
[Federal Register Volume 80, Number 228 (Friday, November 27, 2015)]
[Rules and Regulations]
[Pages 73977-73991]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[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

[[Page 73978]]

20426, Telephone: (202) 502-8473, Robert.Stroh@ferc.gov.
Eugene Blick (Technical Information), Office of Electric Reliability, 
Federal Energy Regulatory Commission, 888 First Street NE., Washington, 
DC 20426, Telephone: (301) 665-1759, Eugene.Blick@ferc.gov.
Darrell G. Piatt, PE (Technical Information), Office of Electric 
Reliability, Federal Energy Regulatory Commission, 888 First Street 
NE., Washington, DC 20426, Telephone: (205) 332-3792, 
Darrell.Piatt@ferc.gov.

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

[[Page 73979]]

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

[[Page 73980]]

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

[[Page 73981]]

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.

[[Page 73982]]

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.
---------------------------------------------------------------------------

    \23\ NOPR, 151 FERC ] 61,236 at P 58.
---------------------------------------------------------------------------

    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

[[Page 73983]]

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

[[Page 73984]]

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

[[Page 73985]]

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

[[Page 73986]]

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

[[Page 73987]]

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

[[Page 73988]]

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

[[Page 73989]]

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.
--------------------------------------------------------------------------------------------------------------------------------------------------------

[[Page 73990]]

 
                                                                        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: DataClearance@ferc.gov, phone: 
(202) 502-8663, fax: (202) 273-0873].
    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: 
oira_submission@omb.eop.gov. 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

[[Page 73991]]

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 
ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at 
public.referenceroom@ferc.gov.

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


