UNITED STATES OF AMERICA
BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

Transmission Operation Reliability)

Standards and Interconnection)Docket No. RM15-16-000

Reliability Operations and Coordination)

Reliability Standards)

JOINT COMMENTS OF INDEPENDENT ELECTRICITY SYSTEM OPERATOR,

ISO NEW ENGLAND INC., MIDCONTINENT INDEPENDENT SYSTEM OPERATOR,
NEW YORK INDEPENDENT SYSTEM OPERATOR, INC., PJM

INTERCONNECTION, L.L.C., AND SOUTHWEST POWER POOL, INC.

Pursuant to Rule 213 of the Rules of Practice and Procedure of the Federal Energy

Regulatory Commission1 (the “Commission”), Independent Electricity System Operator, ISO
New England Inc., Midcontinent Independent System Operator, New York Independent System
Operator, Inc., PJM Interconnection, L.L.C., and Southwest Power Pool (“together, the
“ISOs/RTOs”) submit these comments in response to the Notice of Proposed Rulemaking
(“NOPR”) issued by the Commission in the above-referenced docket on June 18, 2015,
proposing approval of revisions to the Transmission Operations (“TOP”) and Interconnection
Reliability and Operations and Coordination (“IRO”) Reliability Standards developed by the
North American Electric Reliability Corporation (“NERC”).2 The Commission proposes to find
that NERC has adequately addressed the concerns raised by the Commission in the Remand
NOPR issued in November 2013, in which the Commission proposed to remand an earlier
version of proposed TOP and IRO Reliability Standards. Although the Commission is proposing
to approve the TOP and IRO Reliability Standards, it also seeks clarifying comments on, among

1 18 C.F.R. § 385.213 (2013).

2 See Transmission Operations Reliability Standards and Interconnection Reliability Operations and Coordination Reliability Standards, 151 FERC ¶ 61,236 (2015), 80 Fed. Reg. 36280 (June 24, 2015).

other issues, monitoring of non-bulk electric system (“BES”) facilities, and data exchange capabilities. The ISOs/RTOs3 hereby provide comments on those two issues.

I.IDENTIFICATION OF FILING PARTIES

Independent Electricity System Operator is the regional transmission organization

(“RTO”) for Ontario, Canada. ISO New England Inc. is the private, non-profit entity that serves
as the RTO for the six New England states. Midcontinent Independent System Operator is the
RTO for fifteen states in the United States and the Canadian province of Manitoba. The New
York Independent System Operator is the ISO for the New York Control Area. PJM
Interconnection, L.L.C. serves as the RTO in all or part of thirteen states and the District of
Columbia. Southwest Power Pool, Inc., is the RTO for all or part of eight states. Among other
functions, the ISOs/RTOs are registered with NERC as Reliability Coordinators.

II.COMMENTS

A.Non-BES Facilities to be Monitored Should be Included in the Definition of

BES through the Rules of Procedure Exception Process, and the Language in
Reliability Standards IRO-002-4, Requirement R3, IRO-010-2, Requirement
R1.1, and TOP-003-3, Requirement R1.1 Should be Clarified Accordingly.

In its petition, NERC explains how the proposed Reliability Standards address the

recommendations in the 2011 Southwest Outage Blackout Report, in particular with respect to

Finding 17 concerning the impact of sub-100 kV facilities on the reliability of the interconnected
transmission network.4 Specifically, NERC explains that proposed Reliability Standard IRO-
002-4, Requirement R3 addresses monitoring of non-BES facilities by requiring each Reliability
Coordinator to monitor facilities and necessary non-BES facilities in order to identify System

3 The Independent Electricity System Operator (“IESO”) as signatory to these comments should not be interpreted as the IESO’s support of the proposed approval of TOP-001-3, as it includes the retirement of TOP-004-2 R4. The IESO sees this requirement as not being adequately mapped into TOP-001-3. The IESO submitted comments on this docket on June 12, 2015; refer to FERC Accession Number 20150612-5184.

4 NOPR at P 55 (citing NERC Petition at 61).

Operating Limit and Interconnection Reliability Operating Limit exceedances within its

Reliability Coordinator Area. In addition, NERC states that proposed Reliability Standards IRO010-2, Requirement R1.1, and TOP-003-3, Requirement R1.1, address non-BES system data by specifically requiring Reliability Coordinators and Transmission Operators to incorporate any non-BES system data as deemed necessary into their operational planning analyses, real-time monitoring, and real-time assessments.5

NERC further explained that, while the standard drafting team included non-BES

monitoring for the Reliability Coordinator in proposed Reliability Standard IRO-002-4,

Requirement R3, it concluded that it was not necessary to include non-BES monitoring for the Transmission Operator in proposed Reliability Standard TOP-001-3, Requirement R10. Instead, the standard drafting team determined that any non-BES facility elements that are necessary for reliable operation of the BES would be included in the BES through the exception process
provided in Appendix 5C to the NERC Rules of Procedure. NERC stated that the exception process provides the means for Transmission Operators and Reliability Coordinators to include elements in the BES that are necessary for the reliable operation of the interconnected
transmission system but not identified in the BES definition.6

In the NOPR, the Commission proposes to find that NERC adequately addressed the

2011 Southwest Outage Blackout Report recommendation in connection with sub-100 kV

facilities for IRO-002-4, Requirement R3, IRO-010-2, Requirement R1.1, and TOP-003-3,

Requirement R1.1.7 The Commission went on to state, however, that the Transmission Operator
may have a more granular perspective than the Reliability Coordinator of its necessary non-BES

5 NOPR at P 55 (citing NERC Petition at 61).

6 Id. at P 56 (citing NERC petition at 47-48).

7 Id. at P 57.

exceedances, and it is not clear whether or how the Transmission Operator would communicate
any insight it may have to the Reliability Coordinator to ensure monitoring of all necessary
facilities. For this reason, the Commission seeks comment on how NERC will ensure that the
Reliability Coordinator will receive information from the Transmission Operator regarding
which non-BES facilities should be monitored, and states that including such non-BES facilities
in the definition of BES through the Rules of Procedure exception process could be an option to
address any potential gaps for monitoring facilities. The Commission states that, because there
may be potential efficiencies gained by using a more expedited method to include non-BES
facilities that require monitoring, it seeks comments on whether the exception process should be
used exclusively in all cases.8

The ISOs/RTOs respectfully request that, as suggested by the Commission, non-BES facilities to be monitored be included in the definition of BES facilities through the Rules of Procedure exception process, and that this approach be reflected in revisions to proposed
Reliability Standards IRO-002-4, Requirement R3, IRO-010-2, Requirement R1.1, and TOP003-3, Requirement R1.1.

To address the 2011 Southwest Outage Blackout Report’s Finding 17, which concerned
the impact of sub-100 kV facilities on the reliability of the interconnected transmission network,
the standard drafting team initially used the words “sub-100 kV facilities” in proposed
Reliability Standards IRO-002-4, Requirement R3, IRO-010-2, Requirement R1.1, and TOP-

8 NOPR at P 58. In the alternative, the Commission seeks comment regarding whether this concern should be

addressed through a review process of the Transmission Operators’ systems to determine if there are important nonBES facilities that require monitoring. For example, Commission staff could work with NERC, Regional Entities, and applicable entities to review their system modeling and perform an analysis to identify non-BES facilities that need monitoring. Id. at P 59. As explained below, the exception process has been approved by the Commission and should be used to address any potential gaps for monitoring facilities.

003-3, Requirement R1.1. The language was also originally used in proposed Reliability Standard TOP-001-3, Requirement 10.

When the initial versions of the proposed Reliability Standards were posted for comment,
various commenters pointed out to the standard drafting team that sub-100 kV transmission
equipment is not subject to reliability standards unless it is deemed to be a part of the BES. To
address these comments, the standard drafting team replaced “sub-100 kV” with “non-BES
facilities.” When the revised versions of the proposed Reliability Standards were posted for
comment, commenters (including the Standards Review Committee (“SRC”) of the ISO/RTO
Council) explained that the term “non-BES facilities” is outside the scope of Reliability
Standards and, accordingly, they requested that the term “non-BES” be removed from the
proposed Reliability Standards. The SRC explained that the BES inclusion process should
capture any equipment that is sub-100 kV and affects BES reliability so as to bring it into the
scope of Reliability Standards. The standard drafting team did not remove the language from
proposed Reliability Standards IRO-002-4, Requirement R3, IRO-010-2, Requirement R1.1, and
TOP-003-3, Requirement R1.1, and those proposed standards were approved by the NERC
Board of Trustees, with the “non-BES” language included, on November 13, 2014. The standard
drafting team, however, adequately addressed the comments it received by removing the “non-
BES” language from proposed Reliability Standard TOP-001-3, Requirement 10. That proposed
standard was approved by the NERC Board of Trustees on February 12, 2015. As already
mentioned, in its Petition, NERC explained that, for TOP-001-3, Requirement R10, any non-
BES facility elements that are necessary for reliable operation of the BES would be included in
the BES through the exception process provided in Appendix 5C to the NERC Rules of
Procedure.

In Order No. 773, the Commission accepted NERC’s proposal to use the exception
process provided in the NERC Rules of Procedure to add elements to, and remove elements
from, the BES, on a case-by-case basis.9 The Commission found that the exception process
balances the need for effective and efficient administration with due process and clarity of
expectations and promotes consistency in determinations and eliminates regional discretion by
having all decisions on exception requests made at NERC.10 The Commission also found that
the exception process provides for involvement of persons with applicable technical expertise in
making decisions on exception requests and allows for an entity to appeal a final NERC decision
to the Commission.11 Thus, the Commission concluded that the exception process provides a
reasonable mechanism for the Electric Reliability Organization to determine whether a facility or
element should be added to, or removed from, the BES on a case-by case basis.12
Based on the foregoing findings by the Commission, the ISOs/RTOs respectfully submit that any non-BES facility elements to be monitored should be included in the BES through the exception process. In other words, the approach used to address sub-100 kV facilities in
proposed Reliability Standard TOP-001-3, Requirement 10, should also be used for the other
three proposed Reliability Standards. Accordingly, proposed Reliability Standards IRO-002-4,
Requirement R3, IRO-010-2, Requirement R1.1, and TOP-003-3, Requirement R1.1 should be
clarified by deleting the “non-BES” language (as was done for Reliability Standard TOP-001-3,
Requirement 10). In the alternative, to clarify the proposed Reliability Standards and make them
more precise, the words “non-BES facilities” in proposed Reliability Standard IRO-002-4,

9 Revisions to Electric Reliability Organization Definition of Bulk Electric System and Rules of Procedure, Order No. 773, 141 FERC ¶ 61,236 (2012) at P 251.

10 Id.

11 Id.

12 Id. at P 252.

Requirement 3, should be replaced with “sub-100 kV facilities identified as part of the BES through the BES exception process.”13 Similarly, in Reliability Standards IRO-010-2,
Requirement R1.1, and TOP-003-3, Requirement R1.1, the words “non-BES data” should be replaced with “data from sub-100 kV facilities identified as part of the BES through the BES exception process.”14

B. Reliability Risks Associated with Establishing Redundant and Diverse

Routing Data Exchange Capabilities are Adequately Addressed by the Suite of Currently Effective COM and EOP Reliability Standards and the
Proposed TOP and IRO Reliability Standards.

In the NOPR that is the subject of this proceeding, the Commission states that it approved
Reliability Standards COM-001-2 (Communications) and COM-002-4 (Operating Personnel
Communications Protocols) in Order No. 808, and that, in the NOPR underlying that Order
(“COM NOPR”), it had raised concerns on whether Reliability Standard COM-001-2 addresses
“facilities that directly exchange or transfer data.” In response to that concern in the COM

13 With the proposed revisions, Reliability Standard IRO-002-4, Requirement R3 (blacklined) reads as follows: Each Reliability Coordinator shall monitor Facilities, the status of Special Protection Systems, and non-BES facilities sub100 kV facilities identified as part of the BES through the BES exception process 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.

14 With the proposed revisions, Reliability Standard IRO-010-2, Requirement R1.1 (blacklined) reads as follows: The Reliability Coordinator shall maintain a documented specification for the data necessary for it to perform its Operational Planning Analyses, Real-time monitoring, and Real-time Assessments. The data specification shall include but not be limited to:

1.1. A list of data and information needed by the Reliability Coordinator to support its Operational Planning

Analyses, Real-time monitoring, and Realtime Assessments including non-BES data data from sub-100 kV facilities identified as part of the BES through the BES exception process and external network data, as deemed necessary by the Reliability Coordinator.

With the proposed revisions, Reliability Standard TOP-003-3, Requirement R1.1 (blacklined) reads as follows: Each Transmission Operator shall maintain a documented specification for the data necessary for it to perform its
Operational Planning Analyses, Real-time monitoring, and Real-time Assessments. The data specification shall
include, but not be limited to:

1.1. A list of data and information needed by the Transmission Operator to support its Operational Planning

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.15 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.16 The Commission states that it appears that facilities for data
exchange capabilities are addressed in NERC’s proposal in the instant proceeding. However, the
Commission seeks further explanation or clarification regarding whether and how the proposed
TOP and IRO Reliability Standards address redundancy and diverse routing or an equally

effective alternative to redundancy and diverse routing. Further, if NERC or others believe that redundancy and diverse routing are not addressed, the Commission seeks comment on whether there are associated reliability risks of interconnected transmission networks for any failure of data exchange capabilities that are not redundant and diversely routed.17

As explained in detail below, the ISOs/RTOs respectfully submit that reliability risks of interconnected transmission networks related to failure of data exchange capabilities that are not redundantly and diversely routed are addressed in the suite of currently-effective COM and EOP Reliability Standards and the proposed TOP and IRO Reliability Standards.

First, the likelihood appears low that important data communication systems will not include redundancy or not be diversely routed. The proposed TOP and IRO Reliability

15 NOPR at P 67. NERC indicated in its response to the COM NOPR that Reliability Standard COM-001-2 need not include requirements regarding data exchange capability because such capability is or would be covered by other existing or proposed standards. Specifically, NERC explained that data exchange is addressed by the currently
enforceable Reliability Standards IRO-010-1a and IRO-014-1. In addition, NERC stated that data exchange transfer capabilities are directly addressed in proposed Reliability Standard TOP-001-3, as well as in proposed Reliability Standard IRO-002-4, Requirement R1. NERC also stated that the data itself is covered in proposed Reliability
Standard IRO-010-2 and proposed Reliability Standard TOP-003-3. Id. at P 71.

16 Id.

17 NOPR at P 74.

Standards specifically require a Reliability Coordinator to have monitoring systems that provide
information utilized by the Reliability Coordinator’s operating personnel and that give particular
emphasis to alarm management and awareness systems, automated data transfers, and
synchronized information systems, over a redundant infrastructure. More generally, the suite
of currently-effective Reliability Standards and the proposed TOP and IRO Reliability 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. Specifically, Reliability Coordinators,
Transmission Operators, and Balancing Authorities are required to perform assessments in real-
time (every thirty minutes or less) and to continuously monitor the status of facilities18 and, in
order to meet those requirements, Reliability Coordinators, Transmission Operators and
Balancing Authorities need to have redundant or diversely routed data exchange capabilities. In
addition, Reliability Standards IRO-010-1a, Requirement R3,19 TOP-005-2a, Requirement R2,20
and proposed Reliability Standard TOP-003-3, Requirement R5,21 require compliance with data

18 See Reliability Standards IRO-008-1, Requirement R2; IRO-002-2, Requirement R7; TOP-006-2, Requirements R1 and R2.

19 Reliability Standard IRO-010-1a, Requirement R3 provides that “[e]ach Balancing Authority, Generator Owner, Generator Operator, Interchange Authority, Load-serving Entity, Reliability Coordinator, Transmission Operator, and Transmission Owner shall provide data and information, as specified, to the Reliability Coordinator(s) with which it has a reliability relationship.”

20 Reliability Standard TOP-005-2a, Requirement R2 provides that “[u]pon request. Each Balancing Authority and Transmission Operator shall provide to other Balancing Authorities and Transmission Operators with immediate responsibility for operational reliability, the operating data that are necessary to allow these Balancing Authorities and Transmission Operators to perform operational reliability assessments and to coordinate reliable operations. Balancing Authorities and Transmission Operators shall provide the types of data as listed in Attachment 1-TOP-
005 “Electric System Reliability Data,” unless otherwise agreed to by the Balancing Authorities and Transmission Operators with immediate responsibility for operational reliability.”

21 Under proposed Reliability Standard TOP-003-3, Requirement R5, each Transmission Operator, Balancing Authority, Generator Owner, Generator Operator, Load-Serving Entity, Transmission Owner, and Distribution Provider receiving a data specification in Requirement R3 or R4 shall satisfy the obligations of the documented specifications using: a mutually agreeable format; a mutually agreeable process for resolving data conflicts; a mutually agreeable security protocol.

exchange specifications intended to support real-time assessments. Thus, applicable entities
need redundancy and/or diverse routing in order to comply with the requirements of those
Reliability Standards in case an interruption (planned or unplanned, maintenance or event-
related) occurs in their data exchange capabilities. Moreover, the proposed TOP and IRO
Reliability Standards recognize that outages of data exchange and other capabilities will be
necessary and, accordingly, the standards require plans, functionality, coordination, and

communication when those outages take place.22

Second, in the event that there is a loss or failure of data communications and the

Reliability Coordinator, Balancing Authority or Transmission Operator that suffers the loss or
failure does not have diverse and redundant data communication systems, the functional entity
should be able to rely on the redundant and diversely routed voice capabilities that it is required
to maintain pursuant to the COM Reliability Standards.23 This voice capability would enable the
Reliability Coordinator, Balancing Authority or Transmission Operator to obtain the system
operations data it needs in the short term to maintain situational awareness while it re-establishes
its data communications capability. If the failure or loss were long-term in nature, the Reliability
Coordinator, Balancing Authority or Transmission Operator would rely on its operating plan to
continue to meet its functional obligations with regard to the reliable operations of the BES,
which could include operating from a Backup Control Center24 that provides backup
functionality.25

22 See proposed Reliability Standard TOP-001-3, Requirements R9 and R16; proposed Reliability Standard IRO002-4, Requirement R2.

23 See Reliability Standard COM-001-2.

24 Pursuant to Reliability Standard EOP-008-1, Requirement R1.2.2, the Operating Plan for backup functionality

describing the manner in which a Reliability Coordinator, Balancing Authority, or Transmission Operator continues
to meet its functional obligations with regard to the reliable operations of the BES in the event that its primary
control center functionality is lost must include a summary description of the data communications required to
(continued...)

When viewed collectively, the currently-effective COM and EOP Reliability Standards and the proposed TOP and IRO Reliability Standards appear sufficient to mitigate the risks identified by the Commission.

Finally, the ISOs/RTOs note that redundancy of data exchange capabilities is not itself a
core reliability function, but rather a tool used to accomplish core reliability functions. To that
end, to the extent that FERC determines that the existing Reliability Standards identified above
do not adequately address redundancy concerns, the ISOs/RTOs suggest that NERC can address
those concerns through its certification process, rather than through an additional stand-alone
Reliability Standard. At the time of certification, tools needed to support reliability—such as
redundant data exchange capabilities—can be examined to determine their suitability for

accomplishing the required reliability functions.

________________________

(...continued)

support the backup functionality. Reliability Standard EOP-008-1, Requirement R4 provides that “[e]ach Balancing
Authority and Transmission Operator shall have backup functionality (provided either through a facility or
contracted services staffed by applicable certified operators when control has been transferred to the backup
functionality location) that includes monitoring, control, logging, and alarming sufficient for maintaining
compliance with all Reliability Standards that depend on a Balancing Authority and Transmission Operator’s
primary control center functionality respectively. To avoid requiring tertiary functionality, backup functionality is
not required during:

• Planned outages of the primary or backup functionality of two weeks or less

• Unplanned outages of the primary or backup functionality”

25 Notably, the Reliability Coordinator, Balancing Authority or Transmission Operator would be required to make a
report to the Electric Reliability Organization if it were experiencing a long-term loss of data communications
capability.

/s/ Nancy Marconi

Nancy Marconi, Manager, Regulatory Affairs Maia Chase

Senior Analyst - Regulatory Affairs

Independent Electricity System Operator

1600-120 Adelaide St. West Toronto, ON M5H 1T1

nancy.marconi@ieso.ca maia.chase@ieso.ca

/s/ Stephen G. Kozey

Stephen G. Kozey

Senior Vice-President, Legal and
Compliance Services, General Counsel and Secretary

Midcontinent Independent System Operator, Inc.

P.O. Box 4202

Carmel, Indiana 46082-4202
stevekozey@misoenergy.org

/s/ Margoth R. Caley

Raymond W. Hepper

Vice President, General Counsel and Corporate Secretary

Theodore J. Paradise, Assistant General Counsel -
Operations and Planning

Margoth R. Caley, Regulatory Counsel

ISO New England Inc.

One Sullivan Road

Holyoke, MA 01040-2841 rhepper@iso-ne.com

tparadise@iso-ne.com
mcaley@iso-ne.com

/s/ Carl F. Patka

Robert E. Fernandez, General Counsel
Raymond Stalter, Director of Regulatory Affairs Carl F. Patka, Assistant General Counsel Christopher R. Sharp, Compliance Attorney

New York Independent System Operator, Inc.

10 Krey Boulevard
Rensselaer, NY 12144
Tel: (518) 356-6000
Fax: (518) 356-4702
rfernandez@nyiso.com
rstalter@nyiso.com
cpatka@nyiso.com
csharp@nyiso.com

/s/ Craig Glazer/s/ Matt Morais

Craig GlazerMatt Morais

Vice President - Federal Government PolicyAssociate General Counsel, Markets and Regulatory

Robert Eckenrod, Senior CounselPolicy

PJM Interconnection, L.L.C.Erin Cullum Marcussen

2750 Monroe Blvd.Senior Attorney

Audubon, PA 19403Southwest Power Pool, Inc.

Craig.Glazer@pjm.com201 Worthen Drive

Robert.Eckenrod@pjm.comLittle Rock, AR 72223-4936

Office: 501-482-2328
Cell: 603-512-5252
Office: 501-688-2503
Email: mmorais@spp.org
Email: ecullum@spp.org

Dated: August 24, 2015