Transmission Operations Reliability Standards and Interconnection Reliability Operations and Coordination Reliability Standards, 73977-73991 [2015-30110]
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Federal Register / Vol. 80, No. 228 / Friday, November 27, 2015 / Rules and Regulations
standards, the entities with marketbased rates which are affected by this
Final Rule likely come under the
following categories 117 with the
indicated thresholds (in terms of
number of employees 118):
• Hydroelectric Power Generation,
500 employees.
• Fossil Fuel Electric Power
Generation, 750 employees.
• Nuclear Electric Power Generation,
750 employees.
• Solar Electric Power Generation,
250 employees.
• Wind Electric Power Generation,
250 employees.
• Geothermal Electric Power
Generation, 250 employees.
• Biomass Electric Power Generation,
250 employees.
• Other Electric Power Generation,
250 employees.
82. The categories for the applicable
entities have a size threshold ranging
from 250 employees to 750 employees.
For the analysis in this Final Rule, we
are using the threshold of 750
employees for all categories. We
anticipate that a maximum of 82 percent
of the entities potentially affected by
this Final Rule are small. In addition,
we expect that not all of those entities
will be able to or will choose to offer
primary frequency response service.
83. Based on the estimates above in
the Information Collection section, we
expect a one-time cost of $576
(including the burden cost related to
filing both the tariff and the EQR) for
each entity that decides to offer primary
frequency response service.
84. The Commission does not
consider the estimated cost per small
entity to impose a significant economic
impact on a substantial number of small
entities. Accordingly, the Commission
certifies that this Final Rule will not
have a significant economic impact on
a substantial number of small entities.
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VII. Document Availability
85. 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 the
Commission’s Home Page (https://
www.ferc.gov) and in the Commission’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.
117 13
CFR 121.201, Sector 22, Utilities.
regulations at 13 CFR 121.201 state that
‘‘[t]he number of employees . . . indicates the
maximum allowed for a concern and its affiliates
to be considered small.’’
118 SBA’s
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86. From the Commission’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.
87. User assistance is available for
eLibrary and the Commission’s Web site
during normal business hours from the
Commission’s 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.
VIII. Effective Date and Congressional
Notification
88. The Final Rule is effective
February 25, 2016. The Commission has
determined, with the concurrence of the
Administrator of the Office of
Information and Regulatory Affairs of
OMB, that this Final Rule is not a
‘‘major rule’’ as defined in section 351
of the Small Business Regulatory
Enforcement Fairness Act of 1996. This
Final Rule is being submitted to the
Senate, House, Government
Accountability Office, and Small
Business Administration.
List of Subjects in 18 CFR Part 35
Electric power rates; Electric utilities;
Reporting and recordkeeping
requirements.
By the Commission.
Issued: November 20, 2015.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
PART 35—FILING OF RATE
SCHEDULES AND TARIFFS
1. The authority citation for Part 35
continues to read as follows:
■
Authority: 16 U.S.C. 791a–825r, 2601–
2645; 31 U.S.C. 9701; 42 U.S.C. 7101–7352.
2. In § 35.37, revise paragraph (c)(1) to
read as follows:
■
Market power analysis required.
*
*
*
*
*
(c)(1) There will be a rebuttable
presumption that a Seller lacks
horizontal market power with respect to
sales of energy, capacity, energy
imbalance service, generation imbalance
service, and primary frequency response
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service if it passes two indicative market
power screens: a pivotal supplier
analysis based on annual peak demand
of the relevant market, and a market
share analysis applied on a seasonal
basis. There will be a rebuttable
presumption that a Seller lacks
horizontal market power with respect to
sales of operating reserve-spinning and
operating reserve-supplemental services
if the Seller passes these two indicative
market power screens and demonstrates
in its market-based rate application how
the scheduling practices in its region
support the delivery of operating reserve
resources from one balancing authority
area to another. There will be a
rebuttable presumption that a Seller
possesses horizontal market power with
respect to sales of energy, capacity,
energy imbalance service, generation
imbalance service, operating reservespinning service, operating reservesupplemental service, and primary
frequency response service if it fails
either screen.
*
*
*
*
*
[FR Doc. 2015–30140 Filed 11–25–15; 8:45 am]
BILLING CODE 6717–01–P
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
Federal Energy Regulatory
Commission, Energy.
ACTION: Final rule.
AGENCY:
In consideration of the foregoing, the
Commission amends Part 35, Chapter I,
Title 18, Code of Federal Regulations, as
follows.
§ 35.37
73977
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
SUMMARY:
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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
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(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 Commissioncertified 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
1 16
U.S.C. 824o (2012).
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currently-effective requirements or have
little reliability benefit.2
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.
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
2 Electric Reliability Organization Proposal to
Retire Requirements in Reliability Standards, Order
No. 788, 145 FERC ¶ 61,147 (2013).
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).
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 currentlyeffective 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.
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
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.
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: https://www.nerc.com.
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improvements over the currentlyeffective 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 preestablished 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’’).
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
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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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
12 Transmission Operations Reliability Standards
and Interconnection Reliability Operations and
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73979
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).
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
Coordination Reliability Standards, 151 FERC ¶
61,236 (2015) (NOPR).
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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promoting increased efficiencies in
Reliability Standards and reducing
requirements that are either redundant
with other currently-effective
requirements or have little reliability
benefit.14
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.
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
14 See
Order No. 788, 145 FERC ¶ 61,147.
e.g., Order No. 748, 134 FERC ¶ 61,213,
at PP 39–40.
15 See,
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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
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 realtime assessment address other concerns
raised in the Remand NOPR as well as
multiple recommendations in the 2011
Southwest Outage Blackout Report.17
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.
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
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
A. Possible Inconsistences in IROLs
Across Regions
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.’’
17 NERC Petition at 17–18.
18 Remand NOPR, 145 FERC ¶ 61,158 at P 90.
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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
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
E:\FR\FM\27NOR1.SGM
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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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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
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%20
FINAL.pdf.
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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commits to working with stakeholders
and Commission staff during the Project
2015–09 standards development process
to address the issues raised in the
NOPR.
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
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Fmt 4700
Sfmt 4700
73981
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.
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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
B. Monitoring of Non-Bulk Electric
System Facilities
NOPR
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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.
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
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.’’
23 NOPR, 151 FERC ¶ 61,236 at P 58.
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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-time monitoring,
and real-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.
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
24 E.g. NERC, EEI, TAPS, Occidental, and
NIPSCO.
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Fmt 4700
Sfmt 4700
systems that would ensure that all nonBES 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
25 See
E:\FR\FM\27NOR1.SGM
also ISO/RTOs Comments at 3.
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Federal Register / Vol. 80, No. 228 / Friday, November 27, 2015 / Rules and Regulations
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
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
26 See
also ISO/RTOs Comments at 4–6.
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
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27 NERC
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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 nonBES 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
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. . . .’’ https://
www.nerc.com/pa/RAPA/BES%20DL/
BES%20FAQs.pdf.
31 See, e.g., NERC TOP/IRO Petition at 18 and 27–
28.
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73983
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 nonbulk electric system facilities to the
extent necessary. NERC can develop an
equally efficient and effective
alternative that addresses our
concerns.32
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.
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
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.
33 The Commission also notes that Reliability
Standards TOP–003–3 and IRO–010–2 also include
‘‘load-serving entity’’ as an applicable entity.
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Federal Register / Vol. 80, No. 228 / Friday, November 27, 2015 / Rules and Regulations
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.
Comments
39. NERC states that while loadserving 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.
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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
34 North American Electric Reliability Corp. 150
FERC ¶ 61,213 (2015) (March 19 Order).
35 North American Electric Reliability Corp, 153
FERC ¶ 61,024 (2015).
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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
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
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
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.
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.
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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 backup 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
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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.
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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
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.’’
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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.
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.
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.
41 See NERC COM Petition, Exh. M,
(Consideration of Comments on Initial Ballot,
February 25–March 7, 2011) at 30 (emphasis
added).
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73985
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 backup 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
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.’’
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model for use in the TOP and IRO
Standards.43
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.
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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.
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.’’
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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 decisionmaking authority NERC developed in
the TOP and IRO Reliability Standards.
Thus, we determine that no further
action is required.
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 nextday operational planning analysis, realtime 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
44 See Reliability Standards TOP–001–3 and IRO–
014–3.
45 See Reliability Standard IRO–001–4,
Requirement R2.
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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
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).
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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 TOP002-4 (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.
3. Reliability Coordinator Authority in
Next-Day Operations and the Issuance
of Operating Instructions
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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 nextday 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 realtime. 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.)
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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
61. In addition, we do not agree with
NIPSCO’s claim that operating
instructions are ‘‘clearly limited to realtime 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
48 See Reliability Standards IRO-008-2,
Requirements R1 and R2, and IRO-014-3,
Requirement R1.
49 See supra n. 46.
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73987
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.
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-0082 and TOP-002-4 require reliability
coordinators to perform and
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 https://www.nerc.com/files/
Time_Horizons.pdf.
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transmission operators to have an
operational planning analysis to assess
whether its planned operations for nextday 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
5. Performing a Real-Time Assessment
When Real-Time Contingency Analysis
Is Unavailable
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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.
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.).’’
52 See supra n. 48.
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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 TOP001-3 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.
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
53 NERC
TOP/IRO Petition at 18.
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.
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
54 NERC
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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 reestablish SOLs when entering into an
unstudied state must therefore be
imposed to fill this reliability gap.
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
proven reliable power system limits within 30
minutes.’’
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
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Federal Register / Vol. 80, No. 228 / Friday, November 27, 2015 / Rules and Regulations
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 FAC008-3, 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 postcontingency 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
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 realtime 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
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
73989
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.
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 purchasingselling 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)
Number of
respondents 64
Annual
number of
responses per
respondent
Total number
of responses
Average burden &
cost per response 65
Total annual
burden hours &
total annual cost
Cost per respondent ($)
(1)
(2)
(1) * (2) = (3)
(4)
(3) * (4) = (5)
(5) ÷ (1)
FERC–725A
196 (TOP & BA) ....
1
196
96 hrs., $6,369 ..........
TOP–002–4 ...........
196 (TOP & BA) ....
1
196
284 hrs., $18,843 ......
TOP–003–3 ...........
196 (TOP & BA) ....
1
196
230 hrs., $15,260 ......
Sub-Total for
FERC–725A.
mstockstill on DSK4VPTVN1PROD with RULES
TOP–001–3 ...........
...............................
........................
........................
...................................
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
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16:09 Nov 25, 2015
Jkt 238001
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.
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Fmt 4700
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18,816 hrs.,
$1,248,441.
55,664 hrs.,
$3,693,306.
45,080 hrs.,
$2,991,058.
96 hrs, $6,369.
284 hrs., $18,843.
230 hrs., $15,260.
123,252 hrs.,
$7,932,806.
58 Id. at 2. See also Reliability Standard FAC-0112, Requirement R2.
59 Reliability Standard FAC-011-1, Requirement
R2.1 (emphasis added).
60 NERC Petition at 57–58.
61 See Reliability Standard FAC-014-2,
Requirement R2.
62 44 U.S.C. 3507(d) (2012).
63 5 CFR 1320.11.
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Federal Register / Vol. 80, No. 228 / Friday, November 27, 2015 / Rules and Regulations
RM15–16–000 (TRANSMISSION OPERATIONS RELIABILITY STANDARDS, INTERCONNECTION RELIABILITY OPERATIONS AND
COORDINATION RELIABILITY STANDARDS)—Continued
Number of
respondents 64
Annual
number of
responses per
respondent
Total number
of responses
Average burden &
cost per response 65
Total annual
burden hours &
total annual cost
Cost per respondent ($)
(1)
(2)
(1) * (2) = (3)
(4)
(3) * (4) = (5)
(5) ÷ (1)
0 hrs. $0 ................
264 hrs., $17,516 ..
2,508 hrs.,
$166,405.
396 hrs., $26,274 ..
132 hrs., $8,758 ....
39,240 hrs.,
$2,603,574.
0 hrs. $0.
24 hrs., $1,592.
228 hrs., $15,127.
FERC–725Z
IRO–001–4 66 ........
IRO–002–4 ............
IRO–008–2 ............
177 (RC & TOP) ...
11 (RC) .................
11 (RC) .................
1
1
1
177
11
11
0 hrs. $0 ....................
24 hrs., $1,592 ..........
228 hrs., $15,127 ......
IRO–010–2 ............
IRO–014–3 ............
IRO–017–1 ............
11 (RC) .................
11 (RC) .................
180 (RC, PC, &
TP).
1
1
1
11
11
180
36 hrs., $2,388 ..........
12 hrs., $796 .............
218 hrs., $14,464 ......
Sub-Total for
FERC–725Z.
Retirement of current standards
currently in
FERC–725A.
NET TOTAL of
NOPR in RM15–
16.
...............................
........................
........................
...................................
1
457
¥223 hrs., ¥$14,796
........................
........................
...................................
457(RC, TOP, BA,
TSP, LSE, PSE,
& IA).
...............................
mstockstill on DSK4VPTVN1PROD with RULES
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 forprofit and not-for-profit institutions.
Frequency of Responses: On-going.
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
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 https://blsgov/oes/current/
naics3_221000.htm#17-0000.
66 IRO–001–4 is a revised standard with no
increase in burden.
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16:09 Nov 25, 2015
Jkt 238001
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
42,540 hrs.,
$2,822,529.00.
¥101,911 hrs.,
¥$6,761,794.
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).
PO 00000
Frm 00048
Fmt 4700
Sfmt 4700
¥223 hrs.,
¥$14,796.
63,881 hrs.,
$3,993,540.
regulations being amended.68 The
actions approved herein fall within this
categorical exclusion in the
Commission’s regulations.
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
68 18
67 Regulations
36 hrs., $2,388.
12 hrs., $796.
218 hrs., $14,464.
CFR 380.4(a)(2)(ii).
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).
69 5
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Federal Register / Vol. 80, No. 228 / Friday, November 27, 2015 / Rules and Regulations
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.
mstockstill on DSK4VPTVN1PROD with RULES
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
DEPARTMENT OF DEFENSE
Department of the Navy
RIN 0703–AA92
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 (https://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.
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.
16:09 Nov 25, 2015
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.
[No. USN–2013–0011]
VI. Document Availability
VerDate Sep<11>2014
VII. Effective Date and Congressional
Notification
Jkt 238001
32 CFR Part 776
Professional Conduct of Attorneys
Practicing Under the Cognizance and
Supervision of the Judge Advocate
General; Correction
Department of the Navy, DoD.
Final rule; correction.
AGENCY:
ACTION:
On November 4, 2015, the
Department of the Navy (DoN)
published a final rule to comport with
current policy as stated in JAG
Instruction 5803.1 (Series) governing the
professional conduct of attorneys
practicing under the cognizance and
supervision of the Judge Advocate
General. The content of one of its CFRs
is better codified as an appendix, and
this correction amends the CFR
accordingly.
SUMMARY:
This correction is effective
December 4, 2015.
DATES:
FOR FURTHER INFORMATION CONTACT:
Commander Noreen A. Hagerty-Ford,
JAGC, U.S. Navy, Office of the Judge
Advocate General (Administrative Law),
Department of the Navy, 1322 Patterson
Ave. SE., Suite 3000, Washington Navy
Yard, DC 20374–5066, telephone: 703–
614–7408.
SUPPLEMENTARY INFORMATION: The DoN
published a rule at 80 FR 68388 on
November 4, 2015, to revise 32 CFR part
776, to comport with current policy as
stated in JAG Instruction 5803.1 (Series)
governing the professional conduct of
attorneys practicing under the
cognizance and supervision of the Judge
Advocate General. The content of
PO 00000
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73991
§ 776.94 is more appropriate as an
appendix, and this correction amends
the CFR accordingly, redesignating
§ 776.94 as an appendix to subpart D. In
addition, because § 776.94 becomes an
appendix to its subpart, DoN is
redesignating § 776.95 in the November
4 rule as § 776.94.
Correction
In FR Rule Doc. 2015–26982
appearing on page 68388 in the Federal
Register of Wednesday, November 4,
2015, the following corrections are
made:
■ 1. On page 68390, in the first column,
third line, revise ‘‘776.94 Outside Law
Practice Questionnaire and Request.’’ to
read ‘‘Appendix to Subpart D of Part
776—Outside Law Practice
Questionnaire and Request.’’ and in the
seventh line, revise ‘‘776.95 Relations
with Non-USG Counsel.’’ to read
‘‘776.94 Relations with Non-USG
Counsel.’’;
■ 2. On page 68408, in the third column,
second line, revise ‘‘§ 776.94 of this
part’’ to read ‘‘appendix to subpart D of
part 776’’;
■ 3. On page 68408, in the third column,
revise the section heading ‘‘§ 776.94
Outside Law Practice Questionnaire and
Request.’’ to read ‘‘Appendix to Subpart
D of Part 776—Outside Law Practice
Questionnaire and Request.’’; and
■ 4. On page 68409, in the second
column under the Subpart E heading,
revise ‘‘§ 776.95 Relations with NonUSG Counsel.’’ to read ‘‘§ 776.94
Relations with Non-USG Counsel.’’.
Dated: November 20, 2015.
N.A. Hagerty-Ford,
Commander,Office of the Judge Advocate
General,U.S. Navy, Federal Register Liaison
Officer.
[FR Doc. 2015–30190 Filed 11–25–15; 8:45 am]
BILLING CODE 3810–FF–P
DEPARTMENT OF EDUCATION
34 CFR Parts 600, 602, 603, 668, 682,
685, 686, 690, and 691
[Docket ID ED–2010–OPE–0004]
RIN 1840–AD02
Program Integrity Issues
Office of Postsecondary
Education, Department of Education.
ACTION: Final regulations; clarification
and additional information.
AGENCY:
On October 29, 2010, the
Department of Education published in
the Federal Register final regulations for
improving integrity in the programs
authorized under title IV of the Higher
SUMMARY:
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]]>Agencies
[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]
-----------------------------------------------------------------------
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.
-----------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
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: https://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).
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\15\ See, e.g., Order No. 748, 134 FERC ] 61,213, at PP 39-40.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\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.''
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\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\
---------------------------------------------------------------------------
\18\ Remand NOPR, 145 FERC ] 61,158 at P 90.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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.
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29. The Commission stated that including such non-bulk electric
system facilities in the definition of bulk electric system through the
NERC Rules of Procedure exception process could be an option to address
any potential gaps for monitoring facilities but notes that there may
be potential efficiencies gained by using a more expedited method to
include non-bulk electric system facilities that requires monitoring.
The Commission sought comment on whether the BES exception process
should be used exclusively in all cases. Alternatively, the Commission
sought comment on whether this concern can be addressed through a
review process of the transmission operators' systems to determine if
there are important non-bulk electric system facilities that require
monitoring.
Comments
30. Nearly all commenters support the Reliability Standards as
proposed as sufficient for identifying and monitoring non-bulk electric
system facilities, and do not support the alternatives offered by the
Commission in the NOPR.\24\ NERC submits that the proposed data
specification and collection Reliability Standards IRO-010-2 and TOP-
003-3, in addition to the exceptions process will help ensure that the
reliability coordinator can work with transmission operators, and other
functional entities, to obtain sufficient information to identify the
necessary non-bulk electric system facilities to monitor. In support,
NERC points to Reliability Standard IRO-010-2, which provides a
mechanism for the reliability coordinator to obtain the information and
data it needs for reliable operations and to help prevent instability,
uncontrolled separation, or cascading outages. Further, NERC cites
Reliability Standard TOP-003-3, which allows transmission operators to
obtain data on non-bulk electric system facilities, necessary to
perform their operational planning analyses, real[hyphen]time
monitoring, and real[hyphen]time assessments from applicable entities.
NERC explains that any data that the transmission operator obtains
regarding non-bulk electric system facilities under Reliability
Standard TOP-003-3 can be passed on to the reliability coordinator
pursuant to a request under proposed Reliability Standard IRO-010-2.
Accordingly, NERC states that it would be premature to develop an
alternative process before the data specification and bulk electric
system exception process are allowed to work.
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\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\
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\25\ See also ISO/RTOs Comments at 3.
\26\ See also ISO/RTOs Comments at 4-6.
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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\
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\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. . . .'' https://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.
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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.
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\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.
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\34\ North American Electric Reliability Corp. 150 FERC ] 61,213
(2015) (March 19 Order).
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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\
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\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.
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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\
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\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.
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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.
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\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.''
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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\
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\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.''
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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.
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\44\ See Reliability Standards TOP-001-3 and IRO-014-3.
\45\ See Reliability Standard IRO-001-4, Requirement R2.
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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.
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\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).
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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\
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\48\ See Reliability Standards IRO-008-2, Requirements R1 and
R2, and IRO-014-3, Requirement R1.
\49\ See supra n. 46.
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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.
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\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
https://www.nerc.com/files/Time_Horizons.pdf.
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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\
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\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.).''
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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.
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\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.
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\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.
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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.
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\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\
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\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).
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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\
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\60\ NERC Petition at 57-58.
\61\ See Reliability Standard FAC-014-2, Requirement R2.
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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.
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\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.
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\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 https://blsgov/oes/current/naics3_221000.htm#17-0000.
\66\ IRO-001-4 is a revised standard with no increase in burden.
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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.
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\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).
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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.
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\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.
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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 (https://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
