The following
table illustrates the burden to be applied to the information
collection:

       RM15-16-000 (Transmission Operations Reliability Standards, Interconnection Reliability Operations and Coordination Reliability Standards)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                          Annual number                    Average burden &     Total annual burden
                                         Number of        of responses    Total number     cost per response   hours & total annual  Cost per respondent
                                     respondents \64\    per respondent   of responses           \65\                  cost                  ($)
                                   (1).................             (2)     (1) * (2) =  (4).................  (3) * (4) = (5).....  (5) / (1)
                                                                                (3)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                        FERC-725A
--------------------------------------------------------------------------------------------------------------------------------------------------------
TOP-001-3........................  196 (TOP & BA)......               1             196  96 hrs., $6,369.....  18,816 hrs.,          96 hrs, $6,369.
                                                                                $1,248,441.
TOP-002-4........................  196 (TOP & BA)......               1             196  284 hrs., $18,843...  55,664 hrs.,          284 hrs., $18,843.
                                                                                $3,693,306.
TOP-003-3........................  196 (TOP & BA)......               1             196  230 hrs., $15,260...  45,080 hrs.,          230 hrs., $15,260.
                                                                                $2,991,058.
                                                        ------------------------------------------------------------------------------------------------
Sub-Total for FERC-725A..........  ....................  ..............  ..............  ....................  123,252 hrs.,         ...................
                                                                                $7,932,806.
--------------------------------------------------------------------------------------------------------------------------------------------------------

                                                                        FERC-725Z
--------------------------------------------------------------------------------------------------------------------------------------------------------
IRO-001-4 \66\...................  177 (RC & TOP)......               1             177  0 hrs. $0...........  0 hrs. $0...........  0 hrs. $0.
IRO-002-4........................  11 (RC).............               1              11  24 hrs., $1,592.....  264 hrs., $17,516...  24 hrs., $1,592.
IRO-008-2........................  11 (RC).............               1              11  228 hrs., $15,127...  2,508 hrs., $166,405  228 hrs., $15,127.
IRO-010-2........................  11 (RC).............               1              11  36 hrs., $2,388.....  396 hrs., $26,274...  36 hrs., $2,388.
IRO-014-3........................  11 (RC).............               1              11  12 hrs., $796.......  132 hrs., $8,758....  12 hrs., $796.
IRO-017-1........................  180 (RC, PC, & TP)..               1             180  218 hrs., $14,464...  39,240 hrs.,          218 hrs., $14,464.
                                                                                $2,603,574.
                                                        ------------------------------------------------------------------------------------------------
Sub-Total for FERC-725Z..........  ....................  ..............  ..............  ....................  42,540 hrs.,          ...................
                                                                                $2,822,529.00.
Retirement of current standards    457(RC, TOP, BA,                   1             457  -223 hrs., -$14,796.  -101,911 hrs., -      -223 hrs., -
 currently in FERC-725A.            TSP, LSE, PSE, &                                                            $6,761,794.           $14,796.
                                    IA).
NET TOTAL of NOPR in RM15-16.....  ....................  ..............  ..............  ....................  63,881 hrs.,
                                                                                $3,993,540.
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Title: FERC-725Z, Mandatory Reliability Standards: IRO Reliability
Standards, and FERC-725A, Mandatory Reliability Standards for the Bulk-
Power System.
    Action: Proposed Changes to Collections.
    OMB Control Nos: 1902-0276 (FERC-725Z); 1902-0244 (FERC-725A).
    Respondents: Business or other for-profit and not-for-profit
institutions.
    Frequency of Responses: On-going.
---------------------------------------------------------------------------

    \64\ the number of respondents is the number of entities for
which a change in burden from the current standards to the proposed
exists, not the total number of entities from the current or
proposed standards that are applicable.
    \65\ The estimated hourly costs (salary plus benefits) are based
on Bureau of Labor Statistics (BLS) information, as of April 1,
2015, for an electrical engineer ($66.35/hour). These figures are
available at http://blsgov/oes/current/naics3_221000.htm#17-0000.
    \66\ IRO-001-4 is a revised standard with no increase in burden.
---------------------------------------------------------------------------

    72. Necessity of the Information and Internal review: The
Commission has reviewed the requirements of Reliability Standards TOP-
001-3, TOP-002-4, TOP-003-3, IRO-001-4, IRO-002-4, IRO-008-2, IRO-010-
2, IRO-014-3, and IRO-017-1 and made a determination that the standards
are necessary to implement section 215 of the FPA. The Commission has
assured itself, by means of its internal review, that there is
specific, objective support for the burden estimates associated with
the information requirements.
    73. Interested persons may obtain information on the reporting
requirements by contacting the Federal Energy Regulatory Commission,
Office of the Executive Director, 888 First Street NE., Washington, DC
20426 [Attention: Ellen Brown, email<EMAIL_ADDRESS>phone:
(202) 502-8663, fax:<PHONE_NUMBER>].
    74. Comments on the requirements of this rule may also be sent to
the Office of Management and Budget, Office of Information and
Regulatory Affairs [Attention: Desk Officer for the Federal Energy
Regulatory Commission]. For security reasons, comments should be sent
by email to OMB at the following email address:
<EMAIL_ADDRESS>Please reference OMB Control Nos. 1902-
0276 (FERC-725Z) and 1902-0244 (FERC-725A)) in your submission.

IV. Environmental Analysis

    75. The Commission is required to prepare an Environmental
Assessment or an Environmental Impact Statement for any action that may
have a significant adverse effect on the human environment.\67\ The
Commission has categorically excluded certain actions from this
requirement as not having a significant effect on the human
environment. Included in the exclusion are rules that are clarifying,
corrective, or procedural or that do not substantially change the
effect of the regulations being amended.\68\ The actions approved
herein fall within this categorical exclusion in the Commission's
regulations.
---------------------------------------------------------------------------

    \67\ Regulations Implementing the National Environmental Policy
Act of 1969, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats.
& Regulations Preambles 1986-1990 ] 30,783 (1987).
    \68\ 18 CFR 380.4(a)(2)(ii).
---------------------------------------------------------------------------

V. Regulatory Flexibility Act Analysis

    76. The Regulatory Flexibility Act of 1980 (RFA) generally requires
a description and analysis of Proposed Rules that will have significant
economic impact on a substantial number of small entities.\69\ The
Small Business Administration's (SBA) Office of Size Standards develops
the numerical definition of a small business.\70\ The SBA revised its
size standard for electric utilities (effective January 22, 2014) to a
standard based on the number of employees, including affiliates (from a
standard based on megawatt hours).\71\ Reliability Standards TOP-001-3,
TOP-002-4, TOP-003-3, IRO-001-4, IRO-002-4, IRO-008-2, IRO-010-2, IRO-
014-3, and IRO-017-1 are expected to impose an additional burden on 196
entities (reliability coordinators, transmission operators, balancing
authorities, transmission service providers, and planning authorities).
Comparison of the applicable entities with the Commission's small
business data indicates that approximately 82 of these entities are
small entities that will be

affected by the proposed Reliability Standards.\72\ As discussed above,
Reliability Standards TOP-001-3, TOP-002-4, TOP-003-3, IRO-001-4, IRO-
002-4, IRO-008-2, IRO-010-2, IRO-014-3, and IRO-017-1 will serve to
enhance reliability by imposing mandatory requirements for operations
planning, system monitoring, real-time actions, coordination between
applicable entities, and operational reliability data. The Commission
estimates that each of the small entities to whom the proposed
Reliability Standards TOP-001-3, TOP-002-4, TOP-003-3, IRO-001-4, IRO-
002-4, IRO-008-2, IRO-010-2, IRO-014-3, and IRO-017-1 applies will
incur costs of approximately $147,364 (annual ongoing) per entity. The
Commission does not consider the estimated costs to have a significant
economic impact on a substantial number of small entities.
---------------------------------------------------------------------------

    \69\ 5 U.S.C. 601-12.
    \70\ 13 CFR 121.101.
    \71\ SBA Final Rule on ``Small Business Size Standards:
Utilities,'' 78 FR 77343 (Dec. 23, 2013).
    \72\ The Small Business Administration sets the threshold for
what constitutes a small business. Public utilities may fall under
one of several different categories, each with a size threshold
based on the company's number of employees, including affiliates,
the parent company, and subsidiaries. For the analysis in this NOPR,
we are using a 750 employee threshold for each affected entity to
conduct a comprehensive analysis.
---------------------------------------------------------------------------

VI. Document Availability

    77. In addition to publishing the full text of this document in the
Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
Internet through FERC's Home Page (http://www.ferc.gov) and in FERC's
Public Reference Room during normal business hours (8:30 a.m. to 5:00
p.m. Eastern time) at 888 First Street NE., Room 2A, Washington, DC
20426.
    78. From FERC's Home Page on the Internet, this information is
available on eLibrary. The full text of this document is available on
eLibrary in PDF and Microsoft Word format for viewing, printing, and/or
downloading. To access this document in eLibrary, type the docket
number excluding the last three digits of this document in the docket
number field.
    79. User assistance is available for eLibrary and the FERC's Web
site during normal business hours from FERC Online Support at 202-502-
6652 (toll free at 1-866-208-3676) or email at
<EMAIL_ADDRESS>or the Public Reference Room at (202) 502-
8371, TTY<PHONE_NUMBER>. Email the Public Reference Room at
<EMAIL_ADDRESS>
VII. Effective Date and Congressional Notification

    80. This final rule is effective January 26, 2016. The Commission
has determined, with the concurrence of the Administrator of the Office
of Information and Regulatory Affairs of OMB, that this rule is not a
``major rule'' as defined in section 351 of the Small Business
Regulatory Enforcement Fairness Act of 1996.

    By the Commission.
    Issued: November 19, 2015.

Nathaniel J. Davis, Sr.,
Deputy Secretary.
 [FR Doc. 2015-30110 Filed 11-25-15; 8:45 am]
 BILLING CODE 6717-01-P