RM18-20, NERC Petition and proposal

UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION

North American Electric Reliability
Corporation

)
)

Docket No. _______

PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF
PROPOSED RELIABILITY STANDARD CIP-012-1
Shamai Elstein
Senior Counsel
Marisa Hecht
Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
202-400-3000
[email protected]
[email protected]
Counsel for the North American Electric
Reliability Corporation

September 18, 2018

TABLE OF CONTENTS
I.

EXECUTIVE SUMMARY .................................................................................................... 2

II.

NOTICES AND COMMUNICATIONS ................................................................................ 4

III. BACKGROUND .................................................................................................................... 5
A.

Regulatory Framework ..................................................................................................... 5

B.

NERC Reliability Standards Development Procedure ..................................................... 6

C.

Order No. 822 Directive ................................................................................................... 6

D.

Development of the Proposed Reliability Standard ......................................................... 8

IV. JUSTIFICATION FOR APPROVAL..................................................................................... 8

V.

A.

Purpose and Overview of the Proposed Reliability Standard .......................................... 9

B.

Applicability and Scope of the Proposed Reliability Standard ...................................... 10

C.

Requirements of Proposed Reliability Standard CIP-012-1 .......................................... 14

D.

Enforceability of Proposed Reliability Standard ............................................................ 18
EFFECTIVE DATE .............................................................................................................. 19

VI. CONCLUSION ..................................................................................................................... 20

Exhibit A

Proposed Reliability Standard

Exhibit B

Implementation Plan

Exhibit C

Order No. 672 Criteria

Exhibit D

Consideration of Directives

Exhibit E

Implementation Guidance

Exhibit F

Technical Rationale

Exhibit G

Analysis of Violation Risk Factors and Violation Severity Levels

Exhibit H

Summary of Development History and Complete Record of Development

Exhibit I

Standard Drafting Team Roster

1

UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
North American Electric Reliability
Corporation

)
)

Docket No. _______

PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF
PROPOSED RELIABILITY STANDARD CIP-012-1
Pursuant to Section 215(d)(1) of the Federal Power Act (“FPA”), 1 Section 39.5 of the
regulations of the Federal Energy Regulatory Commission (“FERC” or “Commission”), 2 and
Order No. 822, 3 the North American Electric Reliability Corporation (“NERC”) 4 hereby submits
for Commission approval proposed Reliability Standard CIP-012-1 – Cyber Security –
Communications between Control Centers. The proposed Reliability Standard addresses the
Commission’s directive from Order No. 822 to modify the Critical Infrastructure Protection
(“CIP”) Reliability Standards to require Responsible Entities 5 to implement controls to protect
communication links and sensitive Bulk Electric System (“BES”) data communicated between
BES Control Centers. 6 NERC requests that the Commission approve the proposed Reliability

1

16 U.S.C. § 824o (2018).

2

18 C.F.R. § 39.5 (2018).

3

Order No. 822, Revised Critical Infrastructure Protection Reliability Standards, 154 FERC ¶ 61,037 (2016)
(“Order No. 822”), order denying reh’g, Order No. 822-A, 156 FERC 61,052 (2016).

4

The Commission certified NERC as the electric reliability organization (“ERO”) in accordance with
Section 215 of the FPA. N. Am. Elec. Reliability Corp., 116 FERC ¶ 61,062 (2006) (“ERO Certification Order”).

5

As used in the CIP Reliability Standards, a Responsible Entity refers to the registered entities subject to the
CIP Reliability Standards.

6

Unless otherwise designated, all capitalized terms shall have the meaning set forth in the Glossary of Terms
Used in NERC Reliability Standards, http://www.nerc.com/files/Glossary_of_Terms.pdf.

2
Standard, provided in Exhibit A hereto, as just, reasonable, not unduly discriminatory or
preferential, and in the public interest. NERC also requests approval of the associated
Implementation Plan (Exhibit B) and the associated Violation Risk Factors (“VRFs”) and
Violation Severity Levels (“VSLs”) (Exhibit G).
As required by Section 39.5(a) of the Commission’s regulations, 7 this Petition presents the
technical basis and purpose of the proposed Reliability Standard, a summary of the development
history (Exhibit H), and a demonstration that the proposed Reliability Standard meets the criteria
identified by the Commission in Order No. 672 8 (Exhibit C). The NERC Board of Trustees
(“Board”) adopted the proposed Reliability Standard on August 16, 2018.
I.

EXECUTIVE SUMMARY
The proposed Reliability Standard improves upon and expands the protections required by

NERC’s CIP Reliability Standards by requiring Responsible Entities to protect the confidentiality
and integrity of sensitive data pertaining to Real-time operations while being transmitted between
BES Control Centers. As Responsible Entities use this sensitive data to operate and monitor the
system in Real-time, it is critical for BES reliability that the data is accurate and secure. NERC
developed proposed Reliability Standard CIP-012-1 in response to the Commission’s directive in
Order No. 822 to develop modifications to Reliability Standard CIP-006-6 to require Responsible
Entities to implement controls to protect communication links and sensitive BES data
communicated between BES Control Centers. Rather than revise CIP-006-6, NERC determined

7

18 C.F.R. § 39.5(a).

8
Order No. 672, Rules Concerning Certification of the Electric Reliability Organization; and Procedures for
the Establishment, Approval, and Enforcement of Electric Reliability Standards, FERC Stats. & Regs. ¶ 31,204
(“Order No. 672”), order on reh’g, Order No. 672-A, FERC Stats. & Regs. ¶ 31,212 (2006).

3
that a new Reliability Standard was appropriate given the differences in applicability and scope
between CIP-006-6 and proposed CIP-012-1.
Proposed Reliability Standard CIP-012-1 requires Responsible Entities to develop a plan
to mitigate the risks posed by unauthorized modification (integrity) and unauthorized disclosure
(confidentiality) of Real-time Assessment and Real-time monitoring data. The plan must include
the following three components: (1) identification of security protection used to meet the security
objective; (2) identification of where the Responsible Entity applied the security protection; and
(3) identification of the responsibilities of each Responsible Entity for applying the security
protection, if the communicating Control Centers are owned by different entities. Consistent with
the Commission’s directive, proposed CIP-012-1 supports reliable operation of the BES as
protecting the integrity and confidentiality of Real-time Assessment and Real-time monitoring
data helps maintain situational awareness and reliable BES operations through timely and accurate
communication between Control Centers.
Consistent with the directive in Order No. 822, NERC considered the risks posed by
different types of BES Control Centers and the data communicated between those Control Centers
to determine the scope and applicability of the proposed standard. Proposed Reliability Standard
CIP-012-1 applies to all Responsible Entities who own or operate Control Centers, with one
limited exemption. As explained in greater detail below, the exemption applies to facilities that,
while meeting the definition of Control Center, only communicate Real-time data with other
Control Centers regarding a co-located field asset – i.e., a transmission station or generation
facility. The Standard Drafting Team (“SDT”) for the proposed standard determined that such
Control Center communications are more akin to communications from a field asset such that a
compromise of such communications does not pose a heightened risk to reliability in the same

4
manner as the communication of aggregated Real-time Assessment and Real-time monitoring data
between Control Centers. As such, consistent with the Commission’s exclusion of field asset
communications from the directive in Order No. 822, NERC determined that Responsible Entities
should focus resources on protecting aggregated Real-time Assessment and Real-time monitoring
data exchanged between Control Centers, not data from Control Centers that only communicate
data about a specific field asset. In addition, oral communications are not required to be protected
under proposed CIP-012-1 because that method of communication does not present the same
vulnerabilities, as discussed more fully below.
NERC respectfully requests that the Commission approve the proposed Reliability
Standard as just, reasonable, not unduly discriminatory or preferential, and in the public interest.
NERC further requests that the Commission approve the proposed Reliability Standard to become
effective as set forth in the proposed Implementation Plan.
II.

NOTICES AND COMMUNICATIONS
Notices and communications with respect to this filing may be addressed to the following: 9
Shamai Elstein*
Senior Counsel
Marisa Hecht*
Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W.
Suite 600
Washington, D.C. 20005
202-400-3000
[email protected]
[email protected]

Howard Gugel*
Senior Director, Standards and Education
North American Electric Reliability
Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560
[email protected]

9
Persons to be included on the Commission’s service list are identified by an asterisk. NERC respectfully
requests a waiver of Rule 203 of the Commission’s regulations, 18 C.F.R. § 385.203, to allow the inclusion of more
than two persons on the service list in this proceeding.

5
III.

BACKGROUND
The following background information is provided below: (a) an explanation of the

regulatory framework for NERC; (b) a description of the NERC Reliability Standards
Development Procedure; (c) an overview of the Order No. 822 directive addressed in this Petition;
and (d) the history of the Project 2016-02 Modifications to CIP Standards SDT work on proposed
Reliability Standard CIP-012-1.
A.

Regulatory Framework

By enacting the Energy Policy Act of 2005, 10 Congress entrusted the Commission with the
duties of approving and enforcing rules to ensure the reliability of the Bulk-Power System, and
with the duty of certifying an ERO that would be charged with developing and enforcing
mandatory Reliability Standards, subject to Commission approval. Section 215(b)(1) of the FPA
states that all users, owners, and operators of the Bulk-Power System in the United States will be
subject to Commission-approved Reliability Standards. 11 Section 215(d)(5) of the FPA authorizes
the Commission to order the ERO to submit a new or modified Reliability Standard. 12 Section
39.5(a) of the Commission’s regulations requires the ERO to file for Commission approval each
Reliability Standard that the ERO proposes should become mandatory and enforceable in the
United States, and each modification to a Reliability Standard that the ERO proposes to make
effective. 13
The Commission has the regulatory responsibility to approve Reliability Standards that
protect the reliability of the Bulk-Power System and to ensure that such Reliability Standards are
10

16 U.S.C. § 824o.

11

Id. § 824o(b)(1).

12

Id. § 824o(d)(5).

13

18 C.F.R. § 39.5(a).

6
just, reasonable, not unduly discriminatory or preferential, and in the public interest. Pursuant to
Section 215(d)(2) of the FPA and Section 39.5(c) of the Commission’s regulations, the
Commission will give due weight to the technical expertise of the ERO with respect to the content
of a Reliability Standard. 14
B.

NERC Reliability Standards Development Procedure

The proposed Reliability Standard was developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development process. 15 NERC
develops Reliability Standards in accordance with Section 300 (Reliability Standards
Development) of its Rules of Procedure and the NERC Standard Processes Manual. 16 In its ERO
Certification Order, the Commission found that NERC’s proposed rules provide for reasonable
notice and opportunity for public comment, due process, openness, and a balance of interests in
developing Reliability Standards and thus satisfy certain criteria for approving Reliability
Standards. 17 The development process is open to any person or entity with a legitimate interest in
the reliability of the Bulk-Power System. NERC considers the comments of all stakeholders.
Further, a vote of stakeholders and adoption by the Board is required before NERC submits the
Reliability Standard to the Commission for approval.
C.

Order No. 822 Directive

In Order No. 822, the Commission directed NERC to develop modifications to Reliability
Standard CIP-006-6 to require protections for communication network components and data

14

16 U.S.C. § 824o(d)(2); 18 C.F.R. § 39.5(c)(1).

15

Order No. 672 at P 334.

16

The NERC Rules of Procedure are available at http://www.nerc.com/AboutNERC/Pages/Rules-ofProcedure.aspx. The NERC Standard Processes Manual is available at
http://www.nerc.com/comm/SC/Documents/Appendix_3A_StandardsProcessesManual.pdf.
17

ERO Certification Order at P 250.

7
communicated between all BES Control Centers according to the risk posed to the BES. 18 In light
of the critical role Control Center communications play in maintaining BES reliability, the
directive focused on communications between Control Centers, not between a Control Center and
non-Control Center facilities, such as Transmission substations or generation facilities. 19 The
Commission agreed with NERC and other commenters that “inter-Control Center communications
play a critical role in maintaining [BES] reliability by, among other things, helping to maintain
situational awareness and reliable [BES] operations through timely and accurate communication
between Control Centers.” 20
The Commission stated that in response to the directive, NERC should identify the scope
of sensitive BES data that must be protected and specify how the confidentiality, integrity, and
availability of each type of BES data should be protected while it is being transmitted or at rest.21
As an example for the type of data to be protected, the Commission highlighted the data specified
by the Interconnection Reliability Operations and Coordination (“IRO”) and Transmission
Operations (“TOP”) Reliability Standards. Specifically, the Commission cited Reliability Standard
TOP-003-3, Requirements R1, R3, and R5, in which a “[T]ransmission [O]perator must maintain
a documented specification for data and distribute its data specification to entities that have data
required by the [T]ransmission [O]perator’s Operational Planning Analyses, Real-time
[m]onitoring and Real-time Assessments. Entities receiving a data specification must satisfy the
obligation of the documented specification.” 22

18

Order No. 822 at P 3.

19
Id. at P 41 (citing Revised Critical Infrastructure Protection Reliability Standards, Notice of Proposed
Rulemaking, 152 FERC ¶ 61,054, at P 59 (2015) (“Notice of Proposed Rulemaking”).
20

Id. at P 54.

21

Id. at P 56.

22

Id. P 54 n.61.

8
D.

Development of the Proposed Reliability Standard

As further described in Exhibit H hereto, following the issuance of Order No. 822, NERC
initiated a Reliability Standard development project, Project 2016-02 Modifications to CIP
Standards (“Project 2016-02”), to address the directives from Order No. 822 and other revisions
to the currently-effective CIP Reliability Standards. On July 27, 2017, NERC posted the initial
draft of proposed Reliability Standard CIP-012-1 for a 45-day comment period and ballot. The
initial ballot did not receive the requisite approval from the registered ballot body (“RBB”). After
considering comments to the initial draft, NERC posted a second draft of CIP-012-1 for another
45-day comment period and ballot on October 27, 2017, which also failed to receive the requisite
approval from the RBB. On March 16, 2018, NERC posted a third draft of proposed Reliability
Standard CIP-012-1 for another 45-day comment period and ballot. Although the third draft
received the requisite approval from the RBB, the Project 2016-02 SDT determined to make
substantive revisions to CIP-012-1 to address commenter concerns. On May 18, 2018, NERC
posted a fourth draft of proposed Reliability Standard CIP-012-1 for another 45-day comment
period and ballot. The fourth draft of proposed Reliability Standard CIP-012-1 received the
requisite approval from the RBB with affirmative votes of 68.45 percent of the ballot pool. NERC
conducted a 10-day final ballot for proposed Reliability Standard CIP-012-1, which received
affirmative votes of 72.55 percent of the ballot pool. The Board adopted the proposed Reliability
Standard on August 16, 2018.
IV.

JUSTIFICATION FOR APPROVAL
As discussed below and in Exhibit C, the proposed Reliability Standard addresses the

Commission’s directive in Order No. 822 and is just, reasonable, not unduly discriminatory or
preferential, and in the public interest. The following section provides an explanation of:
•

the purpose and overview of the proposed Reliability Standard (Subsection A);

9
•

the scope and applicability of the proposed Reliability Standard (Subsection B);

•

the requirement in proposed Reliability Standard CIP-012-1, including a discussion of the
manner in which it addresses the directive in Order No. 822 (Subsection C); 23 and

•

the enforceability of the proposed Reliability Standard (Subsection D).
A.

Purpose and Overview of the Proposed Reliability Standard

The purpose of the proposed Reliability Standard is to protect the confidentiality and
integrity of Real-time Assessment and Real-time monitoring data transmitted between Control
Centers. In requiring protections of this data, proposed CIP-012-1 helps maintain situational
awareness and reliable BES operations. In order for certain Responsible Entities to adequately
perform their Real-time reliability functions, their associated Control Centers must be capable of
receiving and storing a variety of sensitive BES data from interconnected entities. Helping to
ensure the timeliness and accuracy of these communications through the proposed protections in
CIP-012-1 would thus support reliable operations of the BES.
The SDT determined to address the Commission’s directive by developing a new standard,
proposed Reliability Standard CIP-012-1, rather than revising Reliability Standard CIP-006-6 due
to the differences in scope and applicability. Whereas CIP-006-6, Requirement R1, Part 1.10
requires protections for nonprogrammable communication components outside of a Physical
Security Perimeter (“PSP”) but inside the same Electronic Security Perimeter (“ESP”) for certain
Cyber Assets, proposed CIP-012-1 requires protections for communications between Control
Centers that transmit certain data regardless of the location of Cyber Assets inside or outside a PSP
or ESP. Moreover, the applicability of protections included in proposed CIP-012-1 differs from
that of CIP-006-6. Proposed CIP-012-1 does not apply to BES Cyber Systems. Whereas CIP-0066, Requirement R1, Part 1.10 applies to high impact BES Cyber Systems and medium impact BES
23

Proposed Reliability Standard CIP-012-1 consists of one requirement with three parts.

10
Cyber Systems at Control Centers, proposed CIP-012-1 applies to communications between
certain Control Centers. As a result of these differences, the SDT determined that the
Commission’s directive would best be met by developing a new Reliability Standard instead of
revising CIP-006-6.
As discussed further below, proposed Reliability Standard CIP-012-1 requires Responsible
Entities to develop and implement a plan to address the risks posed by unauthorized disclosure
(confidentiality) and unauthorized modification (integrity) of Real-time Assessment and Real-time
monitoring data while being transmitted between applicable Control Centers. The plan must
include the following: (1) identification of security protections; (2) identification of where the
protections are applied; and (3) identification of the responsibilities of each entity if the Control
Centers are owned or operated by different Responsible Entities.
B.

Applicability and Scope of the Proposed Reliability Standard
1) Applicable Functional Entities and Facilities

Proposed CIP-012-1 applies to entities registered as Balancing Authorities, Generator
Operators, Generator Owners, Reliability Coordinators, Transmission Operators, and
Transmission Owners that own or operate a Control Center as defined in the Glossary of Terms
Used in NERC Reliability Standards. The proposed standard applies to Control Centers with high,
medium, and low impact BES Cyber Systems. Proposed CIP-012-1 focuses on Responsible
Entities that own or operate Control Centers, regardless of the impact level of BES Cyber Systems
located at or associated with those Control Centers. The SDT determined that the sensitivity of
Real-time data communicated between Control Centers is not necessarily dependent on the impact
level of the BES Cyber Systems located at or associated with the Control Centers.
In reviewing the types of Control Centers that should be subject to proposed CIP-012-1,
the SDT instead focused on the types of Real-time data a Control Center would send, and whether,

11
if the data were to be compromised, it would pose a high risk to the reliability of the BES. As the
Commission recognized, “not all communication network components and data pose the same risk
to [BES] reliability and may not require the same level of protection.” 24
In conducting its analysis, the SDT determined that a limited subset of Control Centers
should not be subject to the requirements in proposed CIP-012-1 given the limited data they
transmit to other Control Centers. Specifically, as provided in the applicability section of proposed
CIP-012-1, the following Control Centers are exempt from the proposed standard:
A Control Center that transmits to another Control Center Real-time Assessment or
Real-time monitoring data pertaining only to the generation resource or
Transmission station or substation co-located with the transmitting Control Center.
The manner in which these Control Centers communicate with other Control Centers is no
different from the manner in which a field asset (e.g., generating resources or Transmission
substations) would communicate with a Control Center. In contrast to the Control Centers subject
to proposed CIP-012-1, which exchange aggregated Real-time data, the Control Centers subject to
the proposed exemption only send data regarding the status of a co-located field asset, like remote
terminal unit data. If such data were compromised, the risk to the BES is lower than data from
those Control Centers transmitting data on multiple units. As discussed above, the Commission’s
directive is not focused on the exchange of data between field assets and Control Centers. 25 The
Commission specifically rejected the argument to apply the directive to communications between
all facilities of the BES, such as substations, stating that “the record in the immediate proceeding
does not support such a broad requirement at this time.” 26

24

Order No. 822 at P 56.

25

Id. at P 41 (citing the Notice of Proposed Rulemaking at P 59).

26

Id. at P 57.

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As discussed in more detail in the next subsection, the type of data transmitted between
Control Centers that is within the scope of proposed CIP-012-1 is Real-time Assessment and Realtime monitoring data pertaining to more than just the field asset at which the transmitting Control
Center is located.
2) Data in Scope
The SDT determined that Real-time Assessment and Real-time monitoring data exchanged
between Control Centers should be subject to the protections of proposed CIP-012-1 due to the
critical nature of the data. Reliability Coordinators and Transmission Operators must perform
Real-time Assessments every 30 minutes to assess conditions on the system and determine
whether there are any actual or potential exceedances of System Operating Limits or
Interconnection Reliability Operating Limits. 27 In addition, Reliability Coordinators, Balancing
Authorities, and Transmission Operators must perform Real-time monitoring. 28 Because entities
operate and monitor the BES according to this Real-time information, it is of critical importance
that it is accurate.
Proposed CIP-012-1 excludes other data typically transferred between Control Centers,
such as Operational Planning Analysis data, that is not used by the Reliability Coordinator,
Balancing Authority, and Transmission Operator in Real-time. Although an Operational Planning
Analysis provides information for the next-day operations, entities adjust their operating actions
during the current day based on the data from Real-time Assessments and Real-time monitoring.
If there is suspicion that Operational Planning Analysis data has been compromised, there is also
time to verify the data prior to any impact on Real-time operations. The SDT thus determined

27

Reliability Standards IRO-008-2, Requirement R4 and TOP-001-4, Requirement R13.

28

Reliability Standards IRO-002-5, Requirements R5 and R6 and TOP-001-4, Requirements R10 and R11.

13
that Operational Planning Analysis data, if rendered unavailable, degraded, or misused, would
not adversely impact the reliable operation of the BES within 15 minutes of the activation or
exercise of the compromise as detailed in Reliability Standard CIP-002-5.1a.
More specifically, while Reliability Coordinators and Transmission Operators must
perform an Operational Planning Analysis that includes an assessment of whether planned
operations within their areas will exceed any System Operating Limits, 29 an entity will operate
its system based on an assessment of the conditions on the day of operation as indicated by Realtime monitoring and Real-time Assessments. As a result, although an Operational Planning
Analysis factors into how an entity operates, there is less of a risk that an entity would act on
compromised data from an Operational Planning Analysis given it will base its operating actions
on Real-time inputs. The SDT considered the role of an Operational Planning Analysis in BES
operations and determined that there was a lower risk of affecting the reliability of the BES if
Operational Planning Analysis data is compromised. Therefore, the SDT determined that this
lower risk did not warrant the protections of proposed CIP-012-1. The SDT determined entities
should focus resources on Real-time inputs as those could adversely impact the reliable operation
of the BES within 15 minutes.
While the Commission also directed NERC to consider protecting data at rest, the SDT
determined that because this data resides within BES Cyber Systems, the data is protected by CIP003-6 through CIP-011-2. These protections include the following:
•

29

ESPs: Data at rest stored on a high or medium impact BES Cyber System would
reside within an ESP. The ESP provides a logical border around the network that
can only be accessed through an Electronic Access Point. In addition, other
protections are applied to the ESP that help ensure the data on the BES Cyber
System is secure.

Reliability Standards IRO-008-2, Requirement R1 and TOP-002-4, Requirements R1.

14
•

Electronic access controls: Data at rest on low impact BES Cyber Systems within
applicable Control Centers are protected by electronic access controls that permit
only necessary inbound and outbound electronic access as required by Reliability
Standard CIP-003-6.

•

Physical security controls: In addition to ESPs and electronic access controls noted
above, data at rest on low, medium, and high BES Cyber Systems are protected by
physical controls, such as PSPs for some BES Cyber Systems, as required by
Reliability Standards CIP-003-6 and CIP-006-6.

•

Other protections: The CIP Reliability Standards also require other protections,
such as training and cyber security awareness for personnel (CIP-003-6 and CIP004-6); system security management (CIP-007-6); recovery plans for BES Cyber
Systems (CIP-009-6); and BES Cyber System Information protection (CIP-011-2);
among others, that promote the security of data at rest at Control Centers.

As a result of the protections included in the CIP Reliability Standards, the SDT only included
protections for data while being transmitted between Control Centers in proposed CIP-012-1.
Similarly, oral communication is out of scope. The SDT concluded that oral
communications do not need additional protections under proposed CIP-012-1 because operators
have the ability to terminate the call and initiate a new one via trusted means if they suspect a
problem with, or compromise of, the communication channel. In fact, Reliability Standard COM001-3 requires Reliability Coordinators, Balancing Authorities, and Transmission Operators to
have Alternative Interpersonal Communication capability with certain entities. As a result, these
entities would be able to use the Alternative Interpersonal Communication capability if an
individual suspected a compromise of oral communications on one channel. Given this ability,
proposed CIP-012-1 does not require protections for oral communications.
C.

Requirements of Proposed Reliability Standard CIP-012-1

Proposed Reliability Standard CIP-012-1 consists of a single requirement that requires
Responsible Entities to develop plans to meet the security objective of mitigating the risks posed
by unauthorized modification and unauthorized disclosure of Real-time Assessment and Real-time
monitoring data. Although proposed CIP-012-1 prescribes some items to include in the plan, it

15
allows Responsible Entities to develop and implement a plan that works best for their operational
environment while meeting the security objective. The use of a plan is consistent with other CIP
Reliability Standards, and the objective allows the Reliability Standard to maintain relevancy while
the technology used by Responsible Entities to meet the objective of CIP-012-1 continues to
evolve and improve.
In proposed CIP-012-1, the SDT drafted requirements to provide Responsible Entities the
latitude to protect the communication links, the data, or both, to satisfy the security objective
consistent with the capabilities of the Responsible Entity’s operational environment. Proposed
Reliability Standard CIP-012-1 includes the following requirement and parts, each of which is
discussed below:
R1.

The Responsible Entity shall implement, except under CIP Exceptional
Circumstances, one or more documented plan(s) to mitigate the risks posed
by unauthorized disclosure and unauthorized modification of Real-time
Assessment and Real-time monitoring data while being transmitted between
any applicable Control Centers. The Responsible Entity is not required to
include oral communications in its plan. The plan shall include: [Violation
Risk Factor: Medium] [Time Horizon: Operations Planning]
1.1.

Identification of security protection used to mitigate the risks posed
by unauthorized disclosure and unauthorized modification of Realtime Assessment and Real-time monitoring data while being
transmitted between Control Centers;

1.2.

Identification of where the Responsible Entity applied security
protection for transmitting Real-time Assessment and Real-time
monitoring data between Control Centers; and

1.3.

If the Control Centers are owned or operated by different
Responsible Entities, identification of the responsibilities of each
Responsible Entity for applying security protection to the
transmission of Real-time Assessment and Real-time monitoring
data between those Control Centers.

Requirement R1 mandates that each Responsible Entity develop a plan to mitigate the risks
posed by unauthorized disclosure and unauthorized modification of Real-time Assessment and

16
Real-time monitoring data while being transmitted between any applicable Control Centers.
Responsible Entities must include the following in their plans: (1) identification of security
protections (Part 1.1); (2) identification of where these protections are applied (Part 1.2); and (3)
identification of the responsibilities of each party if the communicating Control Centers are owned
or operated by different Responsible Entities (Part 1.3).
Specifically, pursuant to Part 1.1, Responsible Entities must include the identification of
security protection used to mitigate the risks posed by unauthorized disclosure and unauthorized
modification of Real-time Assessment and Real-time monitoring data while being transmitted
between Control Centers. Responsible Entities may choose logical protection, physical protection,
or a combination of both as long as the protections meet the security objective of mitigating the
risks posed by unauthorized disclosure and unauthorized modification of Real-time Assessment
and Real-time monitoring data while being transmitted between Control Centers. As a result,
Responsible Entities have the latitude to determine which controls are appropriate for their
organization, so long as those controls meet the security objective.
This approach is consistent with the principles for development as articulated by NERC in
its comments to the Notice of Proposed Rulemaking, 30 with which the Commission agreed:
protections for communication links and sensitive bulk electric system data communicated
between bulk electric system Control Centers: (1) should not have an adverse effect on reliability,
including the recognition of instances where the introduction of latency could have negative
results; (2) should account for the risk levels of assets and information being protected, and require
protections that are commensurate with the risks presented; and (3) should be results-based in order

30

Comments of the North American Electric Reliability Corporation in Response to Proposed Rulemaking, at
20-21 Docket No. RM15-14-000 (Sept. 21, 2015).

17
to provide flexibility to account for the range of technologies and entities involved in bulk electric
system communications. 31
Pursuant to Part 1.2, Responsible Entities must include in their plans the identification of
where the Responsible Entity applied security protection for transmitting Real-time Assessment
and Real-time monitoring data between Control Centers. The identification of where security
protection is applied (CIP-012-1 Requirement R1, Part 1.2) promotes alignment with the
identification of Responsible Entity responsibilities (CIP-012-1 Requirement R1, Part 1.3) and
helps with evaluating the overall effectiveness of the protections used.
Pursuant to Part 1.3, Responsible Entities must include in their plans the identification of
the responsibilities of each Responsible Entity for applying security protection to the transmission
of Real-time Assessment and Real-time monitoring data between Control Centers if the Control
Centers are owned or operated by different Responsible Entities. This requirement part does not
explicitly require formal agreements between Responsible Entities partnering for protection of
applicable data, but it provides a clear expectation that Responsible Entities must sort out
responsibilities to help ensure that appropriate protections are in place. Where data is transmitted
between different entities, the SDT determined that it is necessary for both entities to understand
the responsibilities of applying security controls to ensure the data is protected through its entire
transmission. This requirement part will help ensure there is no security gap.
As noted above, in Order No. 822, the Commission stated that NERC should develop
measures to protect the confidentiality, integrity, and availability of sensitive BES data. To that
end, proposed CIP-012-1 requires entities to implement protections for the confidentiality
(unauthorized disclosure) and integrity (unauthorized modification) of Real-time Assessment and

31

Order No. 822 at P 55.

18
Real-time monitoring data. The availability of such data is addressed in existing Reliability
Standards. As the Commission stated, “[p]rotecting the availability of [BES] data involves
ensuring that required data is available when needed for [BES] operations.” 32 Reliability Standard
IRO-002-5 requires redundant and diversely routed data exchange infrastructure within the
Reliability Coordinator’s primary Control Center in order to exchange Real-time data used in Realtime monitoring and Real-time Assessments with Balancing Authorities, Transmission Operators,
and other entities the Reliability Coordinator deems necessary. Similarly, Reliability Standard
TOP-001-4 requires Balancing Authorities and Transmission Operators to have redundant and
diversely routed data exchange infrastructure to exchange Real-time data. The redundancy of data
exchange infrastructure helps to ensure the availability of critical Real-time data for Control
Centers. Additionally, Reliability Standards IRO-010-2 and TOP-003-3 require Reliability
Coordinators, Transmission Operators, and Balancing Authorities to use a mutually agreeable
security protocol for exchange of Real-time data. By agreeing on the same security protocol,
entities communicate directly with the appropriate entities rather than having to translate different
protocols, which further helps to ensure the availability of Real-time data. As a result, the SDT
determined that the confidentiality, integrity, and availability of Real-time Assessment and Realtime monitoring data would be protected by requirements in the suite of Reliability Standards,
including proposed CIP-012-1.
D.

Enforceability of Proposed Reliability Standard

The proposed Reliability Standard also includes a measure that supports the requirement
by clearly identifying what is required and how the ERO will enforce the requirement. The measure

32

Order No. 822 at P 54 n.60.

19
helps ensure that the requirement will be enforced in a clear, consistent, and non-preferential
manner and without prejudice to any party. 33 Additionally, the proposed Reliability Standard
includes a VRF and VSLs. The VRF and VSLs provide guidance on the way that NERC will
enforce the requirement of the proposed Reliability Standard. The VRF and VSLs for the proposed
Reliability Standard comport with NERC and Commission guidelines related to their assignment.
Exhibit G provides a detailed review of the VRF and VSLs, and the analysis of how the VRF and
VSLs were determined using these guidelines.
V.

EFFECTIVE DATE
NERC respectfully requests that the Commission approve the proposed Reliability

Standard to become effective as set forth in the proposed Implementation Plan, provided in Exhibit
B hereto. The proposed Implementation Plan provides that the proposed Reliability Standard shall
become effective on the first day of the first calendar quarter that is 24 calendar months after the
effective date of the Commission’s order approving the proposed Reliability Standard. The 24month implementation period is designed to afford Responsible Entities sufficient time to
implement the new controls and coordinate with other Responsible Entities that own or operate
Control Centers as required in proposed Reliability Standard CIP-012-1.

33

Order No. 672 at P 327.

20
VI.

CONCLUSION
For the reasons set forth above, NERC respectfully requests that the Commission approve:
•

proposed Reliability Standard CIP-012-1, and associated elements included in Exhibit
A, effective as proposed herein; and

•

the proposed Implementation Plan included in Exhibit B.
Respectfully submitted,
/s/ Marisa Hecht
Shamai Elstein
Senior Counsel
Marisa Hecht
Counsel
North American Electric Reliability Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
202-400-3000
[email protected]
[email protected]
Counsel for the North American Electric Reliability Corporation

Date: September 18, 2018

Exhibit A
Proposed Reliability Standard
CIP-012-1

CIP-012-1 – Cyber Security – Communications between Control Centers

A. Introduction
1.

Title: Cyber Security – Communications between Control Centers

2.

Number: CIP-012-1

3.

Purpose: To protect the confidentiality and integrity of Real-time Assessment and
Real-time monitoring data transmitted between Control Centers.

4.

Applicability:
4.1. Functional Entities: The requirements in this standard apply to the following
functional entities, referred to as “Responsible Entities,” that own or operate a
Control Center.
4.1.1. Balancing Authority
4.1.2. Generator Operator
4.1.3. Generator Owner
4.1.4. Reliability Coordinator
4.1.5. Transmission Operator
4.1.6. Transmission Owner
4.2. Exemptions: The following are exempt from Reliability Standard CIP-012-1:
4.2.1. Cyber Assets at Facilities regulated by the Canadian Nuclear Safety
Commission.
4.2.2. The systems, structures, and components that are regulated by the
Nuclear Regulatory Commission under a cyber security plan pursuant
to 10 C.F.R. Section 73.54.
4.2.3. A Control Center that transmits to another Control Center Real-time
Assessment or Real-time monitoring data pertaining only to the
generation resource or Transmission station or substation co-located
with the transmitting Control Center.

5.

Effective Date: See Implementation Plan for CIP-012-1.

B. Requirements and Measures
R1.

The Responsible Entity shall implement, except under CIP Exceptional Circumstances,
one or more documented plan(s) to mitigate the risks posed by unauthorized
disclosure and unauthorized modification of Real-time Assessment and Real-time
monitoring data while being transmitted between any applicable Control Centers. The
Responsible Entity is not required to include oral communications in its plan. The plan
shall include: [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]

Page 1 of 5

CIP-012-1 – Cyber Security – Communications between Control Centers

1.1. Identification of security protection used to mitigate the risks posed by
unauthorized disclosure and unauthorized modification of Real-time Assessment
and Real-time monitoring data while being transmitted between Control
Centers;
1.2. Identification of where the Responsible Entity applied security protection for
transmitting Real-time Assessment and Real-time monitoring data between
Control Centers; and
1.3. If the Control Centers are owned or operated by different Responsible Entities,
identification of the responsibilities of each Responsible Entity for applying
security protection to the transmission of Real-time Assessment and Real-time
monitoring data between those Control Centers.
M1. Evidence may include, but is not limited to, documented plan(s) that meet the
security objective of Requirement R1 and documentation demonstrating the
implementation of the plan(s).

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority” (CEA)
means NERC, the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below
is shorter than the time since the last audit, the CEA may ask an entity to provide
other evidence to show that it was compliant for the full-time period since the
last audit.
The Responsible Entity shall keep data or evidence to show compliance as
identified below unless directed by its CEA to retain specific evidence for a
longer period of time as part of an investigation.
•

The Responsible Entities shall keep data or evidence of each Requirement in
this Reliability Standard for three calendar years.

•

If a Responsible Entity is found non-compliant, it shall keep information
related to the non-compliance until mitigation is complete and approved or
for the time specified above, whichever is longer.

•

The CEA shall keep the last audit records and all requested and submitted
subsequent audit records.

Page 2 of 5

CIP-012-1 – Cyber Security – Communications between Control Centers

1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers
to the identification of the processes that will be used to evaluate data or
information for the purpose of assessing performance or outcomes with the
associated Reliability Standard.

Page 3 of 5

CIP-012-1 – Cyber Security – Communications between Control Centers

Violation Severity Levels
Violation Severity Levels

R#

R1.

Lower VSL

N/A

Moderate VSL

The Responsible Entity
documented its plan(s) but
failed to include one of the
applicable Parts of the plan
as specified in Requirement
R1.

High VSL

The Responsible Entity
documented its plan(s) but
failed to include two of the
applicable Parts of the plan
as specified in Requirement
R1.

Severe VSL

The Responsible Entity failed
to document plan(s) for
Requirement R1;
Or
The Responsible Entity failed
to implement any Part of its
plan(s) for Requirement R1,
except under CIP Exceptional
Circumstances.

D. Regional Variances
None.

E. Associated Documents
Implementation Plan.

Technical Rationale for CIP-012-1.
Implementation Guidance.

Page 4 of 5

CIP-012-1 Version History

Version History
Version

Date

1

Action

Respond to FERC Order No. 822

1

August 16, 2018

1

TBD

Change
Tracking

New

Adopted by NERC Board of Trustees
FERC Order approving CIP-012-1

Page 5 of 5

Exhibit B
Implementation Plan

Implementation Plan

Project 2016-02 Modifications to CIP Standards
Reliability Standard CIP-012-1
Applicable Standard
•

Reliability Standard CIP-012-1 - Cyber Security – Communications between Control Centers

Requested Retirements
•

None

Prerequisite Standard

These standard(s) or definitions must be approved before the Applicable Standard becomes
effective:
•

None

Applicable Entities
•

Balancing Authority

•

Generator Operator

•

Generator Owner

•

Reliability Coordinator

•

Transmission Operator

•

Transmission Owner

Effective Date

Reliability Standard CIP-012-1 - Cyber Security – Communications between Control Centers
Where approval by an applicable governmental authority is required, Reliability Standard CIP-012-1
shall become effective on the first day of the first calendar quarter that is twenty-four (24) calendar
months after the effective date of the applicable governmental authority’s order approving the
standard, or as otherwise provided for by the applicable governmental authority.
Where approval by an applicable governmental authority is not required, Reliability Standard CIP012-1 shall become effective on the first day of the first calendar quarter that is twenty-four (24)
calendar months after the date the standard is adopted by the NERC Board of Trustees, or as
otherwise provided for in that jurisdiction.

Exhibit C
Order No. 672 Criteria

EXHIBIT C
Order No. 672 Criteria
In Order No. 672, 1 the Commission identified a number of criteria it will use to analyze
Reliability Standards proposed for approval to ensure they are just, reasonable, not unduly
discriminatory or preferential, and in the public interest. The discussion below identifies these
factors and explains how the proposed Reliability Standard meets or exceeds the criteria.
1. Proposed Reliability Standards must be designed to achieve a specified reliability
goal and must contain a technically sound means to achieve that goal. 2
The proposed Reliability Standard improves upon and expands the protections required by
NERC’s CIP Reliability Standards by requiring Responsible Entities to protect the confidentiality
and integrity of certain Real-time sensitive data pertaining to Real-time operations while being
transmitted between BES Control Centers, consistent with the Commission directive in Order No.
822 3. Specifically, proposed Reliability Standard CIP-012-1 improves reliability by requiring
Responsible Entities to develop a plan to mitigate the risks posed by unauthorized modification
and unauthorized disclosure of Real-time Assessment and Real-time monitoring data. The plan
must include the following three components: (1) identification of security protection used to meet
the security objective; (2) identification of where the Responsible Entity applied the security
protection; and (3) identification of the responsibilities of each Responsible Entity for applying
the security protection, if the communicating Control Centers are owned by different entities.

1

Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the
Establishment, Approval, and Enforcement of Electric Reliability Standards, Order No. 672, FERC Stats. & Regs. ¶
31,204, order on reh’g, Order No. 672-A, FERC Stats. & Regs. ¶ 31,212 (2006).

2
3

Order No. 672 at PP 321, 324.

Order No. 822, Revised Critical Infrastructure Protection Reliability Standards, 154 FERC ¶ 61,037 (2016)
(“Order No. 822”), order denying reh’g, Order No. 822-A, 156 FERC 61,052 (2016).

Exhibit F includes technical rationale for the proposed Reliability Standard to demonstrate the
technical soundness of the means to achieve the reliability goal.
2. Proposed Reliability Standards must be applicable only to users, owners and
operators of the bulk power system, and must be clear and unambiguous as to what
is required and who is required to comply. 4
The proposed Reliability Standard is clear and unambiguous as to what is required and
who is required to comply, in accordance with Order No. 672. The proposed Reliability Standard
applies to Balancing Authorities, Generator Operators, Generator Owners, Reliability
Coordinators, Transmission Operators, and Transmission Owners that own or operate a Control
Center. The proposed Reliability Standard clearly articulates the actions that such entities must
take to comply with the standard.
3. A proposed Reliability Standard must include clear and understandable
consequences and a range of penalties (monetary and/or non-monetary) for a
violation. 5
The Violation Risk Factor and Violation Severity Levels (“VSLs”) for the proposed
Reliability Standard comport with NERC and Commission guidelines related to their assignment,
as discussed further in Exhibit G. The assignment of the severity level for each VSL is consistent
with the corresponding requirement. The VSLs do not use any ambiguous terminology, thereby
supporting uniformity and consistency in the determination of similar penalties for similar
violations. For these reasons, the proposed Reliability Standard includes clear and
understandable consequences in accordance with Order No. 672.

4

Order No. 672 at PP 322, 325.

5

Order No. 672 at P 326.

4. A proposed Reliability Standard must identify clear and objective criterion or
measure for compliance, so that it can be enforced in a consistent and nonpreferential manner. 6
The proposed Reliability Standard contains measures that support the requirement by
clearly identifying what is required to demonstrate compliance. These measures help provide
clarity regarding the manner in which the requirement will be enforced and help ensure that the
requirement will be enforced in a clear, consistent, and non-preferential manner and without
prejudice to any party.
5. Proposed Reliability Standards should achieve a reliability goal effectively and
efficiently — but do not necessarily have to reflect “best practices” without regard
to implementation cost or historical regional infrastructure design. 7
The proposed Reliability Standard achieves the reliability goals effectively and efficiently
in accordance with Order No. 672. The proposed Reliability Standard clearly articulates the
security objective that applicable entities must meet and provides entities the flexibility to tailor
their plan(s) required under the standard to best suit the needs of their organization.
6. Proposed Reliability Standards cannot be “lowest common denominator,” i.e.,
cannot reflect a compromise that does not adequately protect Bulk-Power System
reliability. Proposed Reliability Standards can consider costs to implement for
smaller entities, but not at consequences of less than excellence in operating system
reliability. 8
The proposed Reliability Standard does not reflect a “lowest common denominator”
approach. The proposed Reliability Standard satisfies the Commission’s directive in Order No.
822 and requires protections for Control Centers containing BES Cyber Systems of any impact
level.

6

Order No. 672 at P 327.

7

Order No. 672 at P 328.

8

Order No. 672 at P 329-30.

7. Proposed Reliability Standards must be designed to apply throughout North
America to the maximum extent achievable with a single Reliability Standard while
not favoring one geographic area or regional model. It should take into account
regional variations in the organization and corporate structures of transmission
owners and operators, variations in generation fuel type and ownership patterns,
and regional variations in market design if these affect the proposed Reliability
Standard. 9
The proposed Reliability Standard applies throughout North America and does not favor
one geographic area or regional model.
8. Proposed Reliability Standards should cause no undue negative effect on
competition or restriction of the grid beyond any restriction necessary for
reliability. 10
The proposed Reliability Standard has no undue negative impact on competition. The
proposed Reliability Standard requires the same performance by each of the applicable
Functional Entities for mitigating the risks posed by unauthorized disclosure and unauthorized
modification of Real-time Assessment and Real-time monitoring data while being transmitted
between any applicable Control Centers. The proposed Reliability Standard does not
unreasonably restrict the available transmission capability or limit use of the Bulk-Power System
in a preferential manner.
9. The implementation time for the proposed Reliability Standard is reasonable. 11
The proposed 24-month implementation period for the proposed Reliability Standard is
just and reasonable and appropriately balances the urgency in the need to implement the standard
against the reasonableness of the time allowed for those who must comply to develop and

9
10
11

Order No. 672 at P 331.
Order No. 672 at P 332.
Order No. 672 at P 333.

implement the necessary plans, develop infrastructure, coordinate among other entities, or develop
other relevant capability.
10. The Reliability Standard was developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development
process. 12
The proposed Reliability Standard was developed in accordance with NERC’s
Commission-approved, ANSI- accredited processes for developing and approving Reliability
Standards. Exhibit H includes a summary of the development proceedings and details the
processes followed to develop the proposed Reliability Standard. These processes included,
among other things, comment and ballot periods. Additionally, all meetings of the drafting team
were properly noticed and open to the public. The initial and additional ballots achieved a
quorum, and the last two additional ballots and final ballot exceeded the required ballot pool
approval levels.
11. NERC must explain any balancing of vital public interests in the development of
proposed Reliability Standards.13
NERC has identified no competing public interests regarding the request for approval of
the proposed Reliability Standard. No comments were received that indicated the proposed
Reliability Standard conflicts with other vital public interests.
12. Proposed Reliability Standards must consider any other appropriate factors. 14
No other negative factors relevant to whether the proposed Reliability Standard is just
and reasonable were identified.

12

Order No. 672 at P 334.

13

Order No. 672 at P 335.

14

Order No. 672 at P 323.

Exhibit D
Consideration of Directives

Project 2016-02 Consideration of Issues and Directives
Federal Energy Regulatory Commission Order No. 822

Directives from FERC Order No. 822
Paragraph
53

Directive Language
53. As discussed in detail below, however, the
Commission concludes that modifications to CIP-006-6
to provide controls to protect, at a minimum,
communication links and data communicated
between bulk electric system Control Centers are
necessary in light of the critical role Control Center
communications play in maintaining bulk electric
system reliability. Therefore, we adopt the NOPR
proposal and direct that NERC, pursuant to section
215(d)(5) of the FPA, develop modifications to the CIP
Reliability Standards to require responsible entities to
implement controls to protect, at a minimum,
communication links and sensitive bulk electric system
data communicated between bulk electric system
Control Centers in a manner that is appropriately
tailored to address the risks posed to the bulk electric
system by the assets being protected (i.e., high,
medium, or low impact).

Consideration of Issue or Directive
The Project 2016-02 Standard Drafting Team (SDT) drafted
Reliability Standard CIP-012-1 Requirement R1 to require
responsible entities to implement one or more documented
plan(s) to mitigate the risks posed by unauthorized disclosure
and unauthorized modification of Real-time Assessment and
Real-time monitoring data while being transmitted between
applicable Bulk Electric System (BES) Control Centers. Due to
the sensitivity of the data being transmitted between the
Control Centers, the SDT created the standard to apply to all
impact levels of BES Cyber Systems (i.e., high, medium, or low
impact).
Based on operational risk, the SDT determined that Real-time
Assessments and Real-time monitoring data was the
appropriate scope of the requirement. This critical information
is necessary for immediate situational awareness and real-time
operation of the BES.

Directives from FERC Order No. 822
Paragraph

Directive Language

Consideration of Issue or Directive
The SDT has drafted the requirement allowing Responsible
Entities the flexibility to apply protection to the
communication links, the data, or both, consistent with their
operational environments to satisfy the security objective of
the Commission’s directive

54

54. NERC and other commenters recognize that interControl Center communications play a critical role in
maintaining bulk electric system reliability by, among
other things, helping to maintain situational awareness
and reliable bulk electric system operations through
timely and accurate communication between Control
Centers.59 We agree with this assessment. In order for
certain responsible entities such as reliability
coordinators, balancing authorities, and transmission
operators to adequately perform their reliability

Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

FERC Order No. 822 specifically references CIP-006-6, which
pertains to physical security controls. CIP-006-6, Requirement
R1, Part 1.10 focuses on protecting the nonprogrammable
communication components between Cyber Assets within the
same ESP for medium and high impact BES Cyber Systems. The
SDT asserts that most of the communications contemplated by
FERC Order No. 822 are not within the same ESP, and, as such,
CIP-006-6, Requirement R1, Part 1.10 would not be the
appropriate location for this requirement.
The SDT agrees that inter-Control Center communications play
a critical role in Bulk Electric System reliability. Responsible
Entities should therefore apply security measures to mitigate
the risks posed by unauthorized disclosure and unauthorized
modification of Real-time Assessment and Real-time
monitoring data. Since the current CIP Reliability Standards do
not address this, the SDT has designed the requirement to
protect the data while it is being transmitted between interentity and intra-entity Control Centers.

2

Directives from FERC Order No. 822
Paragraph

Directive Language
functions, their associated control centers must be
capable of receiving and storing a variety of sensitive
bulk electric system data from interconnected entities.
Accordingly, we find that additional measures to protect
both the integrity and availability of sensitive bulk
electric system data are warranted.60 We also
understand that the attributes of the data managed by
responsible entities could require different information
protection controls. 61 For instance, certain types of
reliability data will be sensitive to data manipulation
type attacks, while other types of reliability data will be
sensitive to eavesdropping type attacks aimed at
collecting operational information (such as line and
equipment ratings and impedances). NERC should
consider the differing attributes of bulk electric system
data as it assesses the development of appropriate
controls.

Consideration of Issue or Directive
The SDT has drafted a requirement that allows responsible
entities to apply protection to the communication links, the
data, or both to satisfy the security objective consistent with
the capabilities of the responsible entity’s operational
environment.

Footnotes:
NERC Comments at 20.
60 Protecting the integrity of bulk electric system data
involves maintaining and ensuring the accuracy and
consistency of inter-Control Center communications.
Protecting the availability of bulk electric system data
59

Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

3

Directives from FERC Order No. 822
Paragraph

55

Directive Language

Consideration of Issue or Directive

involves ensuring that required data is available when
needed for bulk electric system operations.
61 Moreover, in order for certain responsible entities to
adequately perform their Reliability Functions, the
associated control centers must be capable of receiving
and storing a variety of sensitive data as specified by the
IRO and TOP Standards. For instance, pursuant to
Reliability Standard TOP-003-3, Requirements R1, R3
and R5, a transmission operator must maintain a
documented specification for data and distribute its
data specification to entities that have data required by
the transmission operator’s Operational Planning
Analyses, Real-time Monitoring and Real-time
Assessments. Entities receiving a data specification must
satisfy the obligation of the documented specification.
55. With regard to NERC’s development of modifications
responsive to our directive, we agree with NERC and
other commenters that NERC should have flexibility in
the manner in which it addresses the Commission’s
directive. Likewise, we find reasonable the principles
outlined by NERC that protections for communication
links and sensitive bulk electric system data
communicated between bulk electric system Control
Centers: (1) should not have an adverse effect on
reliability, including the recognition of instances where

The SDT drafted Reliability Standard CIP-012-1 to mitigate the
risks posed by unauthorized disclosure and unauthorized
modification of Real-time Assessments and Real-time monitoring
data while being transmitted between Control Centers. The SDT
developed an objective-based rather than prescriptive
requirement. This approach will allow Responsible Entities
flexibility in protecting these communications networks and
sensitive BES data in a manner suited to each of their respective
operational environments. It will also allow Responsible Entities
to implement protection that considers the risks noted by the

Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

4

Directives from FERC Order No. 822
Paragraph

56

Directive Language

Consideration of Issue or Directive

the introduction of latency could have negative results;
(2) should account for the risk levels of assets and
information being protected, and require protections
that are commensurate with the risks presented; and (3)
should be results-based in order to provide flexibility to
account for the range of technologies and entities
involved in bulk electric system communications.62

Commission. The SDT identified a need to mitigate the risks
posed by unauthorized disclosure and unauthorized modification
of Real-time Assessment and Real-time monitoring data
regardless of asset risk level. The proposal requires protection
for all Real-time Assessment and Real-time monitoring data while
being transmitted between Control Centers.

Footnote:
NERC Comments at 20-21.
56. We disagree with the assertion of NIPSCO and
G&T Cooperatives that the risk posed by bulk electric
system communication networks does not justify the
costs of implementing controls. Communications
between Control Centers over such networks are
fundamental to the operations of the bulk electric
system, and the record here does not persuade us
that controls for such networks are not available at a
reasonable cost (through encryption or otherwise).
Nonetheless, we recognize that not all communication
network components and data pose the same risk to
bulk electric system reliability and may not require the
same level of protection. We expect NERC to develop
controls that reflect the risk posed by the asset or
data being protected, and that can be implemented in

62 See

Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

The SDT noted the FERC reference to additional Reliability
Standards (TOP-003-3 and IRO-010-2) and the responsibilities to
protect the data in accordance with those standards. The SDT
interpreted these references as examples of potentially
sensitive BES data and chose to base the CIP-012 requirements
on the data specifications in TOP-003-3 and IRO-010-2. This
consolidates scoping and helps ensure that Responsible Entities
mitigate the risks posed by the unauthorized disclosure and
unauthorized modification of Real-time Assessment and Realtime monitoring data, rather than leaving the scoping of
sensitive bulk electric system data to individual Responsible
Entities.
The SDT drafted CIP-012-1 to address confidentiality and
integrity of Real-time Assessment and Real-time monitoring
5

Directives from FERC Order No. 822
Paragraph

58

Directive Language

Consideration of Issue or Directive

a reasonable manner. It is important to recognize that
certain entities are already required to exchange
necessary real-time and operational planning data
through secured networks using a “mutually
agreeable security protocol,” regardless of the entity’s
size or impact level.63 NERC’s response to the
directives in this Final Rule should identify the scope
of sensitive bulk electric system data that must be
protected and specify how the confidentiality,
integrity, and availability of each type of bulk electric
system data should be protected while it is being
transmitted or at rest.

data. This was accomplished by drafting the requirement to
mitigate the risks posed by unauthorized disclosure and
unauthorized modification. The SDT asserts that the availability
of this data is already required by the performance obligation of
the TOP and IRO Reliability Standards.

Footnote:
63 See Reliability Standards TOP-003-3, Requirement
R5 and IRO-010-2, Requirement R3.
58. Several commenters sought clarification whether
Control Centers owned by multiple registered entities
would be included under the Commission’s proposal.
We clarify that the scope of the directed modifications
apply to Control Center communications from
facilities at all impact levels, regardless of ownership.
The directed modification should encompass
communication links and data for intra-Control Center
and inter-Control Center communications.

Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

The SDT drafted CIP-012-1 to address the data while being
transmitted. The SDT contends that this data is maintained
within BES Cyber Systems, and is afforded the protection of CIP003 through CIP-011 while at rest.

The SDT drafted CIP-012-1 to apply to all impact levels of BES
Cyber Systems (i.e., high, medium, or low impact), regardless of
ownership. The SDT designed the requirement to mitigate the
risks posed by unauthorized disclosure and unauthorized
modification of Real-time Assessment and Real-time monitoring
data while being transmitted between inter-entity and intraentity BES Control Centers.

6

Directives from FERC Order No. 822
Paragraph
62

Directive Language

Consideration of Issue or Directive

62. Several commenters addressed encryption and
latency. Based on the record in this proceeding, it is
reasonable to conclude that any lag in communication
speed resulting from implementation of protections
should only be measureable on the order of
milliseconds and, therefore, will not adversely impact
Control Center communications. Several commenters
raise possible technical implementation difficulties
with integrating encryption technologies into their
current communications networks. Such technical
issues should be considered by the standard drafting
team when developing modifications in response to
this directive, and may be resolved, e.g., by making
certain aspects of the revised CIP Standards eligible
for Technical Feasibility Exceptions.

The SDT developed an objective-based rather than prescriptive
requirement. This approach will allow Responsible Entities
flexibility in mitigating the risks posed by unauthorized
disclosure and unauthorized modification of Real-time
Assessments and Real-time monitoring data in a manner suited
to each of their respective operational environments. It will
also allow Responsible Entities to implement protection that
considers the risks noted by the Commission.

Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

7

Exhibit E
Implementation Guidance

DRAFT Implementation Guidance
Pending Submittal for ERO Enterprise Endorsement

Cyber Security –
Communications
Between Control
Centers
Implementation Guidance for CIP-012-1

NERC | Report Title | Report Date
I

Table of Contents
Introduction ................................................................................................................................................................3
Requirements .............................................................................................................................................................4
General Considerations ..............................................................................................................................................5
Plan Development ...............................................................................................................................................5
Identification of Real-time Assessment and Real-time monitoring data ............................................................5
Identification of Security Protection ...................................................................................................................5
Identification of Where Security Protection is Applied by the Responsible Entity.............................................6
Reference Model ........................................................................................................................................................7
Reference Model Discussion ...............................................................................................................................7
Identification of Security Protection ...................................................................................................................8
Identification of Where Security Protection is Applied by the Responsible Entity.............................................9
Identification of Responsibilities when the Control Centers are Owned or Operated by Different Responsible
Entities.................................................................................................................................................................9
References ............................................................................................................................................................... 12

NERC | DRAFT CIP-012-1 Implementation Guidance
2

Introduction
The Project 2016-02 SDT drafted this Implementation Guidance to provide example approaches for compliance
with CIP-012-1. Implementation Guidance does not prescribe the only approach, but highlights one or more
approaches that would be effective in achieving compliance with the standard. Because Implementation Guidance
only provides examples, entities may choose alternative approaches that better fit their individual situations 1.
Responsible Entities may find it useful to consider this Implementation Guidance document along with the
additional context and background provided in the SDT-developed Technical Rationale and Justification for CIP012-1 document.

Background

The Commission issued Order No. 822 on January 21, 2016. Order 822 approving seven CIP Reliability Standards
and new or modified definitions, and directed modifications be made to the CIP Reliability Standards. Among
other items, the Commission directed NERC to “develop modifications to the CIP Reliability Standards to require
responsible entities to implement controls to protect, at a minimum, communication links and sensitive bulk
electric system data communicated between bulk electric system Control Centers in a manner that is
appropriately tailored to address the risks posed to the bulk electric system by the assets being protected (i.e.,
high, medium, or low impact).” (Order 822, Paragraph 53)
In response to the directive in Order No. 822, the Project 2016-02 standard drafting team (SDT) drafted Reliability
Standard CIP-012-1 to require Responsible Entities to implement controls to protect sensitive Bulk Electric System
(BES) data and communications links between BES Control Centers. Due to the sensitivity of the data being
communicated between Control Centers, the standard applies to all impact levels (i.e., high, medium, or low
impact).
The SDT drafted requirements to provide Responsible Entities the latitude to protect the communication links,
the data, or both, to satisfy the security objective consistent with the capabilities of the Responsible Entity’s
operational environment.

1

NERC’s Compliance Guidance Policy
NERC | DRAFT CIP-012-1 Implementation Guidance
3

Requirements
R1.

The Responsible Entity shall implement, except under CIP Exceptional Circumstances, one or
more documented plan(s) to mitigate the risks posed by unauthorized disclosure and
unauthorized modification of Real-time Assessment and Real-time monitoring data while being
transmitted between any applicable Control Centers. The Responsible Entity is not required to
include oral communications in its plan. The plan shall include: [Violation Risk Factor: Medium]
[Time Horizon: Operations Planning]
1.1. Identification of security protection used to mitigate the risks posed by unauthorized
disclosure and unauthorized modification of Real-time Assessment and Real-time
monitoring data while being transmitted between Control Centers;
1.2. Identification of where the Responsible Entity applied security protection for transmitting
Real-time Assessment and Real-time monitoring data between Control Centers; and
1.3. If the Control Centers are owned or operated by different Responsible Entities,
identification of the responsibilities of each Responsible Entity for applying security
protection to the transmission of Real-time Assessment and Real-time monitoring data
between those Control Centers.

NERC | DRAFT CIP-012-1 Implementation Guidance
4

General Considerations
Plan Development
As noted in the Technical Rationale and Justification for CIP-012-1, the focus of Requirement R1 is implementing
a documented plan to protect information that is critical to the real-time operations of the Bulk Electric System
while in transit between applicable Control Centers. The number of plan(s) and their content may vary depending
on a Responsible Entity's management structure and operating conditions. The Responsible Entity may document
as many plans as necessary to meet its needs. For instance, a Responsible Entity may choose to document one
plan per Control Center or choose an all-inclusive, single plan for its Control Center communication environment.
A Responsible Entity may choose to document one plan for communications between Control Centers it owns and
a separate plan for communications between its Control Centers and the Control Centers of a neighboring Entity.
The number and structure of the plans is at the discretion of the Responsible Entity as long as the plan(s) include
the required elements described in Parts 1.1, 1.2, and 1.3 of Requirement R1.
Identification of Real-time Assessment and Real-time monitoring data
Responsible Entities can expect to receive or have received requests for Operations Planning Analysis, Real-time
Assessment and Real-time monitoring data from their RC(s), BA(s) and TOP(s). These data requests, pursuant to
the data specification from TOP-003 and IRO-010 requirements, may also include other types of data under the
same request. CIP-012 requires protection only for Real-time Assessment and Real-time monitoring data. If the
provided data specification does not indicate which data is Real-time Assessment and Real-time monitoring
data, Responsible Entities could choose to conduct an assessment to identify this data from among the other
data requested or being communicated. Once a data assessment is completed, the Responsible Entity should
confirm its findings with the other communicating entity before applying security controls. If the Real-time
Assessment and Real-time monitoring data is not clearly identified in the provided data specification, the
Responsible Entity should document the methodology used and all actions taken to identify the Real-time
Assessment and Real-time monitoring data.
Identification of Security Protection
Entities have latitude to identify and choose which security protection is used to mitigate the risks posed by
unauthorized disclosure and unauthorized modification of Real-time Assessment and Real-time monitoring data
while being transmitted between Control Centers.
This security protection could consist of logical protection, physical protection, or some combination of both. To
determine security protection, the requirement specifies that it must mitigate the risks posed by unauthorized
disclosure and unauthorized modification of applicable data.
Security protection implementation can be demonstrated in many ways. If a Responsible Entity uses physical
protection, it may demonstrate implementation through review of an applicable Control Center floor plan with
details subsequently confirmed through visual inspection, which identifies the physical security measures in place
protecting the communication link. If the Responsible Entity uses logical protection, it may demonstrate
implementation through an export of the device configuration which applies the security protection. Alternatively,
a Responsible Entity may demonstrate implementation through security control monitoring, using an automated
monitoring tool to generate reports on the encryption service used to protect a communications link. Where the
operational obligations of an entire communication link, including both endpoints, belong to the Control Center
of another Responsible Entity, the Responsible Entity without operational obligations for the communication link
may demonstrate compliance by ensuring the communications link endpoint is within its Control Center, which
could be limited to including the communication link endpoint within a PSP or where other physical protection is
applied.

NERC | DRAFT CIP-012-1 Implementation Guidance
5

Identification of Where Security Protection is Applied by the Responsible Entity
A Responsible Entity should consider its environment when identifying where security protections should be
applied. One approach is to implement security within the Control Center itself to ensure that data confidentiality
and integrity is protected throughout the transmission. The Responsible Entity can identify where security
protection is applied using a logical or physical location The application of security in accordance with CIP-012
requirements does not add additional assets to the scope of the CIP Reliability Standards. Locations of applied
security protection may vary based on many factors such as impact levels of the Control Center, different
technologies, or infrastructures. Where the operational obligations of an entire communication link, including
both endpoints, belong to the Control Center of another Responsible Entity, the Responsible Entity without
operational obligations for the communication link may demonstrate compliance by ensuring the communications
link endpoint is within its Control Center, which could be limited to including the communication link endpoint
within a PSP or where other physical protection is applied.
Identification of where a Responsible Entity applies security protection could be demonstrated with a list or a
Control Center diagram showing either physical or logical security controls. Physical diagrams may require visual
confirmation of these controls. These diagrams or a list could be included within the plan developed for R1. A
Responsible Entity could also use labels to identify on-site devices where CIP-012 security protection is applied.
When exchanging data between two entities, if a Responsible Entity only manages one end of a communication
link, the Responsible Entity is not responsible for identifying where the security protection is applied by the
neighboring entity with which it is exchanging data. However, if a Responsible Entity has taken responsibility for
both ends of the communication link (such as by placing a router within the neighboring entity’s data center), then
the Responsible Entity shall identify where the security protection is applied at both ends of the link.
Similarly, if a Responsible Entity owns and operates both Control Centers which are exchanging data (such as in
the case of a primary and backup Control Center), then the Responsible Entity shall identify where security
protection is applied at both ends of the link.
Identification of Responsibilities when the Control Centers are Owned or Operated by Different
Responsible Entities

The Technical Rationale and Justification for CIP-012-1 identifies key considerations in the Control Center
Ownership section when communications between Control Centers with different owners or operators. Many
operational relationships between Responsible Entities are unique. Consequently, there is no single way to
identify responsibilities for applying security protection to the transmission of Real-time Assessment and Realtime monitoring data between Control Centers.
Implementation of responsibilities could also be demonstrated in many ways. Some examples include a joint
procedure, a memorandum of understanding, or meeting minutes between the two parties where responsibilities
are defined. These responsibilities should be included in both Responsible Entities’ plans satisfying requirement
Part 1.3.
Where the operational obligations of an entire communication link, including both endpoints, belong to the
Control Center of another Responsible Entity, the Responsible Entity without operational obligations for the
communication link may demonstrate compliance by ensuring the communications link endpoint is within its
Control Center, which could be limited to including the communication link endpoint within a PSP or where other
physical protection is applied.

NERC | DRAFT CIP-012-1 Implementation Guidance
6

Reference Model
For this Implementation Guidance, the SDT uses a basic reference model of Primary and Backup Control Centers
(Entity Alpha) to illustrate approaches to demonstrating compliance. These Control Centers communicate to each
other and to a neighboring entity’s Control Center (Entity Beta) in configurations outlined by the diagrams in this
section. The SDT recognizes that the reference model does not contain many of the complexities of a real Control
Center. For this Implementation Guidance, the registration or functions performed in the reference model Control
Center are also not considered. A high level block diagram of the basic reference model is shown below in Figure
1. This Implementation Guidance is developed from the perspective of Entity Alpha.

Entity Alpha’s Primary
Control Center

Communication between Entity Alpha’s
Primary and Backup Control Center

Communication between Entity Alpha’s
Primary Control Center and Entity Beta’s Control Center

Entity Alpha’s Backup
Control Center

Communication between Entity Alpha’s
Backup Control Center and Entity Beta’s Control Center

Entity Beta’s Control
Center

Figure 1: High Level Block Diagram of Reference Model Control Centers

Reference Model Discussion
Requirement R1 requires the implementation of a documented plan. To comply with requirement R1, one
approach to a plan is to first determine which communications are in scope of CIP-012-1. There are multiple ways
to identify an entity’s scope in R1. For example, Entity Alpha in the reference model may first identify the Control
Centers with which it communicates. Entity Alpha would determine that there are three: Entity Alpha’s Primary
Control Center, Entity Alpha’s Backup Control Center, and Entity Beta’s Control Center. Entity Alpha does not need
to consider whether Entity Beta further shares its data with another Entity. That is the responsibility of Entity Beta
and is outside of Entity Alpha’s purview. Additionally, Entity Alpha does not need to consider any communications
to other non-Control Center facilities such as generating plants or substations. These communications are out of
scope for CIP-012-1.
Now that Entity Alpha has identified the Control Centers with which it communicates, Entity Alpha identifies
either: (1) the Real-time Assessment and Real-time monitoring data; or (2) communication links which are used
to transmit Real-time Assessment and Real-time monitoring data between Control Centers. In either case, Entity
Alpha should refer to the data specification for Real-time Assessment and Real-time monitoring data identified in
NERC | DRAFT CIP-012-1 Implementation Guidance
7

TOP-003-3 and IRO-010-2. For this reference model scenario, identifying the communication links used to transmit
Real-time Assessment and Real-time monitoring data may be the most straightforward approach. Through an
evaluation of communication links between Control Centers and an evaluation of how it transmits and receives
Real-time Assessment and Real-time monitoring data, Entity Alpha determined that it communicates applicable
data between its primary and backup Control Centers across a single communication link. Entity Alpha also
determined that it communicates applicable data to and from Entity Beta’s Control Center across one of two links
that originate from either Entity Alpha’s primary or backup Control Center using the Inter-Control Center
Communications Protocol (ICCP).
With an identified scope of communications links, Entity Alpha now considers the three required elements of its
required communications between Control Centers for its plan.
Identification of Security Protection

2

•

Entity Alpha must ensure that protection is applied where identified in its CIP-012-1 plan. The protection
must also meet the security objective of mitigating the risks posed by unauthorized disclosure and
unauthorized modification of applicable data while in transit between Control Centers. The identification
of security protection could be demonstrated by a network diagram similar to that shown in Figure 2 or
Figure 3.

•

In a simple case where the security protection is applied sufficiently close to the Control Center, such as
within the Physical Security Perimeter of the Control Center, Entity Alpha may use a single security
protection method to meet the security objective. For this case, shown in Figure 2, Entity Alpha
implements a Virtual Private Network (VPN) connection across a private leased communication circuit for
each of its three in-scope communication links. To meet the security objective, Entity Alpha further states
that its VPN uses Internet Protocol security (IPsec) with encryption.

•

For more complex scenarios, Entity Alpha may need to use a combination of security controls. For
instance, in Figure 3, Entity Alpha uses a combination of physical security controls (physical access control)
and logical security controls (encrypted communications consistent with the first scenario above) to meet
the security objective. The SDT notes that the same technical architecture could exist where the
responsibilities of the registered entities are different. Therefore as shown in Figure 2 & 3, in the scenario
where entity Alpha owns and operationally manages the communication link and endpoint equipment,
Entity Beta is responsible for ensuring the communication endpoint of the communication link is within a
Control Center. Entity Beta ensures Entity Alpha’s communication link endpoint equipment is within a
Control Center by including the communication endpoint within a Control Center PSP. The physical
controls for the PSP are described in CIP-006 documentation and do not need to be repeated for this
requirement. This satisfies Entity Beta’s obligation for Part 1.1 and 1.2.

•

While these scenarios are all specific to communication links, it is possible that Entity Alpha and Entity
Beta achieve the security objective by applying protection to the data rather than the communication
links. In this scenario, the application enabling the data exchange between Control Centers may be
capable of applying security controls directly to the data. These security controls mitigate the risks posed
by unauthorized disclosure and unauthorized modification of applicable data rather than relying on lower
level network services to provide this security. For instance, Entity Alpha and Entity Beta may apply
security protection at the application layer by using Secure ICCP to exchange applicable data. According
to a report released by Sandia National Labs 2, Secure ICCP provides “data integrity indirectly by providing
a cryptographic checksum. Secure ICCP provides data confidentiality by encrypting ICCP data exchanges.”
Methods other than Secure ICCP could also be used to apply security protection to the data at the
application layer.

https://energy.gov/sites/prod/files/oeprod/DocumentsandMedia/19-Secure_ICCP_Integration.pdf
NERC | DRAFT CIP-012-1 Implementation Guidance
8

Identification of Where Security Protection is Applied by the Responsible Entity

Similar to the identification of security protection above, the identification of where security protection is applied
can also be demonstrated by a network diagram similar to those found in Figures 2 and 3.
•

Figure 2 shows the identification where CIP-012-1 security protection is applied for the Entity Alpha
reference model when a single encrypted tunnel is used to implement the required protection. Entity
Alpha has identified that security protection is applied at each of its Control Centers on the external
Ethernet interface on the WAN router. While the diagram depicts where Entity Beta has applied security
protection for illustrative purposes, Entity Alpha is not responsible for identifying where Entity Beta has
applied security protection.

•

In order to understand the application of security protection in context of who controls the
communication link, it may be helpful to identify both where CIP-012-1 security protection is applied and
the location of the telecommunications carrier (telco) demarcation point. Figure 3 provides such an
example where the telco demarcation point may not be within the Control Center and based the facts
and circumstances surrounding this scenario, Entity Alpha has implemented a combination of security
controls to comply with CIP-012-1. In this scenario, Entity Alpha identifies that it has applied physical
security protection for its PSP and continuing for its WAN router and that it has applied logical security
protection (encryption) at the WAN router. Entity Alpha has also identified the telco demarcation point at
a point in the telecommunications cabling connecting to Entity Alpha’s WAN router, perhaps at a punch
down block for example. In Figure 3, the telco demarcation point is inside the same room as the WAN
router. The telco demarcation points are referenced in the drawing for clarity, but are not part of the plan.

•

Figures 2 & 3 provide an example of where the operational obligations of an entire communications link,
including both endpoints, belong to Entity Alpha. In this case, Entity Beta may be responsible for ensuring
the communications endpoint of the communications link is within their Control Center. Entity Beta
ensures Entity Alpha’s communication link endpoint equipment is within a Control Center by including the
communication endpoint within a Control Center PSP. The documentation provided for Part 1.1 by Entity
Beta fulfils this obligation.

•

The data-centric scenario described above is less intuitive for identifying where security protection is
applied by Entity Alpha. If security protection is applied at the application layer (such as Secure ICCP),
Entity Alpha could reasonably identify the application or service applying the security (such as the Secure
ICCP service) as the location of where security protection is applied.

Identification of Responsibilities when the Control Centers are Owned or Operated by Different
Responsible Entities

Entity Alpha and Entity Beta may determine they each are responsible for one end of the VPN configuration on
their respective WAN routers. Entity Alpha and Entity Beta have agreed to a 30 character pre-shared key for IPSec
authentication.
Rather than use a pre-shared key, Entity Alpha and Entity Beta may decide to use digital certificates for the IPSec
authentication using a trusted certificate authority. In that scenario, Entity Alpha and Entity Beta would agree on
who is the party responsible for managing the certificate authority.
In the example where the communication link and endpoint equipment are owned by Entity Alpha, both entities
should include ownership responsibilities in their plans satisfying requirement 1.3. Examples include but are not
limited to, a letter indicating ownership or responsibility, a copy of a contract indicating ownership or
responsibilities, an excerpt from an operational agreement or manual indicating ownership or responsibility.

NERC | DRAFT CIP-012-1 Implementation Guidance
9

Entity Alpha’s Primary
Control Center

Entity Alpha’s CIP-012
security protection applied
at the external interface of
the WAN router

Entity Alpha’s CIP-012
security protection applied
at the external interface of
the WAN router

Entity Alpha’s Backup
Control Center

WAN Router

WAN Router

ESP Firewall

ESP Firewall

Operator Application Database
Workstations Server
Server

ICCP
Server

Operator Application Database
Workstations Server
Server

ICCP
Server

Communications Carrier
Entity Beta’s CIP-012
security protection applied
at the external interface of
the WAN router

Entity Beta’s
Control Center
WAN Router

ESP Firewall

Operator Application Database
Workstations Server
Server

In the case where Entity Alpha owns
and operationally manages the
communication link and endpoint
equipment, Entity Beta ensures
Entity Alpha’s endpoint equipment
is within the Control Center. Entity
Alpha includes any logical security
protection applied to the
communication link in their plan

ICCP
Server

Figure 2: Network diagram and identification of where security protection is applied

NERC | DRAFT CIP-012-1 Implementation Guidance
10

Entity Alpha’s CIP-012
physical security
protection applied

Physically secured area

Physically secured area

Entity Alpha’s Primary
Control Center

WAN Router
Entity Alpha’s CIP-012
logical security
protection applied

ESP Firewall

Entity Alpha’s Backup
Control Center

WAN Router
Telco
Demarcation
Point

Telco
Demarcation
Point

Entity Alpha’s CIP-012
physical security
protection applied

Entity Alpha’s CIP-012
logical security
protection applied

ESP Firewall

Encrypted
Communications
Operator Application Database
Workstations Server
Server

ICCP
Server

Operator Application Database
Workstations Server
Server

ICCP
Server

Communications Carrier
Entity Beta’s CIP-012
security protection
applied

Entity Beta’s
Control Center
WAN Router

ESP Firewall

Operator Application Database
Workstations Server
Server

In the case where Entity Alpha owns
and operationally manages the
communication link and endpoint
equipment, Entity Beta ensures
Entity Alpha’s endpoint equipment
is within the Control Center. Entity
Alpha includes any logical security
protection applied to the
communication link in their plan

ICCP
Server

Figure 3: Network diagram using a combination of controls for CIP-012-1

NERC | DRAFT CIP-012-1 Implementation Guidance
11

References
Mitre Common Weakness Enumeration (CWE™) list of software weakness types
https://cwe.mitre.org/data/definitions/327.html
Cryptographic Standards and Guidelines
https://csrc.nist.gov/Projects/Cryptographic-Standards-and-Guidelines
NIST Special Publication 800-175B
Guideline for Using Cryptographic Standards in the Federal Government: Cryptographic Mechanisms
http://nvlpubs.nist.gov/nistpubs/SpecialPublications/NIST.SP.800-175B.pdf
Guide to Cryptography
https://www.owasp.org/index.php/Guide_to_Cryptography#Symmetric_Cryptography

NERC | DRAFT CIP-012-1 Implementation Guidance
12

Exhibit F
Technical Rationale

Cyber Security –
Communications between
Control Centers
Technical Rationale and Justification for
Reliability Standard CIP-012-1

NERC | Report Title | Report Date
I

Table of Contents
Preface ...................................................................................................................................................................... iii
Introduction .............................................................................................................................................................. iv
Requirement R1 ......................................................................................................................................................... 1
General Considerations for Requirement R1...................................................................................................... 1
Overview of confidentiality and integrity ........................................................................................................... 1
Alignment with IRO and TOP standards ............................................................................................................. 1
Identification of Where Security Protection is Applied by the Responsible Entity ............................................ 2
Control Center Ownership .................................................................................................................................. 2
References.................................................................................................................................................................. 4

NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1
ii

Preface
The vision for the Electric Reliability Organization (ERO) Enterprise, which is comprised of the North American Electric
Reliability Corporation (NERC) and the seven Regional Entities (REs), is a highly reliable and secure North American
bulk power system (BPS). Our mission is to assure the effective and efficient reduction of risks to the reliability and
security of the grid.
The North American BPS is divided into seven RE boundaries as shown in the map and corresponding table below.
The multicolored area denotes overlap as some load-serving entities participate in one Region while associated
Transmission Owners/Operators participate in another.

FRCC

Florida Reliability Coordinating Council

MRO

Midwest Reliability Organization

NPCC

Northeast Power Coordinating Council

RF

ReliabilityFirst

SERC

SERC Reliability Corporation

Texas RE

Texas Reliability Entity

WECC

Western Electricity Coordinating Council

NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1
iii

Introduction
This document explains the technical rationale and justification for the proposed Reliability Standard CIP-012-1. It
will provide stakeholders and the ERO Enterprise with an understanding of the technology and technical
requirements in the Reliability Standard. It also contains information on the SDT’s intent in drafting the requirements.
This Technical Rationale and Justification for CIP-012-1 is not a Reliability Standard and should not be considered
mandatory and enforceable.
On January 21, 2016, the Federal Energy Regulatory Commission (FERC or Commission) issued Order No. 822,
approving seven Critical Infrastructure Protection (CIP) Reliability Standards and new or modified terms in the
Glossary of Terms Used in NERC Reliability Standards, and directing modifications to the CIP Reliability Standards.
Among others, the Commission directed the North American Electric Reliability Corporation (NERC) to “develop
modifications to the CIP Reliability Standards to require Responsible Entities 1 to implement controls to protect, at a
minimum, communication links and sensitive bulk electric system data communicated between bulk electric system
Control Centers in a manner that is appropriately tailored to address the risks posed to the bulk electric system by
the assets being protected (i.e., high, medium, or low impact).” (Order 822, Paragraph 53)
In response to the directive in Order No. 822, the Project 2016-02 standard drafting team (SDT) drafted Reliability
Standard CIP-012-1 to require Responsible Entities to implement controls to protect sensitive Bulk Electric System
(BES) data and communications links between BES Control Centers. Due to the sensitivity of the data being
communicated between Control Centers, as defined in the Glossary of Terms Used in NERC Reliability Standards, the
standard applies to all impact levels (i.e., high, medium, or low impact).
Although the Commission directed NERC to develop modifications to CIP-006, the SDT determined that modifications
to CIP-006 would not be appropriate. There are differences between the plan(s) required to be developed and
implemented for CIP-012-1 and the protection required in CIP-006-6 Requirement R1 Part 1.10. CIP-012-1
Requirements R1 and R2 protect the applicable data during transmission between two separate Control Centers. CIP006-6 Requirement R1 Part 1.10 protects nonprogrammable communication components within an Electronic
Security Perimeter (ESP) but outside of a Physical Security Perimeter (PSP). The transmission of applicable data
between Control Centers takes place outside of an ESP. Therefore, the protection contained in CIP-006-6
Requirement R1 Part 1.10 does not apply.
The SDT drafted requirements to provide Responsible Entities the latitude to protect the communication links, the
data, or both to satisfy the security objective consistent with the capabilities of the Responsible Entity’s operational
environment.
CIP-012 Exemption (4.2.3) for certain Control Centers
In the process of drafting CIP-012, the SDT became aware of certain generating plant or Transmission substation
situations where such field assets could be dual-classified as Control Centers based on the current Control Center
definition. Their communications to their BA or TOP Control Centers, however, are not included in the intended
scope of CIP-012. This is because the communications do not differ from those of any other generating plant or
substation. The SDT wrote an exemption (Section 4.2.3 within CIP-012) for this particular scenario which is
described in further detail below.
I

1

As used in the CIP Standards, a Responsible Entity refers to the registered entities subject to the CIP Standards.
NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1
iv

Introduction

Figure 1
Figure 1 presents a typical scenario with two Control Centers communicating (in this instance Entity C’s RC Control
Center and Entity A’s TOP Control Center). The communication between them is the intended scope of CIP-012’s
requirements if they meet the types of data inclusions and exclusions within the standard. The TOP Control Center
is communicating with an RTU at two of Entity B’s generating plants (Stations Alpha and Beta). Those RTU’s are
gathering information from each generating unit’s control system. Each generating unit at each plant has an HMI
(Human/Machine Interface; an operator workstation) that the local personnel use to operate their respective units.

Entity B decides that the generating unit at Station Beta, a small peaking facility, will only have an
operator on site during the day. The operator at Station Alpha should be able to remotely start the unit at

NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1
v

Introduction

Station Beta if necessary.

Figure 2
In Figure 2, Entity B installs a dedicated communications circuit from the control system on Station Beta’s control
system and puts a dedicated HMI at Station Alpha operator use. Station Alpha is now “one or more facilities hosting
operating personnel that monitor and control the BES in real time to perform the reliability tasks of…a Generator
Operator for generation Facilities at two or more locations” Because stations Alpha and Beta are two different plant
locations. Station Alpha can now be dual-classified not only as a generation resource but also as a Control Center.
The communications to the TOP and RC Control Centers in Figure 1 have not changed. No new cyber systems are in
place that can impact multiple units. In addition, no cyber systems have been added performing Control Center
functions. The only change is that an HMI for Station Beta has been moved within close physical proximity to an HMI
for Station Alpha.

NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1
vi

Introduction

Figure 3
Although nothing has changed between them, this proximity makes the communication noted in Figure 3 between
Station Alpha and Entity A’s TOP Control Center subject to CIP-012 without the exemption. Two HMIs have been
moved into the same room and a new NERC CIP standard applies to two entities.
This is an anomaly of the current Control Center definition of a facility, room, or building from which certain functions
can be performed without regard to how they are done or what systems they are using. This is a generation specific
example, but the potential situation exists where there are substations with an HMI or protective relay that
“operating personnel” within the substation could use to impact an adjacent substation. It is also clear that in the
criteria for TO’s and GOP’s the “two or more locations” is not a precise enough filter for defining what a Control
Center truly is. The SDT’s attempts to address this issue by clarifying the definition of Control Center pointed out
larger issues that are not within the SDT’s SAR to address at this time. Accordingly, the SDT is handling the issue
through the 4.2.3 exemption within the CIP-012 standard which reads:
4.2.3. A Control Center g that transmits to another Control Center the transmitting Control Center.
The intent of this exemption is to exclude from CIP-012 the normal RTU-style communication from a field asset
providing that field asset’s status. Throughout this scenario or others like it, that communication has not changed
and is still the same data pertaining only to the single location. The SDT recognizes that this communication is not
the intent of the standard for protecting communications between Control Centers and this type of
communications can be using older legacy communication technology and protocols.
The 4.2.3 exemption covers generation resources or Transmission station or substation locations that host
operating personnel and can control BES Facilities at more than one location, possibly making them co-located
Control Centers. The communication is exempt if each location is communicating the Real-time Assessment or Realtime monitoring data with another Control Center pertaining only to that location.

NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1
vii

Introduction

The above diagrams were generation specific. The following diagram is a more generic example:

Figure 4
In Figure 4, each location is communicating only the Real-time Assessment or Real-time monitoring data pertaining
to that single location. The communication from Entity B location one (1) to Entity A would be exempt from CIP012-1.
If Location 2 communicates its data through Location 1,and Location 1 was both controlling and aggregating data
from multiple locations to Entity A’s TOP Control Center, the communication between Location 1 and Entity A’s TOP
Control Center would not be exempt from CIP-012.

NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1
viii

Requirement R1
R1. The Responsible Entity shall implement, except under CIP Exceptional Circumstances, one or more
documented plan(s) to mitigate the risks posed by unauthorized disclosure and unauthorized
modification of Real-time Assessment and Real-time monitoring data while being transmitted
between any applicable Control Centers. The Responsible Entity is not required to include oral
communications in its plan. The plan shall include: [Violation Risk Factor: Medium] [Time Horizon:
Operations Planning]
1.1

Identification of security protection used to mitigate the risks posed by unauthorized disclosure
and unauthorized modification of Real-time Assessment and Real-time monitoring while being
transmitted between Control Centers;

1.2

Identification of where the Responsible Entity applied security protection for transmitting Realtime Assessment and Real-time monitoring data between Control Centers; and

1.3

If the Control Centers are owned or operated by different Responsible Entities, identification of
the responsibilities of each Responsible Entity for applying security protection to the
transmission of Real-time Assessment and Real-time monitoring data between those Control
Centers.

General Considerations for Requirement R1
Requirement R1 focuses on implementing a documented plan to protect information that is critical to the Real-time
operations of the Bulk Electric System while in transit between applicable Control Centers. The SDT does not intend
for the listed order of the three requirement parts to convey any sequence or significance.
Overview of confidentiality and integrity
The SDT drafted CIP-012-1 to address confidentiality and integrity of Real-time Assessment and Real-time monitoring
data. This is accomplished by drafting the requirement to mitigate the risks posed by unauthorized disclosure
(confidentiality) and unauthorized modification (integrity). For this Standard, the SDT relied on the definitions of
confidentiality and integrity as defined by National Institute of Standards and Technology (NIST):
•

Confidentiality is defined as, “Preserving authorized restrictions on information access and disclosure,
including means for protecting personal privacy and proprietary information.” 2

•

Integrity is defined as, “Guarding against improper information modification or destruction, and includes
ensuring information non-repudiation and authenticity.” 3

The SDT asserts that the availability of this data is already required by the performance obligation of the Operating
and Planning Reliability Standards. The SDT drafted CIP-012-1 to address the data while being transmitted. The SDT
maintains that this data resides within BES Cyber Systems, and while at rest is protected by CIP-003-6 through CIP011-2.
Alignment with IRO and TOP standards
The SDT recognized the FERC reference to additional Reliability Standards and the responsibilities to protect the
applicable data in accordance with NERC Reliability Standards TOP-003 and IRO-010. The SDT used these references
to drive the identification of sensitive BES data and chose to base the CIP-012-1 requirements on the Real-time data
2
3

NIST Special Publication 800-53A, Revision 4, page B-3
NIST Special Publication 800-53A, Revision 4, page B-6
NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1
1

Requirement R1

specification elements in these standards. This approach provides consistent scoping of identified data, and does not
require each entity to devise its own list or inventory of this data. Many entities are required to provide this data
under agreements executed with their RC, BA or TOP. Data requiring protection in CIP-012-1 consists of a subset of
data that is identified by the RC, BA, and TOP in the TOP-003 and IRO-010 data specification standards, limited to
Real-time Assessment data and Real-time monitoring data. CIP-012-1 excludes other data typically transferred
between Control Centers such as Operational Planning Analysis data, weather data, market data, and other data that
is not used by the RC, BA, and TOP to perform Real-time reliability assessments and analysis identified in TOP-003
and IRO-010. The SDT determined that Operational Planning Analysis data, if rendered unavailable, degraded, or
misused, would not adversely impact the reliable operation of the BES within 15 minutes of the activation or exercise
of the compromise as detailed in CIP-002- 5.1a. The SDT notes that there may be special instances during which Realtime Assessment or Real-time monitoring data is not identified by the RC, BA, or TOP. This would include data that
may be exchanged between a Responsible Entity’s primary and backup Control Center.
Identification of Where Security Protection is Applied by the Responsible Entity
The SDT noted the need for a Responsible Entity to identify where it will apply protection for applicable data. The
SDT did not specify the location where CIP-012-1 security protection must be applied. This allows latitude for
Responsible Entities to implement the security controls in a manner best fitting their individual circumstances. This
latitude ensures entities can still take advantage of security measures, such as deep packet inspection implemented
at or near the EAP when ESPs are present, while maintaining the capability to protect the applicable data being
transmitted between Control Centers.
The SDT also recognizes that CIP-012 security protection may be applied to a Cyber Asset that is not an identified BES
Cyber Asset, Protected Cyber Asset, or EACMS. The identification of the Cyber Asset as the location where security
protection is applied does not expand the scope of Cyber Assets identified as applicable under Cyber Security
Standards CIP-002 through CIP-011.
The SDT understands that in data exchanges between Control Centers, a single entity may not be responsible for both
ends of the communication link. The SDT intends for a Responsible Entity to identify only where it applied security
protection. The Responsible Entity should not be held accountable for identifying where a neighboring entity applied
security protection at the neighboring entity’s facility. A Responsible Entity, however, may decide to take
responsibility for both ends of a communication link. For example, it may place a router in a neighboring entity’s data
center. In a scenario where a Responsible Entity has taken responsibility for applying security protection on both ends
of the communication link, the Responsible Entity should identify where it applied security protection at both ends
of the link. The SDT intends for there to be alignment between the identification of where security protection is
applied in CIP-012-1 Requirement R1, Part 1.2 and the identification of Responsible Entity responsibilities in CIP-0121 Requirement R1, Part 1.3.
Control Center Ownership
The standard requirements address protection for Real-time Assessment and Real-time monitoring data while being
transmitted between Control Centers owned by a single Responsible Entity. They also cover the applicable data
transmitted between Control Centers owned by two or more separate Responsible Entities. Unlike protection
between a single Responsible Entity’s Control Centers, applying protection between Control Centers owned by more
than one Responsible Entity requires additional coordination. The requirements do not explicitly require formal
agreements between Responsible Entities partnering for protection of applicable data. It is strongly recommended,
however, that these partnering entities develop agreements, or use existing ones, to define responsibilities to ensure
the security objective is met. An example noted in FERC Order No. 822 Paragraph 59 is, “if several registered entities
have joint responsibility for a cryptographic key management system used between their respective Control Centers,
they should have the prerogative to come to a consensus on which organization administers that particular key
management system."
NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1
2

Requirement R1

As an example, Figure 5 shows several data transmissions between Control Centers that a Responsible Entity should
consider to be in-scope. The example does not include all possible scenarios. The solid green lines are in-scope
communications and the dashed red lines are out-of-scope communications.

Figure 5: This reference model is an example and does not include all possible scenarios.
The SDT included Part 1.3 of the plan to address the situation when multiple registered entities are involved with
protecting the data transmitted between Control Centers. Part 1.3 provides a mechanism to specify which entity is
responsible for the application of security controls. The SDT included this requirement part to address security
concerns as well as audit concerns. Where data is transmitted between different entities, the SDT asserts that it is
necessary for both entities to understand the responsibilities of applying security controls to ensure the data is
protected through its entire transmission and there is no security gap. The SDT also asserts this requirement part will
provide evidence which may prevent the simultaneous auditing of multiple entities for each communication link
between Control Centers when operated by different Responsible Entities. Security controls applied by the entity to
achieve compliance with Parts 1.1 and 1.2 of the plan should correlate to the documented responsibilities in Part 1.3
of the entity’s plan.

NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1
3

References
Here are several references to assist entities in developing plan(s) for protection of communication links:
•

NIST Special Publication 800-53A, Revision 4: Security and Privacy Controls for Federal Information Systems
and Organizations

•

NIST Special Publication 800-82: Guide to Industrial Control Systems (ICS) Security

•

NIST Special Publication 800-175B: Guideline for Using Cryptographic Standards in the Federal Government:
Cryptographic Mechanisms

•

NIST Special Publication 800-47: Security Guide for Interconnecting Information Technology Systems

NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1
4

Exhibit G
Analysis of Violation Risk Factors and Violation Severity Levels

Violation Risk Factor and Violation Severity Level
Justifications
Project 2016-02 Modifications to CIP Standards

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in CIP-012-1. Each requirement is assigned a VRF and a VSL. These elements support the determination of
an initial value range for the Base Penalty Amount regarding violations of requirements in FERC-approved Reliability Standards, as defined in
the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT applied the following NERC criteria and FERC Guidelines when
developing the VRFs and VSLs for the requirements.

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•

Emergency operations

•

Vegetation management

•

Operator personnel training

•

Protection systems and their coordination

•

Operating tools and backup facilities

•

Reactive power and voltage control

•

System modeling and data exchange

•

Communication protocol and facilities

•

Requirements to determine equipment ratings

•

Synchronized data recorders

•

Clearer criteria for operationally critical facilities

•

Appropriate use of transmission loading relief.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards

2

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards

3

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL

Moderate VSL

The performance or product
measured almost meets the full
intent of the requirement.

The performance or product
measured meets the majority of
the intent of the requirement.

High VSL

The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet
some of the intent.

Severe VSL

The performance or product
measured does not
substantively meet the intent of
the requirement.

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justifications for CIP-012-1, Requirement R1

Proposed VRF

Medium

NERC VRF Discussion

A VRF of Medium was assigned to this requirement. Cyber security plans enable effective implementation
of the CIP standard’s requirements to mitigate the risks posed by unauthorized disclosure and
unauthorized modification of data used for Real-time Assessments and Real-time monitoring while being
transmitted between Control Centers.

FERC VRF G1 Discussion

N/A

Guideline 1- Consistency
with Blackout Report
FERC VRF G2 Discussion

N/A

Guideline 2- Consistency
within a Reliability Standard
FERC VRF G3 Discussion
Guideline 3- Consistency
among Reliability Standards
FERC VRF G4 Discussion
Guideline 4- Consistency
with NERC Definitions of
VRFs
FERC VRF G5 Discussion

The requirement complements CIP-005-1, Requirement R1, CIP-006-6, Requirement R1, and CIP-007-6,
Requirement R1 which are related to security of networks and communications components. The
proposed VRF is consistent with these related requirements.
Failure to have the required plan would not, under Emergency, abnormal, or restorative conditions
anticipated by the preparations, be expected to adversely affect the electrical state or capability of the
Bulk Electric System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

N/A

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards

5

VRF Justifications for CIP-012-1, Requirement R1

Proposed VRF

Medium

Guideline 5- Treatment of
Requirements that Comingle More than One
Obligation
VSLs for CIP-012-1, Requirement R1

Lower
N/A

Moderate
The Responsible Entity
documented its plan(s) but
failed to include one of the
applicable Parts of the plan as
specified in Requirement R1.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards

High
The Responsible Entity
documented its plan(s) but
failed to include two of the
applicable Parts of the plan as
specified in Requirement R1.

Severe
The Responsible Entity failed to
document plan(s) for
Requirement R1;
Or
The Responsible Entity failed to
implement any Part of its plan(s)
for Requirement R1, except
under CIP Exceptional
Circumstances.

6

VSL Justifications for CIP-012-1 Requirements R1

FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency
in the Determination of
Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent

The requirement is new. Therefore, the proposed VSL does not have the unintended consequence of
lowering the level of compliance.

The requirement is for the Responsible Entity to implement one or more documented plan(s) as specified
in Requirement R1.
The moderate VSL addresses where the Responsible Entity documented its plan(s) but failed to include
one of the applicable parts of the plan as specified in Requirement R1.
The high VSL addresses where the Responsible Entity documented its plan(s) but failed to include two of
the applicable parts of the plan as specified in Requirement R1.
The severe VSL addresses where the Responsible Entity failed to document plan(s) for Requirement R1, or
where the Responsible Entity failed to implement plan(s) for Requirement R1.

Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement

The proposed VSL uses the same terminology as used in the associated requirement and is, therefore,
consistent with the requirement.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards

7

FERC VSL G4

Each VSL is based on a single violation and not cumulative violations.

Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards

8

Exhibit H
Summary of Development History and Complete Record of Development

Summary of Development History

Summary of Development History
The development record for proposed Reliability Standard CIP-012-1 is summarized
below.
I.

Overview of the Standard Drafting Team
When evaluating a proposed Reliability Standard, the Commission is expected to give

“due weight” to the technical expertise of the ERO. 1 The technical expertise of the ERO is
derived from the standard drafting team (“SDT”) selected to lead each project in accordance with
Section 4.3 of the NERC Standard Processes Manual. 2 For this project, the SDT consisted of
industry experts, all with a diverse set of experiences. A roster of the Project 2016-02 –
Modifications to CIP Standards SDT members is included in Exhibit I.
II.

Standard Development History

A. Standard Authorization Request Development
Project 2016-02 – Modifications to CIP Standards was initiated on March 9, 2016 as a
Standards Authorization Request (“SAR”) to address Commission directives in Order No. 822
and other items. 3 The SAR was posted for a 30-day informal comment period from March 23,
2016 through April 21, 2016 and accepted by the Standards Committee on July 20, 2016. In
Order No. 822, the Commission directed NERC to develop modifications to Reliability Standard
CIP-006-6 to require Responsible Entities to implement controls to protect communication links
and sensitive BES data communicated between BES Control Centers. 4 Rather than revise CIP-

1

Section 215(d)(2) of the Federal Power Act; 16 U.S.C. § 824(d)(2) (2012).

2
The NERC Standard Processes Manual is available at
http://www.nerc.com/comm/SC/Documents/Appendix_3A_StandardsProcessesManual.pdf.
3

Order No. 822, Revised Critical Infrastructure Protection Reliability Standards, 154 FERC ¶ 61,037, order
denying reh’g, Order No. 822-A, 156 FERC ¶ 61,037 (2016).

4

Id. at P 3.

1

006-6, the SDT determined that a new Reliability Standard was appropriate given the differences
in applicability and scope between CIP-006-6 and proposed CIP-012-1.
B. First Posting - Comment Period, Initial Ballot and Non-binding Poll
Proposed Reliability Standard CIP-012-1, the associated Implementation Plan, Violation
Risk Factors (“VRFs”), Violation Severity Levels (“VSLs”), and other associated documents
were posted for a 45-day formal comment period from July 27, 2017 through September 11,
2017, with a parallel initial ballot and non-binding poll held during the last 10 days of the
comment period from September 1, 2017 through September 11, 2017. The initial ballot for CIP012-1 received 42.72 percent approval, reaching quorum at 80.26 percent of the ballot pool. The
non-binding poll for the associated VRFs and VSLs received 41.53 percent supportive opinions,
reaching quorum at 77.93 percent of the ballot pool. There were 81 sets of responses, including
comments from approximately 207 different individuals and approximately 139 companies,
representing all 10 industry segments. 5
C. Second Posting - Comment Period, Additional Ballot and Non-binding Poll
Proposed Reliability Standard CIP-012-1, the associated Implementation Plan, VRFs,
VSLs, and other associated documents were posted for a 45-day formal comment period from
October 27, 2017 through December 11, 2017, with a parallel additional ballot as well as the
non-binding poll held during the last 10 days of the comment period from December 1, 2017
through December 11, 2017 (the non-binding poll was extended from December 11, 2017 to
December 12, 2017 to reach quorum). The additional ballot for CIP-012-1 reached quorum at
77.35 percent of the ballot pool and received 63.91 percent approval. The related non-binding

5

NERC, Consideration of Comments, Project 2016-02 Modification to CIP Standards (CIP-012-1) (Oct.
2017),
https://www.nerc.com/pa/Stand/Project%20201602%20Modifications%20to%20CIP%20Standards%20DL/201602_CIP-012-1_Consideration_of_Comments_10272017.pdf.

2

poll for CIP-012-1 reached quorum at 78.62 percent of the ballot pool and received 60.44 percent
supportive opinions. There were 61 sets of responses, including comments from approximately
168 different individuals and approximately 117 companies, representing all 10 industry
segments. 6
D. Third Posting - Comment Period, Additional Ballot and Non-binding Poll
Proposed Reliability Standard CIP-012-1, the associated Implementation Plan, VRFs,
VSLs, and other associated documents were posted for a 45-day formal comment period from
March 16, 2018 through April 30, 2018, with a parallel additional ballot as well as the nonbinding poll held during the last 10 days of the comment period from April 20, 2018 through
April 30, 2018. The additional ballot for CIP-012-1 reached quorum at 78.32 percent of the
ballot pool and received 83.71 percent approval. The related non-binding poll for CIP-012-1
reached quorum at 76.21 percent of the ballot pool and received 79.78 percent supportive
opinions. There were 58 sets of responses, including comments from approximately 155 different
individuals and approximately 108 companies, representing all 10 industry segments. 7
E. Fourth Posting - Comment Period, Additional Ballot and Non-binding Poll
Proposed Reliability Standard CIP-012-1, the associated Implementation Plan, VRFs,
VSLs, and other associated documents were posted for a 45-day formal comment period from
May 18, 2018 through July 3, 2018, with a parallel additional ballot as well as the non-binding
poll held during the last 10 days of the comment period from June 22, 2018 through July 3, 2018

6
NERC, Consideration of Comments, Project 2016-02 Modification to CIP Standards (CIP-012-1) (Mar.
2018),
https://www.nerc.com/pa/Stand/Project%20201602%20Modifications%20to%20CIP%20Standards%20DL/CIP012-1_Consideration_of_Comments_03162018.pdf.
7

NERC, Consideration of Comments, Project 2016-02 Modification to CIP Standards (CIP-012-1) (May
2018),
https://www.nerc.com/pa/Stand/Project%20201602%20Modifications%20to%20CIP%20Standards%20DL/Project2016-02_CIP-012-1_Consideration_of_Comments_Report_05252018.pdf.

3

(non-binding poll was extended an from July 3, 2018 to July 5, 2018 to reach quorum). The
additional ballot for CIP-012-1 reached quorum at 75.4 percent of the ballot pool and received
68.45 percent approval. The related non-binding poll for CIP-012-1 reached quorum at 77.24
percent of the ballot pool and received 69.77 percent supportive opinions. There were 55 sets of
responses, including comments from approximately 149 different individuals and approximately
101 companies, representing all 10 industry segments. 8
F. Final Ballot
Proposed Reliability Standard CIP-012-1 was posted for a 10-day final ballot period from
August 3, 2018 through August 13, 2018. The ballot for proposed Reliability Standard CIP-0121 and associated documents reached quorum at 81.55 percent of the ballot pool, receiving
support from 72.55 percent of the voters.
G. Board of Trustees Adoption
The NERC Board of Trustees adopted proposed Reliability Standard CIP-012-1 on
August 16, 2018. 9

8

NERC, Consideration of Comments, Project 2016-02 Modification to CIP Standards (CIP-012-1) (Aug.
2018),
https://www.nerc.com/pa/Stand/Project%20201602%20Modifications%20to%20CIP%20Standards%20DL/CIP012-1_Consideration_of_Comments_08032018.pdf.
9

NERC, Board of Trustees Agenda Package, Agenda Item 7da (CIP-012-1 – Cyber Security –
Communications between Control Centers) available at
https://www.nerc.com/gov/bot/Agenda%20highlights%20and%20Mintues%202013/Board_Open_Meeting_Agenda
_Package_August_16_2018.pdf.

4

Complete Record of Development

Project 2016-02 Modifications to CIP Standards
Related Files
Status
A 45-day formal comment period for CIP-002-6 - Cyber Security – BES Cyber System Categorization and
CIP-003-8 - Cyber Security – Security Management Controls is open through 8 p.m. Eastern, Tuesday,
October 9, 2018. Ballot pools are being formed through 8 p.m. Eastern, Friday, September 21, 2018. Initial
ballots for the standards and non-binding polls of the associated Violation Risk Factors and Violation Severity Levels
will be conducted September 28 – October 9, 2018.
The final ballot for CIP-012-1 – Cyber Security - Communications between Control Centers concluded 8
p.m. Eastern, Monday, August 13, 2018. The voting results can be accessed via the link below. The standard
will be submitted to the Board of Trustees for adoption and then filed with the appropriate regulatory authorities.
Background
The Version 5 Transition Advisory Group (V5 TAG) transferred issues to the Version 5 SDT that were identified
during the industry transition to implementation of the Version 5 CIP Standards. Specifically, the issues that the SDT
will address are:
•
•
•
•

•
•

•

Cyber Asset and BES Cyber Asset Definitions
Network and Externally Accessible Devices
Transmission Owner (TO) Control Centers Performing Transmission Operator (TOP) Obligations
Virtualization
On January 21, 2016, FERC issued Order No. 822 Revised Critical Infrastructure Protection Reliability Standards. In
this order, FERC approved revisions to version 5 of the CIP standards and also directed that NERC address each of
the Order 822 directives by developing modifications to requirements in CIP standards and the definition of Low
Impact External Routable Connectivity (LERC), or the SDT shall develop an equally efficient and effective
alternative. To address concerns identified in Order 822, the Commission directed the following:
Develop modifications to the CIP Reliability Standards to provide mandatory protection for transient devices used at
Low Impact BES Cyber Systems based on the risk posed to bulk electric system reliability.
Develop modifications to the CIP Reliability Standards to require responsible entities to implement controls to
protect, at a minimum, communication links and sensitive bulk electric system data communicated between bulk
electric system Control Centers in a manner that is appropriately tailored to address the risks posed to the bulk
electric system by the assets being protected (i.e., high, medium, or low impact).
Develop a modification to provide the needed clarity, within one year of the effective date of this Final Rule, to the
LERC definition consistent with the commentary in the Guidelines and Technical Basis section of CIP-003-6.

Standard(s) Affected – CIP-002-5.1, CIP-003-6, CIP-004-6, CIP-005-5, CIP-006-6, CIP-007-6, CIP-008-5, CIP009-6, CIP-010-2, CIP-011-2, CIP-012-1
Purpose/Industry Need
The SDT will modify the CIP family of standards (or develop an equally efficient and effective alternative) to:

•
•
•

Address issues identified by the CIP V5 TAG;
Address FERC directives contained in Order 822; and
Address requests for interpretations as directed by the NERC Standards

Draft

Actions

Dates

Results

08/03/18 08/13/18

Ballot Results (126)

Consideration of
Comments

Final Draft
CIP-012-1
Clean (116) | Redline to Last Posted
(117)
Implementation Plan (118)
Supporting Materials
VRF/VSL Justification
Clean (119)| Redline to Last Posted
(120)
Technical Rationale
Clean (121)| Redline to Last Posted
(122)

Final Ballot
Info (125)
Vote

Implementation Guidance
Clean (123) | Redline to Last Posted
(124)

Draft 4
CIP-012-1
Clean (96) | Redline to Last Posted
(97)
Implementation Plan (98)

Comment Period
Info (108)
Submit Comments

Supporting Materials

Comments Received
(109)

Additional
Ballot

Unofficial Comment Form (Word) (99)
VRF/VSL Justification
Clean (100)| Redline to Last Posted
(101)

05/18/18 07/03/18

Additional Ballot and
Non-binding Poll

Technical Rationale
Clean (102) | Redline to Last Posted
(103)

Updated Info (110)

Implementation Guidance
Clean (104)| Redline to Last Posted
(105)

Vote

Info (111)

06/22/18 07/03/18
Ballot Results (112)

6/22/18 7/5/18
Extended to
reach quorum

Info (115)
Send RSAW feedback
Draft Reliability Standard Audit
to:
Worksheet (RSAW)
[email protected]
Clean (106)| Redline to Draft 3 (107)
t

Consideration of
Comments(114)

Non-binding
Poll
Non-binding Poll
Results (113)

Standard Drafting Team
Nominations
Supporting Materials
Unofficial Nomination Form (Word)
(94)

Nomination Period
Info (95)
Submit Nominations

04/24/18 05/23/18

Initial Ballots for the
Definition and
Implementation Plan
Updated Info (87)
Info (88)
Proposed Definition of Control Center
(84)

Vote

Implementation Plan (85)

Comment Period

Supporting Materials

Info (91)

Unofficial Comment Form (Word) (86)

Submit Comments

Join Ballot Pools

Definition Ballot
Results (89)

04/20/18 04/30/18

03/16/18 04/30/18

Ballot Results (79)
Non-binding Poll
Results (80)

CIP-012-1
Clean (63) | Redline to Last Posted
(64)
Implementation Plan (65)
Supporting Materials

Consideration of Issues and Directives
Clean (67) | Redline to Last Posted
(68)

Comments Received
(92)

03/16/18 04/16/18

Draft 3

Unofficial Comment Form (Word) (66)

Implementation Plan
Ballot Results (90)

Additional Ballot and
Non-binding Poll
Updated Info (77)
Info (78)
Vote

04/20/18 04/30/18

Consideration of
Comments(93)

Comments Received
(82)

VRF/VSL Justification
Clean (69) | Redline to Last Posted
(70)
Implementation Guidance
Clean (71)| Redline to Last Posted
(72)
Technical Rationale
Clean (73)| Redline to Last Posted
(74)

Comment Period
Info (81)
Submit Comments

Consideration of
Comments (83)

03/16/18 04/30/18

Draft Reliability Standard Audit
Worksheet (RSAW)
Clean (75)| Redline to Draft 2 (76)

Send RSAW feedback
to:
[email protected]
t

Technical Rationale and Justification for
CIP-012-1 (57)
Implementation Guidance for CIP-0121 (58)
Supporting Materials

Comment Period
Info (60)
Submit Comments

11/20/17 12/11/17

Comments Received
(61)

Consideration of
Comments (62)

Unofficial Comment Form (Word) (59)

Draft 2
CIP-012-1
Clean (38) | Redline to Last Posted
(39)

Additional Ballot and
Non-binding Poll

Implementation Plan
Clean (40) | Redline to Last Posted
(41)

Info (50)

Updated Info (49)

Vote

12/01/17 12/11/17
(The Nonbinding Poll
was extended
to 12/12/17 to
reach quorum)

Ballot Results (51)
Non-Binding Poll
Results (52)

Supporting Materials
Unofficial Comment Form (Word) (42)
Consideration of Issues and Directives

Comment Period
Info (53)
Submit Comments

10/27/17 12/11/17

Comments Received
(54)

Consideration of
Comments (56)

Clean (43) | Redline to Last Posted
(44)
VRF/VSL Justification
Clean (45) | Redline to Last Posted
(46)
Draft Reliability Standard Audit
Worksheet (RSAW)
Clean (47) | Redline to Last Posted
(48)

Info (55)
Send RSAW feedback
to:
[email protected]
t

12/01/17 12/11/17

Proposed Definition of Control Center
(31)
Technical Rationale and Justification for
CIP-012-1 (32)
Supporting Materials

Comments Received
Comment Periods
Info(35)
Submit Comments

08/14/17 09/12/17

Unofficial Comment Form - Proposed
Definition of Control Center (33)

Proposed Definition
of Control Center
(36)
Technical Rationale
and Justification for
CIP-012-1 (37)

Unofficial Comment Form - Technical
Rationale and Justification for CIP-0121 (34)

Draft 1

Initial Ballot and Nonbinding Poll
Updated Info (23)

CIP-012-1 (17)
Implementation Plan (18)
Supporting Materials

Info (24)
Vote

Ballot Results (25)
09/01/17 09/11/17

Non-binding Poll
Results (26)

Comment Period
Info (27)

Unofficial Comment Form (Word) (19)

Submit Comments

Consideration of Issues and Directives
(20)

Join Ballot Pools

VRF/VSL Justification (21)

Info (30)

07/27/17 09/11/17

07/27/17 08/25/17

Comments Received
(28)

Consideration of
Comments (29)

Draft Reliability Standard Audit
Worksheet (RSAW) (22)

Send RSAW feedback
to:
[email protected]
t

08/17/17 09/11/17

Comment Period

Communication
Networks/Unofficial Comment
Form (14)

Info (15)

02/10/17 03/13/17

Comments Received
(16)

Submit Comments

The Standards Committee accepted the
Standards Authorization Request on
July 20, 2016

Standards Authorization Request
Clean (8) | Redline to Last Posted (9)
Supporting Materials
Unofficial Comment Form (10)
CIP Version 5 Transition Advisory
Group
Issues for Consideration (11)

Comment Period
Info (12)
Submit Comments

06/01/16 06/30/16

Comments Received
(13)

Standards Authorization Request (3)
Supporting Materials
Unofficial Comment Form (Word) (4)
CIP Version 5 Transition Advisory
Group
Issues for Consideration (5)

Supplemental Standard Drafting
Team Nominations
Supporting Materials
Unofficial Nomination Form (Word) (1)

Comment Period
Info (6)
Submit Comments

03/23/16 04/21/16

Nomination Period
Info (2)
Submit Nominations

03/10/16 03/23/16

Comments Received
(7)

Unofficial Nomination Form

Project 2016-02 Modifications to CIP Standards
Supplemental Nomination Period

Nominations for additional standard drafting team (SDT) members are being solicited for Project 2016-02
Modifications to CIP Standards. Use the electronic form to submit nominations by 8 p.m. Eastern,
Wednesday, March 23, 2016. This unofficial version is provided to assist nominees in compiling the
information necessary to submit the electronic form.
Documents and information about this project are available on the Project 2016-02 Modifications to CIP
Standards page. If you have questions, contact either Senior Standards Developer, Stephen Crutchfield at
(609) 651-9455 or Al McMeekin at (404) 446-9675.
By submitting a nomination form, you are indicating your willingness and agreement to actively
participate in face-to-face meetings and conference calls.
Previous drafting or review team experience is beneficial, but not required. A brief description of the
desired qualifications, expected commitment, and other pertinent information is included below.
Background

This solicitation for nominations is to supplement the existing Project 2016-02 Modifications to CIP
Standards SDT that is continuing to address the work in the Project 2016-02 Modifications to CIP
Standards Authorization Request (SAR). NERC is seeking individuals from the United States and Canada
who possess experience in one or more of the following areas:
•

Operations technology

•

Communication networks

•

Virtualization

•

Protection of transient electronic devices

•

Network and externally accessible devices

•

Cyber Asset and BES Cyber Asset definitions

•

Transmission Owner (TO) Control Centers

•

Critical Infrastructure Protection (“CIP”) family of Reliability Standards

The time commitment for Project 2016-02 is expected to be significant. Participants should anticipate
an average workload of 20 hours per week devoted to the drafting team efforts. In-person meetings
will occur typically for 2 ½ - 3 days most months (not including travel time) and meetings will take
place in different parts of North America. When not meeting in person, regularly scheduled

conference calls will be used to conduct drafting team work. Outside the scheduled meetings,
individuals or subgroups will have additional preparation and support work such as researching and
developing proposed concepts, reviewing proposals, compiling comments and drafting responses, etc.
Lastly, outreach is an important component of this drafting team’s effort. Members of the team are
expected to interact with other stakeholders during the revision development process.

Name:
Organization:
Address:

Telephone:
E-mail:
Please briefly describe your experience and qualifications to serve on the requested Standard
Drafting Team (Bio):

If you are currently a member of any NERC drafting team, please list each team here:
Not currently on any active SAR or standard drafting team.
Currently a member of the following SAR or standard drafting team(s):
If you previously worked on any NERC drafting team please identify the team(s):
No prior NERC SAR or standard drafting team.
Prior experience on the following team(s):
Select each NERC Region in which you have experience relevant to the Project for which you are
volunteering:
FRCC
MRO
NPCC

RF
SERC
SPP RE

Texas RE
WECC
NA – Not Applicable

Select each Industry Segment that you represent:
1 — Transmission Owners

Unofficial Nomination Form
Project 2016-02 Modifications to CIP Standards | March 2016

2

2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, and Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations and Regional Entities
NA – Not Applicable
Select each Function 1 in which you have current or prior expertise:
Balancing Authority
Compliance Enforcement Authority
Distribution Provider
Generator Operator
Generator Owner
Interchange Authority
Load-serving Entity
Market Operator
Planning Coordinator

Transmission Operator
Transmission Owner
Transmission Planner
Transmission Service Provider
Purchasing-selling Entity
Reliability Coordinator
Reliability Assurer
Resource Planner

Provide the names and contact information for two references who could attest to your technical
qualifications and your ability to work well in a group:

1

Name:

Telephone:

Organization:

E-mail:

Name:

Telephone:

Organization:

E-mail:

These functions are defined in the NERC Functional Model, which is available on the NERC web site.

Unofficial Nomination Form
Project 2016-02 Modifications to CIP Standards | March 2016

3

Provide the name and contact information of your immediate supervisor or a member of your
management who can confirm your organization’s willingness to support your active participation.
Name:

Telephone:

Title:

Email:

Unofficial Nomination Form
Project 2016-02 Modifications to CIP Standards | March 2016

4

Standards Announcement

Project 2016-02 Modifications to CIP Standards

Supplemental Nomination Period Open through March 23, 2016
Now Available

Nominations are being sought for additional standard drafting team (SDT) members through 8 p.m.
Eastern, Wednesday, March 23, 2016.
Use the electronic form to submit a nomination. If you experience any difficulties in using the electronic
form, contact Wendy Muller. An unofficial Word version of the nomination form is posted on the Standard
Drafting Team Vacancies page and the project page.
By submitting a nomination form, you are indicating your willingness and agreement to actively participate
in face-to-face meetings and conference calls.
Previous drafting or review team experience is beneficial, but not required.
The time commitment for this project is expected to be significant. Participants should anticipate an
average workload of 20 hours per week devoted to the SDT efforts. In person meetings will occur typically
for 2 ½ - 3 days most months (not including travel time) and meetings will take place in different parts of
North America. When not meeting in person, regularly scheduled conference calls will be used to conduct
drafting team work. Outside the scheduled meetings, individuals or subgroups will have additional
preparation and support work such as researching and developing proposed concepts, reviewing
proposals, compiling comments and drafting responses, etc. Lastly, outreach is an important component of
this SDT’s effort. Members of the team are expected to interact with other stakeholders during the
revision development process.
See the project page and unofficial nomination form for more information.
Next Steps

The Standards Committee is expected to appoint members to the team in April 2016. Nominees will be
notified shortly after they have been appointed.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact either Senior Standards Developer, Stephen Crutchfield at
(609) 651-9455 or Al McMeekin at (404) 446-9675.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326

404-446-2560 | www.nerc.com

Standards Announcement | Solicitation of Drafting Team Nominations
Project 2015-10 Single Points of Failure SAR | November 2015

2

Standards Authorization Request Form
NERC welcomes suggestions to improve the reliability
of the bulk power system through improved reliability
standards. Please use this form to submit your request
to propose a new or a revision to a NERC’s Reliability
Standard.

When completed, email this form to:

[email protected]

Request to propose a new or a revision to a Reliability Standard
Title of Proposed Standard(s):

Modifications to CIP Standards

Date Submitted:

March 9, 2016

SAR Requester Information
Name:

Stephen Crutchfield

Organization:

NERC

Telephone:

609-651-9455

E-mail:

[email protected]

SAR Type (Check as many as applicable)
New Standard

Withdrawal of existing Standard

Revision to existing Standard

Urgent Action

SAR Information
Purpose (Describe what the standard action will achieve in support of Bulk Electric System reliability.):
The purpose of this project is to (1) consider the Version 5 Transition Advisory Group (V5TAG) issues
identified in the CIP V5 Issues for Standard Drafting Team Consideration (V5TAG Transfer Document)
and (2) address the Federal Energy Regulatory Commission (Commission) directives contained in Order
822. These revisions will increase reliability and security to the Bulk-Power System (BPS) by enhancing
cyber protection of BPS facilities.
Industry Need (What is the industry problem this request is trying to solve?):
The V5TAG, which consists of representatives from NERC, Regional Entities, and industry stakeholders,
was formed to issue guidance regarding possible methods to achieve compliance with the CIP version 5
standards and to support industry’s implementation activities. During the course of the V5TAG’s
activities, the V5TAG identified certain issues with the CIP Reliability Standards that were more
appropriately addressed by the existing standard drafting team (SDT) for the CIP Reliability Standards.

SAR Information
The V5 TAG developed the V5TAG Transfer Document to explain the issues and recommend that the
SDT consider them in future development activity.
On January 21, 2016, the Commission issued Order No. 822 approving revisions to the CIP version 5
standards and also directing NERC to develop modifications to address:
• Protection of transient electronic devices used at low-impact BES Cyber Systems;
• Protections for communication network components between control centers; and
• Refinement of the Low Impact External Routable Connectivity (LERC) definition.
The Commission did not provide a date by which the modifications for transient devices or
communication networks must be completed. For the LERC definition, however, the Commission
directed that NERC submit the modification within one year of the effective date of Order No. 822
(March 31, 2017).
Brief Description (Provide a paragraph that describes the scope of this standard action.)
The proposed project will consider the issues raised by the V5TAG in the V5TAG Transfer Document and
will address the Commission directives in Order No. 822 through modifications to the CIP standards. The
work will include development of Violation Risk Factors, Violation Severity Levels, and an
Implementation Plan for the modified standards and will meet the deadlines established by the
Commission in Order No. 822.
Detailed Description (Provide a description of the proposed project with sufficient details for the
standard drafting team to execute the SAR. Also provide a justification for the development or revision
of the standard, including an assessment of the reliability and market interface impacts of implementing
or not implementing the standard action.)
As stated above, the purpose of this project is to consider the V5TAG issues in the initial transfer
document V5TAG Transfer Document and address the Commission directives contained in Order 822.
For the directive on the LERC definition, the project is to respond within the deadline required in the
order.
As noted above, the V5TAG identified specific issues with the CIP V5 standards. The V5TAG drafted the
V5TAG Transfer Document to formally recommend that the SDT address these issues during standards
development to consider whether modifications can be made to the standard language. As outlined in
the V5TAG Transfer Document, the specific issues are as follows:
• Cyber Asset and BES Cyber Asset (BCA) Definitions – as foundational definitions within the CIP V5
standards, the understanding of Cyber Asset and BCA terms impacts the scope of the applicable
requirements. The V5TAG recommends the following enhancements:
• Clarify the intent of “programmable” in Cyber Asset.
• Clarify and focus the definition of “BES Cyber Asset” including:

Project 2016-02 Modifications to CIP Standards
March 9, 2016

2

SAR Information
Focusing the definition so that it does not subsume all other cyber asset types.
Considering a lower bound to the term ‘adverse’ in “adverse impact”.
Clarifying the double impact criteria (cyber asset affects a facility and that facility
affects the reliable operation of the BES) such that “N-1 contingency” is not a
valid methodology that can eliminate an entire site and all of its Cyber Assets
from scope.
Network and Externally Accessible Devices – V5TAG recommends improving clarity within the
concepts and requirements concerning Electronic Security Perimeters (ESP), External Routable
Connectivity (ERC), and Interactive Remote Access (IRA) including:
• The 4.2.3.2 exemption phrase “between discrete Electronic Security Perimeters”
• The meaning of the word ‘associated’ in the ERC definition.
• The applicability of ERC including the concept of the term “directly” used in the phrase
“cannot be directly accessed through External Routable Connectivity” within the
Applicability section.
• The IRA definition placement of the phrase “using a routable protocol” in the definition
and with respect to Dial-up Connectivity.
• The Guidelines and Technical Basis sentence, “If dial-up connectivity is used for
Interactive Remote Access, then Requirement R2 also applies.”
Transmission Owner (TO) Control Centers Performing Transmission Operator (TOP) Obligations –
V5TAG is aware of multiple interpretations of the language “used to perform the functional
obligation of” in CIP-002-5.1 Attachment 1, section 2.12 and recommends clarification of:
• The applicability of requirements on a TO Control Center that performs the functional
obligations of a TOP, particularly if the TO has the ability to operate switches, breakers
and relays in the BES.
• The definition of Control Center.
• The language scope of “perform the functional obligations of” throughout the
Attachment 1 criteria.
Virtualization – The CIP V5 standards do not specifically address virtualization. Because of the
increasing use of virtualization in industrial control system environments, V5TAG asked that the
SDT consider CIP-005 and the definitions of Cyber Asset and Electronic Access Point regarding
permitted architecture and the security risks of network, server and storage virtualization
technologies.




•

•

•

The SDT shall also address the Order No. 822 directives by developing modifications to requirements in
CIP standards and the definition of LERC. The Commission directed the following:
•

Per paragraph 32, “...we direct that NERC, pursuant to section 215(d)(5) of the FPA, develop
modifications to the CIP Reliability Standards to provide mandatory protection for transient
devices used at Low Impact BES Cyber Systems based on the risk posed to bulk electric system
reliability. While NERC has flexibility in the manner in which it addresses the Commission’s
concerns, the proposed modifications should be designed to effectively address the risks posed by

Project 2016-02 Modifications to CIP Standards
March 9, 2016

3

SAR Information

•

•

transient devices to Low Impact BES Cyber Systems in a manner that is consistent with the riskbased approach reflected in the CIP version 5 Standards.”
Per paragraph 53, “…the Commission concludes that modifications to CIP-006-6 to provide
controls to protect, at a minimum, communication links and data communicated between bulk
electric system Control Centers are necessary in light of the critical role Control Center
communications play in maintaining bulk electric system reliability. Therefore, we adopt the
NOPR proposal and direct that NERC, pursuant to section 215(d)(5) of the FPA, develop
modifications to the CIP Reliability Standards to require responsible entities to implement
controls to protect, at a minimum, communication links and sensitive bulk electric system data
communicated between bulk electric system Control Centers in a manner that is appropriately
tailored to address the risks posed to the bulk electric system by the assets being protected (i.e.,
high, medium, or low impact).”
Per paragraph 73, “…the Commission concludes that a modification to the Low Impact External
Routable Connectivity definition to reflect the commentary in the Guidelines and Technical Basis
section of CIP-003-6 is necessary to provide needed clarity to the definition and eliminate
ambiguity surrounding the term “direct” as it is used in the proposed definition. Therefore,
pursuant to section 215(d)(5) of the FPA, we direct NERC to develop a modification to provide the
needed clarity, within one year of the effective date of this Final Rule….“

Reliability Functions
The Standard will Apply to the Following Functions (Check each one that applies.)
Regional Reliability
Organization

Conducts the regional activities related to planning and operations, and
coordinates activities of Responsible Entities to secure the reliability of
the Bulk Electric System within the region and adjacent regions.

Reliability Coordinator

Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.

Balancing Authority

Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area and
supports Interconnection frequency in real time.

Project 2016-02 Modifications to CIP Standards
March 9, 2016

4

Reliability Functions
Interchange Authority

Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority Areas.

Planning Coordinator

Assesses the longer-term reliability of its Planning Coordinator Area.

Resource Planner

Develops a >one year plan for the resource adequacy of its specific loads
within a Planning Coordinator area.

Transmission Planner

Develops a >one year plan for the reliability of the interconnected Bulk
Electric System within its portion of the Planning Coordinator area.

Transmission Service
Provider

Administers the transmission tariff and provides transmission services
under applicable transmission service agreements (e.g., the pro forma
tariff).

Transmission Owner

Owns and maintains transmission facilities.

Transmission
Operator

Ensures the real-time operating reliability of the transmission assets
within a Transmission Operator Area.

Distribution Provider

Delivers electrical energy to the End-use customer.

Generator Owner

Owns and maintains generation facilities.

Generator Operator

Operates generation unit(s) to provide real and Reactive Power.

Purchasing-Selling
Entity

Purchases or sells energy, capacity, and necessary reliability-related
services as required.

Market Operator

Interface point for reliability functions with commercial functions.

Load-Serving Entity

Secures energy and transmission service (and reliability-related services)
to serve the End-use Customer.

Reliability and Market Interface Principles
Applicable Reliability Principles (Check all that apply).
1. Interconnected bulk power systems shall be planned and operated in a coordinated manner
to perform reliably under normal and abnormal conditions as defined in the NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled within
defined limits through the balancing of real and Reactive Power supply and demand.

Project 2016-02 Modifications to CIP Standards
March 9, 2016

5

Reliability and Market Interface Principles
3. Information necessary for the planning and operation of interconnected bulk power systems
shall be made available to those entities responsible for planning and operating the systems
reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power systems
shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and maintained
for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems shall be
trained, qualified, and have the responsibility and authority to implement actions.
7. The security of the interconnected bulk power systems shall be assessed, monitored and
maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Does the proposed Standard comply with all of the following Market Interface
Principles?
1. A reliability standard shall not give any market participant an unfair competitive
advantage.
2. A reliability standard shall neither mandate nor prohibit any specific market
structure.
3. A reliability standard shall not preclude market solutions to achieving compliance
with that standard.
4. A reliability standard shall not require the public disclosure of commercially
sensitive information. All market participants shall have equal opportunity to
access commercially non-sensitive information that is required for compliance
with reliability standards.

Enter
(yes/no)
YES
YES
YES
YES

Related Standards
Standard No.

Project 2016-02 Modifications to CIP Standards
March 9, 2016

Explanation

6

Related SARs
SAR ID

Explanation

Regional Variances
Region

Explanation

FRCC
MRO
NPCC
RF
SERC
SPP RE
Texas
RE
WECC

Project 2016-02 Modifications to CIP Standards
March 9, 2016

7

Unofficial Comment Form

Project 2016-02 Modifications to CIP Standards
Standards Authorization Request (SAR)
Do not use this form for submitting comments. Use the electronic form to submit comments on the
Project 2016-02 Modifications to CIP Standards SAR. The electronic comment form must be submitted by
8 p.m. Eastern, Thursday, April 21, 2016.
Documents and information about this project are available on the Project 2016-02 Modifications to CIP
Standards. If you have questions, contact either Senior Standards Developer, Stephen Crutchfield at (609)
651-9455 or Al McMeekin at (404) 446-9675.
Background Information

On January 21, 2016, FERC issued Order No. 822, Revised Critical Infrastructure Protection Reliability
Standards, approving seven CIP Reliability Standards and new or modified definitions. FERC also directed
NERC to develop modifications to address:
•

Protection of transient electronic devices used at low-impact bulk electric system cyber systems;

•

Protections for communication network components between control centers; and

•

Refinement of the definition for Low Impact External Routable Connectivity (LERC)

FERC directed NERC to submit new or modified standards responding to the directives related to the
definition of LERC by March 30, 2016, one year from the effective date of Order No. 822. FERC did not
place any time frame for NERC to respond to the remaining directives.
The CIP Version 5 Transition Advisory Group (V5 TAG) transferred issues to the CIP Version 5 Standard
Drafting Team (SDT) that were identified during the industry transition to implementation of the CIP
Version 5 Standards. Specifically, the issues that the SDT will address are:
•

Cyber Asset and BES Cyber Asset Definitions

•

Network and Externally Accessible Devices

•

Transmission Owner Control Centers Performing Transmission Operator Obligations

•

Virtualization

On March 9, 2016, the NERC Standards Committee accepted and authorized the posting of the
Modifications to CIP Standards SAR. It is posted for a 30-day informal comment period because it is
addressing FERC directives.

Questions

1. Do you agree with the scope and objectives of this SAR? If not, please explain why you do not agree,
and, if possible, provide specific language revisions that would make it acceptable to you.
Yes:
No:
Comments:
2. Are you aware of any Canadian provincial or other regulatory requirements that may need to be
considered during this project in order to develop a continent-wide approach to the standards? If yes,
please identify the jurisdiction and specific regulatory requirements.
Yes:
No:
Comments:
3. Are there any other concerns with this SAR that haven’t been covered in previous questions?
Yes:
No:
Comments:

Unofficial Comment Form | Project 2016-02 Modifications to CIP Standards
Standard Authorization Request | March 21, 2016

2

CIP V5 Issues for Standard Drafting Team Consideration
September 15, 2015

From experience in the V5 Transition Study and the on-going implementation efforts, the CIP Version 5
Transition Advisory Group (V5TAG) identified specific issues with the CIP Version 5 standard language that
caused difficulty in implementation of the requirements. In many cases, the V5TAG members found that
select language within the CIP Version 5 standards may be understood in multiple ways. These
interpretations appear to go beyond the intended flexibility of the standard language that is necessary to
accommodate the diverse nature of facts and circumstances across the electric sector. At this time, the
V5TAG proposes the following issues to be addressed by the CIP V5 Revisions drafting team (SDT) or other
appropriate team for standards development:
•

Cyber Asset and BES Cyber Asset definitions
The foundational definition for the CIP Version 5 standards is ‘Cyber Assets.’ When Cyber
Assets meet a threshold of Bulk Electric System (BES) impact they become ‘BES Cyber Assets
(BCA)’ which are grouped, by a Responsible Entity, into ‘BES Cyber Systems (BCS).’ Viewing
BCAs too broadly can lead to many thousands of devices in the typical utility becoming an
administrative burden for which few if any cyber security controls can actually be applied or
where there is limited associated cyber security risk. Vast amounts of effort would be
expended for these types of cyber assets to track and document their lack of capability for
even the most basic cyber security controls. Viewing BCAs too narrowly could lead to
missing consideration of devices that have a sufficient level of cyber capability and risk
impact.
The SDT should consider the definition of Cyber Asset and clarify the intent of “programmable” by
considering such factors as if a device is merely configurable, its executable code is not field
upgradable, or if its functionality can only be changed via physical DIP switches, swapping internal
chips, etc.
The SDT should consider clarifying and focusing the definition of “BES Cyber Asset” including:
a. Focusing the definition so that it does not subsume all other cyber asset types. Protected
Cyber Assets (PCA), by nature of being on the same network, can have some form of
adverse impact if misused. Electronic Access Control or Monitoring Systems (EACMS) if
misused or unavailable can have some form of adverse impact. This can result in a “hall of

mirrors” effect where everything in or that creates an Electronic Security Perimeter (ESP)
also meets the BCA definition.
b. Considering if there is a lower bound to the term ‘adverse’ in “adverse impact”. For
example, is the focus of a typical generating unit the servers and operator human machine
interfaces (HMI) and controller cabinets and Programmable Logic Controllers (PLCs) or is it
the thousands of individual sensors and transmitters throughout the plant?
c. Clarify the double impact criteria (cyber asset affects a facility and that facility affects the
reliable operation of the BES) such that “N-1 contingency” is not a valid methodology that
can eliminate an entire site and all of its Cyber Assets from scope.
•

Network and Externally Accessible Devices (ERC, ESP, IRA)
The SDT should consider the concepts and requirements concerning Electronic Security Perimeters
(ESP), External Routable Connectivity (ERC), and Interactive Remote Access (IRA) including:
a. Clarify the 4.2.3.2 exemption phrase “between discrete Electronic Security Perimeters.”
When there is not an ESP at the location, consider clarity that the communication
equipment considered out of scope is the same communication equipment that would be
considered out of scope if it were between two ESPs.
b. The word ‘associated’ in the ERC definition is unclear in that it alludes to some form of
relationship but does not define the relationship between the items. Striking ‘associated’
and defining the intended relationship would provide much needed clarity.
c. Review of the applicability of ERC including the concept of the term “directly” used in the
phrase “cannot be directly accessed through External Routable Connectivity” within the
Applicability section. As well, consider the interplay between IRA and ERC.
d. Clarify the IRA definition to address the placement of the phrase “using a routable
protocol” in the definition and clarity with respect to Dial-up Connectivity.
e. Address the Guidelines and Technical Basis sentence, “If dial-up connectivity is used for
Interactive Remote Access, then Requirement R2 also applies.”

•

Transmission Owner (TO) Control Centers Performing Transmission Operator (TOP) Obligations
CIP-002-5.1 Attachment 1 – Impact Reliability Criteria, sections 1.1, 1.2, 1.3, 1.4, 2.11, 2.12, and
2.13 employ the language “used to perform the functional obligation of”, and then lists the
functional registration. It was intended that this caveat would capture entities that perform
obligations of a specific registered function, whether they are registered for that function or not.
However, this language has caused confusion, especially in section 2.12 concerning TOP Control
Centers. The term “functional obligation” may be interpreted to have different meaning in a
variety of situations.

CIP Version 5 Memo Issues

2

One interpretation is for the defined term Control Center to be strictly associated with the
Balancing Authority (BA), Generator Operator (GOP), Reliability Coordinator (RC), and
Transmission Operator (TOP) functional registrations, and that control rooms or dispatch centers
owned and operated by Transmission Owners (TOs) with control of limited BES facilities would be
excluded. A second interpretation may expand or contract the applicability of the Control Center
designation, based on criteria that may not take into consideration overall risk to reliable
operations of the BES.
Early analysis found the potential for TOs (not Registered as TOPs) that only operate limited
breakers to be pulled in as medium impact Control Centers, even if the few Facilities they control
are low impact. (For example, an entity with one 161kV breaker in one substation and a second
161kV breaker in a different substation, both breakers associated with low impact Facilities.) As
currently written, low impact Control Centers are to be identified per criteria 3.1 and could be
commensurate with risk for these scenarios.
Areas for the SDT to address are:
a. CIP-002-5.1, Attachment 1 Control Center criteria for additional clarity and for possible
revisions related to TOP or TO Control Centers performing the functional obligations of a
TOP, in particular for small or lower-risk entities. A potential revision could be a size for
criteria 2.12, Control Centers performing the functional obligations of a TOP.
b. Clarify the applicability of requirements on a TO Control Center that perform the functional
obligations of a TOP, particularly if the TO has the ability to operate switches, breakers and
relays in the BES. Review the corresponding Guidelines and Technical Basis of CIP-002-5.1,
specifically: the “CIP-002-5” section paragraph starting with “Responsibility for the reliable
operation of the BES is spread across all Entity Registrations”; the table following that
paragraph; the “High Impact Rating (H)” section; and the criterion bullets for Control
Centers under the “Medium Impact Rating (M)” section.
c. The definition of Control Center (if pursued, recognize possible impacts on operations and
planning standards and/or glossary terms that include ‘Control Center’, for example, the
revised Glossary term for “System Operator” to be effective July 1, 2016).
d. The language scope of “perform the functional obligations of” throughout the Attachment
1 criteria.
•

Virtualization
The CIP Version 5 standards do not specifically address virtualization. However, because of the
increasing use of virtualization in industrial control system environments, questions around
treatment of virtualization within the CIP Standards are due for consideration.

CIP Version 5 Memo Issues

3

The SDT should consider revisions to CIP-005 and the definitions of Cyber Asset and Electronic
Access Point that make clear the permitted architecture and address the security risks of network,
server and storage virtualization technologies.

The transition to CIP Version 5 continues as the compliance deadline of April 1, 2016 approaches. The
V5TAG continues to discuss challenging issues being undertaken during the on-going implementation.
The group may find additional issues to transfer to the SDT for consideration.

CIP Version 5 Memo Issues

4

Standards Announcement

Project 2016-02 Modifications to CIP Standards
Standards Authorization Request
Informal Comment Period Open through April 21, 2016
Now Available

A 30-day informal comment period for the Project 2016-02 Standard Authorization Request (SAR), is
open through 8 p.m. Eastern, Thursday, April 21, 2016.
Commenting

Use the electronic form to submit comments on the SAR. If you experience any difficulties in using the
electronic form, contact Wendy Muller. An unofficial Word version of the comment form is posted on
the project page.
If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential error
messages, or system lock-out, contact NERC IT support directly at https://support.nerc.net/ (Monday –
Friday, 8 a.m. - 8 p.m. Eastern).
Next Steps

The drafting team will consider all responses received during the comment period and determine the
next steps of the project
For more information on the Standards Development Process, refer to the Standard Processes
Manual.
For more information or assistance, contact either Senior Standards Developer, Stephen Crutchfield at
(609) 651-9455 or Al McMeekin at (404) 446-9675.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Comment

Comments
Received Report
Project Name:

2016-02 Modifications to CIP Standards SAR

Comment Period Start Date:

3/23/2016

Comment Period End Date:

4/21/2016

Associated Ballots:

There were 33 sets of responses, including comments from approximately 33 different people from approximately 32 companies
representing 9 of the Industry Segments as shown in the table on the following pages.

Questions
1. Do you agree with the scope and objectives of this SAR? If not, please explain why you do not agree, and, if possible, provide specific
language revisions that would make it acceptable to you.

2. Are you aware of any Canadian provincial or other regulatory requirements that may need to be considered during this project in order to
develop a continent-wide approach to the standards? If yes, please identify the jurisdiction and specific regulatory requirements.

3. Are there any other concerns with this SAR that haven’t been covered in the previous questions?

Organization
Name

Name

Florida
Chris Gowder
Municipal
Power Agency

Segment(s)

3,4,5,6

Region

FRCC

Group Name

FMPA

Group Member
Name

Group
Member
Organization

Group
Member
Segment(s)

Group Member
Region

Tim Beyrle

Florida
4
Municipal
Power Agency

FRCC

Jim Howard

Florida
5
Municipal
Power Agency

FRCC

Lynne Mila

Florida
4
Municipal
Power Agency

FRCC

Javier Cisneros

Florida
3
Municipal
Power Agency

FRCC

Randy Hahn

Florida
3
Municipal
Power Agency

FRCC

Don Cuevas

Florida
1
Municipal
Power Agency

FRCC

Stan Rzad

Florida
4
Municipal
Power Agency

FRCC

Matt Culverhouse Florida
3
Municipal
Power Agency

FRCC

Tom Reedy

Florida
6
Municipal
Power Agency

FRCC

Steve Lancaster

Florida
3
Municipal
Power Agency

FRCC

Mike Blough

Florida
5
Municipal
Power Agency

FRCC

Mark Brown

Florida
4
Municipal
Power Agency

FRCC

Duke Energy

Southwest
Power Pool,
Inc. (RTO)

Southern
Company Southern
Company
Services, Inc.

Colby Bellville

Jason Smith

1,3,5,6

2

Pamela Hunter 1,3,5,6

FRCC,RF,SERC Duke Energy

Chris Adkins

Florida
3
Municipal
Power Agency

FRCC

Ginny Beigel

Florida
9
Municipal
Power Agency

FRCC

Doug Hils

Duke Energy

1

RF

Lee Schuster

Duke Energy

3

FRCC

Dale Goodwine

Duke Energy

5

SERC

Greg Cecil

Duke Energy

6

RF

2

SPP RE

MRO,SERC,SPP SPP
Shannon Mickens Southwest
RE,WECC
Standards
Power Pool,
Inc. (RTO)
Review Group

SERC

Southern
Company

Jason Smith

Southwest
Power Pool,
Inc. (RTO)

2

SPP RE

Ellen Watkins

Southwest
Power Pool,
Inc. (RTO)

1

SPP RE

Terri Pyle

Southwest
Power Pool,
Inc. (RTO)

1,3,5,6

SPP RE

Mike Buyce

Southwest
Power Pool,
Inc. (RTO)

1,4

SPP RE

Robert A.
Schaffeld

Southern
1
Company Southern
Company
Services, Inc.

SERC

R. Scott Moore

Southern
3
Company Southern
Company
Services, Inc.

SERC

William D. Shultz

Southern
5
Company Southern
Company
Services, Inc.

SERC

Northeast
Power
Coordinating
Council

Ruida Shu

1,2,3,4,5,6

NPCC

RSC No
Dominion

John J. Ciza

Southern
6
Company Southern
Company
Services, Inc.

SERC

Paul Malozewski

Northeast
Power
Coordinating
Council

1

NPCC

Guy Zito

Northeast
Power
Coordinating
Council

NA - Not
Applicable

NPCC

Brian Shanahan

Northeast
Power
Coordinating
Council

1

NPCC

Rob Vance

Northeast
Power
Coordinating
Council

1

NPCC

Mark J. Kenny

Northeast
Power
Coordinating
Council

1

NPCC

Gregory A.
Campoli

Northeast
Power
Coordinating
Council

2

NPCC

Randy MacDonald Northeast
Power
Coordinating
Council

2

NPCC

Wayne Sipperly

Northeast
Power
Coordinating
Council

4

NPCC

David
Ramkalawan

Northeast
Power
Coordinating
Council

4

NPCC

Glen Smith

Northeast
Power
Coordinating
Council

4

NPCC

Brian O'Boyle

Northeast
Power
Coordinating
Council

5

NPCC

Brian Robinson

Northeast
Power
Coordinating
Council

5

NPCC

Bruce Metruck

Northeast
Power
Coordinating
Council

6

NPCC

Alan Adamson

Northeast
Power
Coordinating
Council

7

NPCC

Michael Jones

Northeast
Power
Coordinating
Council

3

NPCC

Michael Forte

Northeast
Power
Coordinating
Council

1

NPCC

Kelly Silver

Northeast
Power
Coordinating
Council

3

NPCC

Brian O'Boyle

Northeast
Power
Coordinating
Council

5

NPCC

Edward Bedder

Northeast
Power
Coordinating
Council

1

NPCC

David Burke

Northeast
Power

3

NPCC

Coordinating
Council

Colorado
Springs
Utilities

Shannon Fair

1,3,5,6

Colorado
Springs
Utilities

Peter Yost

Northeast
Power
Coordinating
Council

4

NPCC

Helen Lainis

Northeast
Power
Coordinating
Council

2

NPCC

Michele Tondalo

Northeast
Power
Coordinating
Council

1

NPCC

Kathleen
Goodman

Northeast
Power
Coordinating
Council

2

NPCC

Silvia Parada
Mitchell

Northeast
Power
Coordinating
Council

4

NPCC

Sylvain Clermont

Northeast
Power
Coordinating
Council

1

NPCC

Si Truc Phan

Northeast
Power
Coordinating
Council

2

NPCC

Kaleb Brimhall

Colorado
Springs
Utilities

5

WECC

Charlie Morgan

Colorado
Springs
Utilities

3

WECC

Shawna Speer

Colorado
Springs
Utilities

1

WECC

Shannon Fair

Colorado
Springs
Utilities

6

WECC

1. Do you agree with the scope and objectives of this SAR? If not, please explain why you do not agree, and, if possible, provide specific
language revisions that would make it acceptable to you.
Bob Reynolds - Southwest Power Pool Regional Entity - 10
Answer

No

Document Name
Comment
The SPP RE respectfully submits the following eight comments to the Project 2016-02 Standards Authorization Request: (1) With respect to clarifying or
revising the definition of Cyber Asset, consider including misuse of the Programmable Electronic Device through misconfiguration or reconfiguration of
the device in the instance that its behavior is affected and its altered behavior impacts the associated Facility. Consider the risk of misuse (i.e., how
would someone misconfigure or reconfigure the device to cause undesired behavior) as appropriate. (2) With respect to clarifying or revising the
definition of External Routable Connectivity (ERC), consider the point in the communication path at which a conversion from routable to non-routable
communication protocol occurs. Is ERC only established if the conversion occurs in the same asset as the BES Cyber Asset or can ERC be
established if the conversion occurs at the remote end of the communication path (e.g., conversion at the Control Center for communication to a serially
connected relay in a substation)? Consider whether ERC exists only if the conversion occurs outside of an established ESP (i.e., there is no ERC if the
device performing the conversion is inside an ESP and protected per the CIP Standards). (3) With respect to CIP-002-5.1, Impact Rating Criteria 3.2
and 3.3, clarify that the Low Impact BES Cyber Systems are associated with Facilities located within the asset as opposed to being associated with the
asset itself. The opening statement in Section 3 of the Impact Rating Criteria states "BES Cyber Systems not included in Sections 1 or 2 above that are
associated with any of the following assets…" The SPP RE has already been presented with an argument that flow meters in a substation are not BES
Cyber Assets because they are associated with a Transmission line and not the Transmission station or substation cited in Impact Rating Criterion
3.2. (4) With respect to Tie Line and other Transmission line flow meters, these Cyber Assets appear to have been unintentionally excluded from
consideration under CIP-002-5.1, Impact Rating Criterion 2.5. Impact Rating Criterion 2.5 excludes consideration of BES Cyber Assets associated with
Transmission lines through its use of "operating between 200 kV and 499 kV at a single station or substation" language. In the instance where the tie
line or other flow meter is associated with a Transmission Line operated between 200 and 499 KV in a substation that satisfies the qualifications of
Impact Rating Criterion 2.5, the meter will be excluded and not be categorized as Medium Impacting. Additionally, some entities are proffering the
argument that the flow meter is not a BES Cyber Asset because its loss or misuse will not affect the reliable operation of the Transmission Facilities in
the substation where the meter resides, overlooking the impact the loss of meter information may have on Control Center operations including ACE
calculation, security-constrained generation dispatch, AGC, and Situational Awareness. An additional Criterion, specific to Transmission line flow
meters, may be required to address this issue. (5) With respect to Physical Security Perimeters and their associated Requirements, clarification is
needed regarding the concept of zoned access within a defined PSP. Specifically, is it acceptable to define an overarching PSP and then establish
areas of access control within the defined PSP where BES Cyber Systems are present and for which different access permissions are established? For
example, can a building containing a Control Center and its associated data center be declared a single PSP while access controls are established that
do not permit all personnel with authorized unescorted access into the building to have authorized unescorted access into one or more access control
zones within the building (e.g., the data center). And, if the zoned access areas are deemed to be independent PSPs, would the application of CIP-0066 R1 Part 1.3 require two access controls to enter the interior PSP containing High Impact BES Cyber Systems, or would the requirement for two
access controls to enter the outer (building) PSP suffice such that a single access control is permitted for the interior PSPs? (6) In consideration of the
results of the investigation of the Ukraine cyberattack, the SPP RE recommends that Cyber Assets outside of the ESP with a machine-to-machine
connection to a Cyber Asset inside the ESP be subjected to the same controls as the Intermediate System. There is a gap in the Standards today
whereby a communication protocol typically used for interactive access (e.g., FTP, SSH, web services) can also be used for system-to-system
communication. While Interactive Remote Access requires the use of an Intermediate System, encryption, and multi-factor authentication to the

Intermediate System, system-to-system communication using the exact same protocols do not require such controls. The Electronic Access Point
cannot tell the difference, thus a successful compromise of the Cyber Asset residing outside of the ESP affords the attacker trusted access into the
ESP. (7) In consideration of the results of the investigation of the Ukraine cyberattack, the SPP RE recommends the Standards Drafting Team consider
whether essential support systems (UPS, PBX/VOIP phone, fire suppression, emergency generation) should be afforded certain protective controls to
mitigate the risk that a successful attack directed at the support systems would adversely impact the asset containing BES Cyber Systems. For
example, one element of the Ukraine attack was directed at a network-connected Uninterruptible Power Supply, removing power from essential Cyber
Assets. (8) The SPP RE understands that a number of Requests for Interpretation have been submitted against CIP Version 5. While NERC staff has
stated publicly that the RFIs would be addressed by the Standards Drafting team, there is no mention of RFIs in the Standards Authorization
Request. To the extent that there are RFIs not included in either the Order 822 or V5TAG items, the Standards Authorization Request should state that
pending RFIs will be considered and addressed in any revisions to the CIP standards.
Likes

0

Dislikes

0

Response

Steven Parker - EnergySec - NA - Not Applicable - NA - Not Applicable
Answer

No

Document Name
Comment
We recommend that the term, Adverse Impact, contained within the BES Cyber Asset definition be itself added as a defined Glossary term. Any attempt
to clarify this phrase by adding language within the BES Cyber Asset definition is likely to complicate, rather than simplify, understanding of the term.
The current outstanding Requests For Interpretation should be added as issues to be addressed by the Standards Drafting Team under this SAR. Per
the Standards Process Manual, Section 7, Interpretations “shall stand until such time as the Interpretation can be incorporated into a future revision of
the Reliability Standard.” Although this statement does not directly apply to the currently open, and unresolved, Requests for Interpretation, we believe
the most logical approach would be to address the identified issues via this SAR rather than a separate interpretation development effort.
We recommend that the scope of the SAR be expanded to address the increasing use of 3rd party (i.e. cloud) services. Numerous utilities are
leveraging new capabilities available from 3rd party providers in ways that enhance the overall security of the grid. Examples include cloud-based
vulnerability scanners, offsite log monitoring services, cloud-based malware analysis and threat detection, cloud-based network monitoring, and
colocation facilities. Unfortunately, the current standards are unduly prohibitive towards these services and as a result may be lowering the overall
security of the grid by discouraging the use of effective, cutting edge tools, techniques, and services. For example, CIP-006 requires EACMS devices to
be within a Physical Security Perimeter. It is not clear how, or if, this requirement can be met for cloud services. The SDT should review existing
language and add, modify, or remove language as needed to accommodate any such services that can be prudently deployed to enhance overall grid
security.
Likes
Dislikes

0
0

Response

Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer

No

Document Name
Comment
Xcel Energy has some concern that the SAR’s inclusion of communication network components between control centers could extend to cabling
between Control Centers. The inclusion of cabling between Control Centers would be in direct contrast to guidance in the CIP standards and the
authority granted in section 215(d)(5) of the FPA by asking entities to be held accountable for equipment they do not own. Communication networks
between discrete Electronic Security Perimeters (ESPs) have been excluded from the CIP standards. Additionally, it is unclear how physical protection
of cabling would afford any additional protection to networks already in compliance with the suite of CIP standards. Furthermore, the documentation of
any physical protection would be administratively burdensome without adding any additional protection.
If any requirement is to be added regarding cabling between Control Centers, we would encourage the drafting team to add it as logical controls such as
encryption or other such measures under CIP-005 and/or CIP-007. To require physical protection of equipment not owned by Registered Entities
seems in direct contrast to previous guidance, outside of the authority documented in section 215(d)(5) of the FPA and add administrate burden with
little value.
Likes

0

Dislikes

0

Response

Ginny Beigel - City of Vero Beach - 9
Answer

No

Document Name
Comment
See response to Question 3.
Likes

0

Dislikes
Response

0

Joe Tarantino - Sacramento Municipal Utility District - 1,3,4,5,6 - WECC
Answer

No

Document Name
Comment

SMUD respectfully suggests an addition to the objective for this SAR be modified to include addressing single points of failure in
communication networks and network equipment that meet the definition of the BCA where this equipment is outside of the ESP but
contained within the Facility.

Likes

0

Dislikes

0

Response

Maryclaire Yatsko - Seminole Electric Cooperative, Inc. - 1,3,4,5,6 - FRCC
Answer

No

Document Name
Comment
Seminole concurs with all items currently listed in the draft Standards Authorization Request. Seminole recommends that additional items should be
included in the SAR
The industry has received guidance from NERC’s Compliance Monitoring and Enforcement group in the form of Frequently Asked Questions and
Lessons Learned. These guidance items need to become formal Guidelines, with appropriate Technical Basis, and placed within the Standards and
approved by the NERC membership
Issues related to Shared Facilities that are not adequately addressed in the standards. Specifically, when multiple entities have BES Cyber Assets
residing at a shared location, there is no clear delineation of responsibility. Without defined responsibilities in the Standard, there is also no
documented process to determine who has responsibility and to document those responsibilities. CFRs, JROs, MOUs, and other contractual
agreements have been discussed as possible solutions to this issue. However, at a minimum, clear formal Guidelines should be added to CIP-0025.1. Additional guidance should be added where appropriate.
Based on experience of both the V5TAG and of entities preparing for the standards, it is clear that significant updates are needed to the Guidelines and
Technical Basis for all CIP Reliability Standards.

Based on these comments, Seminole recommends adding language to address the following items:

1. Guidelines and Technical Basis – As core information used by Entities to ensure a consistent understanding of requirements and based on
Lessons Learned by Entities, Reliability Standards CIP-002 through CIP-011 are authorized for modification by the Standards Development
Team and submitted for ballot to the NERC Ballot Body. These clarifications should minimally consider
i.

Lessons Learned and FAQs published by NERC and Regional Compliance

ii.

Items that may be determined unsupported by the standard and definitions (i.e. BES Reliability Operating Services); and

iii. Industry practices that have evolved from industry’s compliance efforts.
2. Paragraph 51 option - Option to consider removal of Requirement Parts in specific cases considering the same guidelines as those used in the
Paragraph 51 project.
3. Definitions of Low Impact External Routable Connectivity AND External Routable Connectivity - Consider modifying the definitions of
External Routable Connectivity and LERC to ensure consistent language and communication of both ERC and LERC definitions
4. Definitions of Cyber Asset, BES Cyber Asset (BCA), and BES Cyber System (BCS) – The SAR should also authorize changes to clarify
the definition of BES Cyber System, specifically whether BES Cyber Systems include any Cyber Asset type other than a BCA (such as PCA,
EACMS, PACS)
5. Measures and Audit Expectations - Using information provided by the NERC Compliance Monitoring group as one source of information, the
measures section of all requirements and requirements parts should be reviewed and updated as necessary to ensure that an entity who
provides the evidence listed in the measure is able to fully demonstrate compliance under normal circumstances.
6. Exceptional Circumstances - Recommend formalizing guidance for Exceptional Circumstances in a single location.
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Andrew Pusztai - American Transmission Company, LLC - 1
Answer

No

Document Name
Comment
ATC is a member of EEI and supports the comments submitted by the EEI CIP Standards Subgroup related to the draft SAR.
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Douglas Webb - Great Plains Energy - Kansas City Power and Light Co. - 1,3,5,6 - SPP RE
Answer

No

Document Name
Comment
The Edison Electric Institute (EEI) submitted comments relating to this SAR. Their comments address scope and objectives of the SAR for
consideration by the Standards Drafting Team. Kansas City Power & Light Company endorses and incorporates by reference the comments submitted
by EEI.
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Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6 - NPCC, Group Name RSC No Dominion
Answer

No

Document Name
Comment
Request that the scope of virtualization be expanded beyond only CIP-005. Want to remind the SDT that communications between Control Centers
usually involves third parties that tend to be outside of FERC’s jurisdiction.
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Ryan Walter - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Answer
Document Name

No

Comment
The phrase “control centers” in the “Industry Need” section which lists the FERC directives has not been capitalized. FERC Order 822 uses “bulk
electric system Control Centers” when speaking about this directive. Tri-State believes the SAR should use that same language used by FERC in order
to accurately represent what is expected to be in scope of this project.
There is also an error in the “Reliability Functions” section. “Transmission Service Provider” is checked off instead of “Distribution Provider”. The new
versions of the CIP standards do not include Transmission Service Providers, but do include the Distribution Providers.
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Mike Smith - Manitoba Hydro - 1,3,5,6
Answer

No

Document Name
Comment
Virtualization: Manitoba Hydro does not agree with NERC prescribing specific system architecture, technologies or designs. The SDT should continue to
focus on identifying requirements to meet specific security objectives for the virtualization.
Protections for communication network components between control centers: Please clarify the scope of Control Centers. Does it refer to the
communication links between all Control Centres cross entities such as the link between RC Control Center and TOP Control Centre or only the Control
Centers within the resposbile entity.
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Chris Gowder - Florida Municipal Power Agency - 3,4,5,6 - FRCC, Group Name FMPA
Answer
Document Name
Comment

No

FMPA is concerned that the Project 2016-02 SAR is too narrowly focused. There are a number of issues with the current CIP Standards, mostly
concentrated in CIP-002-5.1. The SAR should be written to allow the drafting team to consider how the suite of CIP standards work together. CIP-0025.1 is the foundation of the remainder of the CIP requirements. Narrowly scoping this SAR just prolongs dealing with these problems, and ties the
drafting team’s hands should they identify other concerns. Also, ignoring these issues now will cause more revisions, which in turn will add to the
pervasive confusion and uncertainty already surrounding the CIP standards. The industry needs clarity and resolution to these matters in order to be
assured their efforts to comply are effective and that companies understand their investments are going to the right places.
The following additional items should be considered by the SDT:
1) Section 4.2.2 states “All BES Facilities” as being subject to the standards for all Responsible Entities except for DP’s. This effectively negates the
rest of the requirements, as anything that qualifies as a “Cyber Asset” could not possibly be a “Facility” as well. The language is missing the “Cyber
Assets” component. Suggested language would be “Cyber Assets at all BES Facilities”.
2) Ownership isn’t properly accounted for in the requirements. Shared facilities (generally speaking substations) often involve multiple entities that
own equipment, who may or may not be Responsible Entities as described in CIP-002-5.1. There should be specific language requiring the owner of
the equipment to communicate with the owner of the Facility.
3) Clarify what is meant by “associated with” in the context of the Impact Rating Criteria in CIP-002-5.1 – Attachment 1. Clear up the inconsistencies
in the requirements between the use of “associated with” (criterion 2 & 3 in Attachment 1) in some areas and “used by and located at” (criterion 1 in
Attachment 1) in other parts. Have a process developed for ensuring entities notify if there are devices owned by a different entity that are “associated
with” their BESCS (for example, a meter that one entity needs for the reliable operation of their Control Center that isn’t owned by them).
4) Leasing equipment is a loophole in the requirements based on the language in section 4.2. This should be fixed so an entity isn’t able to lease
equipment and avoid meeting CIP requirements.
5) The scope of equipment applicable to CIP due to applicability to other NERC standards (such as CIP-002-5.1 Section 4.2.1.3) should be clarified
further. For example, a “Protection System” can be made up of multiple devices owned by multiple entities. If an entity owns a component of a
Protection System that isn’t a Cyber Asset, they shouldn’t have to meet CIP requirements.
6) Voice over Internet Protocol (VoIP), much like virtualized servers and environments, is not discussed in the CIP requirements. VoIP telephony
devices should be excluded from the requirements unless they are networked with other BESCS, in which case they could become protected CA’s.
7) There is no mention of “data at rest” in this SAR, although it was clearly part of Order 822 (paragraph 56 – “NERC’s response to the directives in
this Final Rule should identify the scope of sensitive bulk electric system data that must be protected and specify how the confidentiality, integrity, and
availability of each type of bulk electric system data should be protected while it is being transmitted or at rest”).
8) CIP-002-5.1 should be re-written to make sure all assets are properly identified. For example, under R1 of CIP-002-5.1, a Responsible Entity is
only required to find Cyber Assets at each of the six locations listed under R1. However, in Attachment 1 for medium and low impact, the language of
“associated with” is introduced, indicating that there could be assets/locations containing Cyber Assets that are not part of the list of six asset types
listed under R1. The approach taken by R1 is not the one being recommended by NERC or the Regional Entities. The standard should be revised to
clarify the relationship between the six asset types/locations in R1 and the “used by and located at”/ “associated with” language in Attachment 1.
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Matt Stryker - Georgia Transmission Corporation - 1 - SERC
Answer

No

Document Name
Comment
The SAR should be modified to include the following language and scope:Update obsolete references to NERC defined terms or standards through
modifications to the CIP standards. References which are obsolete or require clarification include, but are not limited to:
•

•
•
•
•
•
•

•
•

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To improve consistency within Registered Entity compliance programs, phrasing in CIP-002-5.1 Requirement 1 and Attachment 1 referencing
undefined or unclear terms or phrases such as “Transmission stations and substations”, “generation interconnection Facilities”, “Systems and
facilities critical to system restoration”, “Generation resources”, “BES reactive resource or group of resources” should be removed by the SDT
and instead reference the FERC approved definition of Bulk Electric System (BES) which now included clear and defined qualifications for
inclusion and exclusion of these assets as well as an appeals process to address exceptions. An example would be changing the following
language:
R1.ii. Stations and Substations containing BES Facilities
R1.iii BES Generation Facilities
RAS: Phrasing in CIP-002-5.1 Applicability, Requirement 1, and Attachment 1 referencing variations of Special Protection System (SPS),
Remedial Action Scheme (RAS), or automated switching System that operates BES Elements should be clarified and simplified by the SDT to
reference the new Remedial Action Scheme (RAS) definition which FERC approved 11/19/2015.
The current PSP definition should be clarified by the SDT to address that it should not apply to assets in CIP-006-6 Part 1.1 simply because
they may be secured in a location which meets the PSP definition: “The physical border surrounding locations in which BES Cyber Assets, BES
Cyber Systems, or Electronic Access Control or Monitoring Systems reside, and for which access is controlled.”
Interactive Remote Access definition: The SDT should clarify the phrase “system-to-system process communications” to address scripts or
batch operations performed on-demand or on a periodic basis as not meeting the definition.
The phrase “Collector Bus” as it appears in Attachment 1, Criteria 2.4 and 2.5 should be defined by the SDT. The guidance document
references a report (Final Report from the Ad Hoc Group for Generation Requirements at the Transmission Interface) which predated the
adoption of the NERC BES definition and has not been picked up for development since. The BES definition provides additional clarification of
the applicability to multiple generation scenarios in I2, I4, E1, E2, E3, and E4. Notably, CIP-014-1 does provide a diagram of the collector bus,
but does not include an associated definition.
Attachment 1, Criterion 2.4: Clarify if the Transmission Facilities operated at 500kV or higher are “at a single station or substation” to make the
language and application consistent with Criterion 2.5 to correctly scope BES Cyber Assets.
Clarify CIP-002-5.1 R1.vi for Registered Entities registered for additional functions other than Distribution Providers. Revising the language of
CIP-002-5.1 R1.vi. to state “For Distribution Providers, Protection Systems specified in Applicability section 4.2.1 above at assets which have
not already been considered under Ri-Rv” would be a possible solution.
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Shannon Fair - Colorado Springs Utilities - 1,3,5,6, Group Name Colorado Springs Utilities
Answer

Yes

Document Name
Comment
Colorado Springs Utilities agrees with the scope of the SAR.
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Richard Vine - California ISO - 2
Answer

Yes

Document Name
Comment
No comment
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Erika Doot - U.S. Bureau of Reclamation - 1,5
Answer

Yes

Document Name
Comment
The Bureau of Reclamation believes that the proposed Standards Authorization Request addresses FERC directives in Order No. 822. Reclamation
also supports NERC efforts to address the issues identified by the CIP Version 5 Transition Advisory group.
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Response

Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

Yes

Document Name
Comment
Idaho Power agrees with the items that are currently scoped into the SAR, but also believe it does not go far enough. There are numerous areas within
the v5/v6 standards where clarifications need to be made. Idaho Power doesn’t think that a full re-write of all of the CIP standards is prudent as it will
create continued churn in the industry. Idaho Power believes there should be continual slow improvement in the standards and not large swings that
create guidance gaps from the regulators and understanding gaps from the industry.
The proposed scope does not include a change to the applicability columns to tier ratings (i.e., medium with and without ERC). These need to be more
explicitly split out as they create odd breakdowns in the standards that seem to be creating inconsistencies in the standards. For example, under CIP010-2 R4 Attachment 1, R1.2 requires authorizations for all Transient Devices and R3.1 for removable media for Medium Impact BCS. However,
Medium Impact BCS without external routable connectivity (ERC) do not require an authorization records under CIP-004, specifically R4.1. This means
the critical devices/systems themselves have no authorization requirements, but the transient devices and removable media associated with them do. A
second example is information protection for Medium Impact BCS without ERC. CIP-011-2 requires information protection policies/procedures be
applied equally to all Medium Impact BCS, which includes protecting it in storage, transit, and use. However, once again, there are no requirements to
authorize an individual to gain access to “designated storage locations” under CIP-004-6 Part 4.1.3. This means the information needs to be protected,
but only those Medium BCS with ERC have to have individuals get authorized for access to the information. This seems consistent with not authorizing
individuals to get access to Medium Impact BCS without ERC but not with applying information protection policies to one tier of Medium Impact BCS.
The SDT should consider four risk tiers rather than three if they are going to treat ERC and non-ERC separately in the standards. These are simply two
examples of inconsistencies that have been created by trying to treat them within the same “medium” risk tier. There could still be similar requirements
that would be applied to a Medium Impact BCS with ERC and a Medium Impact BCS without ERC, but inconsistencies would be more easily identified
by breaking out the Medium BCS tier and the Medium without ERC.
The proposed scope does not include changes to CIP-002-5.1. CIP-002 has several inconsistencies and logic issues and no clearly delineated process
allowing no clear way to comply with the standard other than simply deciding on a direction and hoping the regional entity is okay with your approach.
The wording and processes required by CIP-002 need to be refined and clarified to make the expectations more clearly known. For example, the
Guidelines and Technical Basis state, “The following provides guidance that a Responsible Entity may use to identify the BES Cyber Systems that
would be in scope. The concept of BES reliability operating service is useful in providing Responsible Entities with the option of a defined process for
scoping those BES Cyber Systems that would be subject to CIP
‐002‐
This reference
5.1.”
to use of the BROS is stated as an option that may be
useful in identifying BCAs/BCSs. Nowhere in CIP-002 the definition of BCA or BCS does it speak directly to the BROS. The only loose tie-in is that the
definition of BCS talks about reliability tasks, which FERC, in Order 791, clarified they believed it alluded to the NERC Functional Model, which relates
to the high-level responsibilities of registered entities. However, it seems regions are beginning to take a stance that BROS is the hard-line approach as
the only acceptable way to approach identification of CIP assets and BCAs/BCSs. Additionally, the wording of the CIP-002 standard does not ever
specifically state that an entity needs to identify Protected Cyber Assets (PCAs), Electronic Access Control or Monitoring System (EACMS) or Physical
Access Control Systems (PACS), yet the standards expect that entities will know what those devices are in order to apply specific requirements to them.
Entities should not have to read between the lines when trying to comply with mandated compliance standards. Doing so creates confusion,
inconsistencies, and distrust between the regulators and the industry who should be working together to meet common objectives.

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Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment
ERCOT recommends that Project 2016-02 – Modification to CIP standards be limited to 1.) clarifying existing language,2.) addressing the V5 TAG issue
list, and 3.) incorporating the FERC-directed changes discussed in FERC Order No. 822. Introducing new concepts through substantive language
changes in this iteration would be premature. In order to allow CIP Version 5 and 6 concepts to be fully implemented, any proposed substantive
changes should be reserved for future CIP standards projects.
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Andrew Gallo - Austin Energy - 1,3,4,5,6
Answer

Yes

Document Name
Comment
Although Austin Energy (AE) agrees with the SAR’s objectives, we urge the SDT to proceed with caution. Registered Entities are just now reaching
compliance with the Version 5/6 Standards. Unless a device truly creates risk to the BES, we should not include it in the CIP Standards’ scope.
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Jeri Freimuth - APS - Arizona Public Service Co. - 1,3,5,6
Answer

Yes

Document Name
Comment
Arizona Public Service (AZPS) appreciates the opportunity to comment on the proposed SAR. Although AZPS generally supports the scope as
described in the SAR, we believe that there are additional clarifications that should be considered beyond those detailed in the FERC Order 822 and the
CIP Version 5 Transition Advisory Group (V5TAG) considerations.
AZPS believes the industry would benefit from clarification of the definition of the following terms:
•

Transmission Facility – Transmission Facility is not a defined term. Although Facility is a defined term, AZPS does not believe that the Facility
definition aligns with the standard’s intent. AZPS suggests that a definition be provided by the Standard Drafting Team (SDT).

•

Programmable - The SDT should consider defining programmable to clarify that a device would not be included simply because it was
configurable, e.g., has functionality that can be changed locally.

AZPS would also like to suggest that the SDT clarify the intent of the grouping BCAs into BCS by leveraging the logically based perimeter security
controls at the Electronic Security Perimeter (ESP) as well as local, device specific security controls per each BES Cyber Asset’s (BCA)
capability.
AZPS would also like to add some additional comments to the discussion in the V5TAG CIP V5 Issues for Standard Drafting Team Consideration
document.
•

AZPS recommends that the SDT consider not defining “adverse impact” or defining a lower bound thereof within the definition of BES Cyber
Asset, but to revise the body of CIP standards and/or applicable defined terms to utilize already defined terms such as “Adverse Reliability
Impact.” Such would facilitate consistency as well as clarity regarding the N-1 contingency issue and other issues regarding that term identified
by the V5TAG.

•

AZPS believes that when BES Cyber Assets (BCA), such as relays, RTUs, and others, are connected via serial links to IP converters and/or IPenabled security gateways, it would be appropriate to consider those elements downstream of the security gateways as BCA that do not have
External Routable Connectivity (ERC). This is appropriate because the IP- converters and/or IP-enable security gateways require
authentication and provide a protocol break. AZPS believes accurate and timely guidance related to serially connected devices supports the
overall goal of providing appropriate and effective cyber security controls; thus, improving reliability.

•

AZPS supports the CIP V5TAG analysis regarding virtualization. Virtualization is an effective tool for utilities and consideration should be given
to ensuring that flexibility is maintained. An approach should consider the required outcome rather than the specifics of how that outcome is
achieved.

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Warren Cross - ACES Power Marketing - 1,3,5,6 - MRO,WECC,Texas RE,SERC,SPP RE,RF

Answer

Yes

Document Name
Comment
Look to NIST 800-125 for virtualization security.
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Michael Johnson - Burns & McDonnell - NA - Not Applicable - NA - Not Applicable
Answer

Yes

Document Name
Comment

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Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment

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0

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Diana McMahon - Salt River Project - 1,3,6,7 - WECC

Answer

Yes

Document Name
Comment

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0

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Chris Sistrunk - Small End-Use Electricity Customer - NA - Not Applicable - NA - Not Applicable
Answer

Yes

Document Name
Comment

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0

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Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment

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0

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Scott Langston - Tallahassee Electric (City of Tallahassee, FL) - 1,3,5
Answer

Yes

Document Name
Comment

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John Williams - Tallahassee Electric (City of Tallahassee, FL) - 1,3,5
Answer

Yes

Document Name
Comment

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0

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Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

Yes

Document Name
Comment

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Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name

Yes

Comment

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Melanie Seader - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

Yes

Document Name
Comment

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Jason Smith - Southwest Power Pool, Inc. (RTO) - 2 - MRO,SPP RE, Group Name SPP Standards Review Group
Answer

Yes

Document Name
Comment

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0

2. Are you aware of any Canadian provincial or other regulatory requirements that may need to be considered during this project in order to
develop a continent-wide approach to the standards? If yes, please identify the jurisdiction and specific regulatory requirements.
Richard Vine - California ISO - 2
Answer

No

Document Name
Comment
No comment
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Matt Stryker - Georgia Transmission Corporation - 1 - SERC
Answer

No

Document Name
Comment

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Chris Gowder - Florida Municipal Power Agency - 3,4,5,6 - FRCC, Group Name FMPA
Answer

No

Document Name
Comment

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Response

Mike Smith - Manitoba Hydro - 1,3,5,6
Answer

No

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Comment

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0

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Ryan Walter - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Answer

No

Document Name
Comment

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0

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0

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Warren Cross - ACES Power Marketing - 1,3,5,6 - MRO,WECC,Texas RE,SERC,SPP RE,RF
Answer

No

Document Name
Comment

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0

Jason Smith - Southwest Power Pool, Inc. (RTO) - 2 - MRO,SPP RE, Group Name SPP Standards Review Group
Answer

No

Document Name
Comment

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Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6 - NPCC, Group Name RSC No Dominion
Answer

No

Document Name
Comment

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0

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Douglas Webb - Great Plains Energy - Kansas City Power and Light Co. - 1,3,5,6 - SPP RE
Answer

No

Document Name
Comment

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0

Jeri Freimuth - APS - Arizona Public Service Co. - 1,3,5,6
Answer

No

Document Name
Comment

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0

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0

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Andrew Gallo - Austin Energy - 1,3,4,5,6
Answer

No

Document Name
Comment

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0

Response

Melanie Seader - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

No

Document Name
Comment

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0

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0

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Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC

Answer

No

Document Name
Comment

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0

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Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

No

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Comment

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John Williams - Tallahassee Electric (City of Tallahassee, FL) - 1,3,5
Answer

No

Document Name
Comment

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0

Response

Scott Langston - Tallahassee Electric (City of Tallahassee, FL) - 1,3,5
Answer

No

Document Name
Comment

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0

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Andrew Pusztai - American Transmission Company, LLC - 1
Answer

No

Document Name
Comment

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0

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0

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Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

No

Document Name
Comment

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0

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0

Response

Maryclaire Yatsko - Seminole Electric Cooperative, Inc. - 1,3,4,5,6 - FRCC
Answer
Document Name

No

Comment

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0

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Chris Sistrunk - Small End-Use Electricity Customer - NA - Not Applicable - NA - Not Applicable
Answer

No

Document Name
Comment

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0

Response

Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer

No

Document Name
Comment

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0

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0

Response

Laura Nelson - IDACORP - Idaho Power Company - 1
Answer
Document Name
Comment

No

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0

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Diana McMahon - Salt River Project - 1,3,6,7 - WECC
Answer

No

Document Name
Comment

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0

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0

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Ginny Beigel - City of Vero Beach - 9
Answer

No

Document Name
Comment

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0

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0

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Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer
Document Name
Comment

No

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0

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Steven Parker - EnergySec - NA - Not Applicable - NA - Not Applicable
Answer

No

Document Name
Comment

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0

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0

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Erika Doot - U.S. Bureau of Reclamation - 1,5
Answer

No

Document Name
Comment

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0

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Leonard Kula - Independent Electricity System Operator - 2
Answer

No

Document Name
Comment

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0

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0

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Michael Johnson - Burns & McDonnell - NA - Not Applicable - NA - Not Applicable
Answer

No

Document Name
Comment

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0

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0

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Bob Reynolds - Southwest Power Pool Regional Entity - 10
Answer

No

Document Name
Comment

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0

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Shannon Fair - Colorado Springs Utilities - 1,3,5,6, Group Name Colorado Springs Utilities
Answer

No

Document Name
Comment

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Response

3. Are there any other concerns with this SAR that haven’t been covered in the previous questions?
Warren Cross - ACES Power Marketing - 1,3,5,6 - MRO,WECC,Texas RE,SERC,SPP RE,RF
Answer

No

Document Name
Comment
The SDT should prioritize the issues based on whether it is associated with a FERC directive or not. For issues that are not directed by FERC, there
may need to be additional time to find a resolution associated with these issues. The only deadlines on this project are related to the FERC directives.
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Shannon Fair - Colorado Springs Utilities - 1,3,5,6, Group Name Colorado Springs Utilities
Answer

No

Document Name
Comment

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0

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Bob Reynolds - Southwest Power Pool Regional Entity - 10
Answer

No

Document Name
Comment

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0
0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer

No

Document Name
Comment

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0

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0

Response

Erika Doot - U.S. Bureau of Reclamation - 1,5
Answer

No

Document Name
Comment

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0

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0

Response

Steven Parker - EnergySec - NA - Not Applicable - NA - Not Applicable
Answer

No

Document Name
Comment

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0

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0

Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer

No

Document Name
Comment

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0

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0

Response

Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

No

Document Name
Comment

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0

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0

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Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer

No

Document Name

2016-02_CIP_SAR_Unofficial_Comment_Form_ERCOT draft.docx

Comment

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Maryclaire Yatsko - Seminole Electric Cooperative, Inc. - 1,3,4,5,6 - FRCC
Answer

No

Document Name
Comment

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0

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0

Response

Scott Langston - Tallahassee Electric (City of Tallahassee, FL) - 1,3,5
Answer

No

Document Name
Comment

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John Williams - Tallahassee Electric (City of Tallahassee, FL) - 1,3,5
Answer

No

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Comment

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Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC

Answer

No

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Comment

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Andrew Gallo - Austin Energy - 1,3,4,5,6
Answer

No

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Comment

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Douglas Webb - Great Plains Energy - Kansas City Power and Light Co. - 1,3,5,6 - SPP RE
Answer

No

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Comment

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Jason Smith - Southwest Power Pool, Inc. (RTO) - 2 - MRO,SPP RE, Group Name SPP Standards Review Group
Answer

No

Document Name
Comment

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Ryan Walter - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Answer

No

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Comment

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Mike Smith - Manitoba Hydro - 1,3,5,6
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No

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Matt Stryker - Georgia Transmission Corporation - 1 - SERC
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Document Name

No

Comment

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Michael Johnson - Burns & McDonnell - NA - Not Applicable - NA - Not Applicable
Answer

Yes

Document Name
Comment
Burns & McDonnell appreciates the opportunity to comment on the Standard Authorization Request (SAR) titled “Modifications to CIP Standards” with
the following input:
The V5TAG recommended the Standard Drafting Team (SDT) consider Virtualization as part of the SAR due to the increased use of this technology in
industry control system environments. Burns & McDonnell is recommending the Virtualization section of the SAR be amended to indicate that the SDT
not only consider virtualization technology usage by Responsibility Entities (Entity) which they own and operate, but usage of similar technology not
owned or operated by an Entity. Increased interest in “cloud” based services such as Software as a Service (SaaS) and Platform as a Service (PaaS)
have created questions on the application of the standards with no guidance on how they should be applied. Cloud usage of virtual technology is
similar to Entity owned usage of the same technology, but Burns & McDonnell feels it is important that both usage conditions be considered and any
differences in approach be indicated in any final SDT work product. Burns & McDonnell does not believe a separate section should be created for
“cloud” usage, but the SAR section on Virtualization could be updated to cover virtualization technology owned by or usage of services by an
Entity. One recommendation for the re-wording is:
The CIP V5 standards do not specifically address virtualization. Because of the increasing use of virtualization in industrial control system environments
either owned and operated by a Responsible Entity, or from a service provider who owns and operates the environment under the service providers
control, V5TAG asked that the SDT consider CIP-005 and the definitions of Cyber Asset and Electronic Access Point regarding permitted architecture
and the security risks of network, server and storage virtualization technologies under these two type of conditions.
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Richard Vine - California ISO - 2
Answer
Document Name

Yes

Comment
Currently there are no specific requirements or guidelines included within the NERC CIP Reliability Standards v.5/6 relating to utilization of
the cloud. Based on discussions with the regional auditing body, it has been agreed upon that utilization of the cloud for storage of BES
Cyber System Information may be sufficiently secured through field level packet encryption with the responsible entity only holding the
private key. It would be in the interest of the California ISO for there to be a provision included within the NERC CIP Reliability Standards
addressing cloud scenarios.
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Ginny Beigel - City of Vero Beach - 9
Answer

Yes

Document Name
Comment
We belong to the FMPA municipal organization and have arrived at a consensus with the help of one of its SMEs who is immersed in CIP Standards.
Comments follow below:
The SAR falls short of fixing a lot of the core issues related to CIP-002-5.1. The following additional items should be addressed by the SDT:

1) Section 4.2.2 states “All BES Facilities” as being subject to the standards for all Responsible Entities except for DPs. This effectively negates the
rest of the requirements, as anything that qualifies as a “Cyber Asset” could not possibly be a “Facility” as well. The language is missing the “Cyber
Assets” component. Suggested language would be “Cyber Assets at all BES Facilities.”

2) Ownership isn’t properly accounted for in the requirements. Shared facilities (generally speaking substations) often involve multiple entities that
own equipment, who may or may not be Responsible Entities as described in CIP-002-5.1. There should be specific language requiring the owner of
the equipment to communicate with the owner of the Facility.

3) Clarify what is meant by “associated with” in the context of the Impact Rating Criteria in CIP-002-5.1 – Attachment 1. Clear up the inconsistencies
in the requirements between the use of “associated with” (criterion 2 & 3 in Attachment 1) in some areas and “used by and located at” (criterion 1 in
Attachment 1) in other parts. Have a process developed for ensuring entities notify if there are devices owned by a different entity that are “associated
with” their BESCS (for example, a meter that one entity needs for the reliable operation of their Control Center that isn’t owned by them).

4) Leasing equipment is a loophole in the requirements based on the language in section 4.2. This should be fixed so an entity isn’t able to lease
equipment and avoid meeting CIP requirements.

5) The scope of equipment applicable to CIP due to applicability to other NERC standards (such as CIP-002-5.1 Section 4.2.1.3) should be clarified
further. For example, a “Protection System” can be made up of multiple devices owned by multiple entities. If an entity owns a component of a
Protection System that isn’t a Cyber Asset, they shouldn’t have to meet CIP requirements.

6) Voice over Internet Protocol (VoIP), much like virtualized servers and environments, is not discussed in the CIP requirements. VoIP telephony
devices should be excluded from the requirements unless they are networked with other BESCS, in which case they could become protected CA’s.

7) There is no mention of “data at rest” in this SAR, although it was clearly part of Order 822 (paragraph 56 – “NERC’s response to the directives in
this Final Rule should identify the scope of sensitive bulk electric system data that must be protected and specify how the confidentiality, integrity, and
availability of each type of bulk electric system data should be protected while it is being transmitted or at rest”).

8) CIP-002-5.1 should be re-written to make sure all assets are properly identified. For example, under R1 of CIP-002-5.1, a Responsible Entity is
only required to find Cyber Assets at each of the six locations listed under R1. However, in Attachment 1 for medium and low impact, the language of
“associated with” is introduced, indicating that there could be assets/locations containing Cyber Assets that are not part of the list of six asset types
listed under R1. The approach taken by R1 is not the one being recommended by NERC or the Regional Entities. The standard should be revised to
allow for the proper capture of all Cyber Assets either ONLY at the six asset locations, OR both at these locations as well as any other associated
location.

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Diana McMahon - Salt River Project - 1,3,6,7 - WECC
Answer
Document Name
Comment

Yes

For network and externally accessible devices, SRP agrees with improving clarity within the concepts and requirements concerning Electronic Security
Perimeters (ESP), External Routable Connectivity (ERC), and Interactive Remote Access (IRA). However, SRP has additional concerns.
Although much of CIP-005-5 is compatible to CIP V3 requirements, it does include a new requirement related to IRA for High Impact BES Cyber
Systems and Medium Impact BES Cyber Systems with ERC. R2.1 states: Utilize an Intermediate System such that the Cyber Asset initiating
Interactive Remote Access does not directly access an applicable Cyber Asset.
Based on R2.1 and the defined terms, demonstrating compliance with this requirement fundamentally requires evidence of two items:
1.

That an Intermediate System is utilized such that the Cyber Asset initiating IRA does not “directly access” an applicable Cyber Asset; and

2.

That technology for facilitating IRA meets the definition of an Intermediate System.

Issues with #1 – Ambiguity of “Directly Access”
In SRP’s experience the ERO and Regional Entities have used undefined terminology such as “protocol break”, “OSI layer 7 application break”,
“session break” and others to describe what is intended by or compliant with the phrase “does not directly access”. However, SRP believes these terms
mean different things to different subject matter experts and auditors. FERC articulated as much in Order 822. Although this issue has focused on
LERC/LEAP requirements for low impact assets, the same ambiguity exists in the requirements for high/medium impact facilities. Where standards are
unclear or ambiguous, entities are typically afforded flexibility in their compliance approaches. However, SRP believes the ERO has taken a rather
prescriptive view of these requirements where reasonable people could easily differ in their interpretation. These ambiguities in defined terms and
requirements need to be addressed by the SDT.
Issues with #2 – Ambiguity on acceptable Intermediate Systems
As noted in the Glossary of Terms, an Intermediate System is an Electronic Access Control or Monitoring System (EACMS). That notwithstanding, the
ERO and Regional Entities have articulated rather informally and only fairly recently a need to assess each Intermediate System against the definition of
BES Cyber Asset. This creates the potential for the proverbial “hall of mirrors” result, in the sense that individuals can rationalize a circumstance where
seemingly all Cyber Assets (PACS, EACMS, other) could, under some scenario qualify as a BES Cyber Asset. SRP believes this was clearly not the
intent of the Standard Drafting Team, and SRP does not believe this concept was considered for Intermediate Systems evaluated during the CIP V5
pilot project.
Most specifically, an entity that was on the drafting team and participated in the implementation pilot project with no issues was “surprised” with the
Regional Entity’s assessment of compliance on this subject at time of audit. There is clearly a disconnect that needs to be addressed.
Architectures to support Interactive Remote Access to high, medium impact control centers, transmission stations and generation resources are very
costly. Current ambiguity could cause extensive and rework for high and medium impact systems, and be even more impactful if similar architectures
are applied to low impact assets.
The Standards Drafting Team (SDT) must clearly define the term “direct access” for high and medium facilities, ensuring “direct access” has same
meaning for low impact facilities as ordered by FERC in its approval of the CIP V5 revisions. To the extent different controls are appropriate for
high/medium vs. low impact systems, those distinctions must be clear in the language of the standard. SRP further recommends the SDT re-evaluate
the definitions of Interactive Remote Access, Intermediate System, and BES Cyber Asset to ensure entities have a clear understanding of the security
and compliance expectations associated with the standards.

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Chris Sistrunk - Small End-Use Electricity Customer - NA - Not Applicable - NA - Not Applicable
Answer

Yes

Document Name
Comment
I believe that the CIP standards do not properly address security monitoring of networks (routable and non-routable). In my experience in the security
industry that breaches (like electric disturbances) are inevitable, even for control systems. It's a matter of when, not if. The Security Event Monitoring
logging requirements in CIP 007-5 R4 is a start, but I don't believe this data (4.1.1. Detected successful login attempts; 4.1.2. Detected failed access
attempts and failed login attempts; 4.1.3. Detected malicious code.) provides enough digital forensic evidence in the aftermath of an intrusion or even a
cyber attack. Also, the retention period in 4.3 of a minimum of "90 consecutive calendar days" is not sufficient. According to the 2016 M-Trends Report
from FireEye (https://www2.fireeye.com/rs/848-DID-242/images/Mtrends2016.pdf), the median time of network compromise to discovery of the attacker
is 146 days. If a utility only kept 90 days of logs, then it's quite possible that they won't have the forensics data to determine if the attacker used stolen
credentials or malicious code. Also, many utilities don't use authentication or encryption with their Control System Protocols such as DNP3, ICCP, and
Modbus. If an attacker were to spoof, replay, or modify the SCADA traffic, this would not be detected by the current set of monitoring and logging
requirements.
However, IT security best practice of network security montoring (NSM) does provide sufficient network forensics data. NSM is similar to the type of
monitoring and visibility required by NERC PRC 002-2 Disturbance Monitoring and Reporting standard. I wrote a blog post
(https://www.linkedin.com/pulse/comparing-nerc-disturbance-monitoring-reporting-network-sistrunk) about the similarities between PRC 002-2 and
NSM...and how NERC CIP 007 R4 could be improved to provide a bit more forensics data. Collecting NSM type data such as Session Data (timestamp,
source IP address, source port, destination IP, destination port at a minimum) does not require a lot of storage space and would provide a better level of
visibility. Collecting a shorter time period of full network packet captures for High or Medium BES Cyber Systems (including non-routable dial-up access)
also is not very complicated, as IT systems have been doing this a long time.
Since BES systems are becoming more connected, we cannot ignore network security monitoring in the future. I hope it doesn't take a serious cyber
incident to convince the need for monitoring...much like the 1965 and 2003 blackouts convinced us to do disturbance monitoring. I know we haven't had
a cyber attack that caused a power outage here in North America, but as an Electrical Engineer who has worked in the electric utility industry, now
representing the ICS security industry, and also a customer, I want to help ensure that this doesn't happen.

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Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment
Duke Energy requests that the SDT consider revisiting the transfer of employees and the requirement to remove access for that employee in 1 calendar
day which may be viewed as overly burdensome. While this may be outside the scope of this particular SAR, we feel that since the project is regarding
revisions to CIP standards, that we would be remiss not to request further discussion around this topic.
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Andrew Pusztai - American Transmission Company, LLC - 1
Answer

Yes

Document Name
Comment
ATC is a member of EEI and supports the comments submitted by the EEI CIP Standards Subgroup realted to the draft SAR. Please review for
applicability to this question.
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Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

Yes

Document Name
Comment
Texas RE noticed there is a statement on page 4 which says the compliance deadline is April 1, 2016. This has been moved back to July 1, 2016.

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Melanie Seader - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

Yes

Document Name
Comment
In addition to the issues addressed by the SAR, the Edison Electric Institute, on behalf of our members, recommends that the proposed project also
consider the following ten issues:
Issue 1: CIP Exceptional Circumstances
A CIP Exceptional Circumstance is defined as:
“A situation that involves or threatens to involve one or more of the following, or similar, conditions that impact safety or BES reliability: a risk of injury or
death; a natural disaster; civil unrest; an imminent or existing hardware, software, or equipment failure; a Cyber Security Incident requiring emergency
assistance; a response by emergency services; the enactment of a mutual assistance agreement; or an impediment of large scale workforce
availability.”
We appreciate the understanding and recognition for the need to enable provisions for CIP Exceptional Circumstances. However, during
implementation of CIP V5, it has become apparent that the CIP Exceptional Circumstances provision may need to be added to several
requirements. Below are a few situation-based examples:
•

•
•

Risk of injury or death: CIP-004-6 R2 and R4 allow for CIP Exceptional Circumstances to waive the need for Training and the Authorization
based on need to be waived during such circumstances. We believe that CIP-004-6 R3 also should allow for CIP Exceptional Circumstances
because the requirement to obtain a Personal Risk Assessment takes additional time that would hinder the ability of first responders to enter a
Physical Security Perimeter in the event of the need for life saving measures. This would be consistent with CIP-004-3 “except in specified
circumstances such as an emergency.”
Impediment of large scale workforce availability: CIP-007-6 R2 Security Patch Management requirements may be difficult to meet in the event
that a major storm impacts a responsible entity, which requires all employees to report for storm duty for restoration efforts.
Natural disaster: CIP-006-6 R1 Part 1.4 monitoring may not be possible if the physical access point to a PSP is under water or destroyed by a
storm. Similarly, Part 1.3 causes compliance issues if for example, a fire renders a PACS controller panel inoperable and the PSP access
points have failed secure. Emergency response may have to use a physical key, mechanical lock, or an axe to gain access. Without the IAC
language or CIP Exceptional Circumstance provision, PSP access point monitoring is a zero defect issue.

We recommend that the SDT review all of the requirements of CIP V5 to determine whether: a CIP Exceptional Circumstances provision should be
added, the definition of CIP Exceptional Circumstances should be edited, and/or additional explanatory language should be added to the Guidelines and
Technical Basis for each standard regarding CIP Exceptional Circumstances.

Issue 2: BES Cyber Asset definition – “redundancy”
The application of the redundancy clause in the BES Cyber Asset (BCA) definition is unclear because the use of different and separate technologies
and methods reduce reliability risk by providing alternative data sources. For example, VoIP systems, data center phone systems, radios, and other
backup communication systems are alternatives, yet could be considered redundant by auditors and therefore it is unclear whether there are limits to
the application of the BCA adverse impact to these systems. Without such limitations, the BCA definition may encourage registered entities to reduce
their use of backup/alternative systems to reduce their compliance burdens and risk. While redundant assets may typically have identical security risks
and vulnerabilities, requiring both/all to be similarly protected, alternative systems or assets are often substantially different and have drastically
dissimilar risks and vulnerabilities, which reduces overall risk to the BES.
Issue 3: VoIP as a BES Cyber Asset
CIP-002-5.1 4.2.3.2 exempts “Cyber Assets associated with communication networks and data communication links between discrete Electronic
Security Perimeters” from CIP-002-5.1; however, the Guidelines and Technical Basis for CIP-002-5.1 calls out operational directives (TOP, RC, BA) as
an aspect of Inter-Entity Coordination and Communication function. As a result, some auditors are viewing VoIP as in scope for CIP-002-5.1 despite the
exemption and fact that different and separate communication technologies are used for this function. If the exemption does not apply, then the BES
Cyber Asset definition should also apply; however, EEI members are hearing that auditors do not agree and believe that VoIP used for operational
directives are BES Cyber Assets even if the 15 minute impact does not apply due to the redundancy issue mentioned above.
We recommend that the SDT consider these issues and determine how best to address VoIP in the standard that is aligned with the risk to the bulk
electric system.
Issue 4: LERC definition application to assets located external to the low impact asset
The last three asset classes in CIP-002-5.1 R1 are typically implemented across multiple instances of the first three classes (i.e., systems and facilities
critical to system restoration, special protection systems, and distribution provider protection systems are typically implemented at control centers,
substations, and generating resources).
The Low Impact External Routable Connectivity (LERC) definition appears to be based on single asset locations (“direct user-initiated interactive access
or a direct device-to-device connection to a low impact BES Cyber System(s) from a Cyber Asset outside the asset containing those low impact BES
Cyber System(s) via a bi-directional routable protocol connection.”) The phrase “outside the asset” can cause confusion in determining whether LERC
exists for these classes of assets that are implemented across multiple sites.
For example, when evaluating a cranking path as an asset to determine if it has LERC, what does “outside the asset” mean? This could also allow for
routable protocol based communication within the multiple substation cranking path to not be considered LERC and left unprotected if the entire
cranking path is considered a single “asset containing low impact BES Cyber Systems.” It appears these last 3 asset classes are actually criteria that
should affect the categorization of the single site asset class where they are implemented.
Issue 5: Custom software (scripts)
CIP-010-2 R1, Part 1.1, subpart 1.1.3 requires a baseline configuration for “any custom software installed.” The Guidelines and Technical Basis for this
requirement states that “custom software installed may include scripts developed for local entity functions.” It is unclear whether all scripts must be
considered custom software or whether only scripts that can have an impact on the bulk electric system within 15 minutes must be considered custom
software under this requirement. A risk-based clarification should be added to this requirement to set boundaries as to what is considered custom
software. For example, a script that alters the behavior or function of a BES Cyber Asset or System should be included; however, a script that simply
gathers log data, and whose only impact to the BES Cyber Asset is the allocation of incidental CPU cycles, need not be included.

Issue 6: Applicability of the requirement part to Cyber Asset vs. Cyber System
Some requirements such as in the CIP-007-6 standard apply to Cyber Assets within a BES Cyber System (e.g., the R2 security patch management
requirements), others apply at either the BES Cyber System level or Cyber Asset level (e.g., the R4 Part 4.1 logging requirements), and others don’t
specific if they apply at the system or asset level (e.g., R3 Part 3.1 method to deter, detect, or prevent malicious code). Although the applicable systems
for each of these requirements is generally the same (i.e., high and medium impact BES Cyber Systems and their associated EACMS, PACS, and
PCA), the difference in the requirements language applicability to Cyber Assets, BES Cyber System, or both makes what is necessary to comply with
the requirements unclear.
For example, the requirements section for CIP-007-6 R3 Part 3.1 does not specify whether this requirement applies at the BES Cyber System level or
Cyber Asset level, therefore it is unclear whether a responsible entity can protect a medium impact BES Cyber System through deploying an anti-virus
solution at the BES Cyber System level or whether the entity must deploy the solution at each Cyber Asset to comply with the requirement part.
Consistency among the requirements language would be helpful in clearing up this confusion.
Issue 7: Control Center definition
The NERC document titled “CIP V5 Issues for Standard Drafting Team Consideration” already raises issues with the Control Center definition related to
Transmission Owner Control Centers; however, it does not address issues related to Generator Operators.
By definition, a Control Center is “one or more facilities hosting operating personnel that monitor and control the Bulk Electric System (BES) in real-time
to perform the reliability tasks, including their associated data centers … 4) a Generator Operator for generation Facilities at two or more locations.”
Dispersed or distributed generation facilities (e.g., wind, solar, hydro) may not have the traditional control building with a horseshoe operator control
desk (“facility hosting operating personnel that monitor and control”). Does the facility have to perform all “real-time … reliability tasks” or as few as one?
Does a control room at a single wind farm, which controls a hundred turbines spread over many miles, meet the control center definition or does it
become a control center only if it controls multiple wind farms? Also, if personnel maintains the Cyber Assets (e.g., patching or troubleshooting) is this
considered “monitor and control” even though they are not personnel performing real-time reliability tasks. Does operating personnel mean those
charged with the responsibility to monitor and control the BES or simply personnel who may be located at the generation Facility to maintain the
equipment? Also, do each of the “generation Facilities at two or more locations” need to meet the Bulk Electric System definition to be within scope of
the Control Center definition? CIP-002-5.1 Requirement R1, iii uses Generation resources, which could be interpreted to include all generation sources,
even those that do not meet the Bulk Electric System definition.
As dispersed or distributed generation increases, clarity in language of the standard will become more important.
Issue 8: Security patches for operating Cyber Assets brought into scope under CIP V5
CIP-007-6 R2, Part 2.2 is clear concerning the ongoing evaluation of security patches as of July 1, 2016, but is unclear on what is required for the initial
execution of the process (“evaluate security patches for applicability that have been released since the last evaluation”) when there is no “last
evaluation.”
The standard does not require all Systems to be updated by July 1, 2016, but does require a baseline configuration, which includes a listing of all
applied patches. The Guidelines and Technical Basis for CIP-010-2 states that “security patches applied would include all patches that have been
applied on the cyber asset… CIP-010 Requirement R1, Part 1.1.5 requires entities to list all applied historical and current patches.” This documentation
requirement is particularly burdensome for an asset that has been in service for six years or longer as it requires entities to contact and work closely
with their vendors to identify and get historical security patches. Also, documenting all historical patches, especially those that happened years ago will
have little, if any impact on reliability.

Issue 9: Guidance for Secure Interactive Remote Access
In the Guidelines and Technical Basis for CIP-005-5, under Requirement R2 it states: “see Secure Remote Access Reference Document (see remote
access alert).” Also, the Rationale for R2 states “Additional information is provided in Guidance for Secure Interactive Remote Access published by
NERC in July 2011.” We believe these references are to the same document, which is properly titled under the Rationale and note that the 2011 NERC
document was written in the context of V3 and not V5. Please evaluate the relevance of this guidance document to the most recent version (currently
CIP-005-5). Also please clarify that IRA is intended to address access remotely from outside the organization (i.e., not to include accesses internally
between protected networks).
Issue 10: Mistakes in Guidelines and Technical Basis
In implementing CIP V5, we’ve noticed a number of mistakes, which should be addressed, including:
•

•
•

•

The rationale statements from the -5 standards were lost in several of the -6 versions of the standards. For example, the second sentence of
the CIP-007-5 R2 rationale “The remediation plan can be updated as necessary to maintain the reliability of the BES, including an explanation
of any rescheduling of the remediation actions.” was not carried forward to the -6 Guidelines and Technical Basis, even though there were no
changes to the requirement between versions. We recommend reviewing the Rationales in the -6 standards and adding any that were deleted
to the Guidelines and Technical Basis of the standard.
For CIP-007-6 Part 2.2 the Guidelines and Technical Basis states: “Determination that a security related patch, hotfix, and/or update poses too
great a risk to install on a system or is not applicable due to the system configuration should not require a TFE.” However there are no CIP007-6 R2 Parts have TFE provisions.
For CIP-004-6 R4, under the Guidelines and Technical Basis, the Rationale for this requirement states: “to ensure that individuals with access
to BES Cyber Systems and the physical and electronic locations where BES Cyber System Information is stored by the Responsible Entity have
been properly authorized for such access. “ ‘Authorization’ should be considered to be a grant of permission by a person or persons
empowered by the Responsible Entity to perform such grants and included in the delegations referenced in CIP-003-6” CIP V3 required
designating approvers; however this requirement was not included in CIP-003-6 and therefore the emphasized text should be removed.
For CIP-004-6 R4, the Rationale also references “quarterly reviews in Part 4.5”; however there is no Part 4.5 in CIP-004-6 R4.

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Jeri Freimuth - APS - Arizona Public Service Co. - 1,3,5,6
Answer

Yes

Document Name
Comment
NERC’s webpage for this SAR “Project 2016-02 Modifications to CIP Standards”, as of 4/11/2016, states the following:
“Also the scope of this work will incorporate existing and future RFIs relating to the CIP-002 through CIP-011 family of standards.”

AZPS does not believe any RFIs are addressed in the current SAR. We recommend updating the SAR to reference existing submitted RFIs as
appropriate. Finally, AZPS recommends removal from the SAR of functional registrations that are no longer included in the Compliance Registry, e.g.,
Interchange Authority, Load-Serving Entity and Purchasing-Selling Entity.
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Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6 - NPCC, Group Name RSC No Dominion
Answer

Yes

Document Name
Comment
Request that the SAR explicitly reference the correct title of the V5 TAG document, which we believe is “CIP V5 Issues for Standard Drafting Team
Consideration, “dated on September 15, 2015.
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Chris Gowder - Florida Municipal Power Agency - 3,4,5,6 - FRCC, Group Name FMPA
Answer

Yes

Document Name
Comment
Distribution Provider is not checked as an affected Reliability Function.
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Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company

Answer
Document Name

4-15-16 DRAFT CIP V5 Implementation Issues.pdf

Comment
Southern supports the comments of EEI. See attached.
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Comments received from Ginette Lacasse, Seattle City Light
Here are our Subject Matter Expert’s (SME) comments. Non-italicized text is copied from SAR, with SME additions in RED. Additional SME
comments are in italics.
Questions
1. Do you agree with the scope and objectives of this SAR? If not, please explain why you do not agree, and, if possible, provide specific
language revisions that would make it acceptable to you.
Yes:
No: X
Comments:
In several sections the language of the SAR summarizes that of the foundation V5TAG document, but in doing so conflates or glosses over
important concepts. Seattle City Light would like to see clarification to the SAR in the following two sections: (added text in red to clarify)
A) Cyber Asset and BES Cyber Asset (BCA) Definitions – as foundational definitions within the CIP V5 standards, the understanding of Cyber
Asset and BCA terms impacts the scope of the applicable requirements. ‘Right-sizing’ the definitions of “Cyber Asset” and “BES Cyber Asset”
balances between the administrative burden and negligible security benefit of an overly broad interpretation and the cyber security risk of
too narrow an interpretation. The V5TAG recommends the following enhancements:

•
•
•
•
•

Clarify the intent of “programmable” in Cyber Asset.
Clarify and focus the definition of “BES Cyber Asset” including:
Focusing the definition so that it does not subsume all other cyber asset types.
Considering a lower bound to the term ‘adverse’ in “adverse impact”.
Clarifying the double impact criteria (cyber asset affects a facility and that facility affects the reliable operation of the BES) such that “N1 contingency” is not a valid methodology that can eliminate an entire site and all of its Cyber Assets from scope.

B) Network and Externally Accessible Devices – V5TAG recommends improving clarity within the concepts and requirements concerning
Electronic Security Perimeters (ESP), External Routable Connectivity (ERC), and Interactive Remote Access (IRA) including:
• The 4.2.3.2 exemption phrase “between discrete Electronic Security Perimeters.” When there is not an ESP at the location, consider
clarity that the communication equipment considered out of scope is the same communication equipment that would be considered
out of scope if it were between two ESPs.
2 Are you aware of any Canadian provincial or other regulatory requirements that may need to be considered during this project in order
to develop a continent-wide approach to the standards? If yes, please identify the jurisdiction and specific regulatory requirements.
Yes:
No: X
Comments:
3 Are there any other concerns with this SAR that haven’t been covered in previous questions?
Yes: X
No:
Comments:
Seattle would like to see the SAR address three additional areas:
Clarify those standards and parts where the requirement applies solely to the applicable BES Cyber System, those standards and parts where
the requirement applies solely to individual BES Cyber Assets, those where the requirement applies to both BCS and BCA or to either at the
option of the responsible entity, and those where the requirement applies to both BCS and BCA or to either depending on the circumstances
and configuration.
B) Clarify application of CIP-002-5, in particular the R1 identification of BES Cyber Systems and their association with specific types of assets
(small “a”). The linkage is inconsistent: for High impact rating it is any “BCS located at and used by” a Control Center whereas for Medium
A)

impact rating it is any “BCS associated with any of the following,” the “following” being a mixed-bag collection of capital “F” Facilities,
various systems or groups of Elements, specifically defined terms such as Control Center and Special Protection System, and undefined
common-language concepts such as “generation” and “BES reactive resource.” Please also clarify the intent of “used by” and “associated
with.” Does “used by” mean “essential to the operation of,” “involved in the operation of,” or something else? Does “associated with”
combine the concepts of “used by and located at,” or would it be sufficient to be either “situated at the physical location of” or “used by”?
The present language creates considerable confusion.
C) Clarify the application of Intermediate System, as discussed by Salt River Project in their comments. Seattle supports Salt River’s position and
analysis.
Seattle also supports the position that Florida Municipal Power Authority as they submitted in their comments.
Comments received from Kara Douglas – NRG
Questions
1. Do you agree with the scope and objectives of this SAR? If not, please explain why you do not agree, and, if possible, provide specific
language revisions that would make it acceptable to you.
Yes:
No: X
Comments:
A) Please consider the definition of Cyber Asset and clarify the intent of the term “Programmable” through consideration of whether a
device is merely configurable, its executable code is not field upgradable or field Programmable, or if its functionality can only be changed
via physical DIP switches, swapping internal chips, etc. (which relates to upgrading the executable in the Programmable code and the ability
to field program the configuration)
B) In relation to the terms: “adverse impact” and “control center”, NRG proposes that when addressing TO and TOP Control Center
functional obligations in CIP-002-5.1 Attachment 1, it also consider addressing similar issues facing Generator Owners (GO) and Generator
Operators (GOP). There are GOP “control centers” that do not have traditional control capabilities over generator breakers or output but
simply verbally direct generator actions. In this case it is the GOs that perform the actual output changes and breaker operation. Clarifying
GO/GOP obligations in tandem with proposed TO/TOP clarification for determining impact is a step forward.
2. Are you aware of any Canadian provincial or other regulatory requirements that may need to be considered during this project in order to
develop a continent-wide approach to the standards? If yes, please identify the jurisdiction and specific regulatory requirements.

Yes:
No: X
Comments:
3. Are there any other concerns with this SAR that haven’t been covered in previous questions?
Yes:
No: X
Comments:
Comments received from Marc Donaldson, Tacoma Power
1. Do you agree with the scope and objectives of this SAR? If not, please explain why you do not agree, and, if possible, provide specific
language revisions that would make it acceptable to you.
Yes:
No: X
Comments: Tacoma Power suggests the following scope changes:
•
•
•

SDT should clarify CIP-005 R1 Part 1.5 with respect to encrypted communications, either in the G&TB or, directly within the requirement
language.
SDT could provide clarity on CIP-002 eliminating ambiguous language (“Facility” vs. “facility” & “location”) etc.
SDT should clarify whether CIP Exceptional Circumstance exception applies to CIP-004 R3 (PRA). Within the Guidelines and Technical
Basis, there is this clarifier “except for program specified exceptional circumstances that are approved by the single senior management
official or their delegate and impact the reliability of the BES or emergency response.” We suggest the SDT include an exception for CIP
Exceptional Circumstance specifically within the requirement language.

2. Are you aware of any Canadian provincial or other regulatory requirements that may need to be considered during this project in order to
develop a continent-wide approach to the standards? If yes, please identify the jurisdiction and specific regulatory requirements.
Yes:

No: X
Comments:
3. Are there any other concerns with this SAR that haven’t been covered in previous questions?
Yes:
No: X
Comments:

Standards Authorization Request Form
NERC welcomes suggestions to improve the reliability
of the bulk power system through improved reliability
standards. Please use this form to submit your request
to propose a new or a revision to a NERC’s Reliability
Standard.

When completed, email this form to:

[email protected]

Request to propose a new or a revision to a Reliability Standard
Title of Proposed Standard(s):

Modifications to CIP Standards

Date Submitted:

June 1, 2016

SAR Requester Information
Name:

Stephen Crutchfield

Organization:

NERC

Telephone:

609-651-9455

E-mail:

[email protected]

SAR Type (Check as many as applicable)
New Standard

Withdrawal of existing Standard

Revision to existing Standard

Urgent Action

SAR Information
Purpose (Describe what the standard action will achieve in support of Bulk Electric System reliability.):
The purpose of this project is to (1) consider the Version 5 Transition Advisory Group (V5TAG) issues
identified in the CIP V5 Issues for Standard Drafting Team Consideration (V5TAG Transfer Document)
and (2) address the Federal Energy Regulatory Commission (Commission) directives contained in Order
822. These revisions will increase reliability and security to the Bulk-Power System (BPS) by enhancing
cyber protection of BPS facilities.
Industry Need (What is the industry problem this request is trying to solve?):
The V5TAG, which consists of representatives from NERC, Regional Entities, and industry stakeholders,
was formed to issue guidance regarding possible methods to achieve compliance with the CIP V5
standards and to support industry’s implementation activities. During the course of the V5TAG’s
activities, the V5TAG identified certain issues with the CIP Reliability Standards that were more
appropriately addressed by the existing standard drafting team (SDT) for the CIP Reliability Standards.

SAR Information
The V5TAG developed the V5TAG Transfer Document to explain the issues and recommend that the SDT
consider them in future development activity.
On January 21, 2016, the Commission issued Order No. 822 approving revisions to the CIP version 5
standards and also directing NERC to develop modifications to address:
• Protection of transient electronic devices used at low-impact BES Cyber Systems;
• Protections for communication network components between control centers; and
• Refinement of the Low Impact External Routable Connectivity (LERC) definition.
The Commission did not provide a date by which the modifications for transient devices or
communication networks must be completed. For the LERC definition, however, the Commission
directed that NERC submit the modification within one year of the effective date of Order No. 822
(March 31, 2017).
Brief Description (Provide a paragraph that describes the scope of this standard action.)
The proposed project will consider the issues raised by the V5TAG in the V5TAG Transfer Document and
will address the Commission directives in Order No. 822 through modifications to the CIP standards. The
work will include development of Violation Risk Factors, Violation Severity Levels, and an
Implementation Plan for the modified standards and will meet the deadlines established by the
Commission in Order No. 822.
Detailed Description (Provide a description of the proposed project with sufficient details for the
standard drafting team to execute the SAR. Also provide a justification for the development or revision
of the standard, including an assessment of the reliability and market interface impacts of implementing
or not implementing the standard action.)
As stated above, the purpose of this project is to consider the V5TAG issues in the initial transfer
document V5TAG Transfer Document and address the Commission directives contained in Order 822.
For the directive on the LERC definition, the project is to respond within the deadline required in the
order.
As noted above, the V5TAG identified specific issues with the CIP V5 standards. The V5TAG drafted the
V5TAG Transfer Document to formally recommend that the SDT address these issues during standards
development to consider whether modifications can be made to the standard language. As outlined in
the V5TAG Transfer Document, the specific issues are as follows:
• Cyber Asset and BES Cyber Asset (BCA) Definitions – as foundational definitions within the CIP V5
standards, the understanding of Cyber Asset and BCA terms impacts the scope of the applicable
requirements. The V5TAG recommends the following enhancements:
• Clarify the intent of “programmable” in Cyber Asset.
• Clarify and focus the definition of “BES Cyber Asset” including:
 Focusing the definition so that it does not subsume all other cyber asset types.
 Considering a lower bound to the term ‘adverse’ in “adverse impact”.

Project 2016-02 Modifications to CIP Standards
June 1, 2016

2

SAR Information
Clarifying the double impact criteria (cyber asset affects a facility and that facility
affects the reliable operation of the BES) such that “N-1 contingency” is not a
valid methodology that can eliminate an entire site and all of its Cyber Assets
from scope.
Network and Externally Accessible Devices – V5TAG recommends improving clarity within the
concepts and requirements concerning Electronic Security Perimeters (ESP), External Routable
Connectivity (ERC), and Interactive Remote Access (IRA) including:
• The 4.2.3.2 exemption phrase “between discrete Electronic Security Perimeters”
• The meaning of the word ‘associated’ in the ERC definition.
• The applicability of ERC including the concept of the term “directly” used in the phrase
“cannot be directly accessed through External Routable Connectivity” within the
Applicability section.
• The IRA definition placement of the phrase “using a routable protocol” in the definition
and with respect to Dial-up Connectivity.
• The Guidelines and Technical Basis sentence, “If dial-up connectivity is used for
Interactive Remote Access, then Requirement R2 also applies.”
Transmission Owner (TO) Control Centers Performing Transmission Operator (TOP) Obligations –
V5TAG is aware of multiple interpretations of the language “used to perform the functional
obligation of” in CIP-002-5.1 Attachment 1, section 2.12 and recommends clarification of:
• The applicability of requirements on a TO Control Center that performs the functional
obligations of a TOP, particularly if the TO has the ability to operate switches, breakers
and relays in the BES.
• The definition of Control Center.
• The language scope of “perform the functional obligations of” throughout the
Attachment 1 criteria.
Virtualization – The CIP V5 standards do not specifically address virtualization. Because of the
increasing use of virtualization in industrial control system environments, V5TAG asked that the
SDT consider the CIP V5 standards and the associated definitions regarding permitted
architecture and the security risks of virtualization technologies.


•

•

•

The SDT shall also address the Order No. 822 directives by developing modifications to requirements in
CIP standards and the definition of LERC. The Commission directed the following:
•

Per paragraph 32, “...we direct that NERC, pursuant to section 215(d)(5) of the FPA, develop
modifications to the CIP Reliability Standards to provide mandatory protection for transient
devices used at Low Impact BES Cyber Systems based on the risk posed to bulk electric system
reliability. While NERC has flexibility in the manner in which it addresses the Commission’s
concerns, the proposed modifications should be designed to effectively address the risks posed by
transient devices to Low Impact BES Cyber Systems in a manner that is consistent with the riskbased approach reflected in the CIP version 5 Standards.”

Project 2016-02 Modifications to CIP Standards
June 1, 2016

3

SAR Information
•

•

Per paragraph 53, “…the Commission concludes that modifications to CIP-006-6 to provide
controls to protect, at a minimum, communication links and data communicated between bulk
electric system Control Centers are necessary in light of the critical role Control Center
communications play in maintaining bulk electric system reliability. Therefore, we adopt the
NOPR proposal and direct that NERC, pursuant to section 215(d)(5) of the FPA, develop
modifications to the CIP Reliability Standards to require responsible entities to implement
controls to protect, at a minimum, communication links and sensitive bulk electric system data
communicated between bulk electric system Control Centers in a manner that is appropriately
tailored to address the risks posed to the bulk electric system by the assets being protected (i.e.,
high, medium, or low impact).”
Per paragraph 73, “…the Commission concludes that a modification to the Low Impact External
Routable Connectivity definition to reflect the commentary in the Guidelines and Technical Basis
section of CIP-003-6 is necessary to provide needed clarity to the definition and eliminate
ambiguity surrounding the term “direct” as it is used in the proposed definition. Therefore,
pursuant to section 215(d)(5) of the FPA, we direct NERC to develop a modification to provide the
needed clarity, within one year of the effective date of this Final Rule….“

In addition, the SDT will review and address the CIP V5 requirements for CIP Exceptional Circumstances
exceptions.
Finally, the SDT will review the Guidelines and Technical Basis sections of the CIP V5 standards and
adjust where appropriate as well as correct any grammatical, punctuation, and/or formatting errors,
and make other errata changes to the CIP V5 standards, as necessary.

Reliability Functions
The Standard will Apply to the Following Functions (Check each one that applies.)
Regional Reliability
Organization

Conducts the regional activities related to planning and operations, and
coordinates activities of Responsible Entities to secure the reliability of
the Bulk Electric System within the region and adjacent regions.

Reliability Coordinator

Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.

Project 2016-02 Modifications to CIP Standards
June 1, 2016

4

Reliability Functions
Balancing Authority

Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area and
supports Interconnection frequency in real time.

Interchange Authority

Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority Areas.

Planning Coordinator

Assesses the longer-term reliability of its Planning Coordinator Area.

Resource Planner

Develops a >one year plan for the resource adequacy of its specific loads
within a Planning Coordinator area.

Transmission Planner

Develops a >one year plan for the reliability of the interconnected Bulk
Electric System within its portion of the Planning Coordinator area.

Transmission Service
Provider

Administers the transmission tariff and provides transmission services
under applicable transmission service agreements (e.g., the pro forma
tariff).

Transmission Owner

Owns and maintains transmission facilities.

Transmission
Operator

Ensures the real-time operating reliability of the transmission assets
within a Transmission Operator Area.

Distribution Provider

Delivers electrical energy to the End-use customer.

Generator Owner

Owns and maintains generation facilities.

Generator Operator

Operates generation unit(s) to provide real and Reactive Power.

Purchasing-Selling
Entity

Purchases or sells energy, capacity, and necessary reliability-related
services as required.

Market Operator

Interface point for reliability functions with commercial functions.

Load-Serving Entity

Secures energy and transmission service (and reliability-related services)
to serve the End-use Customer.

Project 2016-02 Modifications to CIP Standards
June 1, 2016

5

Reliability and Market Interface Principles
Applicable Reliability Principles (Check all that apply).
1. Interconnected bulk power systems shall be planned and operated in a coordinated manner
to perform reliably under normal and abnormal conditions as defined in the NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled within
defined limits through the balancing of real and Reactive Power supply and demand.
3. Information necessary for the planning and operation of interconnected bulk power systems
shall be made available to those entities responsible for planning and operating the systems
reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power systems
shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and maintained
for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems shall be
trained, qualified, and have the responsibility and authority to implement actions.
7. The security of the interconnected bulk power systems shall be assessed, monitored and
maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Does the proposed Standard comply with all of the following Market Interface
Principles?
1. A reliability standard shall not give any market participant an unfair competitive
advantage.
2. A reliability standard shall neither mandate nor prohibit any specific market
structure.
3. A reliability standard shall not preclude market solutions to achieving compliance
with that standard.
4. A reliability standard shall not require the public disclosure of commercially
sensitive information. All market participants shall have equal opportunity to
access commercially non-sensitive information that is required for compliance
with reliability standards.

Enter
(yes/no)
YES
YES
YES
YES

Related Standards
Standard No.

Project 2016-02 Modifications to CIP Standards
June 1, 2016

Explanation

6

Related Standards

Related SARs
SAR ID

Explanation

Regional Variances
Region

Explanation

FRCC
MRO
NPCC
RF
SERC
SPP RE
Texas
RE
WECC

Project 2016-02 Modifications to CIP Standards
June 1, 2016

7

Standards Authorization Request Form
When completed, email this form to:

[email protected]

NERC welcomes suggestions to improve the reliability
of the bulk power system through improved reliability
standards. Please use this form to submit your request
to propose a new or a revision to a NERC’s Reliability
Standard.

Request to propose a new or a revision to a Reliability Standard
Title of Proposed Standard(s):

Modifications to CIP Standards

Date Submitted:

March 9June 1, 2016

SAR Requester Information
Name:

Stephen Crutchfield

Organization:

NERC

Telephone:

609-651-9455

E-mail:

[email protected]

SAR Type (Check as many as applicable)
New Standard

Withdrawal of existing Standard

Revision to existing Standard

Urgent Action

SAR Information
Purpose (Describe what the standard action will achieve in support of Bulk Electric System reliability.):
The purpose of this project is to (1) consider the Version 5 Transition Advisory Group (V5TAG) issues
identified in the CIP V5 Issues for Standard Drafting Team Consideration (V5TAG Transfer Document)
and (2) address the Federal Energy Regulatory Commission (Commission) directives contained in Order
822. These revisions will increase reliability and security to the Bulk-Power System (BPS) by enhancing
cyber protection of BPS facilities.
Industry Need (What is the industry problem this request is trying to solve?):
The V5TAG, which consists of representatives from NERC, Regional Entities, and industry stakeholders,
was formed to issue guidance regarding possible methods to achieve compliance with the CIP version
5V5 standards and to support industry’s implementation activities. During the course of the V5TAG’s
activities, the V5TAG identified certain issues with the CIP Reliability Standards that were more
appropriately addressed by the existing standard drafting team (SDT) for the CIP Reliability Standards.

SAR Information
The V5 TAG developed the V5TAG Transfer Document to explain the issues and recommend that the
SDT consider them in future development activity.
On January 21, 2016, the Commission issued Order No. 822 approving revisions to the CIP version 5
standards and also directing NERC to develop modifications to address:
• Protection of transient electronic devices used at low-impact BES Cyber Systems;
• Protections for communication network components between control centers; and
• Refinement of the Low Impact External Routable Connectivity (LERC) definition.
The Commission did not provide a date by which the modifications for transient devices or
communication networks must be completed. For the LERC definition, however, the Commission
directed that NERC submit the modification within one year of the effective date of Order No. 822
(March 31, 2017).
Brief Description (Provide a paragraph that describes the scope of this standard action.)
The proposed project will consider the issues raised by the V5TAG in the V5TAG Transfer Document and
will address the Commission directives in Order No. 822 through modifications to the CIP standards. The
work will include development of Violation Risk Factors, Violation Severity Levels, and an
Implementation Plan for the modified standards and will meet the deadlines established by the
Commission in Order No. 822.
Detailed Description (Provide a description of the proposed project with sufficient details for the
standard drafting team to execute the SAR. Also provide a justification for the development or revision
of the standard, including an assessment of the reliability and market interface impacts of implementing
or not implementing the standard action.)
As stated above, the purpose of this project is to consider the V5TAG issues in the initial transfer
document V5TAG Transfer Document and address the Commission directives contained in Order 822.
For the directive on the LERC definition, the project is to respond within the deadline required in the
order.
As noted above, the V5TAG identified specific issues with the CIP V5 standards. The V5TAG drafted the
V5TAG Transfer Document to formally recommend that the SDT address these issues during standards
development to consider whether modifications can be made to the standard language. As outlined in
the V5TAG Transfer Document, the specific issues are as follows:
• Cyber Asset and BES Cyber Asset (BCA) Definitions – as foundational definitions within the CIP V5
standards, the understanding of Cyber Asset and BCA terms impacts the scope of the applicable
requirements. The V5TAG recommends the following enhancements:
• Clarify the intent of “programmable” in Cyber Asset.
• Clarify and focus the definition of “BES Cyber Asset” including:

Project 2016-02 Modifications to CIP Standards
March 9June 1, 2016

2

SAR Information
Focusing the definition so that it does not subsume all other cyber asset types.
Considering a lower bound to the term ‘adverse’ in “adverse impact”.
Clarifying the double impact criteria (cyber asset affects a facility and that facility
affects the reliable operation of the BES) such that “N-1 contingency” is not a
valid methodology that can eliminate an entire site and all of its Cyber Assets
from scope.
Network and Externally Accessible Devices – V5TAG recommends improving clarity within the
concepts and requirements concerning Electronic Security Perimeters (ESP), External Routable
Connectivity (ERC), and Interactive Remote Access (IRA) including:
• The 4.2.3.2 exemption phrase “between discrete Electronic Security Perimeters”
• The meaning of the word ‘associated’ in the ERC definition.
• The applicability of ERC including the concept of the term “directly” used in the phrase
“cannot be directly accessed through External Routable Connectivity” within the
Applicability section.
• The IRA definition placement of the phrase “using a routable protocol” in the definition
and with respect to Dial-up Connectivity.
• The Guidelines and Technical Basis sentence, “If dial-up connectivity is used for
Interactive Remote Access, then Requirement R2 also applies.”
Transmission Owner (TO) Control Centers Performing Transmission Operator (TOP) Obligations –
V5TAG is aware of multiple interpretations of the language “used to perform the functional
obligation of” in CIP-002-5.1 Attachment 1, section 2.12 and recommends clarification of:
• The applicability of requirements on a TO Control Center that performs the functional
obligations of a TOP, particularly if the TO has the ability to operate switches, breakers
and relays in the BES.
• The definition of Control Center.
• The language scope of “perform the functional obligations of” throughout the
Attachment 1 criteria.
Virtualization – The CIP V5 standards do not specifically address virtualization. Because of the
increasing use of virtualization in industrial control system environments, V5TAG asked that the
SDT consider the CIP-005 V5 standards and the associated definitions of Cyber Asset and
Electronic Access Point regarding permitted architecture and the security risks of network,
server and storage virtualization technologies.




•

•

•

The SDT shall also address the Order No. 822 directives by developing modifications to requirements in
CIP standards and the definition of LERC. The Commission directed the following:
•

Per paragraph 32, “...we direct that NERC, pursuant to section 215(d)(5) of the FPA, develop
modifications to the CIP Reliability Standards to provide mandatory protection for transient
devices used at Low Impact BES Cyber Systems based on the risk posed to bulk electric system
reliability. While NERC has flexibility in the manner in which it addresses the Commission’s
concerns, the proposed modifications should be designed to effectively address the risks posed by

Project 2016-02 Modifications to CIP Standards
March 9June 1, 2016

3

SAR Information

•

•

transient devices to Low Impact BES Cyber Systems in a manner that is consistent with the riskbased approach reflected in the CIP version 5 Standards.”
Per paragraph 53, “…the Commission concludes that modifications to CIP-006-6 to provide
controls to protect, at a minimum, communication links and data communicated between bulk
electric system Control Centers are necessary in light of the critical role Control Center
communications play in maintaining bulk electric system reliability. Therefore, we adopt the
NOPR proposal and direct that NERC, pursuant to section 215(d)(5) of the FPA, develop
modifications to the CIP Reliability Standards to require responsible entities to implement
controls to protect, at a minimum, communication links and sensitive bulk electric system data
communicated between bulk electric system Control Centers in a manner that is appropriately
tailored to address the risks posed to the bulk electric system by the assets being protected (i.e.,
high, medium, or low impact).”
Per paragraph 73, “…the Commission concludes that a modification to the Low Impact External
Routable Connectivity definition to reflect the commentary in the Guidelines and Technical Basis
section of CIP-003-6 is necessary to provide needed clarity to the definition and eliminate
ambiguity surrounding the term “direct” as it is used in the proposed definition. Therefore,
pursuant to section 215(d)(5) of the FPA, we direct NERC to develop a modification to provide the
needed clarity, within one year of the effective date of this Final Rule….“

In addition, the SDT will review and address the CIP V5 requirements for CIP Exceptional Circumstances
exceptions.
Finally, the SDT will review the Guidelines and Technical Basis sections of the CIP V5 standards and
adjust where appropriate as well as correct any grammatical, punctuation, and/or formatting errors,
and make other errata changes to the CIP V5 standards, as necessary.

Reliability Functions
The Standard will Apply to the Following Functions (Check each one that applies.)
Regional Reliability
Organization

Conducts the regional activities related to planning and operations, and
coordinates activities of Responsible Entities to secure the reliability of
the Bulk Electric System within the region and adjacent regions.

Reliability Coordinator

Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.

Project 2016-02 Modifications to CIP Standards
March 9June 1, 2016

4

Reliability Functions
Balancing Authority

Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area and
supports Interconnection frequency in real time.

Interchange Authority

Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority Areas.

Planning Coordinator

Assesses the longer-term reliability of its Planning Coordinator Area.

Resource Planner

Develops a >one year plan for the resource adequacy of its specific loads
within a Planning Coordinator area.

Transmission Planner

Develops a >one year plan for the reliability of the interconnected Bulk
Electric System within its portion of the Planning Coordinator area.

Transmission Service
Provider

Administers the transmission tariff and provides transmission services
under applicable transmission service agreements (e.g., the pro forma
tariff).

Transmission Owner

Owns and maintains transmission facilities.

Transmission
Operator

Ensures the real-time operating reliability of the transmission assets
within a Transmission Operator Area.

Distribution Provider

Delivers electrical energy to the End-use customer.

Generator Owner

Owns and maintains generation facilities.

Generator Operator

Operates generation unit(s) to provide real and Reactive Power.

Purchasing-Selling
Entity

Purchases or sells energy, capacity, and necessary reliability-related
services as required.

Market Operator

Interface point for reliability functions with commercial functions.

Load-Serving Entity

Secures energy and transmission service (and reliability-related services)
to serve the End-use Customer.

Project 2016-02 Modifications to CIP Standards
March 9June 1, 2016

5

Reliability and Market Interface Principles
Applicable Reliability Principles (Check all that apply).
1. Interconnected bulk power systems shall be planned and operated in a coordinated manner
to perform reliably under normal and abnormal conditions as defined in the NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled within
defined limits through the balancing of real and Reactive Power supply and demand.
3. Information necessary for the planning and operation of interconnected bulk power systems
shall be made available to those entities responsible for planning and operating the systems
reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power systems
shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and maintained
for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems shall be
trained, qualified, and have the responsibility and authority to implement actions.
7. The security of the interconnected bulk power systems shall be assessed, monitored and
maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Does the proposed Standard comply with all of the following Market Interface
Principles?
1. A reliability standard shall not give any market participant an unfair competitive
advantage.
2. A reliability standard shall neither mandate nor prohibit any specific market
structure.
3. A reliability standard shall not preclude market solutions to achieving compliance
with that standard.
4. A reliability standard shall not require the public disclosure of commercially
sensitive information. All market participants shall have equal opportunity to
access commercially non-sensitive information that is required for compliance
with reliability standards.

Enter
(yes/no)
YES
YES
YES
YES

Related Standards
Standard No.

Project 2016-02 Modifications to CIP Standards
March 9June 1, 2016

Explanation

6

Related Standards

Related SARs
SAR ID

Explanation

Regional Variances
Region

Explanation

FRCC
MRO
NPCC
RF
SERC
SPP RE
Texas
RE
WECC

Project 2016-02 Modifications to CIP Standards
March 9June 1, 2016

7

Unofficial Comment Form

Project 2016-02 Modifications to CIP Standards
Standards Authorization Request (SAR)
Do not use this form for submitting comments. Use the electronic form to submit comments on the
Project 2016-02 Modifications to CIP Standards SAR. The electronic comment form must be submitted by
8 p.m. Eastern, Thursday, June 30, 2016.
Additional information about this project is available on the Project 2016-02 Modifications to CIP
Standards page. If you have questions, contact either Senior Standards Developer, Stephen Crutchfield at
(609) 651-9455 or Al McMeekin at (404) 446-9675.
Background Information

On January 21, 2016, the Commission issued Order No. 822, Revised Critical Infrastructure Protection
Reliability Standards, approving seven CIP Reliability Standards and new or modified definitions. On
March 9, 2016, the NERC Standards Committee accepted the Standards Authorization Request (SAR) and
authorized the posting of the Modifications to CIP Standards SAR. It was posted for a 30-day informal
comment period March 23 – April 21, 2016. Based on the comments received, the Standard Drafting
Team (SDT) made minor revisions to the SAR which will be posted for an additional 30-day informal
comment period.
It was noted in the comments received on the SAR that the Virtualization issue involved more than just
CIP-005 standards and the defined terms Cyber Asset and Electronic Access Point. To correct this, the SDT
revised the sentence to: “Because of the increasing use of virtualization in industrial control system
environments, V5TAG asked that the SDT consider CIP-005 and the definitions of Cyber Asset and
Electronic Access Point the CIP V5 standards and the associated definitions regarding permitted
architecture and the security risks of network, server and storage virtualization technologies.”
Other commenters suggested that the SDT include provisions to address CIP Exceptional Circumstances. A
sentence was added to the SAR to include this topic: “In addition, the SDT will review and address the CIP
V5 requirements for CIP Exceptional Circumstances exceptions.”
A sentence was also added to the SAR allowing the SDT to make errata changes to the standards as
necessary and to correct grammatical, punctuation and/or formatting errors in the V5 Standards: “Finally,
the SDT will review the Guidelines and Technical Basis sections of the CIP V5 standards and adjust where
appropriate as well as correct any grammatical, punctuation, and/or formatting errors, and make other
errata changes to the CIP V5 standards, as necessary.”
In the previous version of the SAR, the Transmission Service Provide (TSP) Reliability Function was
checked as an applicable function. The TSP is not applicable under the CIP standards and this function was
corrected by unchecking the TSP Reliability Function in this version of the SAR. Similarly, the Distribution

Provider (DP) Reliability Function was left unchecked in the original SAR. The CIP Standards apply to the
DP, so this was corrected by checking the DP Reliability Function in this version of the SAR.
Questions

1. The CIP SDT revised the SAR based on the comments received in the previous posting as noted above.
Do you agree with these revisions to the SAR? If not, please explain why you do not agree, and, if
possible, provide specific language revisions that would make it acceptable to you.
Yes:
No:
Comments:

Unofficial Comment Form | Project 2016-02 Modifications to CIP Standards
Standards Authorization Request | June 2016

2

CIP V5 Issues for Standard Drafting Team Consideration
September 15, 2015

From experience in the V5 Transition Study and the on-going implementation efforts, the CIP Version 5
Transition Advisory Group (V5TAG) identified specific issues with the CIP Version 5 standard language that
caused difficulty in implementation of the requirements. In many cases, the V5TAG members found that
select language within the CIP Version 5 standards may be understood in multiple ways. These
interpretations appear to go beyond the intended flexibility of the standard language that is necessary to
accommodate the diverse nature of facts and circumstances across the electric sector. At this time, the
V5TAG proposes the following issues to be addressed by the CIP V5 Revisions drafting team (SDT) or other
appropriate team for standards development:
•

Cyber Asset and BES Cyber Asset definitions
The foundational definition for the CIP Version 5 standards is ‘Cyber Assets.’ When Cyber
Assets meet a threshold of Bulk Electric System (BES) impact they become ‘BES Cyber Assets
(BCA)’ which are grouped, by a Responsible Entity, into ‘BES Cyber Systems (BCS).’ Viewing
BCAs too broadly can lead to many thousands of devices in the typical utility becoming an
administrative burden for which few if any cyber security controls can actually be applied or
where there is limited associated cyber security risk. Vast amounts of effort would be
expended for these types of cyber assets to track and document their lack of capability for
even the most basic cyber security controls. Viewing BCAs too narrowly could lead to
missing consideration of devices that have a sufficient level of cyber capability and risk
impact.
The SDT should consider the definition of Cyber Asset and clarify the intent of “programmable” by
considering such factors as if a device is merely configurable, its executable code is not field
upgradable, or if its functionality can only be changed via physical DIP switches, swapping internal
chips, etc.
The SDT should consider clarifying and focusing the definition of “BES Cyber Asset” including:
a. Focusing the definition so that it does not subsume all other cyber asset types. Protected
Cyber Assets (PCA), by nature of being on the same network, can have some form of
adverse impact if misused. Electronic Access Control or Monitoring Systems (EACMS) if
misused or unavailable can have some form of adverse impact. This can result in a “hall of

mirrors” effect where everything in or that creates an Electronic Security Perimeter (ESP)
also meets the BCA definition.
b. Considering if there is a lower bound to the term ‘adverse’ in “adverse impact”. For
example, is the focus of a typical generating unit the servers and operator human machine
interfaces (HMI) and controller cabinets and Programmable Logic Controllers (PLCs) or is it
the thousands of individual sensors and transmitters throughout the plant?
c. Clarify the double impact criteria (cyber asset affects a facility and that facility affects the
reliable operation of the BES) such that “N-1 contingency” is not a valid methodology that
can eliminate an entire site and all of its Cyber Assets from scope.
•

Network and Externally Accessible Devices (ERC, ESP, IRA)
The SDT should consider the concepts and requirements concerning Electronic Security Perimeters
(ESP), External Routable Connectivity (ERC), and Interactive Remote Access (IRA) including:
a. Clarify the 4.2.3.2 exemption phrase “between discrete Electronic Security Perimeters.”
When there is not an ESP at the location, consider clarity that the communication
equipment considered out of scope is the same communication equipment that would be
considered out of scope if it were between two ESPs.
b. The word ‘associated’ in the ERC definition is unclear in that it alludes to some form of
relationship but does not define the relationship between the items. Striking ‘associated’
and defining the intended relationship would provide much needed clarity.
c. Review of the applicability of ERC including the concept of the term “directly” used in the
phrase “cannot be directly accessed through External Routable Connectivity” within the
Applicability section. As well, consider the interplay between IRA and ERC.
d. Clarify the IRA definition to address the placement of the phrase “using a routable
protocol” in the definition and clarity with respect to Dial-up Connectivity.
e. Address the Guidelines and Technical Basis sentence, “If dial-up connectivity is used for
Interactive Remote Access, then Requirement R2 also applies.”

•

Transmission Owner (TO) Control Centers Performing Transmission Operator (TOP) Obligations
CIP-002-5.1 Attachment 1 – Impact Reliability Criteria, sections 1.1, 1.2, 1.3, 1.4, 2.11, 2.12, and
2.13 employ the language “used to perform the functional obligation of”, and then lists the
functional registration. It was intended that this caveat would capture entities that perform
obligations of a specific registered function, whether they are registered for that function or not.
However, this language has caused confusion, especially in section 2.12 concerning TOP Control
Centers. The term “functional obligation” may be interpreted to have different meaning in a
variety of situations.

CIP Version 5 Memo Issues

2

One interpretation is for the defined term Control Center to be strictly associated with the
Balancing Authority (BA), Generator Operator (GOP), Reliability Coordinator (RC), and
Transmission Operator (TOP) functional registrations, and that control rooms or dispatch centers
owned and operated by Transmission Owners (TOs) with control of limited BES facilities would be
excluded. A second interpretation may expand or contract the applicability of the Control Center
designation, based on criteria that may not take into consideration overall risk to reliable
operations of the BES.
Early analysis found the potential for TOs (not Registered as TOPs) that only operate limited
breakers to be pulled in as medium impact Control Centers, even if the few Facilities they control
are low impact. (For example, an entity with one 161kV breaker in one substation and a second
161kV breaker in a different substation, both breakers associated with low impact Facilities.) As
currently written, low impact Control Centers are to be identified per criteria 3.1 and could be
commensurate with risk for these scenarios.
Areas for the SDT to address are:
a. CIP-002-5.1, Attachment 1 Control Center criteria for additional clarity and for possible
revisions related to TOP or TO Control Centers performing the functional obligations of a
TOP, in particular for small or lower-risk entities. A potential revision could be a size for
criteria 2.12, Control Centers performing the functional obligations of a TOP.
b. Clarify the applicability of requirements on a TO Control Center that perform the functional
obligations of a TOP, particularly if the TO has the ability to operate switches, breakers and
relays in the BES. Review the corresponding Guidelines and Technical Basis of CIP-002-5.1,
specifically: the “CIP-002-5” section paragraph starting with “Responsibility for the reliable
operation of the BES is spread across all Entity Registrations”; the table following that
paragraph; the “High Impact Rating (H)” section; and the criterion bullets for Control
Centers under the “Medium Impact Rating (M)” section.
c. The definition of Control Center (if pursued, recognize possible impacts on operations and
planning standards and/or glossary terms that include ‘Control Center’, for example, the
revised Glossary term for “System Operator” to be effective July 1, 2016).
d. The language scope of “perform the functional obligations of” throughout the Attachment
1 criteria.
•

Virtualization
The CIP Version 5 standards do not specifically address virtualization. However, because of the
increasing use of virtualization in industrial control system environments, questions around
treatment of virtualization within the CIP Standards are due for consideration.

CIP Version 5 Memo Issues

3

The SDT should consider revisions to CIP-005 and the definitions of Cyber Asset and Electronic
Access Point that make clear the permitted architecture and address the security risks of network,
server and storage virtualization technologies.

The transition to CIP Version 5 continues as the compliance deadline of April 1, 2016 approaches. The
V5TAG continues to discuss challenging issues being undertaken during the on-going implementation.
The group may find additional issues to transfer to the SDT for consideration.

CIP Version 5 Memo Issues

4

Standards Announcement

Project 2016-02 Modifications to CIP Standards
Standards Authorization Request
Informal Comment Period Open through June 30, 2016
Now Available

A 30-day informal comment period for the Project 2016-02 Standards Authorization Request (SAR), is
open through 8 p.m. Eastern, Thursday, June 30, 2016.
Commenting

Use the electronic form to submit comments on the SAR. If you experience any difficulties in using the
electronic form, contact Wendy Muller. An unofficial Word version of the comment form is posted on
the project page.
If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential error
messages, or system lock-out, contact NERC IT support directly at https://support.nerc.net/ (Monday –
Friday, 8 a.m. - 8 p.m. Eastern).
Next Steps

The drafting team will review all responses received during the comment period and determine the next
steps of the project
For more information on the Standards Development Process, refer to the Standard Processes
Manual.
For more information or assistance, contact either Senior Standards Developer, Stephen Crutchfield at
(609) 651-9455 or Al McMeekin at (404) 446-9675.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Comment Report
Project Name:

2016-02 Modifications to CIP Standards SAR June 2016

Comment Period Start Date:

6/1/2016

Comment Period End Date:

6/30/2016

Associated Ballots:

There were 21 sets of responses, including comments from approximately 21 different people from approximately 21 companies
representing 8 of the Industry Segments as shown in the table on the following pages.

Questions
1. The CIP SDT revised the SAR based on the comments received in the previous posting as noted above. Do you agree with these revisions
to the SAR? If not, please explain why you do not agree, and, if possible, provide specific language revisions that would make it acceptable
to you.

Organization
Name
Duke Energy

MRO

Name

Segment(s)

Colby Bellville 1,3,5,6

Emily
Rousseau

1,2,3,4,5,6

Region

FRCC,RF,SERC

MRO

Group Name

Duke Energy

MRO-NERC
Standards
Review
Forum
(NSRF)

Group Member
Name

Group
Member
Organization

Group
Member
Segment(s)

Group
Member
Region

Doug Hils

Duke Energy

1

RF

Lee Schuster

Duke Energy

3

FRCC

Dale Goodwine

Duke Energy

5

SERC

Greg Cecil

Duke Energy

6

RF

Joe Depoorter

Madison Gas
& Electric

3,4,5,6

MRO

Chuck Lawrence

American
1
Transmission
Company

MRO

Chuck Wicklund

Otter Tail
Power
Company

MRO

Dave Rudolph

Basin Electric 1,3,5,6
Power
Cooperative

MRO

Kayleigh Wilkerson

Lincoln
Electric
System

MRO

Jodi Jenson

Western Area 1,6
Power
Administration

MRO

Larry Heckert

Alliant Energy 4

MRO

Mahmood Safi

Omaha Public 1,3,5,6
Utility District

MRO

Shannon Weaver

Midwest ISO
Inc.

2

MRO

Mike Brytowski

Great River
Energy

1,3,5,6

MRO

Brad Perrett

Minnesota
Power

1,5

MRO

Scott Nickels

Rochester
4
Public Utilities

MRO

Terry Harbour

MidAmerican
Energy
Company

1,3,5,6

MRO

Tom Breene

Wisconsin
3,4,5,6
Public Service
Corporation

MRO

1,3,5

1,3,5,6

BC Hydro and Patricia
Power
Robertson
Authority

Northeast
Power
Coordinating
Council

Ruida Shu

1,2,3,5

1,2,3,4,5,6,7

BC Hydro

NPCC

RSC

Tony Eddleman

Nebraska
Public Power
District

1,3,5

MRO

Amy Casucelli

Xcel Energy

1,3,5,6

MRO

Patricia Robertson

BC Hydro and 1
Power
Authority

WECC

Venkataramakrishnan BC Hydro and 2
Vinnakota
Power
Authority

WECC

Pat G. Harrington

BC Hydro and 3
Power
Authority

WECC

Clement Ma

BC Hydro and 5
Power
Authority

WECC

Paul Malozewski

Hydro One.

1

NPCC

Guy Zito

Northeast
Power
Coordinating
Council

NA - Not
Applicable

NPCC

Mark J. Kenny

Eversource
Energy

1

NPCC

Gregory A. Campoli

NY-ISO

2

NPCC

Randy MacDonald

New
Brunswick
Power

2

NPCC

Wayne Sipperly

New York
Power
Authority

4

NPCC

David Ramkalawan

Ontario Power 4
Generation

NPCC

Glen Smith

Entergy
Services

4

NPCC

Brian Robinson

Utility
Services

5

NPCC

Bruce Metruck

New York
Power
Authority

6

NPCC

Alan Adamson

New York
State
Reliability
Council

7

NPCC

Colorado
Springs
Utilities

Southwest
Power Pool,
Inc. (RTO)

Shannon Fair 1,3,5,6

Shannon
Mickens

2

Colorado
Springs
Utilities

SPP RE

Edward Bedder

Orange &
Rockland
Utilities

1

NPCC

David Burke

UI

3

NPCC

Michele Tondalo

UI

1

NPCC

Sylvain Clermont

Hydro Quebec 1

NPCC

Si Truc Phan

Hydro Quebec 2

NPCC

Brian Shanahan

National Grid

1

NPCC

Michael Jones

National Grid

3

NPCC

Michael Forte

Con-Edison

1

NPCC

Kelly Silver

Con-Edison

3

NPCC

Peter Yost

Con-Edison

4

NPCC

Sean Bodkin

Dominion

4

NPCC

Silvia Parada Mitchell NextEra
Energy

4

NPCC

Brian O'Boyle

Con-Edison

5

NPCC

Kathleen M.
Goodman

ISO-NE

2

NPCC

Helen Lainis

IESO

2

NPCC

Laura Mcleod

NB Power

1

NPCC

Kaleb Brimhall

Colorado
Springs
Utilities

5

WECC

Charlie Morgan

Colorado
Springs
Utilities

3

WECC

Shawna Speer

Colorado
Springs
Utilities

1

WECC

Shannon Fair

Colorado
Springs
Utilities

6

WECC

Southwest
Power Pool
Inc.

2

SPP RE

Southwest
Power Pool
Inc

2

SPP RE

SPP
Shannon Mickens
Standards
Review Group
Jason Smith

ACES Power
Marketing

Warren Cross 1,3,4,5

Kim VanBrimer

Southwest
Power Pool
Inc

John Allen

City Utilities of 1,4
Springfield

SPP RE

Mike Buyce

City Utilities of 1,4
Springfield

SPP RE

Paul Mehlhaff

Sunflower
1
Electric Power
Corporation

SPP RE

TARA Lightner

Sunflower
1
Electric Power
Corporation

SPP RE

MRO,RF,SERC,SPP ACES
Brazos Electric
RE,Texas
Standards
Power Cooperative,
RE,WECC
Collaborators Inc.

BREC

1,5

Texas RE

Western Farmers
Electric Cooperative

WFEC

1,5

SPP RE

Old Dominion Electric ODEC
Cooperative

3,4

SERC

Golden Spread
Electric Cooperative

GSEC

5

SPP RE

Prairie Power, Inc.

PPI

1,3

SERC

Arizona Electric
Power Cooperative,
Inc.

AEPC

1

WECC

1

RF

Hoosier Energy Rural HE
Electric Cooperative,
Inc.

2

SPP RE

1. The CIP SDT revised the SAR based on the comments received in the previous posting as noted above. Do you agree with these revisions
to the SAR? If not, please explain why you do not agree, and, if possible, provide specific language revisions that would make it acceptable
to you.
Bob Reynolds - 10
Answer

No

Document Name
Comment
The SPP RE respectfully submits the following two comments to the Project 2016-02 Standards Authorization Request: (1) Reference the comments
submitted by the SPP Regional Entity (SPP RE) April 2016. In those comments, the SPP RE pointed out that Tie Line and other Transmission line flow
meters appear to have been unintentionally excluded from consideration under CIP-002-5.1, Impact Rating Criterion 2.5. This significant issue does not
appear to have been included in the revised SAR. The original SPP RE comment is restated here: “Impact Rating Criterion 2.5 excludes consideration
of BES Cyber Assets associated with Transmission lines through its use of “operating between 200 kV and 499 kV at a single station or substation”
language. In the instance where the tie line or other flow meter is associated with a Transmission Line operated between 200 and 499 KV in a
substation that satisfies the qualifications of Impact Rating Criterion 2.5, the meter will be excluded and not be categorized as Medium
Impacting. Additionally, some entities are proffering the argument that the flow meter is not a BES Cyber Asset because its loss or misuse will not affect
the reliable operation of the Transmission Facilities in the substation where the meter resides, overlooking the impact the loss of meter information may
have on Control Center operations including ACE calculation, security-constrained generation dispatch, AGC, and Situational Awareness. An additional
Criterion, specific to Transmission line flow meters, may be required to address this issue.” (2) The SPP RE notes that the revised SAR still makes no
mention of the consideration of submitted and outstanding Requests for Interpretation. NERC staff has stated publicly that the RFIs would be
addressed by the Standards Drafting Team. The SPP RE is aware that at least one of the issues discussed in the April 2016 comments to the SAR has
been formally submitted as a Request for Interpretation. To fail to consider outstanding RFIs in the course of modifying the CIP Standards under this
SAR would be a missed opportunity to address significant confusion regarding the expectations of the Requirements under question.
Likes

0

Dislikes

0

Response

Mike Smith - 1,3,5,6
Answer

No

Document Name
Comment
For virtualization, Manitoba Hydro does not agree with NERC prescribing specific system architecture, technologies or designs. SDT should continue to
focus on identifying requirements to meet specific objectives for the virtualization.
Manitoba Hydro agrees with adding more CIP V5 requirements exceptions for CIP Exceptional Circumstance.
Likes
Dislikes

0
0

Response

Emily Rousseau - 1,2,3,4,5,6 - MRO, Group Name MRO-NERC Standards Review Forum (NSRF)
Answer

No

Document Name
Comment
The NSRF agrees with the drafting team’s addition of “reviewing and addressing the CIP V5 requirements for CIP Exceptional Circumstances
exceptions” to the SAR. However, we request clarification on the scope of Guidelines and Technical Basis sections that may be changed with updates
to the associated Standards within this project. We believe that addressing all CIP V5 Guidelines and Technical Basis sections within the scope of this
revision may make the project unwieldy as it already contains a substantial scope of work to address FERC directives. We suggest that only Guidelines
and Technical Basis sections related to standards language updates should be addressed within the scope of this project.
Likes

0

Dislikes

0

Response

Patricia Robertson - 1,2,3,5, Group Name BC Hydro
Answer

No

Document Name
Comment
CIP-002-5.1
A) The topic of adverse impact should provide more clarity on the real-time requirement as well.
B) Per Medium Impact criterion 2.3 for generation resources, need further clarity on the extent of planning horizon > 1 year contingencies to consider
regarding the determination of BES Adverse Reliability Impacts to a given Interconnection. The Guidelines and Technical basis of CIP-002-5.1
reference as an example, TPL-003 Category C3 contingency system studies but otherwise, there is no lower or upper limit indicated regarding the depth
of contingencies to be considered. The limit is currently subjective for Transmission Planners and Planning Coordinators.
Furthermore, per the definition of Adverse Reliability Impact, there is direct reference to impacts on a given Interconnection but it is not clear whether
this is only considering inter-tie paths or general BES impacts beyond a specific BES location (i.e. generation plant or substation). The Guidelines and
Technical basis state only widespread impacts are to be considered instead of localized impacts but it is not clear what is considered ‘widespread’.
CIP-005-5 The fundamental concepts of the intermediate system are omitted or subjective. The standards should define what the requirements are for
this system, whether it is strictly a jump host (not mentioned in the standards) or can have more functionality (i.e. software installed upon it). This should
be included in the ’Network and Externally Accessible Devices’ section.
CIP-005-5/CIP-003-6 A clear exemption is given for low impact systems is given in CIP-003-6 Guidelines and Technical Basis (CIP-006-6 pg 28) “To
future-proof the standards, and in order to avoid future technology issues, the definitions specifically exclude “point-to-point communications between
intelligent electronic devices that use routable communication protocols for time-sensitive protection or control functions between Transmission station
or substation assets containing low impact BES Cyber Systems,” such as IEC 61850 messaging.” The ‘Network and Externally Accessible Device’”

section should address this topic for medium impact BCS/BCA as well. These technologies are not limited to low impact systems and guidance should
be provided.
CIP-007-5: Regarding security patch applications and cyber vulnerability assessments:
•

Certain legacy devices (i.e. HMIs, PLCs, etc.) can be in a “fragile” state and are at high-risk regarding the application of software updates, which
include cyber security related updates. There is a demonstrable risk in breaking their functionality which can have an adverse impact on the
BES as the only solution is to replace the device entirely or at best, perform a complete reset of the device. This is mainly due to bugs that
could be introduced by vendors through their patches (not enough regression testing done by the vendors) and for which even testing prior to
implementation in a production environment may not identify all such bugs prior to implementation. Recommend providing guidance around
how to handle the application of cyber security patches to these “fragile” devices and to potentially not mandate security patch applications in all
cases where there may be demonstrable evidence of adverse BES impact.

•

Further guidance is required within the Guidelines and Technical basis on the exact difference between a ‘paper’ exercise cyber vulnerability
assessments (CVA) and ‘active’ CVA with respect to Medium Impact facilities and the extent an entity is expected to go to achieve this. It has
been communicated by Regional Entities’ audit approach that paper scans must incorporate some active component to pull configuration
settings, etc. from a device for analysis. For legacy devices (namely firmware devices), these active component scans can also pose a risk in
breaking the functionality of said devices, which can cause adverse impact to the BES. Recommend including guidance around how to handle
CVAs pertaining to these firmware devices without potentially breaking their functionality.

Likes

0

Dislikes

0

Response

Chris Mattson - 1,3,4,5,6
Answer

No

Document Name
Comment
Tacoma asks that the SDT consider removing the final two sentences from the last paragraph of CIP-005-5, Guidelines and Technical Basis, Section 4
– Scope and Applicability of the CIP Cyber Security Standards, Requirement R1. These are shown in bold below for identification:
The standard adds a requirement to detect malicious communications for Control Centers. This is in response to FERC Order No. 706, Paragraphs 496503, where ESPs are required to have two distinct security measures such that the BES Cyber Systems do not lose all perimeter protection if one
measure fails or is misconfigured. The Order makes clear that this is not simply redundancy of firewalls, thus the SDT has decided to add the security
measure of malicious traffic inspection as a requirement for these ESPs. Technologies meeting this requirement include Intrusion Detection or
Intrusion Prevention Systems (IDS/IPS) or other forms of deep packet inspection. These technologies go beyond source/destination/port rule
sets and thus provide another distinct security measure at the ESP.
Tacoma is asking the SDT to consider that there are other methods and technologies for detecting malicious traffic in addition to deep packet
inspection. This change to the G&TB would make the standard more consistent with the language in FERC Order No. 706, Paragraph 501 which
indicates that it is not the commission’s intent to mandate any specific mechanism to be the second security measure. The language from the FERC
order is shown below for reference and the pertinent language is shown in bold:
Paragraph 501. In response to SDG&E and Entergy, in stating that the placement of security measures in front of systems provides a layer of protection
for those systems, the Commission was not giving priority to “in front” measures. In fact, the Commission acknowledged in the CIP NOPR that defense

in depth measures are generally integrated within and constitute part of a system or program. In commenting that defense in depth measures may also
be effectively placed in front of a system, the Commission intended only to acknowledge that there are multiple ways to implement a defense in depth
strategy. The Commission is not mandating any specific mechanism to be the second security measure. We are also not requiring uniformity
of security measures, only that each responsible entity have at least two security measures unless it is not technically feasible to do so. The
revised CIP Reliability Standard should allow enough flexibility for a responsible entity to take into account each site’s specific environment. The
Commission believes that this, in conjunction with the allowance of technical feasibility exceptions, alleviates FPL Group’s concern that the
Commission’s proposal is a “one size fits all” approach.
Also, the SDT should clarify CIP-005 R1 Part 1.5 with respect to encrypted communications either in the G&TB or directly within the requirement
language. It important that the SDT clarify how to detect malicious communications when the communications includes encrypted information that is not
readily decrypted to allow inspection.
Likes

0

Dislikes

0

Response

Maryclaire Yatsko - 1,3,4,5,6 - FRCC
Answer

No

Document Name
Comment
.
Although Seminole concurs with all items currently listed in the draft Standards Authorization Request, Seminole recommends that additional items
should be included in the SAR. Seminole thanks the SAR team for addressing our previous comments, in addition to those of others, related to
Exceptional Circumstances and the Guidelines and Technical Basis.

While the changes addressed are necessary to address mandatory requirements from FERC, this SAR does not address the fundamental deficiencies
in the current CIP standards. Until these fundamental issues are addressed, the electric sector will continue to struggle implementing the current
standard, be faced with inefficiencies in the standard that do not improve cyber and physical security, and have difficulty using new and improved
capabilities in a rapidly evolving marketplace.
Seminole recommends adding the following items to the SAR:
1. Update CIP-002 Requirements and the Guidelines and Technical Basis section to clarify the expectations in complying with this standard. Update
evidence requirements to make clear the expectations of the standard. Clarify attachment 1 to address V5TAG Lessons Learned and FAQs. Resolve
issues in the Guidelines and Technical Basis that are inconsistent with the definition of BES Cyber Asset and BES Cyber System.

2. The SDT will review applicable Standards and Requirements to clarify the SDT’s intent for management of shared Facilities when more than one
Registered Entity owns Facilities inside a single asset. Interconnections within the BES and with Distribution Providers within a single asset create
significant complexity for entities in some regions. This results in a need for a significant number of MOU, CFR, or JRO that both complicates
compliance and the audit process.

3. The SDT will review the Measures in the CIP V5 standards and adjust where appropriate to allow an entity that provides evidence consistent with the
identified measures to determine compliance if no deficiencies are identified in the provided evidence. This may include modifying measures to match
the CIP Version 5 Evidence Request or by clarifying either the measures or Guidelines and Technical basis to clarify intent for adjustment of the
evidence request.

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Julie Hall - 6
Answer

No

Document Name
Comment
Comments: Entergy requests that more detail be provided regarding the actions that will be considered regarding CIP Exceptional Circumstances. Is
more specificity regarding what constitutes a CIP Exceptional Circumstance being considered? Is more specificity regarding how to declare and
document a CIP Exceptional Circumstance being considered? Will more clarity regarding standards affected by CIP Exceptional Circumstance,
including a possible increase of applicable standards, be considered? Some particular questions Entergy has regarding the scope of standards affected
by CIP Exceptional Circumstances include:
•

CIP-004-5.1 R3 does not include the “except during CIP Exceptional Circumstances” language, yet the Guidelines and Technical Basis section
states “Each Responsible Entity shall ensure a personnel risk assessment is performed for all personnel who are granted authorized electronic
access and/or authorized unescorted physical access to its BES Cyber Systems, including contractors and service vendors, prior to their being
granted authorized access, except for program specified exceptional circumstances that are approved by the single senior management official
or their delegate and impact the reliability of the BES or emergency response.” The language in the Guidelines and Technical Basis seems
logical as it may not be feasible to validate PRA’s during a widespread emergency response (i.e. a hurricane) especially when response support
is provided by many other companies and/or vendors across the country. It is requested that the “except during CIP Exceptional Circumstances”
language be added to the appropriate parts of CIP-004-5.1 R3, particularly CIP-004-5.1 R3 Part 3.5.

•

The “except during CIP Exceptional Circumstances” language exists in CIP-006-5 R2 Part 2.1 and Part 2.2 which states that logging and
continuous escorting of visitors is not required during CIP Exceptional Circumstances. However, none of the CIP-006-5 R1 parts include the
“except during CIP Exceptional Circumstances” language, which in turn requires alerting, monitoring, logging of access approved individuals.
This may not be feasible during a widespread event that results in total loss of power at many sites over a widespread geographical area. It is
requested that the “except during CIP Exceptional Circumstances” language be added to the appropriate parts of CIP-006-5, particularly R1 to
ensure consistency across CIP-006-5.

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Scott Brame - 3,4,5 - SERC
Answer

No

Document Name
Comment
The following comments are from my CIP SME.
• Per paragraph 73, “…the Commission concludes that a modification to the Low Impact External Routable Connectivity definition to reflect the
commentary in the Guidelines and Technical Basis section of CIP-003-6 is necessary to provide needed clarity to the definition and eliminate ambiguity
surrounding the term “direct” as it is used in the proposed definition. Therefore, pursuant to section 215(d) (5) of the FPA, we direct NERC to develop a
modification.
This is where I believe FERC’s order falls short. Although, the definition for LERC needs to be improved and needs to reflect the commentary
in the Guidelines and Technical Basis section of CIP-003-6. In my opinion, the requirements for low impact critical assets is incomplete. It
appears like the SDT was rushed to provide requirements for low impact. Although, the SDT included some basic requirements for low
impact critical assets they should have also included requirements for malware and virus protections. In addition, there should be
requirements for logging and auditing of systems and system access. These requirements do not need to be as stringent and comprehensive
as what is required for medium and high impact critical assets, but they should also be required for low impact critical assets.
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Warren Cross - 1,3,4,5 - MRO,WECC,Texas RE,SERC,SPP RE,RF, Group Name ACES Standards Collaborators
Answer

No

Document Name
Comment
Thank you for the opportunity to provide comments regarding the Standards Authorization Request (SAR) in response to FERC Directives and v5TAG
recommendations. While the current SAR attempts to resolve issues around LERC, virtualization and communication protections, ACES believes the
SAR doesn’t adequately detail the areas of concern for LERC and fails to allow for technology advances, which may ultimately hinder industry adoption
of more secure solutions to address cyber security threats.
How LERC will be defined based upon the ability to communicate and interactive communication capabilities between Low Impact Facilities that have
BES Cyber Assets associated with them has yet to be fully vetted. The ability to communicate with a BES Cyber Asset isn’t the same as interacting with
the BES Cyber Asset. This distinction needs to be clearly defined. Another issue for Low Impact BES Cyber Systems is the need for a common
definition of when serial devices are in scope and not in scope for consistent industry implementation.
Host-based security applications, advanced security threat analysis services, and cloud-based networks are not in scope for the SAR. There are
mechanisms in place in the CIP standards that allow for exceptions, such as TFEs and CIP Exceptional Circumstances. ACES believes that these
definitions could be expanded to include technology that exists outside of the standard to be able to be used, with approval, in order to provide the entity
with a stronger defense in depth security profile.

If the drafting team proposes to modify definitions, they should consider a process that is non-prescriptive and provides flexibility for registered entities
to decide how to best defend against cyber security threats based on their risk analysis. There may be significant advantages for industry to adopt new
emerging security applications and cloud based security services. The CIP standards should not limit the tools or technology available to mitigate cyber
security risks. We ask the drafting team to consider how the revisions to the CIP standards would allow for the power industry to match the security
best practices of other industries against the latest security threats and vulnerabilities.

Thank you for your time and attention regarding this SAR.

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Erika Doot - 1,5
Answer

No

Document Name
Comment
The Bureau of Reclamation agrees with the drafting team’s addition of “reviewing and
addressing the CIP V5 requirements for CIP Exceptional Circumstances exceptions” to the SAR.
However, Reclamation requests clarification on the scope of Guidelines and Technical Basis sections
that may be changed with updates to the associated Standards within this project. Reclamation
believes that addressing all CIP V5 Guidelines and Technical Basis sections within the scope of this
revision may make the project unwieldy as it already contains a substantial scope of work to address
FERC directives. Reclamation suggests that only Guidelines and Technical Basis sections related to
standards language updates should be addressed within the scope of this project.
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Shannon Fair - 1,3,5,6, Group Name Colorado Springs Utilities
Answer
Document Name

Yes

Comment
CSU supports the standard dradting teams updates to the SAR.
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Thomas Foltz - 3,5
Answer

Yes

Document Name
Comment

AEP suggests that the SDT include separate balloting and commenting for Guidelines and Technical Basis throughout this project. With the
development of implementation guidance, AEP is unsure whether the Guidelines and Technical Basis document should remain a part of the
codified Reliability Standard. If it does, then stakeholders should have the ability to vote and comment on the contents specifically.

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Shannon Mickens - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

Yes

Document Name
Comment
As our review group evaluated the revised SAR, we noticed that the V5TAG recommends providing clarity in the definitions of the two terms ‘External
Routable Connectivity (ERC)’ and ‘Interactive Remote Access (IRA). We suggest the drafting team either develop a new SAR or modify this one in
order to require the term ‘External Routable Connectivity (ERC)’ to have the acronym and revised definition updated in the NERC Glossary and also
included in the Rules of Procedure (RoP) for consistency and proper alignment. Additionally, we suggest the drafting team edit the SAR to review the
Rules of Procedure where the acronym (IRA), is used to refer to ‘Inherent Risk Assessment’ wheras the CIP Standards refer to a term ‘Interactive
Remote Access’ but do not use an acronym. There could be confusion if an acronym is used in either document for either of these terms. We suggest
not using an acronym for either term in any document.
We also request clarification on why there is a specific deadline for updating the definition of LERC.
As for the term ‘Low Impact External Routable Connectivity-LERC’, we suggest the drafting team edit the SAR to clarify that a revised definition will also
be included in the RoP.

When clarifying the ‘lower bound’ clarification in “adverse impact”, we would appreciate a clear example (beyond the one used in the V5TAG document)
that explains this concept.
We also request the SDT review or consider creating definitions or otherwise providing clarity for ‘custom software’ and the use of ‘scripts’. There are
several instances of regional inconsistencies in the scope of ‘scripts’ that should be included in an entity’s baseline. Direction or clarity from this drafting
team would be appreciated. Additional requirements or definitions may not be required, but guidance, rationale, or technical background would be
beneficial.
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Stephanie Little - 1,3,5,6
Answer

Yes

Document Name
Comment
Arizona Public Service (AZPS) appreciates the opportunity to comment on the revised SAR, and submits the following comments previously provided in
response to the initial SAR. Although AZPS generally supports the scope as described in the SAR, we believe that there are additional clarifications
that should be considered beyond those detailed in the FERC Oder 822 and the CIP Version 5 Transition Advisory Group (V5TAG) considerations.
AZPS believes the industry would benefit from clarification of the definition of the following terms:
•

Transmission Facility – Transmission Facility is not a defined term. Although Facility is a defined term, AZPS does not believe that the Facility
definition aligns with the standard’s intent. AZPS suggests that a definition be provided by the Standard Drafting Team (SDT).

•

Programmable - The SDT should consider defining programmable to clarify that a device would not be included simply because it was
configurable, e.g., has functionality that can be changed locally.

AZPS would also like to suggest that the SDT clarify the intent of the grouping BCAs into BCS by leveraging the logically based perimeter security
controls at the Electronic Security Perimeter (ESP) as well as local, device specific security controls per each BES Cyber Asset’s (BCA) capability.
AZPS would also like to add some additional comments to the discussion in the V5TAG CIP V5 Issues for Standard Drafting Team Consideration
document.
•

AZPS recommends that the SDT consider not defining “adverse impact” or defining a lower bound thereof within the definition of BES Cyber
Asset, but to revise the body of CIP standards and/or applicable defined terms to utilize already defined terms such as “Adverse Reliability
Impact.” Such would facilitate consistency as well as clarity regarding the N-1 contingency issue and other issues regarding that term identified
by the V5TAG.

•

AZPS believes that when BES Cyber Assets (BCA), such as relays, RTUs, and others, are connected via serial links to IP converters and/or IPenabled security gateways, it would be appropriate to consider those elements downstream of the security gateways as BCA that do not have
External Routable Connectivity (ERC). This is appropriate because the IP- converters and/or IP-enable security gateways require
authentication and provide a protocol break. AZPS believes accurate and timely guidance related to serially connected devices supports the
overall goal of providing appropriate and effective cyber security controls; thus, improving reliability.

•

AZPS supports the CIP V5TAG analysis regarding virtualization. Virtualization is an effective tool for utilities and consideration should be given
to ensuring that flexibility is maintained. An approach should consider the required outcome rather than the specifics of how that outcome is
achieved.

AZPS also notes that NERC’s webpage for this SAR “Project 2016-02 Modifications to CIP Standards”, as of 4/11/2016, states the following:
"Also the scope of this work will incorporate existing and future RFIs relating to the CIP-002 through CIP-011 family of standards.”
AZPS does not believe any RFIs are addressed in the current SAR. We recommend updating the SAR to reference existing submitted RFIs as
appropriate. Finally, AZPS recommends removal from the SAR of functional registrations that are no longer included in the Compliance Registry, e.g.,
Interchange Authority, Load-Serving Entity and Purchasing-Selling Entity.
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Ruida Shu - 1,2,3,4,5,6,7 - NPCC, Group Name RSC
Answer

Yes

Document Name
Comment
We support the revisions to the SAR.
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Andrea Jessup - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
BPA agrees with the revised scope of the SAR with three exceptions regarding the “Transmission Owner (TO) Control Centers Performing
Transmission Operator (TOP) Obligations –” bullet and sub-bullets:
1. BPA proposes that the SDT clearly identify which function holds the compliance documentation responsibilities.
2. BPA believes the NERC Glossary definition of control center is adequate and should not be revised. The current definition maintains the
distinction between control centers and substations.
3. BPA believes no clarification of the ‘performs the functions of’ language is needed for Attachment 1.

Likes

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larry brusseau - 1
Answer

Yes

Document Name
Comment

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Colby Bellville - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment

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Laura Nelson - 1
Answer

Yes

Document Name
Comment

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Darin Ferguson - 1,3,5,7 - SERC

Answer

Yes

Document Name
Comment

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Rachel Coyne - 10
Answer
Document Name
Comment
Texas RE supports those comments suggesting that this project should identify continued areas for improvement within the existing CIP V5 Standards
and avoid engaging in a wholesale “rewrite” of the CIP Standards at this point in time. Consistent with this principle, the Standards Drafting Team
(SDT) has properly identified the FERC directives from Order No. 822 and the various V5 Tag recommendations as the framework upon which to base
the scope of this project.

However, Texas RE believes that the SDT should also take the opportunity to address two other areas to develop a strong record and enhance
regulatory certainty around the application of the new suite of CIP Standards becoming effective on July 1, 2016. First, Texas RE agrees with those
comments suggesting that the Commission should consider the interaction among the various CIP Standards, including the interaction between CIP002-5.1 and the rest of the Standards as a group. The SDT may specifically wish to address the interplay between the various bright-line impact
categories in the CIP-002-5.1 Standard and the risk assessments associated with the other CIP-005 Standards.

Second, Texas RE recommends that the SDT explicitly consider and determine whether aspects of the various supporting materials associated with the
CIP Standards, including a number of Lessons Learned, FAQs, and other guidance documents should be incorporated directly into the CIP Standards
themselves. For example, the October 2015 CIP V5 Consolidated FAQs and Answers provided that “HVAV, UPS, and other support systems . . . will
not be the focus of compliance monitoring” unless such systems are within an Electronic Security Perimeter. (p. 7). However, some HVAC and other
systems may fall within the definition of a BES Cyber System and be subject, among other things, to the categorization requirements set forth in CIP002-5.1, R1. The SDT could add clarity to the Standards by explicitly considering whether HVAC and other support systems should be (or is already)
included within the BES Cyber System definition or conversely carved out of the CIP Standards in certain circumstances. This will encourage reliability
and regulatory certainty by permitting entities to look to the Standard language to understand their compliance obligations, as well as produce a
transparent record of the rationale underpinning a particular approach.

Changes to SAR Redlined Language
In addition to Texas RE’s suggestions regarding the scope of this project, Texas RE also suggests two additional revisions to the revised SAR
language. First, the scope of the CIP Exceptional Circumstances exception language appears vague. Texas RE presumes that the SDT incorporated
the recommendations from the Edison Electric Institute and others suggesting primarily that the SDT should consider whether the CIP Exceptional
Circumstances exception should be added to additional CIP V5 requirements. Texas RE recommends making this more explicit by revising the SAR

language to state: “In addition, the SDT will review and address whether it is appropriate to include CIP Exceptional Circumstances exceptions within
additional CIP V5 requirements.”

Second, Texas RE supports the SDT’s inclusion of language in the SAR permitting the SDT to make non-substantive changes to the Standards and
Guidelines and Technical Basis sections to correct grammar, punctuation, and/or formatting errors. However, it is possible to read the proposed
language to suggest that “errata” changes are somehow broader than such non-substantive revisions. Texas RE would suggest clarifying that “errata”
changes to the CIP V5 Standards by inserting the word “non-substantive” in front of the word “errata” in the existing redline language.
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Posting Document/Unofficial Comment Form

Project 2016-02 Modifications to CIP Standards
Communication Networks

Do not use this form for submitting comments. Use the electronic form to submit comments
on the Standard Drafting Team’s (SDT) approach and draft language to address the Federal Energy
Regulatory Commission (Commission or FERC) directive regarding Communication Networks. The
electronic form must be submitted by 8 p.m. Eastern, March 13, 2017.
To minimize the number of posted documents, the SDT included everything in this single document
with the questions following the suggested approach and draft language.
Additional information is available on the project page. If you have questions, contact Senior Standards
Developer, Al McMeekin (via email) or at (404) 446-9675.
Introduction

On January 21, 2016, the Commission issued Order No. 822 approving seven CIP Reliability Standards
and new or modified definitions and issuing certain directives requesting modifications to the CIP
Reliability Standards. The focus of this informal comment period is on the directive from the
Commission requesting NERC to “develop modifications to the CIP Reliability Standards to require
responsible entities to implement controls to protect, at a minimum, communication links and sensitive
bulk electric system data communicated between bulk electric system Control Centers in a manner that
is appropriately tailored to address the risks posed to the bulk electric system by the assets being
protected (i.e., high, medium, or low impact).” (Order 822, Paragraph 53)
The SDT is working through an evaluation process to determine appropriate actions to take in order to
meet the Commission’s directive. The informal posting reflected herein represents the initial
exploratory efforts to research the scope and objectives of the draft standard and associated
requirements. The SDT will consider all comments received from industry stakeholders and will revise
the draft language accordingly. The revised language may expand in scope and the security objective(s)
may be modified to align with industry comments.
The SDT is considering the following assumptions and is requesting stakeholder input through the
comment form below on the validity of these assumptions:
•

A formal definition of “sensitive BES data” is not required because Responsible Entities are
already required to identify operational reliability data in FERC-approved Reliability Standards
TOP-003-3 and IRO-010-2.

•

Data at rest within a BES Cyber System is already afforded protections in existing CIP standards
(CIP-003, 005, 007, etc.), is perishable, and has a diminished need for protection over time.

•

The existing definition of Control Center is adequate.

In addressing the directive, the SDT’s initial efforts are focused specifically on the communication links
transmitting sensitive data between Control Centers. While the directive language in Order 822
specifically references modifications to CIP-006-6 which handles physical security controls, the SDT is
considering language around logical protections of these communication links through a programmatic
approach. Because these requirements will apply to Control Centers at all impact levels (high, medium,
and low), the SDT is also proposing to create a new CIP Reliability Standard, CIP-012-1, to address the
protection of sensitive BES data transmitted between Control Centers. While the SDT is not yet certain
of the full scope of requirements necessary to address the directive found in paragraph 53 of Order
822. Some of the draft language the SDT is currently considering and requesting stakeholder feedback
on is as follows.
Draft Language

The Responsible Entity shall implement one or more documented plan(s) that achieve the security
objective to protect confidentiality and integrity 1 of data required for reliable operation of the BES. The
plan applies to data being transferred across communication networks between Control Centers, both
inter-entity and intra-entity and shall include each of the applicable parts below:
1.1

Procedure(s) to identify the communication networks requiring protections;

1.2

Procedure(s) for defining the boundaries of communication networks transmitting data required
for reliable operation identified in 1.1, if applicable;

1.3

Method(s) for protecting communication networks between Control Centers identified in 1.1,
where technically feasible.

Examples of evidence may include, but are not limited to, plan documents; documentation such as
representative diagrams, configuration settings or demonstration materials to illustrate and verify that
confidentiality and integrity of data transmitted between Control Centers has been protected and
satisfies the security objective. Information gathering during walk-downs or visual inspections can
validate the implementation of necessary controls. The documentation as referenced may be used to
further validate where protections may or may not be required.
Draft Guidance

This draft language mandates that communication networks required for reliable operation between
Control Centers be identified and protected. The Responsible Entity has flexibility in determining how
to implement the draft language.
In developing plan(s), the number of plan(s) and their content should be guided by a Responsible
Entity's management structure and operating conditions. Each Responsible Entity is required to
implement one or more documented plan(s) that achieve the stated security objective of protecting the
1 NIST Special Publication 800-53A : Revision 4, Appendix B : http://nvlpubs.nist.gov/nistpubs/SpecialPublications/NIST.SP.800-53Ar4.pdf

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confidentiality and integrity of data that is required for reliable operation and is transmitted between
Control Centers. To achieve this objective, the Responsible Entity is required to document and
implement plan(s) that include a procedure(s) for the identification of communication networks that
transmit operational reliability data between Control Centers. The plan(s) should identify the applicable
communication networks both within the entity’s footprint, and any applicable networks between
Responsible Entities. When defining the procedures for identifying applicable communication networks,
the Responsible Entity should ensure that the methods chosen include rationale supporting the
identification of such communication networks. As one possible solution, the Responsible Entity could
apply CIP-002 criteria to identify all inter-Control Center and intra-Control Center communication links
that could adversely impact the reliable operation of the Control Center within 15 minutes. Another
possible solution to identifying in-scope communication networks is to take a data-centric approach.
The Responsible Entity could identify applicable operational reliability data that is transmitted between
Control Centers. This data has already been identified for some applicable entities (Reliability
Coordinator (RC) and Transmission Operator (TOP)) in the data specification requirements. Responsible
Entities such as the Distribution Provider (DP) and Generator Operator (GOP) that do not have existing
data specification requirements should identify, at a minimum, operational reliability data that has
been requested by a Balancing Authority (BA), RC, or TOP as operational reliability data.
The Responsible Entity could then use the data identified in the previous step to determine which
communication links require protection under CIP-12-1. Examples of these communication links are:
1. Data link(s) between neighboring Transmission Operators
2. Data link(s) between a Balancing Authority and a Reliability Coordinator
3. Data link(s) between a Generator Operator and a Balancing Authority
4. Data link(s) between a Transmission Owner and a Transmission Operator
5. Data link(s) between a Distribution Provider and a Transmission Operator
6. Data link(s) between Reliability Coordinators
7. Data link(s) between two Primary Control Centers owned by a Responsible Entity
8. Data link(s) between a Primary and Backup Control Center owned by a Responsible Entity
The plan(s) should address how the boundary is determined for all communication networks that are
identified using the entity-developed procedure(s) (e.g. ESP boundary, Router outside of an ESP but
within a PSP, Cyber Asset used as an electronic access control for a low impact BES Cyber System, etc.).
A Responsible Entity has the freedom to identify these boundaries as it sees fit. The entity should take
the various features of its environment into account and determine the most effective and efficient
solution when defining these boundaries. There is no limitation on where boundary protection must
begin and terminate, other than ensuring that the endpoint identified is controlled by the Responsible
Entity. The SDT recommends that when selecting the endpoint, Responsible Entities carefully consider
reliability concerns and technical limitations. Endpoints identified by the Responsible Entity are not
meant to represent additional assets to be included in the scope of the CIP Reliability Standards. The
intent of the endpoint identification is to ensure each Responsible Entity identifies clear demarcation of
where the protections applied to the in-scope communications networks exist. The boundaries can vary
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based upon impact levels of the Control Center containing BES Cyber Systems, different technologies,
or infrastructures. The list of example network boundaries is provided below:
•

Electronic Access Point on the Electronic Security Perimeter boundary of a High or Medium
Impact BES Cyber System

•

Router outside of an Electronic Security Perimeter that is protected under an Entity’s Physical
Security Program

•

A Cyber Asset that performs the role of an Electronic Access Control for a low impact BES Cyber
System

Additionally, the Responsible Entity must document and implement plans for the protection of the
confidentiality and integrity of operational reliability data communicated between Control Centers. This
security objective could be achieved through a variety of methods or combination of methods (e.g. site
to site encryption, application layer encryption, physical protection, etc.). The methods must address
the confidentiality and integrity of the operational reliability data and protect the data on the
applicable communication networks/data links between Control Centers. The protections to be applied
to the communication links identified by the Responsible Entity are chosen at the Responsible Entity’s
discretion. However, the Responsible Entity should exercise caution to ensure that both confidentiality
and integrity of the in-scope communication links are protected. Some examples of methods that can
be implemented include but are not limited to:
•

Site to site encryption: Site to site encryption provides a means to securely transmit and access
information between two or more sites. Site to site encryption allows peers at both ends of the
identified link to encrypt and decrypt packets using mutually agreed-upon keys or certificates and
methods of encryption. This method can be used to achieve the protection of both the
confidentiality and integrity of the communication link provided that the encryption method
chosen not only obfuscates the data payload, but also provides a means to verify that the data
payload did not change between the source and destination.

•

Application layer encryption: Application-layer encryption protects the data at the highest layer in
the BES cyber system providing the sensitive data, making it invisible to all the layers below. If a
Responsible Entity chooses this option, care must be taken to ensure the inclusion of both
confidentiality and integrity. If the solution implemented only addresses confidentiality, the
Responsible Entity will need to also implement a complementary control, such as a hashing
mechanism, to protect against the manipulation of the data.

•

Physical protections: In some cases, a Responsible Entity may choose to implement physical
protections on the communication links in question. Secure conduit can be a method to help
secure the confidentiality and integrity of an in-scope link between Control Centers, as well as
helping ensure availability. While this measure can be used, it is suggested that a Responsible
Entity complement physical protections with logical protections to fully ensure that the integrity
and confidentiality of data transmitted between Control Centers is protected.

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Questions

1. The SDT asserts that the referenced data is already afforded protections at rest under existing CIP
standards (CIP-003, 005, 007, etc.), is perishable, and has a diminished need for protection over
time. Do you agree with the SDT’s assertion? If you agree, please supply a rationale to support the
position.
Yes
No
Comments:
2. If you do not agree with the SDT’s assertion in Question 1, please identify the type of data, the risk
posed at rest, and supply the rationale to support the position.
Comments:
3. Future enforceable Reliability Standards IRO-010-2 and TOP-003-3 identify “data required for
reliable operation.” For example, Requirement R1 of IRO-010-2 states:
R1. 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 and external network data, as deemed necessary by the
Reliability Coordinator.
TOP-003-3 Requirements R1 & R2 also have similar requirements for BAs and TOPs.
Do you agree that outlining this approach for identifying “data required for reliable operation” in
the Guidelines and Technical Basis is sufficient; consequently, an additional definition of “sensitive
BES data” or a requirement to identify “sensitive BES data” is not necessary? If not, please explain.
Yes
No
Comments:
4. The SDT asserts that “availability” of inter-and intra-entity Control Center communication of data is
being addressed in Project 2016-01 Modifications to TOP and IRO Standards, specifically Reliability
Standards TOP-001-4 and IRO-002-5. The proposed standards require redundant and diversely
routed data exchange capabilities at a Responsible Entity’s primary Control Center. Do you agree
that “availability” is adequately addressed by these standards? If not, please provide rationale to
support your position.
Yes
No
Comments:

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5. The SDT is proposing to develop a new CIP standard because the directives of FERC Order 822
related to the protection of communication networks used to exchange sensitive BES data
regardless of the entity’s size or impact level. Do you agree with the drafting of a new CIP standard
to address this issue? If you disagree and would prefer to include requirements in existing CIP
Standards, such as CIP-003 and CIP-005, please provide rationale and propose requirement
language.
Yes
No
Comments:
6. The SDT evaluated multiple approaches to addressing the directive. The approach proposed in this
informal posting focuses on the protection of communication links. An alternative approach could
focus on the protection of the sensitive BES data itself. Do you agree with the SDT’s approach to
focus the draft language on the protection of communication links? If not, please provide rationale
and propose alternative language.
Yes
No
Comments:
7. Do you agree with the security objective of the draft language? If not, please propose alternative
language.
Yes
No
Comments:
8. Is it clear what types of plans, procedures, and methods are needed to meet the draft language? If
not, please propose alternative language.
Yes
No
Comments:
9. The SDT uses the term “communication networks” throughout the draft language including an
obligation to define the boundaries of such communication networks. Does the SDT need to define
the term for inclusion in the NERC Glossary of Terms? If so, please propose a definition of
“communication networks.”
Yes
No
Comments:

Unofficial Comment Form
Project 2016-02 Modifications to CIP Standards | February 2017

6

Standards Announcement

2016-02 Modifications to CIP Standards
Communication Networks and
CIP Exceptional Circumstances
Informal Comment Period Open through March 13, 2017
Now Available

The Project 2016-02 Standard Drafting Team (SDT) is requesting stakeholder input on two issues it is
addressing: (1) the Federal Energy Regulatory Commission directive regarding Communication
Networks; and, (2) determining if additional CIP requirements are impacted during a declared CIP
Exceptional Circumstance. 30-day informal comment periods are open through 8 p.m. Eastern,
Monday, March 13, 2017 for stakeholders to provide feedback on the SDT’s approach and draft
language for each issue. To minimize the number of posted documents, the SDT included everything in
a single document for each issue with the suggested approach and draft language preceding the
questions.
Commenting

Use the electronic form to submit comments. If you experience any difficulties using the electronic
form, contact Wendy Muller.
If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential error
messages, or system lock-out, contact NERC IT support directly at https://support.nerc.net/ (Monday –
Friday, 8 a.m. - 5 p.m. Eastern).
•

Passwords expire every 6 months and must be reset.

•

The SBS is not supported for use on mobile devices.

•

Please be mindful of ballot and comment period closing dates. We ask to allow at least 48
hours for NERC support staff to assist with inquiries. Therefore, it is recommended that users try
logging into their SBS accounts prior to the last day of a comment/ballot period.

Next Steps

The drafting team will review all responses received during the informal comment period and
determine the next steps of the project.

For more information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Senior Standards Developer, Al McMeekin (via email) or at
(404) 446-9675.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement
Project 2016-02 Modifications to CIP Standards | February 2017

2

Comment Report
Project Name:

2016-02 Modifications to CIP Standards | Communication Networks

Comment Period Start Date:

2/10/2017

Comment Period End Date:

3/13/2017

Associated Ballots:

There were 48 sets of responses, including comments from approximately 121 different people from approximately 91 companies
representing 10 of the Industry Segments as shown in the table on the following pages.

Questions
1. The SDT asserts that the referenced data is already afforded protections at rest under existing CIP standards (CIP-003, 005, 007, etc.), is
perishable, and has a diminished need for protection over time. Do you agree with the SDT’s assertion? If you agree, please supply a
rationale to support the position.

2. If you do not agree with the SDT’s assertion in Question 1, please identify the type of data, the risk posed at rest, and supply the rationale
to support the position.

3. Future enforceable Reliability Standards IRO-010-2 and TOP-003-3 identify “data required for reliable operation.” For example, Requirement
R1 of IRO-010-2 states:
R1. The Reliability Coordinator shall maintain a documented specification for the data necessary for it to perform its Operational Planning
‐tim e m o n ito rin g , an d
Analyses, Real
1.1. A list of data and information needed by the Reliability Coordinator to support its Operational Planning Analyses, Real ‐
time monitoring,
.‐BES d ata
and Realtime Assessments including non
TOP-003-3 Requirements R1 & R2 also have similar requirements for BAs and TOPs.
Do you agree that outlining this approach for identifying “data required for reliable operation” in the Guidelines and Technical Basis is
sufficient; consequently, an additional definition of “sensitive BES data” or a requirement to identify “sensitive BES data” is not necessary?
If not, please explain.

4. The SDT asserts that “availability” of inter-and intra-entity Control Center communication of data is being addressed in Project 2016-01
Modifications to TOP and IRO Standards, specifically Reliability Standards TOP-001-4 and IRO-002-5. The proposed standards require
redundant and diversely routed data exchange capabilities at a Responsible Entity’s primary Control Center. Do you agree that “availability”
is adequately addressed by these standards? If not, please provide rationale to support your position.

5. The SDT is proposing to develop a new CIP standard because the directives of FERC Order 822 related to the protection of communication
networks used to exchange sensitive BES data regardless of the entity’s size or impact level. Do you agree with the drafting of a new CIP
standard to address this issue? If you disagree and would prefer to include requirements in existing CIP Standards, such as CIP-003 and CIP005, please provide rationale and propose requirement language.

6. The SDT evaluated multiple approaches to addressing the directive. The approach proposed in this informal posting focuses on the
protection of communication links. An alternative approach could focus on the protection of the sensitive BES data itself. Do you agree with
the SDT’s approach to focus the draft language on the protection of communication links? If not, please provide rationale and propose
alternative language.

7. Do you agree with the security objective of the draft language? If not, please propose alternative language.

8. Is it clear what types of plans, procedures, and methods are needed to meet the draft language? If not, please propose alternative
language.

9. The SDT uses the term “communication networks” throughout the draft language including an obligation to define the boundaries of such
communication networks. Does the SDT need to define the term for inclusion in the NERC Glossary of Terms? If so, please propose a
definition of “communication networks.”

Organization
Name
Tennessee
Valley
Authority

Duke Energy

Seattle City
Light

Name

Brian Millard

Segment(s)

1,3,5,6

Colby Bellville 1,3,5,6

Ginette
Lacasse

1,3,4,5,6

Region

SERC

Group Name

Tennessee
Valley
Authority

FRCC,RF,SERC Duke Energy

WECC

Seattle City
Light Ballot
Body

Group Member
Name

Group
Member
Organization

Group
Member
Segment(s)

Group Member
Region

Scott, Howell D.

Tennessee
Valley
Authority

1

SERC

Grant, Ian S.

Tennessee
Valley
Authority

3

SERC

Thomas, M. Lee

Tennessee
Valley
Authority

5

SERC

Parsons, Marjorie Tennessee
S.
Valley
Authority

6

SERC

Doug Hils

Duke Energy

1

RF

Lee Schuster

Duke Energy

3

FRCC

Dale Goodwine

Duke Energy

5

SERC

Greg Cecil

Duke Energy

6

RF

Pawel Krupa

Seattle City
Light

1

WECC

Hao Li

Seattle City
Light

4

WECC

Bud (Charles)
Freeman

Seattle City
Light

6

WECC

Mike Haynes

Seattle City
Light

5

WECC

Michael Watkins

Seattle City
Light

1,4

WECC

Faz Kasraie

Seattle City
Light

5

WECC

John Clark

Seattle City
Light

6

WECC

Tuan Tran

Seattle City
Light

3

WECC

Laurrie Hammack Seattle City
Light

3

WECC

Entergy

Julie Hall

6

Entergy/NERC Oliver Burke
Compliance

Entergy 1
Entergy
Services, Inc.

SERC

Entergy 5
Entergy
Services, Inc.

SERC

DTE Energy - 5
DTE Electric

RF

Daniel Herring

DTE Energy - 4
DTE Electric

RF

Karie Barczak

DTE Energy - 3
DTE Electric

RF

Kelly Silver

Con Edison
Company of
New York

1,3,5,6

NPCC

Edward Bedder

Orange and
Rockland
Utilities

NA - Not
Applicable

NPCC

Paul Malozewski Hydro One.

1

NPCC

Guy Zito

Northeast
Power
Coordinating
Council

NA - Not
Applicable

NPCC

Randy
MacDonald

New
Brunswick
Power

2

NPCC

Wayne Sipperly

New York
Power
Authority

4

NPCC

Glen Smith

Entergy
Services

4

NPCC

Brian Robinson

Utility Services 5

NPCC

Bruce Metruck

New York
Power
Authority

6

NPCC

Alan Adamson

New York
State
Reliability
Council

7

NPCC

Jaclyn Massey

DTE Energy - Karie Barczak 3,4,5
Detroit Edison
Company

DTE Energy - Jeffrey Depriest
DTE Electric

Con Ed Kelly Silver
Consolidated
Edison Co. of
New York

1,3,5,6

Northeast
Power
Coordinating
Council

1,2,3,4,5,6,7,8,9,10 NPCC

Ruida Shu

NPCC

Con Edison

RSC no
Dominion

Edward Bedder

Orange &
Rockland
Utilities

1

NPCC

David Burke

Orange &
Rockland
Utilities

3

NPCC

1

NPCC

Sylvain Clermont Hydro Quebec 1

NPCC

Si Truc Phan

Hydro Quebec 2

NPCC

Helen Lainis

IESO

2

NPCC

Laura Mcleod

NB Power

1

NPCC

MIchael Forte

Con Edison

1

NPCC

Kelly Silver

Con Edison

3

NPCC

Peter Yost

Con Edison

4

NPCC

Brian O'Boyle

Con Edison

5

NPCC

Greg Campoli

NY-ISO

2

NPCC

Kathleen
Goodman

ISO-NE

2

NPCC

Michael
Schiavone

National Grid

1

NPCC

Michael Jones

National Grid

3

NPCC

David
Ramkalawan

Ontario Power 5
Generation
Inc.

NPCC

Quintin Lee

Eversource
Energy

1

NPCC

Silvia Mitchell

NextEra
6
Energy Florida Power
and Light Co.

NPCC

Joseph
DePoorter

Madison Gas
& Electric

MRO

Larry Heckert

Alliant Energy 4

MRO

Amy Casucelli

Xcel Energy

MRO

Michele Tondalo UI

Midwest
Reliability
Organization

Russel
Mountjoy

10

MRO NSRF

3,4,5,6

1,3,5,6

Southwest
Power Pool,
Inc. (RTO)

Shannon
Mickens

2

SPP RE

Chuck Lawrence American
Transmission
Company

1

MRO

Michael
Brytowski

Great River
Energy

1,3,5,6

MRO

Jodi Jensen

Western Area 1,6
Power
Administratino

MRO

Kayleigh
Wilkerson

Lincoln
Electric
System

1,3,5,6

MRO

Mahmood Safi

Omaha Public 1,3,5,6
Power District

MRO

Brad Parret

Minnesota
Power

1,5

MRO

Terry Harbour

MidAmerican
Energy
Company

1,3

MRO

Tom Breene

Wisconsin
3,5,6
Public Service

MRO

Jeremy Volls

Basin Electric 1
Power Coop

MRO

Kevin Lyons

Central Iowa
Power
Cooperative

1

MRO

Mike Morrow

Midcontinent
Independent
System
Operator

2

MRO

Southwest
Power Pool
Inc.

2

SPP RE

SPP
Shannon
Standards
Mickens
Review Group
Mike Buyce

City Utilities of 1,4
Springfield

SPP RE

Robert Gray

Board of
Public
Utilities,KS
(BPU)

3

SPP RE

Stewart Dover

Lafayette
Utilities
System

2

SPP RE

Public Service Sheranee
Enterprise
Nedd
Group

1,3,5,6

NPCC,RF

PSEG REs

John Allen

City Utilities of 4
Springfield,
Missouri

SPP RE

Tim Kucey

PSEG - PSEG 5
Fossil LLC

RF

Karla Jara

PSEG Energy 6
Resources
and Trade
LLC

RF

Jeffrey Mueller

PSEG - Public 3
Service
Electric and
Gas Co

RF

Joseph Smith

PSEG - Public 1
Service
Electric and
Gas Co

RF

1. The SDT asserts that the referenced data is already afforded protections at rest under existing CIP standards (CIP-003, 005, 007, etc.), is
perishable, and has a diminished need for protection over time. Do you agree with the SDT’s assertion? If you agree, please supply a
rationale to support the position.
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

No

Document Name
Comment
Texas RE requests the SDT consider defining the term “sensitive BES data”, which could include ICCP, Historian, and backup data, since a goal of this
project should be to provide clear requirements for identifying and protecting Control Centers required for reliable operation. The undefined term,
sensitive BES data, is already being used among several non-CIP standards and defining the term would encourage consistency and lessen confusion.
Likes

0

Dislikes

0

Response

Aaron Austin - AEP - 3,5
Answer

No

Document Name
Comment
AEP contends that CIP standards, specifically CIP-003,005,006, 007, 009, 010, and 011 concentrate on BCS, EACMS, PCA, PACS devices and data
resident on them.
Likes

0

Dislikes

0

Response

Gerry Adamski - Essential Power, LLC - 5
Answer
Document Name
Comment

No

Is the operational data a subset of all sensitive data? I would offer that certain modeling update information would not fall under this framework and
could have negative impacts on the BES (e.g. ratings changes, configuration/outage changes, etc.). If that is captured in the scope of operational data,
then ok but I infer from the presentation of the information that real-time variable data is what is being targeted here.
Likes

0

Dislikes

0

Response

Wendy Center - U.S. Bureau of Reclamation - 1,5
Answer

No

Document Name
Comment
Reclamation recommends removing the phrase “is perishable, and has a diminished need for protection over time.” Reclamation agrees that data at
rest is already afforded protections under other applicable CIP standards. Reclamation disagrees that all data at rest is perishable and has a diminished
need for protection over time.
Likes

0

Dislikes

0

Response

Vivian Vo - APS - Arizona Public Service Co. - 1,3,5,6
Answer

No

Document Name
Comment
AZPS agrees with the assumption that data at rest within a Control Center is already afforded protections under existing CIP standards (CIP-003-6,
CIP-005-5, CIP-007-6, etc.), but respectfully notes that this assumption is outside the scope of the directive set forth by FERC in Order No. 822.
Pursuant to FERC Order No. 822, Paragraph 53, the directive targets communication links and data communicated between bulk electric system
(“BES”) Control Centers. (Emphasis Added.) Thus, the directive does not encompass or extend to include data at rest within BES Control Centers.
Rather, it is intended to ensure that data in transit between such Control Centers are afforded appropriate protections. To ensure that the scope of the
directive is accurately captured, AZPS offers the following revision to the referenced assumption:
Data at rest within a BES Cyber System is already afforded protections under existing CIP standards and is not within the scope of this directive.
Likes

0

Dislikes

0

Response

Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Richard Kinas - Orlando Utilities Commission - 3,5
Answer

Yes

Document Name
Comment
Currently many PI or other Historians that store near real time data are located outside of ESPs since this data, once it is stored on the Historian is not
used for operations. However some entities may use data stored on Histroians as a feedback loop into their control systems. In these specific
siturations the data "at rest" on the Historians may have an operational impact. Data that resides within an entities EMS is constantly being updated, the
"data points" exist in memory and store data values in these data points are constantly being updated. If data wishes to be preserved it is written to a
histroian before being overwirtten.
Likes

0

Dislikes

0

Response

Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer
Document Name
Comment

Yes

Data needed for the operation of the BES is already protected and exists only to transmit operational controls which are transient in nature.
Likes

0

Dislikes

0

Response

Russel Mountjoy - Midwest Reliability Organization - 10, Group Name MRO NSRF
Answer

Yes

Document Name
Comment
The NSRF agrees with the SDT. NERC has already defined Operating Reliability Data (ORD) and recipients are required to sign an ORD
Confidentiality Agreement, which should elimate the need for a requirement. Additionally, NERC Standards of Conduct as well as most FERC approved
tariffs have provisions for protection of sensitive data.
Likes

0

Dislikes

0

Response

Lona Hulfachor - Salt River Project - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
SRP agrees with the SDT assertions:
•

CIP-003: Identifies all security management controls used by the entity to address high, medium, and low impact BES Cyber Systems (BCS).

•

CIP-004: R4 Part 4.1 requires entities to develop processes to control not only electronic and physical access, it also requires processes to
control access to designated BES Cyber System Information storage, otherwise known as repositories, as determined in CIP-011. These
repositories are where “referenced data” would exist “at rest”.

•

CIP-005: The entirety of the Standard is based on specifying a controlled Electronic Security Perimeter (ESP) in supporting of protecting BCS
(including information “at rest” within the BCS).

•

CIP-006: In the same manner as CIP-005 and ESP protections, the physical protections afforded by CIP-006 protect the BCS from
unauthorized individuals “walking-up” to components of the BCS where “at rest” “referenced data” may exist.

•

CIP-007: The entirety of the Standard is based on specifying technical, operational, and procedural controls to protect the BCS (including the
information “at rest” within the BCS).

•

CIP-010: The change and configuration management controls prevent and detect unauthorized changes to the BCS (including information “at
rest” within the BCS). Vulnerability assessment requirements are also in support of protecting the BCS (including information “at rest” within the
BCS).

•

CIP-011: R1 requires the identification of BES Cyber System Information. An article of acceptable evidence included in the measures of R1 is
the identification of “repositories or electronic and physical locations designated for housing BES Cyber System Information”. These identified
locations are used as input for CIP-004 R4 Part 4.1 (in order to verify access controls).

Likes

0

Dislikes

0

Response

Brian Millard - Tennessee Valley Authority - 1,3,5,6 - SERC, Group Name Tennessee Valley Authority
Answer

Yes

Document Name
Comment
The same information that is two seconds old in a real-time SCADA system may be retained for five years in a corporate (non-control) data historian.
NERC CIP-002-5.1 scopes the applicability of the protections on assets which have a real-time impact on reliable BES operations. As such, any
information utilized by real-time systems for a fifteen minute time horizon are already afforded protections in CIP-002 through 011.
While data at rest may have impacts on planning or historical analysis, it cannot be reasonably inferred to have a fifteen minute impact on reliable
operations. Many multi-purpose Operating Systems support encrypted file systems. As such, any mandate for data at rest protections would be more
appropriately scoped in CIP-011 and applied to electronic repositories of BES Cyber System information.
The Confidentiality, Integrity and Availability triad is commonly utilized in designing effective controls for information systems. Regulatory frameworks
which provide protections for data at rest are focused on confidentiality of financial transactions and/or Personally Identifiable Information. Power control
systems have unique characteristics which make Availability and Integrity paramount.
Encryption for data at rest inherently is focused on making access to information more restricted. This inherently creates potential to adversely impact
Availability, which may be counter-productive to reliable BES operations.
Likes

0

Dislikes
Response

0

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer

Yes

Document Name
Comment
Supporting APPA comments
Likes

0

Dislikes

0

Response

Kelly Silver - Con Ed - Consolidated Edison Co. of New York - 1,3,5,6, Group Name Con Edison
Answer

Yes

Document Name
Comment
We agree that existing CIP standards protections address the referenced data at rest.
The referenced data is covered in the cited Standards. Consider that real-time SCADA data performance may be impacted by disk encryption.
Likes

0

Dislikes

0

Response

Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment
Duke Energy agrees with the assertion that the referenced data is already afforded protections under existing CIP standards.
Likes

0

Dislikes

0

Response

Jeff Johnson - Sempra - San Diego Gas and Electric - 1,2,3,4,5,6,7,8 - WECC
Answer

Yes

Document Name
Comment
The data is resting on systems that are protected by CIP controls.
Likes

0

Dislikes

0

Response

Kara Douglas - NRG - NRG Energy, Inc. - 3,4,5,6 - FRCC,MRO,WECC,Texas RE,NPCC,SERC,SPP RE,RF
Answer

Yes

Document Name
Comment
NRG agrees with the rationale because, the data at rest is not being used in the real-time operation of the Bulk Electric System i.e. the 15 minute impact
process. Also, the CIP Standards provide the appropriate protection for data integrity and confidentiality for in-scope systems.
Likes

0

Dislikes

0

Response

Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer
Document Name
Comment

Yes

The referenced data while at rest is covered in the cited Standards. Consider that real-time SCADA data performance may be impacted by disk
encryption.
Likes

1

Dislikes

Illinois Municipal Electric Agency, 4, Thomas Bob
0

Response

Jason Snodgrass - Georgia Transmission Corporation - 1
Answer

Yes

Document Name
Comment
Once referenced data has been received by a BES Cyber Asset it is then protected under the CIP Standards. There is no need to protect stale data.
Likes

0

Dislikes

0

Response

Guy Andrews - Georgia System Operations Corporation - 3,4
Answer

Yes

Document Name
Comment
Once referenced data has been received by a BES Cyber Asset it is then protected under the CIP Standards. There is no need to protect stale data.
Likes

0

Dislikes

0

Response

Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer
Document Name

Yes

Comment
ERCOT agrees with the SDT’s assertion. While at rest, the data required for reliable operation resides within existing BCS data and is afforded
protections under existing CIP Standards. Much of the referenced data has a limited time of need for protection and can be made public after a certain
number of days. Requiring additional protections of data at rest may not be necessary and due to the limited time of sensitivity, may not have a positive
cost benefit.
Likes

0

Dislikes

0

Response

Joe Tarantino - Sacramento Municipal Utility District - 1,3,4,5,6 - WECC
Answer

Yes

Document Name
Comment

In use and transport is the highest risk. Exisiting controls are sufficient.

Likes

0

Dislikes

0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
BPA agrees with the SDT assertion. BPA believes the referenced data is already afforded protections at rest under existing standards.
Likes
Dislikes

0
0

Response

Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer

Yes

Document Name
Comment
Xcel Energy agrees with the rationale that the data is perishable and is already afforded protection under existing CIP standards. Any data that is at rest
does not meet the 15-minute impact criteria for adversely impacting real-time operations.
Likes

0

Dislikes

0

Response

Candace Morakinyo - WEC Energy Group, Inc. - 3,4,5 - MRO,RF
Answer

Yes

Document Name
Comment
Existing CIP-011 requirements adequately identify and protect BES Cyber System information at rest.
Likes

0

Dislikes

0

Response

Deborah VanDeventer - Edison International - Southern California Edison Company - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
Access to the host systems is strictly controlled via the current CIP standards and requirements.
Likes

0

Dislikes

0

Response

Mike Kraft - Basin Electric Power Cooperative - 1,3,5,6
Answer

Yes

Document Name
Comment
Basin Electric Power Cooperative agrees NERC has already defined Operating Reliability Data and recipients are required to sign a Confidentiality
Agreement, which should elimate the need for a requirement. In addition, Basin Electric agrees existing CIP standards provide protection for this data
at rest.
Likes

0

Dislikes

0

Response

Brandon Cain - Southern Company - Southern Company Services, Inc. - NA - Not Applicable - SERC
Answer

Yes

Document Name
Comment
Yes, Southern Company agrees with the SDT’s assertion. Real-time reliability data used by Control Centers is only sensitive within a short time
window; it becomes perishable quickly and the need to maintain protections for that data diminishes over time. For data “at rest”, Southern Company
views the language in the FERC Order, specifically paragraph 54, intending to address a reliability gap to protect communications between Controls
Centers from “data manipulation type attacks” and “eavesdropping attacks”. The existing controls applied in accordance with CIP-011 and CIP-006-6
R1.10 sufficiently address protection of sensitive BES data “at rest” and in logical transit within an ESP, respectively. Additionally, the existing controls
applied in accordance with CIP-004 (Access Management), CIP-005 (ESPs, encryption, multi-factor authentication), and CIP-007 (system security
controls, account management) provide by extension added layers of security to protect data “at rest.”
Likes

0

Dislikes

0

Response

Chris Scanlon - Exelon - 1,3,5,6
Answer

Yes

Document Name

COMM Network - Exelon Comments - 3.13.17.docx

Comment
See attachment Q1
Likes

0

Dislikes

0

Response

Mark Riley - Associated Electric Cooperative, Inc. - 1,3,5,6
Answer

Yes

Document Name
Comment
AECI agrees that the referenced data is already afforded protections at rest under the current CIP Standards. Operational Reliability Data becomes
stale over time and has a diminished need for protection.
Likes

0

Dislikes

0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion
Answer

Yes

Document Name
Comment
The referenced data is covered in the cited Standards. Consider that real-time SCADA data performance may be impacted by disk encryption.
Likes

0

Dislikes

0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group

Answer

Yes

Document Name
Comment
The SPP Standards Review Group agrees with the rationale because, the data at rest is not being used in the Real-time operation of the Bulk Electric
System i.e. the 15 minute impact process. Also, the CIP Standards provide the appropriate protection for data integrity and confidentiality for in scope
systems.
Likes

0

Dislikes

0

Response

sean erickson - Western Area Power Administration - 1,6
Answer

Yes

Document Name
Comment
Yes, much of the critical data between control centers is only valid for that immediate time period, control data hours or days old only has historical
value.
Likes

0

Dislikes

0

Response

Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2
Answer

Yes

Document Name
Comment
•

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NERC has already defined Operating Reliability Data (ORD). Additionally, recipients are required to sign an ORD Confidentiality Agreement,
which should elimate the need for a requirement.
0
0

Response

Marc Donaldson - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6
Answer

Yes

Document Name
Comment
Tacoma supports the comments of Utility Services, Inc
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0

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Julie Hall - Entergy - 6, Group Name Entergy/NERC Compliance
Answer

Yes

Document Name
Comment

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0

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Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 1,3,4
Answer

Yes

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Comment

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0

Glen Farmer - Avista - Avista Corporation - 1,3,5
Answer

Yes

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Comment

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0

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Mike Smith - Manitoba Hydro - 1,3,5,6
Answer

Yes

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Comment

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0

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Andrew Gallo - Austin Energy - 1,3,4,5,6
Answer

Yes

Document Name
Comment

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0

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Preston Walker - PJM Interconnection, L.L.C. - 2 - SERC,RF

Answer

Yes

Document Name
Comment

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0

Response

Lan Nguyen - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

Yes

Document Name
Comment

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0

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Lauren Price - American Transmission Company, LLC - 1
Answer

Yes

Document Name
Comment

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0

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Laura Nelson - IDACORP - Idaho Power Company - 1
Answer
Document Name

Yes

Comment

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0

Response

Jamie Monette - Allete - Minnesota Power, Inc. - 1
Answer

Yes

Document Name
Comment

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0

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0

Response

Anton Vu - Los Angeles Department of Water and Power - 1,3,5,6
Answer

Yes

Document Name
Comment

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0

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0

Response

Sheranee Nedd - Public Service Enterprise Group - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer
Document Name
Comment

Yes

Likes

3

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PSEG - Public Service Electric and Gas Co., 1, Smith Joseph; PSEG - PSEG Fossil LLC, 5, Kucey Tim;
PSEG - Public Service Electric and Gas Co., 3, Mueller Jeffrey
0

Response

David Gordon - Massachusetts Municipal Wholesale Electric Company - 5
Answer

Yes

Document Name
Comment

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0

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0

Response

Douglas Webb - Great Plains Energy - Kansas City Power and Light Co. - 1,3,5,6 - SPP RE
Answer

Yes

Document Name
Comment

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0

2. If you do not agree with the SDT’s assertion in Question 1, please identify the type of data, the risk posed at rest, and supply the rationale
to support the position.
Marc Donaldson - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6
Answer
Document Name
Comment
No comment
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Response

Vivian Vo - APS - Arizona Public Service Co. - 1,3,5,6
Answer
Document Name
Comment
AZPS respectfully asserts that the SDT’s assertion in Question 1 is beyond the scope of the directive set forth in Order 822 at paragraph 53. Further,
AZPS is concerned that the assumption paints all data retained with BES Control Centers with too “broad of a brush stroke.” This is particularly evident
in the SDT’s assumption that all data within Control Centers is perishable and has a diminished need for protection as such statements appear to be
considering the “freshness” of real-time data only.
AZPS notes that the data contained and retained within BES Control Centers includes more than real-time data. In particular, BES Control Centers
often also retain data related to the operations and long-term planning time horizons. Such data, which is outside of data indicative of real-time status,
may not age and become perishable in the same manner or time period as data communicating real-time status. Because the verbiage utilized in the
assumption is extremely broad and does not clearly distinguish the or otherwise narrow the specific data to which the assumption applies, AZPS
disagrees with the assumption set forth by the SDT as such assumption has the effect of “broad brushing” all data communicated between and “at rest”
within BES Control Centers with the same importance and usability when, in fact, such data has varying levels of criticality, usability, confidentiality,
etc.
AZPS reiterates that it agrees with the SDT that the risk associated with data “at rest” within Control Centers is negligible given the applicability of
existing CIP reliability standards to such data, but, for the reasons set forth above, must respectfully disagree with the assumption and re-urge the SDT
to adopt the proposed revisions recommended in response to Question 1.
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Response

Douglas Webb - Great Plains Energy - Kansas City Power and Light Co. - 1,3,5,6 - SPP RE
Answer
Document Name
Comment
Not Applicable
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0

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0

Response

Candace Morakinyo - WEC Energy Group, Inc. - 3,4,5 - MRO,RF
Answer
Document Name
Comment
n/a
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0

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0

Response

Brandon Cain - Southern Company - Southern Company Services, Inc. - NA - Not Applicable - SERC
Answer
Document Name
Comment
N/A
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0

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0

Response

Chris Scanlon - Exelon - 1,3,5,6
Answer
Document Name
Comment
See attachment Q1
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0

Response

Wendy Center - U.S. Bureau of Reclamation - 1,5
Answer
Document Name
Comment
Reclamation recommends removing the phrase “is perishable, and has a diminished need for protection over time.” Reclamation agrees that data at
rest is already afforded protections under other applicable CIP standards. Reclamation disagrees that data all at rest is perishable and has a diminished
need for protection over time. Reclamation recommends that each entity be responsible to determine the value of its data at rest, if and when the data
at rest is perishable, and the necessary level of protection. As examples, some data between control centers may include sensitive data such as
configuration information of the network or relay protection systems. If the data that is transferred is deemed to be sensitive, then the associated data at
rest may also be sensitive.
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0

Response

Aaron Austin - AEP - 3,5
Answer
Document Name

Comment
The CIP standards do not necessarily apply to Cyber Assets that perform operating day ahead activities or other comparable functions that may be
capable of impacting the BES beyond the 15 minute threshold.
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0

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Sheranee Nedd - Public Service Enterprise Group - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer
Document Name
Comment
N/A
Likes

3

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PSEG - Public Service Electric and Gas Co., 1, Smith Joseph; PSEG - PSEG Fossil LLC, 5, Kucey Tim;
PSEG - Public Service Electric and Gas Co., 3, Mueller Jeffrey
0

Response

Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Answer
Document Name
Comment
HQT’s understanding of the objectives behind the drafting of CIP-012 is to protect communication links and therefore sensitive bulk electric system data
exchanged between bulk electric system Control Centers in a manner that is appropriately tailored to address the risks posed to the BES by the assets
being protected (i.e., high, medium, or low impact). Why are the security objectives are silent regarding avaibility?
Protection of data at rest is (currently) not part of the objectives of CIP-012. Furthermore, our understanding of the different CIPs is that it does not fully
address the security objectives of confidentiality and integrity of data at rest. CIP-005 is about establishing enclaves to protect the cybet assets, CIP-007
about the protection of the Cybe assets, CIP-011 to prevent unauthorized access (Guidelines and Technical Basis mention confidentiality but not
integrity).

Furthermore, the princips of CIA (Confidentiality Integrity Avaibility) may be implied but they are not precise enough to ensure that the objectives are
meet in the existing CIP standards (CIP-003, 005, 007, 011 etc.). The concepts of confidentiality are treated in a certain ways but the concepts of
integrity are not explicit.
The objectifs of CIP-012 could say ”Develop a security plan to ensure the confidentiality, integrity of data at rest and in-transit between Control Centers,
both inter-entity and intra-entity”
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Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name
Comment
NA
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0

Response

Gerry Adamski - Essential Power, LLC - 5
Answer
Document Name
Comment
See above
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0

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Kara Douglas - NRG - NRG Energy, Inc. - 3,4,5,6 - FRCC,MRO,WECC,Texas RE,NPCC,SERC,SPP RE,RF

Answer
Document Name
Comment
N/A
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0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Please see Texas RE’s response to #1.
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0

Response

Brian Millard - Tennessee Valley Authority - 1,3,5,6 - SERC, Group Name Tennessee Valley Authority
Answer
Document Name
Comment
See comment above.
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0

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer
Document Name
Comment
Supporting APPA comments
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0

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Andrew Gallo - Austin Energy - 1,3,4,5,6
Answer
Document Name
Comment
N/A
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0

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Lan Nguyen - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer
Document Name
Comment
N/A
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0

Jeff Johnson - Sempra - San Diego Gas and Electric - 1,2,3,4,5,6,7,8 - WECC
Answer
Document Name
Comment
N/A
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0

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Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer
Document Name
Comment
n/a
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0

Response

Russel Mountjoy - Midwest Reliability Organization - 10, Group Name MRO NSRF
Answer
Document Name
Comment
See comments for Question No. 1
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Response

Lona Hulfachor - Salt River Project - 1,3,5,6 - WECC
Answer
Document Name
Comment
SRP agrees with the SDT’s assertion in Question 1.
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0

3. Future enforceable Reliability Standards IRO-010-2 and TOP-003-3 identify “data required for reliable operation.” For example,
Requirement R1 of IRO-010-2 states:
R1. The Reliability Coordinator shall maintain a documented specification for the data necessary for it to perform its Operational Planning
‐tim e m o n ito rin g , an d
Analyses, Real
1.1. A list of data and information needed by the Reliability Coordinator to support its Operational Planning Analyses, Real ‐
time monitoring,
‐BES d ata
and Realtime Assessments including non
TOP-003-3 Requirements R1 & R2 also have similar requirements for BAs and TOPs.
Do you agree that outlining this approach for identifying “data required for reliable operation” in the Guidelines and Technical Basis is
sufficient; consequently, an additional definition of “sensitive BES data” or a requirement to identify “sensitive BES data” is not necessary?
If not, please explain.
Andrew Gallo - Austin Energy - 1,3,4,5,6
Answer

No

Document Name
Comment
The SDT should refine references to make it clear IRO-010 and TOP-003 data is limited to only data transmitted between control centers, because data
between field assets and the control center is not in-scope. Also, this should not be in the Guidelines and Technical Basis section of a Standard
because it would not be enforceable.
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Lan Nguyen - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
CenterPoint Energy believes the “data required for reliable operation” identified in TOP-003-3 and IRO-010-2 is too broad and goes beyond the scope of
“sensitive bulk electric system data” that should be protected. For example, portions of the data requested in TOP-003-3 and IRO-010-2 could be nonBES data that may only serve a purpose under certain system configurations or conditions. Data specified as necessary for Operational Planning
Analyses is based in large part on projections and forecasts which should not fall under the label of “sensitive bulk electric system data.” For example,
outages, Facility Ratings, equipment limitations, and Protection System degradation use data exchange capabilities (phone systems, email, web based

portals, FTP exchange, RTU, etc.) which may go beyond ‘communication links’ between Control Centers and should remain flexible enough to allow for
normal and abnormal Real-time system conditions and what Operating Plans are being implemented at that time.
CenterPoint Energy recommends that the drafting team narrow the scope to a subset of the data identified in TOP-003-3 and IRO-010-2. CenterPoint
Energy also recommends the drafting team develop criteria in the requirement language for determining what “sensitive bulk electric system data”
should be separate from the holistic list of data necessary for functions described in the latest revisions of TOP and IRO Standards. CenterPoint
Energy does not believe referencing the TOP-003-3 and IRO-010-2 standards in the requirement language is necessary as this may become
problematic in the future if the language in these standards changes or becomes obsolete.
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Response

Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

No

Document Name
Comment
Duke Energy does not agree that a definition of “sensitive BES data” is not necessary. The question above alludes to expectations for the RC/BA/TOP
in IRO-010-2 and TOP-003-3, but the reference fails to point out how this would apply to other functions such as the GOP. It is not enough to refer to
the RC/BA/TOP data requirements if the standard is also applicable to other functions unless the applicability of data required from the GO/GOP/TO/DP
by the RC/BA/TOP is limited.
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0

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0

Response

Lona Hulfachor - Salt River Project - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
SRP agrees that IRO-010-2 is the correct standard to identify “sensitive BES data”; however, SRP believes R3 should be used to determine what an
entity is actually sending to the RC, as opposed to R1 (what the RC is asking for). This benefits entities with fewer functional registrations by eliminating
data sources that are not applicable to them.
SRP agrees that TOP-003-3 R1 and R2 can be used to identify “sensitive BES data”.

TOP-003-3: SRP provides the same evidence for both R1 and R2:
•

R1: Data necessary for Operational Planning, Real-time monitoring, and Real-time Assessments.

•

R2: Data necessary for analysis functions and Real-time monitoring.

SRP would like to see examples that include sensitive BES data transmitted between primary and back-up Control Centers. SRP also requests
clarification on requirements for entities that own their communications network and protection of data transferred within the same private network.
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Richard Kinas - Orlando Utilities Commission - 3,5
Answer

No

Document Name
Comment
The data for Operational Planning Analysis does not address the data that is used to perform other required functions such as calculating ACE for a BA.
Data Required for reliable operation should include Data used during the performance of any Reliability Related Task (RRT) as defined with the entities
training program under requirement PER-005-2 R1.1
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Kara Douglas - NRG - NRG Energy, Inc. - 3,4,5,6 - FRCC,MRO,WECC,Texas RE,NPCC,SERC,SPP RE,RF
Answer

No

Document Name
Comment
NRG suggests that the drafting team develop a definition for the term “sensitive BES data” - something similar in effect to the term “BES Cyber Systems
Information” defined for CIP-011. Also, NRG recommends the definition for the term “sensitive BES data” include language addressing the 15 minute
impact operational criteria.
NRG’s proposed language for “sensitive BES data” definition: “Data if rendered unavailable, degraded, or misused within 15 minutes would adversely
impact the Real-Time operation of the Bulk Electric System.”

Our interpretation of the proposed language is that the drafting team has a concern for the protection of the data being transmitted. Since the data being
transmitted can’t be broken down and identified as sensitive data or non-sensitive data, the recommendation of developing a definition seems to be the
safest path. Additionally, NRG recommends that the drafting team review the term “reliable operation” in the NERC Glossary of Terms. Also, if the term
is used in the Requirement, NRG recommends using the term’s definition out of the glossary. This is a defined term and we propose that the term
should be capitalized. NRG seeks to understand, with this being a defined term, does this change the drafting team’s intent for the use of this term?
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0

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0

Response

Jason Snodgrass - Georgia Transmission Corporation - 1
Answer

No

Document Name
Comment
TOP-03-3 R1.1 requires a list of data and information needed, including non-BES data and external network data deemed necessary by the
Transmission Operator. Because the requirement is vague using the verbiage such as “information needed” and “non-BES data” it may be difficult or
impractical to protect the various methods used to communicate information or non-BES data. Methods of communication could include voice, email,
text messages, or faxes.
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0

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0

Response

Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

No

Document Name
Comment
Responsible Entities are audited to the requirement language and cannot be held to the language in the GTB. If there is a desired outcome from a
requirement, it should be stated in the requirement language; the GTB should not be used to imply the inherent meaning of a requirement. If the SDT's
intent is to rely on documentation developed in TOP-003, the requirement should state that. If the SDT's intent is to rely on “a list of data and information
needed by the Reliability Coordinator to support Operational Planning Analyses,” etc., the requirement should state that. The GTB should provide only
additional guidance.
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0

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0

Response

Aaron Austin - AEP - 3,5
Answer

No

Document Name
Comment
AEP believes trying to connect multiple requirements to dissimiliar standards or standard families poses a huge risk in that altering the “origin” standard
requirement without also modifying the “destination” requirement may result in a violation.Written guidelines provided by NERC explaining what
“sesntive BES data” means would be helpful since the terms can be interpreted in various ways by each RC, BA and TOP.
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0

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0

Response

Guy Andrews - Georgia System Operations Corporation - 3,4
Answer

No

Document Name
Comment
TOP-03-3 R1.1 requires a list of data and information needed, including non-BES data and external network data deemed necessary by the
Transmission Operator. Because the requirement is vague using the verbiage such as “information needed” and “non-BES data” it may be difficult or
impractical to protect the various methods used to communicate information or non-BES data. Methods of communication could include voice, email,
text messages, or faxes.
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0

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0

Response

Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer
Document Name

No

Comment
ERCOT does not agree with the approach of putting this in the Guidelines and Technical Basis section of a Standard since it is not enforceable or
recognized by some ERO compliance staff.

While the scoping of IRO-010 and TOP-003 may be too broad, having clear criteria will assist in clear implementation and understanding among the
entities required to comply with the requirement. Without clear scope being defined, it could be left up to each responsile entity to determine what they
think meets this criteria. That seems to be problematic since the responsible entities on each end of the communication link may not agree. It will also
cause consistency issues with responsible entities that are under different regions. There will be a constant comparison of practices and could result in
auditors determining what is necessary.

The SDT should consider refining references to make it clear that IRO-010 and TOP-003 data is limited to only data transmitted between control
centers. The data between field assets and the control center is out of scope. Also consider clarifying language that is clear that IRO-010 and TOP-003
informaton that is transferred verbally, including any VoIP, is not included in scope. In lieu of using IRO-010 and TOP-003, the SDT could consider
creating a definition of the relevant data. Either of these approaches would be beneficial to facilitate getting necessary understanding, agreements,
and/or regional rules implemented. Not having clear criteria will only increase the time needed to implement the standard. Entities will have to negotiate
agreement on relevant data and then proceed with implementing protections.

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0

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0

Response

Gerry Adamski - Essential Power, LLC - 5
Answer

No

Document Name
Comment
If it inlcudes system configuration and modeling data that can be modified via inter-entity communication networks, then yes.
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0

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Response

Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE

Answer

No

Document Name
Comment
Many of the systems that are identified in the lists required by TOP-003 R1 and IRO-010 R1 are used for Operational Planning activities only and would
not fully define what should fall within the 15 minute adverse impact criteria defined in current NERC CIP Standards which state that only systems that if
rendered unavailable, degraded, or misused would, within 15 minutes of its required operation, misoperation, or non-operation, adversely impact one or
more Facilities, systems, or equipment, which, if destroyed, degraded, or otherwise rendered unavailable when needed, would affect the reliable
operation of the Bulk Electric System.
Xcel Energy does not believe that IRO-010-2 and TOP-003-3 language adequately defines what ‘sensitive data’ should be included under this new
Standard and that a definition of Sensitive Data needs to be created independent of TOP-003-3 requirements or any other Ops & Planning standard.
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Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

No

Document Name
Comment
The SPP Standards Review Group suggests that the drafting team develops a definition for the term “sensitive BES data” something similar to the term
“BES Cyber Systems Information” defined for CIP-011. Also, we recommend the definition for the term “sensitive BES data” include language
addressing the 15 minute impact operational criteria.
SPP’s proposed language for “sensitive BES data”definition:
Data if rendered unavailable, degraded, or misused within 15 minutes would adversely impact the Real-Time operation of the Bulk Electric System.
Our interpretation of the proposed language is that the drafting team has a concern for the protection of the data being transmitted. Since the data being
transmitted can’t be broken down and identified as sensitive data or non-sensitive data, the recommendation of developing a definition seems to be the
safest path. Additionally, we recommend that the drafting team review the term “reliable operation” in the NERC Glossary of Terms. Also, if the term is
used in the Requirement, we recommend using the term’s definition out of the glossary. Our research shows that this is a defined term and we propose
that the term should be capitalized. Finally, we would ask with this being a defined term, does this change the drafting team’s intent for the use of this
term?
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0

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0

Wendy Center - U.S. Bureau of Reclamation - 1,5
Answer

No

Document Name
Comment
To promote consistency as the standards change, Reclamation recommends NERC define “sensitive BES data” and “data required for reliable
operation” in the NERC Glossary of Terms so that these phrases may be used for all standards (specifically IRO, TOP, and CIP).
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0

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0

Response

Chris Scanlon - Exelon - 1,3,5,6
Answer

No

Document Name
Comment
See attachment Q1
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0

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0

Response

Douglas Webb - Great Plains Energy - Kansas City Power and Light Co. - 1,3,5,6 - SPP RE
Answer

No

Document Name
Comment
The case can be made that a requirement to identify, or a definition of, “sensitive BES data” Is not necessary as it is already identified.
In consideration of Question 3, we ask another question. The CIP Standards exist to address security risks of the BES to ensure reliability. In order to
do that we protect the systems and infrastructure needed to perform the tasks or functions required for BES reliability operating services. Those
systems predominately include the data necessary for these functions. “Are the CIP Standards meant to secure more than the data necessary to

perform reliability tasks? And what gaps, if any, are not addressed or clearly identified in the data deemed necessary to perform reliability obligations in
IRO-010-2?”
To protect BES reliability, entities are required under the CIP Standards to protect operational data and BES Cyber Systems Information. This is the
same data identified as Real-time monitoring and Real-time Assessment data in IRO-010-2 R1 and TOP-003-3 R1 and R2. Thus the protections may
need to be extended to consider Operational Planning Analysis or those data elements that are relevant to promulgate an attack with a longer shelf life
of applicability or use.
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0

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0

Response

Vivian Vo - APS - Arizona Public Service Co. - 1,3,5,6
Answer

No

Document Name
Comment
AZPS disagrees with the SDT’s interpretation and asserions relative to broad applicability of the data required for reliable operation under TOP-003-3
and IRO-010-2 to the data contemplated in the directive set forth in Order 822 at paragraph 53. AZPS notes that both TOP-003-3 and IRO-010-2 and
the data associated therewith are applicable to the operations planning time horizon and not the real-time operations time horizon. Given the focus of
the FERC directive on data in transit between Control Centers during real-time operations, AZPS recommends that the SDT re-evaluate its
interpretation as set forth above and assess the need for development of a definition of “sensitive BES data.” To scope such definition, AZPS
recommends that the SDT reference the definition of Real-Time Assessment in the Glossary of Terms, and those reliability standards that address the
performance of Real-Time Assessments and monitoring to identify the data communicated between Control Centers in real-time for performance of
such assessments and monitoring.
Further, since each entity has discretion to determine the confidential nature of its data, without a definition, different data could be assigned different
levels of sensitivity and confidentiality by different entities. This would create unnecessary ambiguity and complexity for receiving entities – especially
where such entity has multiple adjacent Balancing Authorities, Transmission Operators, Generation Operators, etc. AZPS respectfully asserts that, to
eliminate inconsistencies and ensure that the real-time data that is critical to reliable operations is uniformly identified and protected amongst all
interconnected entities, a definition is necessary.
Finally, AZPS notes that the Guidelines and Technical Basis is not enforceable in finding an entity out of compliance and should be available for
supplemental information only. Therefore, while AZPS is not opposed to the provision of guidance, development of a definition for sensitive BES data to
be included in the Glossary of Terms is recommended.
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0

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0

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer

Yes

Document Name
Comment
Supporting APPA comments
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0

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0

Response

Preston Walker - PJM Interconnection, L.L.C. - 2 - SERC,RF
Answer

Yes

Document Name
Comment
While PJM does agree with the draft language, we feel that it could be tied closely to the CIP-002 assessment (<15 minute impact). For entities that
look to the guidance section and chose to use the IRO and TOP standards as a starting point, it should be more apparent that only data used for realtime reliability purposes, that fall within the 15 minute impact, would need to be protected per this standard. It could be mis-interpreted that the
guidance suggests protecting all data included in the IRO and TOP standards, even data that may not fall into this real-time category.
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0

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0

Response

Kelly Silver - Con Ed - Consolidated Edison Co. of New York - 1,3,5,6, Group Name Con Edison
Answer

Yes

Document Name
Comment
We agree using TOP-003 and IRO-010 Standards to identify data but we believe Operational Planning Analyses data is out of scope.
Explicitly stating what data each entity requires in a Standard would not be beneficial. Currently each RC and TOP defines their own requirements for
the data that they need from others (per TOP-003-3 and IRO-010). We are concerned that multiple definitions may lead to conflict.

Likes

0

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0

Response

Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment
We agree with the basic approach of using TOP-003 and IRO-010 Standards to identify this data but needs to be limited to real time data. We believe
TOP-003 and IRO-010 include data that is not “real time” so would be outside this document’s scope. An example of data which is out of scope includes
data used for Operational Planning Analyses.
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1

Dislikes

Illinois Municipal Electric Agency, 4, Thomas Bob
0

Response

Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Answer

Yes

Document Name
Comment
HQT agree, but the reference should be clearly stated. Since IRO-010-2 and TOP-003-3 are future enforceable reliability Standards, the SDT should
evaluate the risk of those not being endorsed. If this should happen, the basis would be absent of CIP-012. Also, with the present suggestion, CIP
standard would be used to define controls of IRO and TOP standards. This situation could cause an audit gap: the CIP auditors would not have
requirement from IRO or TOP to audit against and IRO and TOP auditors would not security requirement to audit against.
Likes

0

Dislikes

0

Response

Joe Tarantino - Sacramento Municipal Utility District - 1,3,4,5,6 - WECC
Answer

Yes

Document Name
Comment

SMUD does not recommend a prescriptive approach. It should be a risk based decision based on the entities risk anaysis.

Likes

0

Dislikes

0

Response

Candace Morakinyo - WEC Energy Group, Inc. - 3,4,5 - MRO,RF
Answer

Yes

Document Name
Comment
The CIP standards are related to protecting BES Cyber Systems and BES Cyber System Information. The Ops and Planning standards are related to
other aspects of reliabile operation. Any mixing and matching between CIP and non-CIP standards requirements is an opportunity for confusion,
mistakes and potential compliance "double jeopardy".
Likes

0

Dislikes

0

Response

David Gordon - Massachusetts Municipal Wholesale Electric Company - 5
Answer

Yes

Document Name
Comment
MMWEC supports comments submitted by APPA.
Likes
Dislikes

0
0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion
Answer

Yes

Document Name
Comment
We agree with the basic approach of using TOP-003 and IRO-010 Standards to identify this data but needs to be limited to real time data. We believe
TOP-003 and IRO-010 include data that is not “real time” so would be outside this document’s scope. An example of data which is out of scope includes
data used for Operational Planning Analyses.
Likes

0

Dislikes

0

Response

Brandon Cain - Southern Company - Southern Company Services, Inc. - NA - Not Applicable - SERC
Answer

Yes

Document Name
Comment
Yes, Southern Company agrees with the SDT’s approach to utilizing existing Standard requirements that already require the identification of “data and
information needed by the RC” to be referenced in the Guidelines and Technical Basis in forming the basis for data transmitted between Control
Centers requiring protections in accordance with this Standard. Given the extensive amount of approved and enforceable Standard requirements, as
well as those approved for future enforcement, filed with FERC, or under development that are addressing “data exchange via a secure network”, “all
data between Control Centers to use a mutually agreeable security protocol”, and “procedures to address the quality of real-time data”, Southern
Company agrees that the specific requirements of IRO-010 and TOP-003 sufficiently address the identification of data needing to be protected when
transmitted between Control Centers. Any additional attempt to define “sensitive BES data” or to add additional requirements to identify “sensitive BES
data” is not necessary.
Likes

0

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0

Response

Marc Donaldson - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6
Answer

Yes

Document Name
Comment
Tacoma supports the comments of Utility Services, Inc
Likes

0

Dislikes

0

Response

sean erickson - Western Area Power Administration - 1,6
Answer

Yes

Document Name
Comment
We do not need a clarifier.
Likes

0

Dislikes

0

Response

Brian Millard - Tennessee Valley Authority - 1,3,5,6 - SERC, Group Name Tennessee Valley Authority
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Mike Smith - Manitoba Hydro - 1,3,5,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Russel Mountjoy - Midwest Reliability Organization - 10, Group Name MRO NSRF
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Glen Farmer - Avista - Avista Corporation - 1,3,5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 1,3,4
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Julie Hall - Entergy - 6, Group Name Entergy/NERC Compliance
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Jeff Johnson - Sempra - San Diego Gas and Electric - 1,2,3,4,5,6,7,8 - WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Lauren Price - American Transmission Company, LLC - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Jamie Monette - Allete - Minnesota Power, Inc. - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Sheranee Nedd - Public Service Enterprise Group - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer

Yes

Document Name
Comment

Likes

3

Dislikes
Response

PSEG - Public Service Electric and Gas Co., 1, Smith Joseph; PSEG - PSEG Fossil LLC, 5, Kucey Tim;
PSEG - Public Service Electric and Gas Co., 3, Mueller Jeffrey
0

Anton Vu - Los Angeles Department of Water and Power - 1,3,5,6
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Mark Riley - Associated Electric Cooperative, Inc. - 1,3,5,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Mike Kraft - Basin Electric Power Cooperative - 1,3,5,6

Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Please see Texas RE’s response to #1.
Likes

0

Dislikes
Response

0

4. The SDT asserts that “availability” of inter-and intra-entity Control Center communication of data is being addressed in Project 2016-01
Modifications to TOP and IRO Standards, specifically Reliability Standards TOP-001-4 and IRO-002-5. The proposed standards require
redundant and diversely routed data exchange capabilities at a Responsible Entity’s primary Control Center. Do you agree that “availability”
is adequately addressed by these standards? If not, please provide rationale to support your position.
Wendy Center - U.S. Bureau of Reclamation - 1,5
Answer

No

Document Name
Comment
To promote consistency as the standards change, Reclamation recommends NERC define “availability” in the NERC Glossary of Terms so that the term
may be used for all standards (specifically IRO, TOP, and CIP standards).
Likes

0

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0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
BPA does not agree that “availability” is adequately addressed by redundant and diversely routed data exchange capabilities at the primary Control
Center for the following reasons:
1. Currently, the proposed language on page 2 includes protection of “confidentiality and integrity of data required for reliable operation of the
BES” and eliminates “availability” from the language of the requirement. However, in the Confidentiality/Integrity/Availability (CIA) triad for
information security, each leg must be balanced against the other two legs. By segregating Availability to TOP-001-4 and IRO-002-5, while
leaving Confidentiality/Integrity in the proposed CIP-012 standard, it becomes impossible to properly balance all three legs of the triad to
achieve optimum Reliability of the BES. The cyber security triad represents design tradeoffs; entities can’t properly design communications
networks – or worse: existing infrastructure may need to be rebuilt – if one of the options (Availability) is removed from consideration.
2. While the requirements of TOP-001-4 and IRO-002-5 (redundancy and diverse routing of data) can be used to achieve increased Availability, it
can also be achieved through other equally effective methods. Therefore, “availability” is not adequately addressed by TOP-001-4 and IRO002-5 and limits entities’ options to address availability by other methods more appropriate to their systems.
Therefore, BPA proposes that “availability” be added into the proposed language on page 2 to meet the security objectives of Order 822, i.e., “…to
protect AVAILBILITY, confidentiality and integrity of data required for reliable operation....”

BPA also encourages the SDT to use the Guidelines and Technical Basis section to recognize the distinction between the engineering/design term
“availability” (in which availability is quantitative – e.g., a system is designed to be available 99.99% of the time) and the cyber security
application in which availability is a qualitative element of security that is constantly balanced against two other (often competing) elements
(confidentiality and integrity).
Likes

0

Dislikes

0

Response

Lan Nguyen - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
CenterPoint Energy does not believe that TOP-001-4 and IRO-002-5 adequately address availability of inter-entity and intra-entity Control Center
communication of data. Both Standards speak to data exchange capability having redundant and diversely routed data exchange infrastructure
(hardware) once external data enters the primary Control Center. TOP-001-4 and IRO-002-5 do not ensure availability or communication of data
between inter-entity and intra-entity Control Centers, but only the redundancy of infrastructure internal to the requesting entity’s primary Control
Center. Rationale language is specific to this, “Infrastructure that is not within the TOP’s primary Control Center is not addressed by the proposed
requirement.” CenterPoint Energy believes data exchange capability used in TOP-001-4 does not fully address ‘data links’ between inter-entity and
intra-entity Control Centers.
CenterPoint Energy recommends the drafting team re-evaluate “availability” and how it can be adequately addressed by other existing standards.
Likes

0

Dislikes

0

Response

Marc Donaldson - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6
Answer

Yes

Document Name
Comment
Tacoma supports the comments of Utility Services, Inc
Likes

0

Dislikes

0

Response

Brandon Cain - Southern Company - Southern Company Services, Inc. - NA - Not Applicable - SERC
Answer

Yes

Document Name
Comment
Yes, Southern Company agrees with the SDT that “availability” is adequately addressed by the other Standards referenced and by common industry
practices. Southern Company also offers to the SDT that the only aspect of cyber security at issue under this directive is data integrity. Not only is it
appropriate for this effort to be silent regarding availability, we would request that the SDT consider that this Standard should also remain silent
regarding “confidentiality.” Including confidentiality will likely result in unintended consequences with no commensurate reduction in risk to BES
reliability.
Likes

0

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0

Response

Chris Scanlon - Exelon - 1,3,5,6
Answer

Yes

Document Name
Comment
See attachment Q1
Likes

0

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0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion
Answer
Document Name
Comment

Yes

Availability is adequately covered by other standards.
Likes

0

Dislikes

0

Response

Candace Morakinyo - WEC Energy Group, Inc. - 3,4,5 - MRO,RF
Answer

Yes

Document Name
Comment
Redundancy and diversity are the primary tools available to support "availability".
Likes

0

Dislikes

0

Response

Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Answer

Yes

Document Name
Comment
HQT agree, but the reference should be clearly stated. Since IRO-010-2 and TOP-003-3 are future enforceable reliability Standards, the SDT should
evaluate the risk of those not being endorsed. If this should happen, the basis would be absent of CIP-012. Also, with the present suggestion, CIP
standard would be used to define controls of IRO and TOP standards. This situation could cause an audit gap: the CIP auditors would not have
requirement from IRO or TOP to audit against and IRO and TOP auditors would not security requirement to audit against.
Likes

0

Dislikes

0

Response

Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment
ERCOT agrees with the SDT’s assertion that “availability” is currently addressed by other reliability standards. While TOP-001-4 and IRO-002-5 do
address availability, the SDT could cite more of the standards that provide this compliance and enforcement coverage.
Likes

0

Dislikes

0

Response

Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment
Availability is adequately covered by other standards.
Likes

1

Dislikes

Illinois Municipal Electric Agency, 4, Thomas Bob
0

Response

Lona Hulfachor - Salt River Project - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
SRP has been generally supportive of the direction the SDT has gone for both TOP-001-4 and IRO-002-5 standard development under project 2016-01.
Likes

0

Dislikes

0

Response

Kelly Silver - Con Ed - Consolidated Edison Co. of New York - 1,3,5,6, Group Name Con Edison

Answer

Yes

Document Name
Comment
Availability is already defined in the data specifications of each RC and TOP.
Likes

0

Dislikes

0

Response

Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment
Duke Energy agrees that the “availability” of this data is being addressed in Project 2016-01 Modifications to TOP and IRO Standards. We would like to
mention to the drafting team that the definition of “Control Center” may need to be re-visited as a result of these new protections. Currently, the
definition of “Control Center” may include generation control rooms. We do not believe that these additional protections being proposed by the draft
language should be applicable to generation control rooms.
Likes

0

Dislikes

0

Response

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer

Yes

Document Name
Comment
Supporting APPA comments
Likes

0

Dislikes
Response

0

sean erickson - Western Area Power Administration - 1,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Vivian Vo - APS - Arizona Public Service Co. - 1,3,5,6
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Douglas Webb - Great Plains Energy - Kansas City Power and Light Co. - 1,3,5,6 - SPP RE

Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Mike Kraft - Basin Electric Power Cooperative - 1,3,5,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Mark Riley - Associated Electric Cooperative, Inc. - 1,3,5,6
Answer
Document Name

Yes

Comment

Likes

0

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0

Response

David Gordon - Massachusetts Municipal Wholesale Electric Company - 5
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Joe Tarantino - Sacramento Municipal Utility District - 1,3,4,5,6 - WECC
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

Gerry Adamski - Essential Power, LLC - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Anton Vu - Los Angeles Department of Water and Power - 1,3,5,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Sheranee Nedd - Public Service Enterprise Group - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer

Yes

Document Name
Comment

Likes
Dislikes

3

PSEG - Public Service Electric and Gas Co., 1, Smith Joseph; PSEG - PSEG Fossil LLC, 5, Kucey Tim;
PSEG - Public Service Electric and Gas Co., 3, Mueller Jeffrey
0

Response

Guy Andrews - Georgia System Operations Corporation - 3,4
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Jamie Monette - Allete - Minnesota Power, Inc. - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Aaron Austin - AEP - 3,5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Jason Snodgrass - Georgia Transmission Corporation - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Lauren Price - American Transmission Company, LLC - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Kara Douglas - NRG - NRG Energy, Inc. - 3,4,5,6 - FRCC,MRO,WECC,Texas RE,NPCC,SERC,SPP RE,RF
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Jeff Johnson - Sempra - San Diego Gas and Electric - 1,2,3,4,5,6,7,8 - WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Richard Kinas - Orlando Utilities Commission - 3,5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Julie Hall - Entergy - 6, Group Name Entergy/NERC Compliance
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 1,3,4
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Glen Farmer - Avista - Avista Corporation - 1,3,5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Russel Mountjoy - Midwest Reliability Organization - 10, Group Name MRO NSRF
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Mike Smith - Manitoba Hydro - 1,3,5,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Preston Walker - PJM Interconnection, L.L.C. - 2 - SERC,RF
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Andrew Gallo - Austin Energy - 1,3,4,5,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Brian Millard - Tennessee Valley Authority - 1,3,5,6 - SERC, Group Name Tennessee Valley Authority
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE does not have comments in response to this question.
Likes

0

Dislikes
Response

0

5. The SDT is proposing to develop a new CIP standard because the directives of FERC Order 822 related to the protection of communication
networks used to exchange sensitive BES data regardless of the entity’s size or impact level. Do you agree with the drafting of a new CIP
standard to address this issue? If you disagree and would prefer to include requirements in existing CIP Standards, such as CIP-003 and
CIP-005, please provide rationale and propose requirement language.
Brian Millard - Tennessee Valley Authority - 1,3,5,6 - SERC, Group Name Tennessee Valley Authority
Answer

No

Document Name
Comment
Any focus on protection of communications networks is misplaced. Protection of data, regardless of the communications medium or network, needs to
be the focus of any standards development activities.
Distributed generation, proliferation of smart metering, and ever increasing capabilities in speed and bandwidth of communications technologies are
creating new sources of data that can be beneficial in real-time power operations. Entities require innovative mechanisms to securely acquire real-time
information into SCADA systems to enable better decision making, whether the data comes via cellular, satellite, leased line, or private carrier
connections.
NERC should benchmark with other regulatory bodies which oversee industries with similar needs, such as the financial sector. The financial industry
originally used carbon-paper copies of credit cards, submitted to centralized clearing houses, to process credit transactions. Visa provided the first
electronic, real-time transaction clearing terminal in 1979. The technologically has proliferated to the point that any smart phone can be used to execute
financial transactions in real time. The physical and cyber security of the end points themselves may not be under control of financial institutions.
Essentially, what the financial sector has done is provide interfaces to a very sensitive network to millions of devices in real time.
There are many parallels to the power sector, wherein a large quantity of devices increasingly need to send data to control systems over a variety of
communications technologies securely, in real-time.
Financial companies have an inherent financial interest in maximizing availability and accessibility of the financial network to increase transactions.
Power systems have an inherent reliability interest in getting more information to enable operators to make better real-time decisions.
NERC is in a unique position wherein it may leverage lessons learned from others industries who have decades of experience addressing these types
of issues. Any standards development would greatly benefit from cross-pollinization of expertise and not be overly prescriptive so as to limit emerging
technologies such a quantum or crypto block chain techniques.
Likes

0

Dislikes

0

Response

Preston Walker - PJM Interconnection, L.L.C. - 2 - SERC,RF
Answer
Document Name

No

Comment
PJM would prefer to put the language in CIP-005 for Highs and Mediums and CIP-003 for Lows.
Likes

0

Dislikes

0

Response

Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

No

Document Name
Comment
Duke Energy disagrees with the drafting of a new standard to address this directive. We feel that based on the current draft language, this requirement
would be better suited in CIP-003-3. Adding to an already existing framework rather than creating a new standard is preferable. Creating a new
standard would also require an entity to create additional documentation, rather than adding to already existing documentation.
Likes

0

Dislikes

0

Response

Kelly Silver - Con Ed - Consolidated Edison Co. of New York - 1,3,5,6, Group Name Con Edison
Answer

No

Document Name
Comment
We believe that protection of communications networks would best be incorporated into existing CIP-005 or CIP-011 Standards.
Likes

0

Dislikes

0

Response

Lona Hulfachor - Salt River Project - 1,3,5,6 - WECC

Answer

No

Document Name
Comment
SRP disagrees with the proposition to develop a new CIP standard. SRP suggests keeping requirements for low impact systems in CIP-003. Since
CIP-005 already protects the BCS up to the point of EAP, it is possible to add another requirement to protect “BES sensitive data” between EAPs via
site to site encryption, application layer encryption, or physical protections (as described in the “Draft Guidance” section). In addition to CIP-003 and
CIP-005, the SDT should consider modifying CIP-006 R1.10, which includes requirements to protect cabling and other nonprogrammable
communication components, to ensure no conflicts.
SRP prefers a risk-based approach that has different requirements for high, medium, and low impact systems.
Likes

0

Dislikes

0

Response

Russel Mountjoy - Midwest Reliability Organization - 10, Group Name MRO NSRF
Answer

No

Document Name
Comment
If the objective is to provide protection of the telecommunications interface or boundaries at control centers, it appears this is already addressed under
CIP-002 and CIP-006. Clarifying language for existing standards would be sufficient to address protection issues.
Likes

0

Dislikes

0

Response

Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer

No

Document Name
Comment
The existing cyber security controls in CIP-003 and CIP-005 already provide the basis for the protection of the communication links between control
centers. It is better to enhance these requriements to include the communication links then a new requirement

Likes

0

Dislikes

0

Response

Kara Douglas - NRG - NRG Energy, Inc. - 3,4,5,6 - FRCC,MRO,WECC,Texas RE,NPCC,SERC,SPP RE,RF
Answer

No

Document Name
Comment
NRG recommends maintaining the current Standards (CIP-003, CIP-005, CIP-006, CIP-007, and CIP-011) and revise them accordingly or as needed to
protect the data. These particular Standards have the potential to address the concerns pertaining to sensitive BES data, regardless of the entity’s size
or impact level. Also, they can reduce the potential of creating redundancy issues.
Likes

0

Dislikes

0

Response

Jason Snodgrass - Georgia Transmission Corporation - 1
Answer

No

Document Name
Comment
If the SDT develops a new CIP standard it could be difficult for an entity to know which standard to apply if there is any overlap between existing
standards and thus the preference would be to incorporate any new requirements into CIP-003 and CIP-005.
Likes

0

Dislikes

0

Response

Laura Nelson - IDACORP - Idaho Power Company - 1
Answer
Document Name
Comment

No

In isolation, it might be less confusing to group the new requirements together; however, the continued addition of new standards, attachments, etc. has
made the standards increasingly difficult for Responsible Entities to fully understand and comply with. If these new requirements are necessary, IPC
suggests adding them to CIP-005-5 as R3 with associated parts since CIP-005-5 deals with ESP boundaries and external connections.
Likes

0

Dislikes

0

Response

Aaron Austin - AEP - 3,5
Answer

No

Document Name
Comment
Requirements for communications to high and medium impact BCS should reside in the location with the other electronic access requirements in CIP005. Similarly, the requirements for communications between low impact BCS at control centers should reside with the other requirements for low
impact BCS written comenserate with the risk. There should be a “high water mark” provision to protect communications from low impact BCS at
control centers to high and/or medium impact BCS at control centers.
Likes

0

Dislikes

0

Response

Guy Andrews - Georgia System Operations Corporation - 3,4
Answer

No

Document Name
Comment
If the SDT develops a new CIP standard it could be difficult for an entity to know which standard to apply if there is any overlap between existing
standards and thus the preference would be to incorporate any new requirements into CIP-003 and CIP-005.
Likes

0

Dislikes
Response

0

Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Answer

No

Document Name
Comment
CIP-005 is used to define the network compliance controls. Spreading network compliance controls throughout different CIP could result in confusion in
the application of the different required controls. The CIA requirements for data (in transit or at rest) should be explicitly defined in CIP-005.
Likes

0

Dislikes

0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
BPA does not agree that a new standard is required. A new standard could result in isolated requirements that do not blend with – or even contradict –
existing requirements. The objectives can be met by coordinating with existing standards such as CIP-003 & CIP-005.
BPA also proposes that the Guidelines and Technical Basis section should emphasize that entities can/should leverage evidence from the numerous
other CIP standards where data quality, confidentiality and availability is also addressed.

Potential language to be incorporated into CIP-005-x R3:
Applicable Systems: High Impact BES Cyber Systems at Control Centers; Medium Impact BES Cyber Systems at Control Centers
Requirements: R3. The Responsible Entity shall implement one or more documented plan(s) that achieve the security objective to protect availability,
confidentiality and integrity of data required for reliable operation of the BES. The plan applies to data being transferred across communication networks
between Control Centers, both inter-entity and intra-entity and shall include each of the applicable requirement parts in CIP-005-x Table R3.
3.1 Identify data required for reliable operation of the BES (if not already identified under IRO-010-2 and TOP-003-3).
3.2 Where technically feasible, have one or more methods for protecting availability, confidentiality and integrity of the data identified in 3.1.
3.3 Have one or more methods for alarming to a central location when loss of protection of data failed to a central location with a method of immediate
response.
3.4 Have one or more methods for timely response to alarms identified in 3.3.

Potential language to be incorporated into the next version of CIP-003-x, R1.2, For its assets identified in CIP-002 containing low impact BES Cyber
Systems, if any:
New:
1.2.7. Ensuring the availability, confidentiality and integrity of data required for reliable operation of the BES between Control Centers, both inter-entity
and intra-entity.
Likes

0

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0

Response

Joe Tarantino - Sacramento Municipal Utility District - 1,3,4,5,6 - WECC
Answer

No

Document Name
Comment
No – utilize existing standards. The impact level should be considered within the the context of existing standards.
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0

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0

Response

Candace Morakinyo - WEC Energy Group, Inc. - 3,4,5 - MRO,RF
Answer

No

Document Name
Comment
It may be impossible to protect the "networks". It is more important to ensure the availability, confidentiality and integrity of the data flowing over those
networks. As previously noted, redundancy and diversity, along with monitoring, are tools which can ensure availability, and can be addressed in the
ops & planing standards. Properly implemented encryption, is a tool which can ensure confidentiality and integrity of the data and can be addressed
within CIP-005.
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0

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Response

0

Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer

No

Document Name
Comment
Xcel Energy believes a new Standard is not required to address the risks identified in FERC Order 822. Xcel Energy believes that existing CIP-003 and
CIP-005 standards should be updated as determined necessary to address the concerns identified in the order. Current CIP Standards include a
comprehensive set of requirements to protect the Bulk Electric System and specific controls to address new risks should be integrated into existing
requirements when possible. Creating a new standard would add unnecessary complexity and lead to confusion when it may include requirements
already covered by CIP-003, CIP-005, CIP-006 and potentially CIP-011. The development of a new Standard to address this concern without
coordination of existing CIP requirements would also create an unknown and complex audit approach with risk of creating instances of double
jeaproady that could otherwise be prevented with proper integration and revisions of current CIP Standards to address the concern.
Likes

0

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0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

No

Document Name
Comment
We recommend maintaining the current Standards (CIP-003, CIP-005) and revising them accordingly or as needed. These particular Standards have
the potential to address the concerns pertaining to sensitive BES data regardless of the entity’s size or impact level. Also, they can reduce the potential
of creating redundancy issues.
Likes

0

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0

Response

Wendy Center - U.S. Bureau of Reclamation - 1,5
Answer
Document Name
Comment

No

Reclamation recommends the requirements for protecting communication networks should be included in CIP-003-7i for low impact BES Cyber
Systems; and CIP-005-5 for the high and medium BES Cyber Systems.
Likes

0

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0

Response

Brandon Cain - Southern Company - Southern Company Services, Inc. - NA - Not Applicable - SERC
Answer

No

Document Name
Comment
Southern Company disagrees with this approach and respectfully requests the SDT to consider the technical and procedural controls that result from
these new requirements will almost certainly be designed, implemented, and maintained in conjunction with the controls in CIP-005 (for Highs and
Mediums) and CIP-003 (for Lows). Rather than create a new set of requirements, guidance, RSAWs, etc. for something that will have to be audited
along with and as if it were a part of CIP-005 (for Highs and Mediums) or part of CIP-003 (for Lows), we would recommend modifying those Standards.
Likes

0

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0

Response

Mike Kraft - Basin Electric Power Cooperative - 1,3,5,6
Answer

No

Document Name
Comment
Basin Electric would prefer low impact requirements be kept in CIP-003 as this minimizes potential confusion with low impact level only entities. Basin
Electric would prefer additions to CIP-005 vs. a new standard as the protections for high and medium impact levels would be closely tied to an
Electronic Security Perimeter and crossing the applicable boundary for a Control Center.
Likes

0

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Response

0

Vivian Vo - APS - Arizona Public Service Co. - 1,3,5,6
Answer

No

Document Name
Comment
AZPS can see the value in the development of an entirely new standard; however, AZPS is concerned that the development of an entirely new standard
is beyond the scope of the FERC directive, which states that “modifications to CIP-006-6 to provide controls to protect, at a minimum, communication
links and data communicated between bulk electric system Control Centers are necessary in light of the critical role Control Center communications
play in maintaining bulk electric system reliability.” Therefore, AZPS requests that the SDT evaluate and clarify whether the SAR provides the additional
authority necessary for the development of a new standard, as opposed to the modification of CIP-006-6.

Likes

0

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0

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Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2
Answer

No

Document Name
Comment
If the objective is to provide protection of the telecommunications interface or boundaries at control centers, it appears this is already addressed under
CIP-002 and CIP-006. At most this would require some clarifying language.
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0

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0

Response

sean erickson - Western Area Power Administration - 1,6
Answer
Document Name
Comment

No

Per the NSRF: If the objective is to provide protection of the telecommunications interface or boundaries at control centers, it appears this is already
addressed under CIP-002 and CIP-006. Clarifying language for existing standards would be sufficient to address protection issues.

Likes

0

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0

Response

Andrew Gallo - Austin Energy - 1,3,4,5,6
Answer

Yes

Document Name
Comment
A new standard will assist in defining the requirements addressing the inter-relationship between entities of differing impact levels.
Likes

0

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0

Response

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer

Yes

Document Name
Comment
Supporting APPA comments
Likes

0

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0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

Yes

Document Name
Comment
The Standard Drafting Team’s proposed approach seems consistent with the discussion in FERC Order No. 822 delineating between the CIP
Standards focusing on “boundary” issues – that is, the definition of boundaries and the creation of protections at those boundaries – and the data
security and communication link issue for BES sensitive data being transmitted across such boundaries.
Likes

0

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0

Response

Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment
There are concerns about the applicability section and how it will interact with the existing CIP Standards exemption 4.2.3.2. The applicability section
should limit the scope to only real time communication networks or data between Control Centers.
Would like additional guidance on the applicability of technologies like voice communication email, text messaging …

Consider including language for CIP Exceptional Circumstances
Likes

1

Dislikes

Illinois Municipal Electric Agency, 4, Thomas Bob
0

Response

Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment
Since these requirements are not limited to just communications between entities at the same impact level, a new standard will assist in defining the
requirements that address the interrelationship between entities of differing impact levels.

Likes

0

Dislikes

0

Response

Sheranee Nedd - Public Service Enterprise Group - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer

Yes

Document Name
Comment
A new standard would be less disruptive. This way all policy/procedure changes would be contained in 1 document.
Likes

3

Dislikes

PSEG - Public Service Electric and Gas Co., 1, Smith Joseph; PSEG - PSEG Fossil LLC, 5, Kucey Tim;
PSEG - Public Service Electric and Gas Co., 3, Mueller Jeffrey
0

Response

Gerry Adamski - Essential Power, LLC - 5
Answer

Yes

Document Name
Comment
A new standard would be preferred to specify the communication network requirements.
Likes

0

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0

Response

Deborah VanDeventer - Edison International - Southern California Edison Company - 1,3,5,6 - WECC
Answer
Document Name
Comment

Yes

Because of the way SCE has organized the assignment of CIP requirements into Programs, this has no impact to us operationally. SCE believes the
general benefit of creating a new CIP standard (CIP-012) is that like requirements would be grouped together and easier to locate.
Likes

0

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0

Response

David Gordon - Massachusetts Municipal Wholesale Electric Company - 5
Answer

Yes

Document Name
Comment
MMWEC supports comments submitted by APPA.
Likes

0

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0

Response

Mark Riley - Associated Electric Cooperative, Inc. - 1,3,5,6
Answer

Yes

Document Name
Comment
The requirements span multiple impact levels and a new standard would assist entities in identifying the applicability of the new requirements.
Likes

0

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0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion
Answer
Document Name

Yes

Comment
Request the SDT consider and address how existing CIP Standards exemption 4.2.3.2 could be impacted.
There are concerns about the applicability section and how it will interact with the existing CIP Standards exemption 4.2.3.2. The applicability section
should limit the scope to only real time communication networks or data between Control Centers.
Would like additional guidance on the applicability of technologies like voice communication email, text messaging.
Consider including language for CIP Exceptional Circumstances.
Likes

0

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0

Response

Chris Scanlon - Exelon - 1,3,5,6
Answer

Yes

Document Name
Comment
See attachment Q1
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0

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0

Response

Marc Donaldson - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6
Answer

Yes

Document Name
Comment
Tacoma supports the comments of Utility Services, Inc
Likes
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0
0

Response

Lan Nguyen - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

Yes

Document Name
Comment

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0

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0

Response

Mike Smith - Manitoba Hydro - 1,3,5,6
Answer

Yes

Document Name
Comment

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0

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0

Response

Glen Farmer - Avista - Avista Corporation - 1,3,5
Answer

Yes

Document Name
Comment

Likes

0

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Response

0

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 1,3,4
Answer

Yes

Document Name
Comment

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0

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0

Response

Julie Hall - Entergy - 6, Group Name Entergy/NERC Compliance
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Jeff Johnson - Sempra - San Diego Gas and Electric - 1,2,3,4,5,6,7,8 - WECC
Answer

Yes

Document Name
Comment

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0

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0

Response

Lauren Price - American Transmission Company, LLC - 1
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Jamie Monette - Allete - Minnesota Power, Inc. - 1
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Anton Vu - Los Angeles Department of Water and Power - 1,3,5,6
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Douglas Webb - Great Plains Energy - Kansas City Power and Light Co. - 1,3,5,6 - SPP RE
Answer
Document Name
Comment

Yes

Likes

0

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Response

0

6. The SDT evaluated multiple approaches to addressing the directive. The approach proposed in this informal posting focuses on the
protection of communication links. An alternative approach could focus on the protection of the sensitive BES data itself. Do you agree with
the SDT’s approach to focus the draft language on the protection of communication links? If not, please provide rationale and propose
alternative language.
sean erickson - Western Area Power Administration - 1,6
Answer

No

Document Name
Comment
What you are trying to protect data/link/network will ultimately determine how best to protect it, and it is not clear from this request what that is.
per the NSRF: The NSRF recommends focusing on the boundaries or interface points, not the links between control centers.
Likes

0

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0

Response

Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2
Answer

No

Document Name
Comment
We agree with focusing on the boundaries or interface points, not the links between control centers.
Likes

0

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0

Response

Marc Donaldson - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6
Answer
Document Name
Comment

No

Tacoma supports the comments of Utility Services, Inc
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0

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0

Response

Vivian Vo - APS - Arizona Public Service Co. - 1,3,5,6
Answer

No

Document Name
Comment
AZPS does not agree that protection of the communication links alone achieves the FERC directive, which also references controls to protect the data
communicated between BES Control Centers. Controls that would be applicable to the protection of data include controls such as encryption, which is
different and superior to the controls that would be used to protect communication links alone.
Likes

0

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0

Response

Mike Kraft - Basin Electric Power Cooperative - 1,3,5,6
Answer

No

Document Name
Comment
Basin Electric prefers objective based standards/requirements. If the objective can be met via multiple methods (e.g. protected communication links or
protecting the data itself), Basin Electric would prefer the flexibility to choose the approach and method. The proposal does include flexibitily within the
protection of communication links approach which is appreciated.
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0

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0

Response

Wendy Center - U.S. Bureau of Reclamation - 1,5

Answer

No

Document Name
Comment
Reclamation recommends including requirements for protecting communication networks in CIP-003-7i for low impact BES Cyber Systems, in CIP-0055 for high and medium BES Cyber Systems, and in CIP-006-6 Requirement R1 Part 1.10 for physical security.
Likes

0

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0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

No

Document Name
Comment
The review group recommends working on a multiple approach solution to address the directive. The Primary Solution could address the protection of
the communication link. As an alternative method, we recommend the drafting team consider other methods that are not link level controls. Additionally,
we would ask the drafting team to provide clarity on the difference between “communication links” and “communication networks”.
Likes

0

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0

Response

David Gordon - Massachusetts Municipal Wholesale Electric Company - 5
Answer

No

Document Name
Comment
MMWEC supports comments submitted by APPA.
Likes

0

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Response

0

Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer

No

Document Name
Comment
The SDT should continue to evaluate multiple approaches to address the directive. Allowing the entity to determine which is appropriate based on
situation. It might not be feasible to always implement link controls between entities.
Likes

0

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0

Response

Candace Morakinyo - WEC Energy Group, Inc. - 3,4,5 - MRO,RF
Answer

No

Document Name
Comment
Rather than focusing on the links, we should focus on protecting the data. If that means implementing certain protections such as encryption over the
links, that's fine. Don't focus on the links themselves.
Likes

0

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0

Response

Joe Tarantino - Sacramento Municipal Utility District - 1,3,4,5,6 - WECC
Answer

No

Document Name
Comment

No – SMUD requests that the definition of communication links should be clarified.

Likes

0

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0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
BPA does not agree that focusing on protection of the communication links is the best approach to meet the FERC directive. Merely protecting the
network, or communications links, does not necessarily protect the data carried by the network. However, if the requirement instead emphasizes
protection of data, BPA believes entities will gain the additional benefit of creating a more secure cyber environment overall.
BPA proposes that draft language be revised to require method(s) for protecting “applicable data” rather than “communication links” between Control
Centers.
Likes

0

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0

Response

Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Answer

No

Document Name
Comment
The strategy of protecting the sensitive BES data itself is a better one than to focus on wether the data is at rest or in-transit. The CIA objectives could
be added to CIP-005 & CIP-011. This would maintain the current consistency and approach of the CIP standard.
Likes

0

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0

Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer

No

Document Name
Comment
ERCOT does not agree with protection of communication links. The requirement should be written to allow entities to implement the program that fits
their needs and infrastructure. Some may be best suited to protect the data and others may be best suited in protecting the communication links. The
security objects should remain as it is with options in how to achieve the objective as articulated in the draft guidance.
Likes

0

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0

Response

Guy Andrews - Georgia System Operations Corporation - 3,4
Answer

No

Document Name
Comment
Either of the two approaches could provide good security measure but why limit the entity to only one approach. It would be better to allow each entity to
choose their own approach which best fits their environment.
Likes

0

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0

Response

Aaron Austin - AEP - 3,5
Answer

No

Document Name
Comment
AEP believes the security directive for the requirements should be written in a way to permit any responsible entity to achieve the directive, regardless
of technology or preferred architecture.
Likes

0

Dislikes

0

Response

Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

No

Document Name
Comment
Either approach of protecting the data or the communication links should be an option for a Responsible Entity as long as the Responsible Entity meets
the security objective of providing confidential data that has integrity.
Likes

0

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0

Response

Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer

No

Document Name
Comment
We like the option to protect either the data or the links. We would like to see these options clearly defined within the requirements and not just in the
guidance. The Standard should be an outcome based Standard.
FERC Order 822 section 58 clarifies this scope as inter-Control Center and intra-Control Center communications. The guidance seems to extend the
scope beyond this by including references to DP’s and listing Data links without reference to Control Centers.
Likes

1

Dislikes

Illinois Municipal Electric Agency, 4, Thomas Bob
0

Response

Jason Snodgrass - Georgia Transmission Corporation - 1
Answer
Document Name

No

Comment
Either of the two approaches could provide good security measure but why limit the entity to only one approach. It would be better to allow each entity to
choose their own approach which best fits their environment.
Likes

0

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0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

No

Document Name
Comment
Texas RE suggests that the suggested requirements could be more clear. FERC Order No. 822, P. 56 provides that “NERC’s response to the
directives in this Final Rule should identify the scope of sensitive bulk electric system data that must be protected and specify how the confidentiality,
integrity, and availability of each type of bulk electric system data should be protected while it is being transmitted or at rest.” Elsewhere, FERC Order
No. 822 specifically refuted reliance on the EOP-008-1 Standard because that Standard “does not provide for the protection of communication links and
sensitive bulk electric system data communicated between bulk electric systems Control Centers.” FERC Order No. 822, P. 63. In short, FERC Order
No. 822 appears to specifically contemplate protections for both communications links and electric system data as separate categories.

On page 4 of the Unofficial Comment Form, the Standard Drafting Team (SDT) notes that “the Responsible Entity must document and implement plans
for the protection of the confidentiality and integrity of operational reliability data communicated between Control Centers.” The SDT then references
examples of methods to protect data, such as site to site encryption and application layer encryption. Texas RE believes these are appropriate
examples of methods to protect electric system data that is consistent with the intent of FERC Order No. 822.

However, Texas RE is concerned that the SDT’s proposal potentially subsumes these data-focused protection methods under protections for physical
communications links themselves. Although such protections are appropriate, FERC Order No. 822 appears to view data security and physical
communications link protections as separate, augmentative elements of a robust data security program. As such, Texas RE recommends that the SDT
further specify that in order to achieve the security objective to protect confidentiality and integrity of data required for the reliable operation of the BES,
responsible entities include the following language:

1.4 Method(s) for protecting the operational reliability of data communicated between Control Centers identified in 1.1, where technically
feasible.
Likes

0

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0

Response

Kara Douglas - NRG - NRG Energy, Inc. - 3,4,5,6 - FRCC,MRO,WECC,Texas RE,NPCC,SERC,SPP RE,RF
Answer

No

Document Name
Comment
NRG likes the approach of protecting communication links because you can identify the data, but at what point does the data transfer ownership from
the responsible entity to the RC or BA (therefore, NRG also recommends that the SDT also definine the data to be protected). From that standpoint,
additional requirement protections to be added into CIP-005 are recommended (by NRG) to protect the confidentiality and integrity of the data.
NRG recommends working on a multiple approach to address the directive. The primary solution could address the protection of the communication
link. As an alternative method, NRG recommends that the drafting team consider other methods that are not link level controls. Additionally, NRG asks
that the drafting team provide clarity on the difference between “communication links” and “communication networks”.
Likes

0

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0

Response

Jeff Johnson - Sempra - San Diego Gas and Electric - 1,2,3,4,5,6,7,8 - WECC
Answer

No

Document Name
Comment
As written, it is unclear what constitutes a “communication link”, especially if that link is provided by a 3rd party. The standard should address the
protection of the data.
Likes

0

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0

Response

Russel Mountjoy - Midwest Reliability Organization - 10, Group Name MRO NSRF
Answer
Document Name

No

Comment
The NSRF recommends focusing on the boundaries or interface points, not the links between control centers.
Likes

0

Dislikes

0

Response

Lona Hulfachor - Salt River Project - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
SRP does not agree with the SDT’s approach to focus the draft language on the protection of communication links. The focus of the draft language
should be on both the communication links and the sensitive BES data, as required by FERC Order No. 822. The reliability of the communication links
and integrity of sensitive BES data are critical to the reliability of the BES.
SRP proposes merging the language that focuses on protection of communication with the language in the “Draft Guidance” section pertaining to the
data-centric approach.
Likes

0

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0

Response

Kelly Silver - Con Ed - Consolidated Edison Co. of New York - 1,3,5,6, Group Name Con Edison
Answer

No

Document Name
Comment
1. Recommend that the SDT focus on protecting the data for reliability and availability.
2. We recommend that this Standard not prescribe the method for protecting the data but the objective of reliability and availability as the focus.
Alternative approaches of application security or communication security controls should be allowed and clearly addressed in the
Requirements. The proposed procedures in Draft Language 1.1 and 1.2 would not be required.

3. FERC Order 822 section 58 clarifies this scope as inter-Control Center and intra-Control Center communications. The guidance seems to
extend the scope beyond this
4. Recommend reviewing NIST Special Publication 800-47 which is titled Security Guideline for Interconnecting Information Technology Systems
with a focus toward reliability and availability
5. The Standard should be an outcome-based Standard.
Likes

0

Dislikes

0

Response

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer

No

Document Name
Comment
Supporting APPA comments
Likes

0

Dislikes

0

Response

Andrew Gallo - Austin Energy - 1,3,4,5,6
Answer

No

Document Name
Comment
This requirement should be drafted to allow Responsible Entities to implement an approach which fits the needs of its processes and infrastructure;
allowing for either data and/or communication link protection.
Likes

0

Dislikes
Response

0

Brian Millard - Tennessee Valley Authority - 1,3,5,6 - SERC, Group Name Tennessee Valley Authority
Answer

No

Document Name
Comment
TVA notes that within a cloud-based communications network such as the Internet, an MPLS network, a meshed network, or other non-point-to-point
type of communications topology, it would be difficult to quantify a “link” as a physical or logical construct, as the “link” may be constructed of a virtual
circuitry that traverses any number of underlying physical components. The language should be revised to focus on protecting information instead of
antiquated notions of physical communication components associated with “links.”
TVA is also concerned that the proposed language is vague enough to encompass transport links carrying an e-mail sent between two Control Centers,
as no qualifications are provided regarding timeliness of the information. Should Internet based transport relay the e-mail, the registered entity would be
obligated to protect, end-to-end, the Internet “data-links” connecting the two Control Centers.
TVA suggests focusing on the “sensitive bulk electric system data” moving between Control Centers and not underlying communications infrastructure.
Likes

0

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0

Response

Douglas Webb - Great Plains Energy - Kansas City Power and Light Co. - 1,3,5,6 - SPP RE
Answer

Yes

Document Name
Comment
We support a path forward of focusing on protection of communication links with language to limit the scope of data to be protected with that data that
does not have a shelf life or is considered perishable.
Likes

0

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0

Response

Brandon Cain - Southern Company - Southern Company Services, Inc. - NA - Not Applicable - SERC
Answer
Document Name

Yes

Comment
Yes, Southern Company supports the SDTs approach focused on protection of communication links between Control Centers. Additionally, Southern
requests the SDT to consider the providing clarifying language that ensures the proper scoping of this Standard to be “communications between Control
Centers” and exclude their associated data centers. The definition of Control Center could inadvertently require additional protections be afforded to
communications between an entity’s Control Centers and it’s own data centers, and that does not appear to be the intent stated in the FERC Order.
Likes

0

Dislikes

0

Response

Chris Scanlon - Exelon - 1,3,5,6
Answer

Yes

Document Name
Comment
See attachment Q1
Likes

0

Dislikes

0

Response

Mark Riley - Associated Electric Cooperative, Inc. - 1,3,5,6
Answer

Yes

Document Name
Comment
AECI agrees with the SDT's approach that the focus should be on the communication links rather than the sensitive BES data itself.
Likes

0

Dislikes

0

Response

Deborah VanDeventer - Edison International - Southern California Edison Company - 1,3,5,6 - WECC

Answer

Yes

Document Name
Comment
It is likely that the same types of logical controls would be utilized to protect either. It would be best to further the already established concept of
protecting communication networks/links and explain how that, in turn, protects the data.
Likes

0

Dislikes

0

Response

Sheranee Nedd - Public Service Enterprise Group - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer

Yes

Document Name
Comment
We agree with the approach to focus the draft language on the protection of the communication links. If the SDT decides to focus on the sensitive BES
data, then a definition for “sensitive BES data” would need to be developed. The applicable requirements in IRO-10-2 and TOP-003-3 do not adequately
address this.
Likes

3

Dislikes

PSEG - Public Service Electric and Gas Co., 1, Smith Joseph; PSEG - PSEG Fossil LLC, 5, Kucey Tim;
PSEG - Public Service Electric and Gas Co., 3, Mueller Jeffrey
0

Response

Julie Hall - Entergy - 6, Group Name Entergy/NERC Compliance
Answer

Yes

Document Name
Comment
Perhaps the language should be edited in a manner that will allow entities to protect links and/or the sensitive BES data itself, allowing entities flexability
in achieving the security objective.
Likes
Dislikes

0
0

Response

Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment
Duke Energy agrees with the approach that the focus of the protection should be on the communication links rather than the sensitive BES data itself.
Likes

0

Dislikes

0

Response

Lan Nguyen - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

Yes

Document Name
Comment
CenterPoint Energy agrees that the focus should be on the protection of the communication link used to transport sensitive BES data and not the
sensitive BES data itself. This aligns with the language in the FERC order “to require responsible entities to implement controls to protect, at a
minimum, all communication links and sensitive bulk electric system data communicated between all bulk electric system Control Centers.”(FERC Order
822, P.41)
Likes

0

Dislikes

0

Response

Gerry Adamski - Essential Power, LLC - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Anton Vu - Los Angeles Department of Water and Power - 1,3,5,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Jamie Monette - Allete - Minnesota Power, Inc. - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Lauren Price - American Transmission Company, LLC - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 1,3,4
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Glen Farmer - Avista - Avista Corporation - 1,3,5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Mike Smith - Manitoba Hydro - 1,3,5,6

Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Preston Walker - PJM Interconnection, L.L.C. - 2 - SERC,RF
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion
Answer
Document Name
Comment
1)

Recommend that the SDT focus on protecting the data for reliability and availability

2)
We recommend that this Standard not prescribe the method for protecting the data but the objective of reliability and availability as the focus.
Alternative approaches of application security or communication security controls should be allowed and clearly addressed in the Requirements. The
proposed procedures in Draft Language 1.1 and 1.2 would not be required.
3)
FERC Order 822 section 58 clarifies this scope as inter-Control Center and intra-Control Center communications. The guidance seems to extend
the scope beyond this
4)
Recommend reviewing NIST Special Publication 800-47 which is titled Security Guideline for Interconnecting Information Technology Systems
with a focus toward reliability and availability

5)

The Standard should be an outcome based Standard.

We like the option to protect either the data or the links. We would like to see these options clearly defined within the requirements and not just in the
guidance. The Standard should be an outcome based Standard.
FERC Order 822 section 58 clarifies this scope as inter-Control Center and intra-Control Center communications. The guidance seems to extend the
scope beyond this by including references to DP’s and listing Data links without reference to Control Centers.
Likes

0

Dislikes
Response

0

7. Do you agree with the security objective of the draft language? If not, please propose alternative language.
Brian Millard - Tennessee Valley Authority - 1,3,5,6 - SERC, Group Name Tennessee Valley Authority
Answer

No

Document Name
Comment
It is the Entity’s responsibility to protect its information systems, regardless of the origin of information that is fed info an information system. Specifically,
the draft Guidance language directs REs to establish controls for data links between DPs and TOPs. In such a scenario, the DP may not be subject to
any regulatory controls and the TOP has no mechanism to enforce what a DP is doing with their end of a communications link. Accordingly, the TOP is
powerless to enforce end-to-end data link protections required by the draft language.
In the event that an RE has the ability to control data-link security end-to-end with other entities, such a protection still provides no inherent cyber
security benefit for the information carried over the data link; the information itself may contain a malicious payload carried over an otherwise trusted
data-link.
It is incumbent upon REs to configure information systems under their control to ensure that information provided to information systems is safe,
trustworthy, and appropriately vetted; and potential for adverse impact of incomplete, untrustworthy, or malicious data has been appropriately mitigated.
For example, on a Microsoft Windows server, the RE may install security patches that were downloaded from the public Internet. Such information is
potentially adversely impactful to a BES Cyber System. However, the entity takes appropriate action to ensure the security patches are genuine. Even
though communications links utilized for the vast majority of the transport are untrustworthy, appropriate application layer controls are leveraged to
ensure the trustworthiness of the communications payload.
Likes

0

Dislikes

0

Response

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer

No

Document Name
Comment
Supporting APPA comments
Likes

0

Dislikes
Response

0

Preston Walker - PJM Interconnection, L.L.C. - 2 - SERC,RF
Answer

No

Document Name
Comment
PJM proposes that the objective should focus on protecting the communication networks. Proposed language: “The Responsible Entity shall implement
one or more documented plan(s) to protect data being transferred across communication networks between Control Centers, both inter-entity and intraentity that include each of the applicable parts below:”
The “Purpose” should include the security objective (confidentiality and integrity of data required for reliable operation of the BES).
Likes

0

Dislikes

0

Response

Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

No

Document Name
Comment
Duke Energy does not disagree with the security objective to protect confidentiality and integrity of data required for reliable operation of the BES. We
do not agree that the current draft language is measurable, and thus would make it difficult to audit. Moreoever, the draft language does not appear to fit
the mold of other standards which are performance based. Also, more descriptive language needs to be placed in the requirement. Currently, as written,
an entity would need to refer to the Guidelines and Technical Basis section to determine what was necessary to comply.
Likes

0

Dislikes

0

Response

Kelly Silver - Con Ed - Consolidated Edison Co. of New York - 1,3,5,6, Group Name Con Edison
Answer
Document Name
Comment

No

We suggest "reliability and availability" replace "confidentiality and integrity" because EMS/SCADA systems are built on "reliability and availability."
There should be flexibility when it comes to enforcing encryption and specifying methods and end points.
Likes

0

Dislikes

0

Response

Jeff Johnson - Sempra - San Diego Gas and Electric - 1,2,3,4,5,6,7,8 - WECC
Answer

No

Document Name
Comment
The security objective should be to protect the data.
Likes

0

Dislikes

0

Response

Kara Douglas - NRG - NRG Energy, Inc. - 3,4,5,6 - FRCC,MRO,WECC,Texas RE,NPCC,SERC,SPP RE,RF
Answer

No

Document Name
Comment
The security objective is not clearly stated. We recommend the drafting team put more emphasis or focus on the integrity of the data instead the
confidentially. Additionally, we recommend a definition of data to be protected such as: Data if rendered unavailable, degraded, or misused within 15
minutes would adversely impact the Real-Time operation of the Bulk Electric System. Does this mean that everytime you do a database change, that
change control per the CIP standards must be utilized? (for example, if the database is degraded, it may have a 15 minute impact).
Likes

0

Dislikes

0

Response

Jason Snodgrass - Georgia Transmission Corporation - 1

Answer

No

Document Name
Comment
Propose deleting reference of confidentiality in the standard and focus on integrity because adding confidentiality expands the scope of the FERC
Directive.
Likes

0

Dislikes

0

Response

Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer

No

Document Name
Comment
We suggest “reliability and availability” replace “confidentiality and integrity” because EMS/SCADA systems are built on “reliability and availability”.
Likes

1

Dislikes

Illinois Municipal Electric Agency, 4, Thomas Bob
0

Response

Guy Andrews - Georgia System Operations Corporation - 3,4
Answer

No

Document Name
Comment
Propose deleting reference of confidentiality in the standard and focus on integrity because adding confidentiality expands the scope of the FERC
Directive.
Likes

0

Dislikes
Response

0

Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Answer

No

Document Name
Comment
The commission is asking to implement controls to protect, at a minimum, the communication links and the data being communicated. The concepts
introduced by the SDT (Confidentiality, Integrity, availability), are valid, but are not directly required by the commission. Also, the current CIPs do not
mention those concepts. Either the requirements of the commission are updated or the SDT should fallback to the commission language.
Likes

0

Dislikes

0

Response

Deborah VanDeventer - Edison International - Southern California Edison Company - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
In regards to the objectives, confidentiality and integrity have not been stated as explicit objectives in the current Standards, although they are obviously
implied. The security objective should align with the current standards – “to protect against compromise that could lead to misoperation or instability in
the BES.”
Likes

0

Dislikes

0

Response

Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer

No

Document Name
Comment
The language regarding physical security in the guidance section is concerning to Xcel Energy as physical security is not specifically referenced in the
Standard or Requirement language. Cabling within an ESP spanning multiple PSPs is already required to be physically secured (or deploy alternative

measures such as encryption) under CIP-006-6 R1.10, so requiring this on all wiring would greatly increase the scope of cabling beyond what is needed
under CIP v6. If the SDT/FERC believes that all cabling in Control Centers need to be physically protected, then Xcel Energy would suggest the SDT
update the existing language in CIP-006-6 R1.10 instead of through a new, separate, standard which raises the concern of double jeopardy and adds a
new “spaghetti” requirement previously done away with by v5/v6.

Xcel Energy suggests that the word ‘confidentiality’ be removed from draft language “The Responsible Entity shall implement one or more documented
plan(s) that achieve the security objective to protect confidentiality and integrity of data required for reliable operation of the BES” to ensure
consistency throughout the other CIP standards.

Likes

0

Dislikes

0

Response

David Gordon - Massachusetts Municipal Wholesale Electric Company - 5
Answer

No

Document Name
Comment
MMWEC supports comments submitted by APPA.
Likes

0

Dislikes

0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer
Document Name
Comment

No

The security objective is not clearly stated. We recommend the drafting team put more emphasis or focus on the integrity of the data instead of the
confidentially. Additionally, we recommend a definition of the data to be protected such as: Data if rendered unavailable, degraded, or misused within 15
minutes would adversely impact the Real-time operation of the Bulk Electric.
Likes

0

Dislikes

0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion
Answer

No

Document Name
Comment
We suggest “reliability and availability” replace “confidentiality and integrity” because EMS/SCADA systems are built on “reliability and availability”.
Likes

0

Dislikes

0

Response

Vivian Vo - APS - Arizona Public Service Co. - 1,3,5,6
Answer

No

Document Name
Comment
AZPS does not agree with the security objective of the draft language as it is overly broad and extends beyond the scope of the directive set forth in
Order 822 at Paragraph 53, which specifically targets data in transit between Control Centers. To the extent that this language is retained, AZPS
recommends that the security objective be revised to state:
“…achieve the security objective to protect confidentiality and integrity of data communicated between bulk electric system Control Centers and the
associated communication links…”

Likes
Dislikes

0
0

Response

Marc Donaldson - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6
Answer

No

Document Name
Comment
Tacoma supports the comments of Utility Services, Inc
Likes

0

Dislikes

0

Response

Lona Hulfachor - Salt River Project - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
SRP agrees with the security objective of protecting the confidentiality and integrity of data that is required for reliable operation and is transmitted
between Control Centers.
Likes

0

Dislikes

0

Response

Russel Mountjoy - Midwest Reliability Organization - 10, Group Name MRO NSRF
Answer

Yes

Document Name
Comment
If the security objective is to protect the confidentiality and integrity of operational reliability data transmitted between control centers, the NSRF agrees
Likes

0

Dislikes

0

Response

Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

Yes

Document Name
Comment
As it is understood, the objective is to ensure that data transmitted is received in a way that the recipient can be confident the data is complete and
accurate.
Likes

0

Dislikes

0

Response

Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment
In meeting the security triad of confidentiality, integrity, and availability, the security objective for availability is already addressed and monitored as
noted under question 4. This requirement should be limited to the remaining two objectives of integrity and confidentiality.
Likes

0

Dislikes

0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name
Comment

Yes

BPA agrees with the security objective but suggests that the supporting language needs to be modified to support the objective of protecting data rather
than emphasizing protection of communication links. As discussed above, BPA also encourages the SDT to incorporate the requirements into existing
CIP standards rather than creating a new standard. Wherever the requirements reside, BPA proposes the following edits to the draft SDT language:

The Responsible Entity shall implement one or more documented plan(s) that achieve the security objective to protect availability, confidentiality and
integrity of data required for reliable operation of the BES. The plan applies to data being transferred across communication networks between Control
Centers, both inter-entity and intra-entity and shall include each of the applicable parts below:

1.
i.

Identification of the data required for reliable operation of the BES (if not already identified under IRO-010-2 and TOP-003-3);

ii.

Method(s) for protecting applicable data between Control Centers identified in 1.1, where technically feasible.

iii. Loss of protection of data should be alarmed to a central location with a method of timely response.
Likes

0

Dislikes

0

Response

Candace Morakinyo - WEC Energy Group, Inc. - 3,4,5 - MRO,RF
Answer

Yes

Document Name
Comment
Yes, the primary objective should be on protecting the data.
Likes

0

Dislikes

0

Response

Wendy Center - U.S. Bureau of Reclamation - 1,5
Answer
Document Name

Yes

Comment
Reclamation recommends adding the draft language to CIP-003-7i for low impact BES Cyber Systems, to CIP-005-5 for high and medium BES Cyber
Systems, and to CIP-006-6 Requirement R1 Part 1.10 for physical security.
Likes

0

Dislikes

0

Response

Chris Scanlon - Exelon - 1,3,5,6
Answer

Yes

Document Name
Comment
See attachment Q1
Likes

0

Dislikes

0

Response

Brandon Cain - Southern Company - Southern Company Services, Inc. - NA - Not Applicable - SERC
Answer

Yes

Document Name
Comment
Southern Company agrees with the security objective of the draft language, but as previously stated, believes the language including the requirement to
demonstrate confidentiality be removed. Although confidentiality is part of the foundational CIA security triad, in most instances confidentiality does not
have a real-time (<15 minute) impact to the reliability of the BES.
Likes

0

Dislikes

0

Response

Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2

Answer

Yes

Document Name
Comment
If the security objective is to protect the confidentiality and integrity of operational reliability data transmitted between control centers, we agree.
Likes

0

Dislikes

0

Response

Andrew Gallo - Austin Energy - 1,3,4,5,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Lan Nguyen - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Mike Smith - Manitoba Hydro - 1,3,5,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Glen Farmer - Avista - Avista Corporation - 1,3,5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 1,3,4
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

Julie Hall - Entergy - 6, Group Name Entergy/NERC Compliance
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Lauren Price - American Transmission Company, LLC - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Aaron Austin - AEP - 3,5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Jamie Monette - Allete - Minnesota Power, Inc. - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Sheranee Nedd - Public Service Enterprise Group - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer

Yes

Document Name
Comment

Likes

3

Dislikes
Response

PSEG - Public Service Electric and Gas Co., 1, Smith Joseph; PSEG - PSEG Fossil LLC, 5, Kucey Tim;
PSEG - Public Service Electric and Gas Co., 3, Mueller Jeffrey
0

Anton Vu - Los Angeles Department of Water and Power - 1,3,5,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Gerry Adamski - Essential Power, LLC - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Joe Tarantino - Sacramento Municipal Utility District - 1,3,4,5,6 - WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Mark Riley - Associated Electric Cooperative, Inc. - 1,3,5,6

Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Mike Kraft - Basin Electric Power Cooperative - 1,3,5,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Douglas Webb - Great Plains Energy - Kansas City Power and Light Co. - 1,3,5,6 - SPP RE
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

sean erickson - Western Area Power Administration - 1,6
Answer
Document Name

Yes

Comment

Likes

0

Dislikes
Response

0

8. Is it clear what types of plans, procedures, and methods are needed to meet the draft language? If not, please propose alternative
language.
sean erickson - Western Area Power Administration - 1,6
Answer

No

Document Name
Comment
Referring to the protection of communication links, does this mean select individual links or does it really mean an entire network?
per the NSRF:The question assumes the development of a new standard. The NSRF believes the objectives can be met through simple clarifying
language in CIP-002 and CIP-006. We believe the intent of the Order is met though other changes that have occurred in the standards over
time. Confidentiality is appropriately addressed through the NERC ORD Confidentiality Agreement. The integrity of data is also addressed in multiple
standards dealing with managing the quality of data used by operators (there are 136 references to data quality in the current set of standards).
Likes

0

Dislikes

0

Response

Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2
Answer

No

Document Name
Comment
The question assumes the development of a new standard. We believe the objectives can be met through simple clarifying language in CIP-002 and
CIP-006. We believe the intent of the Order is met though other changes that have occurred in the standards over time. Confidentiality is appropriately
addressed through the NERC ORD Confidentiality Agreement. The integrity of data is also addressed in multiple standards dealing with managing the
quality of data used by operators (there are 136 references to data quality in the current set of standards).
Likes

0

Dislikes

0

Response

Marc Donaldson - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6
Answer

No

Document Name
Comment
Tacoma supports the comments of Utility Services, Inc
Likes

0

Dislikes

0

Response

Vivian Vo - APS - Arizona Public Service Co. - 1,3,5,6
Answer

No

Document Name

Project 2016-02 Communication Networks - Comment for Question 8.docx

Comment
Please see the attached document for AZPS' comments regarding Question 8.
Likes

0

Dislikes

0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion
Answer

No

Document Name
Comment
We do not agree with the draft language which focuses on networks. This language should focus on data.
We like the option to protect either the data or the links. We would like to see these options clearly defined within the requirements and not just in the
guidance. Replace “communication networks” with “communication networks or BES reliability data”. Include in 1.1 that this is for networks or data
between Control Centers.
Likes

0

Dislikes
Response

0

David Gordon - Massachusetts Municipal Wholesale Electric Company - 5
Answer

No

Document Name
Comment
MMWEC supports comments submitted by APPA.
Likes

0

Dislikes

0

Response

Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer

No

Document Name
Comment
This question can only be answered once a determination has been made as to whether a new standard is going to be created or updates are made to
existing standards.
Likes

0

Dislikes

0

Response

Candace Morakinyo - WEC Energy Group, Inc. - 3,4,5 - MRO,RF
Answer

No

Document Name
Comment
A CIP-005 requirement for physical protection or encryption of data flowing between ESPs associated with High and/or Medium Impact BES Cyber
Systems should be sufficient to address this need.
Likes

0

Dislikes

0

Response

Jamie Monette - Allete - Minnesota Power, Inc. - 1
Answer

No

Document Name
Comment
The openness left to entities allows flexible solutions that would be more appropriate than prescriptive requirements would allow. This flexibility leaves
concerns to what degree it would be audited to, this is similar to the Low Impact requirements.
Likes

0

Dislikes

0

Response

Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer

No

Document Name
Comment
We like the option to protect either the data or the links. We would like to see these options clearly defined within the requirements and not just in the
guidance. Replace “communication networks” with “communication networks or BES reliability data”. Include in 1.1 that this is for networks or data
between Control Centers.

Likes

1

Dislikes

Illinois Municipal Electric Agency, 4, Thomas Bob
0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name

No

Comment
Please see Texas RE’s comment in response to Question 6.
Likes

0

Dislikes

0

Response

Jeff Johnson - Sempra - San Diego Gas and Electric - 1,2,3,4,5,6,7,8 - WECC
Answer

No

Document Name
Comment
Delete 1.1
1- Define the boundaries of communication networks transmitting data required for reliable operations. 2- Method(s) for protecting the in scope data
between Control Centers where technically feasible.
Likes

0

Dislikes

0

Response

Russel Mountjoy - Midwest Reliability Organization - 10, Group Name MRO NSRF
Answer

No

Document Name
Comment
The question assumes the development of a new standard. The NSRF believes the objectives can be met through simple clarifying language in CIP002 and CIP-006. We believe the intent of the Order is met though other changes that have occurred in the standards over time. Confidentiality is
appropriately addressed through the NERC ORD Confidentiality Agreement. The integrity of data is also addressed in multiple standards dealing with
managing the quality of data used by operators (there are 136 references to data quality in the current set of standards).
Likes

0

Dislikes
Response

0

Kelly Silver - Con Ed - Consolidated Edison Co. of New York - 1,3,5,6, Group Name Con Edison
Answer

No

Document Name
Comment
Language should focus on data, not networks. There should be flexibility when it comes to enforcing encryption and specifying methods and end points.
Likes

0

Dislikes

0

Response

Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

No

Document Name
Comment
Duke Energy suggests the drafting team consider the balance between existing CIP requirements, and the proposed requirement to protect and encrypt
communication paths. There are existing CIP requirements in CIP-005-5 that certain communications links be inspected for malicious code for inbound
and outbound communications. If a communication link is now expected to be encrypted, the ability to inspect the traffic for malicious code will not be
feasible. If an entity determines that encryption is therefore not a possible option to be able to maintain compliance with existing requirements, the only
suggested protection mechanism left would be physical and is not feasible in most situations.
Likes

0

Dislikes

0

Response

Lan Nguyen - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
CenterPoint Energy has concerns with implementing methods for protecting communication links between Control Centers (R1.3) in situations where
the end point is not owned by the entity. What would be the compliance implications if the owner of the end point is not willing to implement

protections? CenterPoint Energy recommends that the drafting team provide guidance around ownership of communication links and how to comply
with the requirement in these situations.
Likes

0

Dislikes

0

Response

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer

No

Document Name
Comment
Supporting APPA comments
Likes

0

Dislikes

0

Response

Brian Millard - Tennessee Valley Authority - 1,3,5,6 - SERC, Group Name Tennessee Valley Authority
Answer

No

Document Name
Comment
The responsibilities assigned to REs potentially cover information systems for which the RE has no control, creating compliance obligation that would be
impossible to satisfy.
Likes

0

Dislikes

0

Response

Douglas Webb - Great Plains Energy - Kansas City Power and Light Co. - 1,3,5,6 - SPP RE
Answer
Document Name

Yes

Comment
We also believe sub Requirements 1.1 and 1.2 look as if they can be consolidated. Proposed language follows at the end of this response.
Possible Alternative Language:
R1. The Responsible Entity shall implement one or more documented plan(s) that achieve the security objective to protect confidentiality and integrity[1]
of data required for reliable operation of the BES. The plan applies to data being transferred across communication networks between Control Centers,
both inter-entity and intra-entity and shall include each of the applicable parts below:
R1.1 Procedure(s) to identify networks requiring protections, and their associated boundaries.
R1.2 Procedure(s) to associate the categorization completed under CIP-002-5.1a with the identified networks in R1.1.
R1.3 Procedure(s) to design, construct, and implement protections for the networks identified in R1.1. The procedure shall be tailored to address the
high, medium, and low impact risks associated with the networks in R1.2.
R1.4 Procedure(s) to address protections for networks identified in R1.1 where technically feasible.

[1] NIST Special Publication 800-53A : Revision 4, Appendix B (Glossary) [NIST incorporates by reference the definition found in U.S. Code,
Coordination of Federal Information Policy, Information Security (44 U.S.C. §3542), defining “integrity” as “Guarding against improper
information modification or destruction, and includes ensuring information non-repudiation and authenticity.”]
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0

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0

Response

Mike Kraft - Basin Electric Power Cooperative - 1,3,5,6
Answer

Yes

Document Name
Comment
Basin Electric would prefer the plans, procedures and methods be included in CIP-003 and CIP-005 as appropriate vs. in the new proposed standard
CIP-012.
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0

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0

Chris Scanlon - Exelon - 1,3,5,6
Answer

Yes

Document Name
Comment
See attachment Q1
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0

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0

Response

Sheranee Nedd - Public Service Enterprise Group - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer

Yes

Document Name
Comment
For requirement 1.3, we recommend adding the bulleted list from the Draft Guidance Section (similar to CIP-006-6 R1.10) into the requirement
language. The requirement would be written as follows:
1.3 Method(s) for protecting communication networks between Control Centers identified in 1.1, where technically feasible. The Responsible
Entity shall document and implement one or more of the following:
•

Site to site encryption; or

•

Application layer encryption; or

•

Physical protections.

Likes

3

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PSEG - Public Service Electric and Gas Co., 1, Smith Joseph; PSEG - PSEG Fossil LLC, 5, Kucey Tim;
PSEG - Public Service Electric and Gas Co., 3, Mueller Jeffrey
0

Response

Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer
Document Name

Yes

Comment
ERCOT requests that the SDT also consider guidance on where parties at either end of a communication link are not in agreement.
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0

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0

Response

Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

Yes

Document Name
Comment
It is important to maintain flexibility for Responsilbe Entities to develop controls that work best within their environment and for their situation. The less
prescriptive the requirements, the more flexible and agile the Responsible Entity can be to work within the skills sets of their personnel and respond to
the changing security and technology landscapes. IPC suggests that the requirements state objectives and requirements to document positions and
controls and be less prescriptive than the CIP standards are in their current state.
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0

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0

Response

Brandon Cain - Southern Company - Southern Company Services, Inc. - NA - Not Applicable - SERC
Answer

Yes

Document Name
Comment

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0

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0

Response

Wendy Center - U.S. Bureau of Reclamation - 1,5
Answer

Yes

Document Name
Comment

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0

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0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

Yes

Document Name
Comment

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0

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0

Response

Mark Riley - Associated Electric Cooperative, Inc. - 1,3,5,6
Answer

Yes

Document Name
Comment

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0

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0

Response

Joe Tarantino - Sacramento Municipal Utility District - 1,3,4,5,6 - WECC
Answer
Document Name
Comment

Yes

Likes

0

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0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment

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0

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0

Response

Gerry Adamski - Essential Power, LLC - 5
Answer

Yes

Document Name
Comment

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0

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0

Response

Anton Vu - Los Angeles Department of Water and Power - 1,3,5,6
Answer

Yes

Document Name
Comment

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0

Dislikes

0

Response

Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Answer

Yes

Document Name
Comment

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0

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0

Response

Guy Andrews - Georgia System Operations Corporation - 3,4
Answer

Yes

Document Name
Comment

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0

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0

Response

Aaron Austin - AEP - 3,5
Answer

Yes

Document Name
Comment

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0

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Response

0

Jason Snodgrass - Georgia Transmission Corporation - 1
Answer

Yes

Document Name
Comment

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0

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0

Response

Lauren Price - American Transmission Company, LLC - 1
Answer

Yes

Document Name
Comment

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0

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0

Response

Kara Douglas - NRG - NRG Energy, Inc. - 3,4,5,6 - FRCC,MRO,WECC,Texas RE,NPCC,SERC,SPP RE,RF
Answer

Yes

Document Name
Comment

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0

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0

Response

Julie Hall - Entergy - 6, Group Name Entergy/NERC Compliance

Answer

Yes

Document Name
Comment

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0

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0

Response

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 1,3,4
Answer

Yes

Document Name
Comment

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0

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0

Response

Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer

Yes

Document Name
Comment

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0

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0

Response

Glen Farmer - Avista - Avista Corporation - 1,3,5
Answer
Document Name

Yes

Comment

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0

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0

Response

Lona Hulfachor - Salt River Project - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment

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0

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0

Response

Mike Smith - Manitoba Hydro - 1,3,5,6
Answer

Yes

Document Name
Comment

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0

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0

Response

Preston Walker - PJM Interconnection, L.L.C. - 2 - SERC,RF
Answer
Document Name
Comment

Yes

Likes

0

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0

Response

Andrew Gallo - Austin Energy - 1,3,4,5,6
Answer

Yes

Document Name
Comment

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0

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Response

0

9. The SDT uses the term “communication networks” throughout the draft language including an obligation to define the boundaries of such
communication networks. Does the SDT need to define the term for inclusion in the NERC Glossary of Terms? If so, please propose a
definition of “communication networks.”
Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer

No

Document Name
Comment
Supporting APPA comments
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0

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0

Response

Lan Nguyen - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
CenterPoint Energy recommends using the term “communication link(s)” instead of “communication networks” in the requirement language to align with
the FERC directive. The term “communication networks” can encompass many types of networks, some of which are currently out of scope for the CIP
Standards. CenterPoint Energy believes the focus should be on the protections around the communication links used to transmit sensitive bulk electric
system data between Control Centers. CenterPoint Energy recommends the following changes:
“The Responsible Entity shall implement one or more documented plan(s) that achieve the security objective to protect confidentiality and integrity of
data required for reliable operation of the BES. The plan applies to data being transferred across communication links between Control Centers, both
inter-entity and intra-entity and shall include each of the applicable parts below:
1.1

Procedure(s) to identify the communication links requiring protections;

1.2

Procedure(s) for defining the boundaries of communication links transmitting data required for reliable operation identified in 1.1, if applicable;

1.3

Method(s) for protecting communication links between Control Centers identified in 1.1, where technically feasible.”

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0

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0

Preston Walker - PJM Interconnection, L.L.C. - 2 - SERC,RF
Answer

No

Document Name
Comment
PJM asserts that “between Control Centers” already clarifies the scope.
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0

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0

Response

Kelly Silver - Con Ed - Consolidated Edison Co. of New York - 1,3,5,6, Group Name Con Edison
Answer

No

Document Name
Comment
CIP-002 Exemptions already utilize the "communications networks" term. However, consider that the FERC Order Section 58 clarifies the focus and the
scope on inter-Control Center and intra-Control Center communications
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0

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0

Response

Lona Hulfachor - Salt River Project - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
Draft language, applicable part 1.1 call for procedure(s) to identify the communications network requiring protections. A defined term for communication
network may restrict an entity’s flexibility in determining how to implement the draft language.
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0

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0

Response

Russel Mountjoy - Midwest Reliability Organization - 10, Group Name MRO NSRF
Answer

No

Document Name
Comment
The term "communication networks" is used elsewhere in the standards. The NSRF believes that defining the term for one standard would have
unintended impacts on other standards.
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0

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0

Response

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 1,3,4
Answer

No

Document Name
Comment
Does not need to be defined, because from a simple view it includes everything outside the CIP ESP.
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0

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0

Response

Jeff Johnson - Sempra - San Diego Gas and Electric - 1,2,3,4,5,6,7,8 - WECC
Answer
Document Name
Comment

No

The standard uses two terms; "communication networks" and "communication links". Use one term, not two. We believe the standard should address
securing the data, not the "networks" or "links".
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0

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0

Response

Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer

No

Document Name
Comment
Recommend a NO vote on defining “communication network”
But consider that the FERC Order Section 58 clarifies the focus and the scope on inter-Control Center and intra-Control Center communications
Likes

1

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Illinois Municipal Electric Agency, 4, Thomas Bob
0

Response

Jamie Monette - Allete - Minnesota Power, Inc. - 1
Answer

No

Document Name
Comment
The term “communication networks” is used elsewhere in the standards. The NSRF believes that defining the term for one standard would have
unintended impacts on other standards.
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0

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0

Response

Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE

Answer

No

Document Name
Comment
The term communication Networks has many different applications and is too broad of a term to be used in in Standard Language without adding a
defined term in the NERC Glossary. The FERC directive only references “Links.” Xcel Energy would suggest formal definitions be drawn up for both
Communication Networks and Links.
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0

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0

Response

Mark Riley - Associated Electric Cooperative, Inc. - 1,3,5,6
Answer

No

Document Name
Comment
The term "communication networks" is already used in the applicability section of the CIP standards. Defining this term could have unintended
consequences.
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0

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0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion
Answer

No

Document Name
Comment
Recommend a NO vote on defining “communication network”.
But consider that the FERC Order Section 58 clarifies the focus and the scope on inter-Control Center and intra-Control Center communications.
Likes
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0
0

Response

Brandon Cain - Southern Company - Southern Company Services, Inc. - NA - Not Applicable - SERC
Answer

No

Document Name
Comment
Southern Company respectfully requests that the SDT refrain from attempting to define “communications networks” as an attempt could be defined so
broadly to open the door to varying degrees of interpretation, or alternatively a restrictive definition could place limitations on a Responsible Entity’s
implementation. The language, as specified in R1.2, places the responsibility on the Entity to define “the boundaries of communication networks
transmitting data required for reliable operation” and should be determined by the Entity without the need for another defined term.
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0

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0

Response

Vivian Vo - APS - Arizona Public Service Co. - 1,3,5,6
Answer

No

Document Name
Comment
AZPS recommended in its response to Question 8 that the term “communication networks” be replaced with the term “communication links.” AZPS
recommends that the term “communication links” be defined as:
The logical communication path that uses a routable protocol to connect BES Control Centers and over which Sensitive BES Data is transmitted.
If the term “communication network” is retained, AZPS recommends the same definition:
The logical communication path that uses a routable protocol to connect BES Control Centers and over which Sensitive BES Data is transmitted.
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0

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0

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Marc Donaldson - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6
Answer

No

Document Name
Comment
Tacoma supports the comments of Utility Services, Inc
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0

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0

Response

Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2
Answer

No

Document Name
Comment
The phrase “communication networks” is used elsewhere in the standards. To define the term for one standard would have unintended impacts on
other standards.
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0

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0

Response

Mike Smith - Manitoba Hydro - 1,3,5,6
Answer

No

Document Name
Comment

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0

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0

Response

Lauren Price - American Transmission Company, LLC - 1
Answer

No

Document Name
Comment

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0

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0

Response

Anton Vu - Los Angeles Department of Water and Power - 1,3,5,6
Answer

No

Document Name
Comment

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0

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0

Response

Gerry Adamski - Essential Power, LLC - 5
Answer

No

Document Name
Comment

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0

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0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name
Comment

No

Likes

0

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0

Response

David Gordon - Massachusetts Municipal Wholesale Electric Company - 5
Answer

No

Document Name
Comment

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0

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0

Response

Mike Kraft - Basin Electric Power Cooperative - 1,3,5,6
Answer

No

Document Name
Comment

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0

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0

Response

Brian Millard - Tennessee Valley Authority - 1,3,5,6 - SERC, Group Name Tennessee Valley Authority
Answer

Yes

Document Name
Comment
TVA suggests focusing on the “sensitive bulk electric system data” moving between Control Centers and not underlying communications infrastructure.

Likes

0

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0

Response

Andrew Gallo - Austin Energy - 1,3,4,5,6
Answer

Yes

Document Name
Comment
“A collection of interconnected components utilized for transmitting and/or receiving data.”
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0

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0

Response

Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment
Duke Energy supports a definition of “communication networks”. Use of the term “communication” creates some ambiguity, particularly
what types of communication this applies. It is not known if all forms of communication fall under this purview, specifically verbal
communication avenues.
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0

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0

Response

Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer
Document Name
Comment

Yes

The collection of networked communication devices that provide routable transmission of data.
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0

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0

Response

Richard Kinas - Orlando Utilities Commission - 3,5
Answer

Yes

Document Name
Comment
Communication networks - Any technology that allows the transfer of information and data, including voice, between two endpoints.
Likes

0

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0

Response

Kara Douglas - NRG - NRG Energy, Inc. - 3,4,5,6 - FRCC,MRO,WECC,Texas RE,NPCC,SERC,SPP RE,RF
Answer

Yes

Document Name
Comment
NRG recommends that the SDT provide a defined term for “Communication Networks” into the the NERC GOT.
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0

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0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name

Yes

Comment
Texas RE would support the SDT in defining the term “communication networks”.

In addition, Texas RE recommends adding the following to the list of examples of communication links:
Data link(s) between a Generator Operators.
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0

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0

Response

Jason Snodgrass - Georgia Transmission Corporation - 1
Answer

Yes

Document Name
Comment
Proposed definition - Communication network is data link used to connect one location to another location for the purpose of transmitting and receiving
digital data used in intra-Control Center communications for reliability operations of the BES.
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0

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0

Response

Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

Yes

Document Name
Comment
IPC suggests communication networks be defined as, "Those networks used to logically and physically transport a communications link."
Likes
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0
0

Response

Aaron Austin - AEP - 3,5
Answer

Yes

Document Name
Comment
AEP believes this will help define the extent of the requirements.
Likes

0

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0

Response

Guy Andrews - Georgia System Operations Corporation - 3,4
Answer

Yes

Document Name
Comment
Proposed definition - Communication network is data link used to connect one location to another location for the purpose of transmitting and receiving
digital data used in intra-Control Center communications for reliability operations of the BES.
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0

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0

Response

Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment
ERCOT asserts that “networks” may be too broad and implicate unintended equipment based on a common understanding of the term. Consider the
use of “Communication Link” instead. Proposed definition: communications infrastructure between two or more locations for the purpose of transmitting
and receiving data.

Likes

0

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0

Response

Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC
Answer

Yes

Document Name
Comment
A definition of “communication networks” should be provided in the context of the CIP standard. This would minimize the risk of miss interpretation by
the entities. In this case, we think that part of the definition should mention the logical network, not the physical network (not the equipment). So the
definition could be logical network that is being used to transport data used by the BES
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0

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0

Response

Sheranee Nedd - Public Service Enterprise Group - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer

Yes

Document Name
Comment
We recommend the following definition: Communication Network: a system of sending and receiving information, i.e. data, from point A to point B using
a network of logical and physical devices. The term ‘communication network’ excludes equipment facilities used exclusively for Interpersonal
Communication or Alternative Interpersonal Communication, as defined in the NERC Glossary of Terms.
Likes

3

Dislikes

PSEG - Public Service Electric and Gas Co., 1, Smith Joseph; PSEG - PSEG Fossil LLC, 5, Kucey Tim;
PSEG - Public Service Electric and Gas Co., 3, Mueller Jeffrey
0

Response

Joe Tarantino - Sacramento Municipal Utility District - 1,3,4,5,6 - WECC
Answer
Document Name

Yes

Comment
Yes – Clarity is always welcomed.
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0

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0

Response

Deborah VanDeventer - Edison International - Southern California Edison Company - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
If the term “communication networks” is not formally defined, industry interpretations will vary widely.
Likes

0

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0

Response

Candace Morakinyo - WEC Energy Group, Inc. - 3,4,5 - MRO,RF
Answer

Yes

Document Name
Comment
The SDT needs to make it clear whether there are deliniations / transitions between routable and other forms (serial, dial-up) forms of communication
network. They should also make it clear what specific protections apply to those parts of the communication network over which a Registered Entity has
direct control (up to and including the ESP) and those parts over which a Registered Entity may have little or no control (e.g. network communication
links between ESPs).
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0

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0

Response

Wendy Center - U.S. Bureau of Reclamation - 1,5

Answer

Yes

Document Name
Comment
To promote consistency as the standards change, Reclamation recommends NERC define “communication network” in the NERC Glossary of Terms.
Reclamation recommends the following definition of Communication Network: “A system of communication connections consisting of (but not limited to)
cables, fibers, microwave radio links, satellites, etc. used to connect computers or other terminals for the purpose of exchanging data required for the
reliable operation of the BES.”
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0

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0

Response

Chris Scanlon - Exelon - 1,3,5,6
Answer

Yes

Document Name
Comment
See attachment Q1
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0

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0

Response

Douglas Webb - Great Plains Energy - Kansas City Power and Light Co. - 1,3,5,6 - SPP RE
Answer

Yes

Document Name
Comment
We support a NERC Glossary Term for “Communication Network.”
Suggested Definition

Communication Network – Logical connections between two or more control centers which pass real time operational reliability data required for reliable
operation of the Bulk Electric System. The connections may include, but are not limited to, physical equipment, through tunneling, or other virtual
constructs.
Potential GTB support: The Communication Network is a layer 3 (network layer) construct as established by the International Organization for
Standardization (1989-11-15). "ISO/IEC 7498-4:1989 -- Information technology -- Open Systems Interconnection -- Basic Reference Model: Naming
and
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0

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0

Response

sean erickson - Western Area Power Administration - 1,6
Answer

Yes

Document Name
Comment
The document continually uses the terms, “communication links”, “communication networks”, “data links”, “in-scope communication networks”, “in-scope
communication links”, and in one case “communication networks/data links”, without clarifying the differences between any of the terms, or their
intended use. This adds ambiguity to the document. Questions surface regarding the nature of a link being a single path, and do multiple links form a
network? What is the difference between a communication link and a data link, does one carry voice traffic and the other does not? Do “in-scope” vs.
“not in-scope” links or networks need to be identified separately? If the terms are being used interchangeably, then the correct term and its definition
needs to be identified and used consistently.
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0

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0

Response

Glen Farmer - Avista - Avista Corporation - 1,3,5
Answer

Yes

Document Name
Comment

Likes
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0
0

Response

Julie Hall - Entergy - 6, Group Name Entergy/NERC Compliance
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

Yes

Document Name
Comment

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0

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0

Response

Additional comments received by Chris Scanlon of Exelon
Questions

1. The SDT asserts that the referenced data is already afforded protections at rest under existing CIP standards (CIP-003, 005, 007, etc.),
perishable, and has a diminished need for protection over time. Do you agree with the SDT’s assertion? If you agree, please supply a
rationale to support the position.

Yes
No
Comments: Exelon agrees that the referenced data is already afforded protections at rest under the existing CIP Standards through physical
and logical protections. The standards use a layered defense-in-depth approach based on the impact rating of the BES Cyber Systems. For
example, for the BES Cyber Systems that communicate with a routable protocol using External Routable Connectivity, more granular security
controls are applied to those BES Cyber Systems from CIP-005-5, CIP-006-6, CIP-007-6, and CIP-010-2. Whereas for those BES Cyber
Systems that do not communicate externally, the CIP-006-6 standards affords specific physical security controls to “restrict physical access”
along with the logical controls from CIP-007-6 and CIP-010-2 to support, malicious code prevention, security patch managements,
configuration baselines, etc.
There is also a diminished need to protect real-time reliability operating data over time given that it is only used for real-time operation at a
point-in-time. Once it is replaced by newer information, there is less of a need to protect the referenced data over time.
Additional thoughts & General Comments:
1) There is a disconnect between the requirement language and the Guidelines and Technical Basis (GT&B) section. The following examples

identify specific instances where the GT&B and requirement language are inconsistent.
a. The draft requirement describes the applicable communication networks as those transmitting “data required for reliable operation of the BES” whereas
the guidance refers to networks that transmit “operational reliability data between Control Centers.” The former indicates a measure of Responsible Entity
discretion in identifying the critical networks, whereas the latter would seem to capture any network transmitting operational reliability data, regardless of
the effect of that data on reliable operation.

The guidance later refers to identifying “communication links that could adversely impact the reliable operation of the Control Center within
15 minutes.” That seems to push for a measure of entity discretion in designing a process for identifying such networks and conflict with the
identification of all networks that transmit “operational reliability data between Control Centers
b. The GT&B section uses wording such as “required” or “must” which is requirement language and not guidance. The GT&B is to explain the

requirement language.
c. The GT&B states that “the Responsible Entity should ensure that the methods chosen include rationale supporting the identification of such

communication networks” however the Requirement only states that there be “1.1 Procedure(s) to identify the communication networks
requiring protections.”

d. The GT&B suggests that a “Responsible Entity complement physical protections with logical protections to fully ensure that the integrity and

confidentiality of data transmitted between Control Centers is protected.” Are there cases where physical security would not be sufficient
thereby making this a requirement to achieve the security objective.
e. The GT&B suggests that “the Responsible Entity must document and implement plans for the protection of the confidentiality and integrity of

operational reliability data communicated between Control Centers.” We are obligated to demonstrate that we have implemented the Plan(s),
but this reads as if we have to have separate evidence that demonstrates the plans that were used to implement.
2) What does it mean for a communication network to be within an entity’s “footprint”? Does that refer to networks within a retail distribution

area? Does that refer to communication networks at an entity’s facility? If it is associated with the” utility footprint”, how does that concept
apply to entities without a traditional utility “footprint” such as a GOP or RC?
3) The GT&B should specifically state that a Responsible Entity that lacks a Control Center is not subject to the Standard. For example, a GOP
with only a control room for a single generating facility location would not have a “Control Center” and would not therefore be subject to the
Standard. From a compliance perspective, it is helpful when the guidance says this explicitly.
4) By definition, only RCs, BAs, TOPs, and GOPs can have “Control Centers” yet the CIP Standards generally apply the DPs, TOs, GOs, and
IAs as well. Are these latter entities exempt from the Standard?
5) The application of the Standard to protect communications networks should not inhibit an entity’s ability to participate in programs (e.g. anti-

terrorism, CRISP, etc.) where network connections to government or other entities are necessary to share information. The GT&B should
provide guidance supporting that the protections of communications are not intended to inhibit these types of data monitoring activities or
with the confidentiality and data integrity required by the Standard.
6) Addressing the need to clearly scope this Standard to ESP to ESP networks.

Below is discussion for allowing the Control Center to Control Center links assessed for this requirement in 1.1 to be able to be limited by a
registered entity to Control Center ESP to Control Center ESP links (inter and intra). We would prefer to see the scope more defined within
the Standard, but would at a minimum expect to see more clarity within the Guidance.
a. The guidance suggests the possibility of using NERC CIP-002 criteria to identify all inter-Control Center and intra-Control communication
links. “As one possible solution, the Responsible Entity could apply CIP-002 criteria to identify all inter-Control Center and intra-Control

Center communication links that could adversely impact the reliable operation of the Control Center within 15 minutes.” By application of
the existing NERC CIP standards the CIP-002 criteria would identify communication links between ESPs (inter and intra Control Center).
There is an assumption statement that the SDT makes that is only true if the links are limited to ESP to ESP. “The SDT asserts that the
referenced data is already afforded protections at rest under existing CIP standards (CIP-003, 005, 007, etc.), is perishable, and has a
diminished need for protection over time. “. Non ESP devices holding operational data at rest may not be currently protected as part of
NERC CIP standards as they are not in NERC CIP Scope. Example: PMU data transmitted between Control Centers but not having 15
minute impact.
b. Providing communications protections in this standard to non ESP to ESP links would mean that we are protecting networks under the rigor
of this new NERC CIP standard without protecting the end devices (endpoints) under the NERC CIP requirements. By not using the same
criteria there is risk to performers dealing with additional complexities of the NERC CIP standards and there is risk that auditors would
initially interpret the end devices of these protected networks as being misclassified. The NERC CIP Standards determine the NERC CIP
devices and the ESPs protecting those devices with a 15 minute impact criteria. The initial scope of the communications network
requirements reasonably would be limited to links between those protected devices.
c. If planning and operational data without a 15 minute criterial is required to be in this standard then the standard needs more than network
communications to ensure the standards cover that protection, it would require additional device protections.
d. With this allowed limitation of ESP to ESP links the issues related to a lack of clarity of “communication networks”, “communication links”,
“sensitive bulk electric system data” are reduced as the scope of the protected networks is easily defined.

2. If you do not agree with the SDT’s assertion in Question 1, please identify the type of data, the risk posed at rest, and supply the rationale to
support the position.
Comments:
Not Applicable.

3. Future enforceable Reliability Standards IRO-010-2 and TOP-003-3 identify “data required for reliable operation.” For example,
Requirement R1 of IRO-010-2 states:

R1. 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 and external network data, as deemed necessary by the Reliability Coordinator.
TOP-003-3 Requirements R1 & R2 also have similar requirements for BAs and TOPs.
Do you agree that outlining this approach for identifying “data required for reliable operation” in the Guidelines and Technical Basis is
sufficient; consequently, an additional definition of “sensitive BES data” or a requirement to identify “sensitive BES data” is not necessary? If
not, please explain.
Yes
No
Comments: Exelon does not agree with placing the obligation for what data is to be considered should be placed into the GT&B. Exelon does support
leveraging existing descriptions of data required for reliable operation as much as possible so that data classified is consistent across the
Standards. For entities covered by IRO-010 and TOP-003, CIP-012 should include in the Requirement language which data is required for
protection. Having different groups of reliability data for the same entities will make compliance efforts needlessly complex with no added
benefit to reliable operation.
4. The SDT asserts that “availability” of inter-and intra-entity Control Center communication of data is being addressed in Project 2016-01
Modifications to TOP and IRO Standards, specifically Reliability Standards TOP-001-4 and IRO-002-5. The proposed standards require
redundant and diversely routed data exchange capabilities at a Responsible Entity’s primary Control Center. Do you agree that “availability”
is adequately addressed by these standards? If not, please provide rationale to support your position.
Yes
No
Comments: Exelon agrees that the separate “Project 2016-01 Modifications to TOP and IRO Standards” covers the availability of the
referenced data. In addition, covering the availability of data in this project goes beyond the scope of the Commission’s directive, which is
addressed only at protecting communication links and data for confidentiality and integrity.
5. The SDT is proposing to develop a new CIP standard because the directives of FERC Order 822 related to the protection of communication
networks used to exchange sensitive BES data regardless of the entity’s size or impact level. Do you agree with the drafting of a new CIP
standard to address this issue? If you disagree and would prefer to include requirements in existing CIP Standards, such as CIP-003 and CIP005, please provide rationale and propose requirement language.

Yes
No
Comments: Exelon agrees that the directive should be addressed through a new Standard, as proposed by the SDT. The other CIP Standards
exempt “Cyber Assets associated with communication networks and data communication links between discrete Electronic Security
Perimeters.” Revising those Standards to cover this new topic would require revisiting those exemptions in each Standard. It may be simpler
to use an entirely specific Standard rather than re-opening the exemption for each existing CIP Standard.
6. The SDT evaluated multiple approaches to addressing the directive. The approach proposed in this informal posting focuses on the
protection of communication links. An alternative approach could focus on the protection of the sensitive BES data itself. Do you agree with
the SDT’s approach to focus the draft language on the protection of communication links? If not, please provide rationale and propose
alternative language.
Yes
No
Comments: Exelon supports responding to the directive by focusing on protecting the confidentiality and integrity of data sent over
communication links; thereby applying protections to the data by addressing the communication links.
Exelon would prefer to change the “where technically feasible” language to “based on Cyber Asset capability.” The version 5 set of
Standards introduced the notion that there may be limitations to Cyber Assets and the SDT reduced the number of instances associated with
Technical Feasibility Exceptions (TFE). For example, Requirement 1.3 could be rewritten to state: “Method(s) for protecting communication
networks between Control Centers identified in 1.1, based on Cyber Asset capability.” This would imply documenting the lack of capability
but not require a TFE. Nearly any mitigating measures that would be required for a TFE could be considered protections that are documented
to meet this requirement.
Exelon appreciates the SDT adding examples to the GT&B about approaches that can be implemented to meet the obligation of protecting
communication networks. Exelon recommends that the SDT consider adding some text regarding the feasibility of these methods to the
GT&B and whether the feasibility would ultimately affect whether the method would be viable:
•

Site to site encryption – this is the most feasible approach at this time and focuses the protections on the end-points of the communications
networks directly that make up the site-to-site encryption. Additionally, with this approach, there would not need to be an analysis of any of
the intermediate communication networks or the transport layer communication networks since the site-to-site encryption protects the entire
communication path.

•

Application layer encryption – there are several barriers that would make this approach unlikely for mass use:

o

Lack of support – most vendors do not have these capabilities nor have them on their roadmaps

o

Lack of standards – if a vendor has application layer encryption it is most often proprietary

o

Lack of depth – some of the solutions that use SSL or TLS and all but TLS 1.2 have been deprecated.
Once standards have been created for an interoperable application layer encryption protocol that also includes reliability and integrity
features, then this would be the long range goal. This would provide the highest level of transport protections from device to device.

•

Physical protections – depending on the size of the entity, deploying physical protections sufficient to protect the confidentiality and integrity
of the referenced data, this may not be a feasible approach due to the cost of retrofitting and the limited protection it provides. It may be
useful for short runs but as an overall approach may not possible.

7. Do you agree with the security objective of the draft language? If not, please propose alternative language.
Yes
No
Comments: Exelon agrees with the security objective to protect communication networks between Control Centers. Exelon agrees with the security
objective, however, requests the SDT add more clarity to the requirement language for what communication network end-points are actually expected to
be protected and whether every intermediate communication network is required to be protected when implementations such as application-layer security
or site-to-site virtual private networks are used.

8. Is it clear what types of plans, procedures, and methods are needed to meet the draft language? If not, please propose alternative
language.
Yes
No
Comments: The current draft language is reminiscent of V3 CIP-002 with entities determining their own risk based method without the
guidance of a bright line. That did not work well to bring consistent implementation and left entities and regions unevenly
protected. Defining the data to be protected as that which is transmitted between Control Center ESP to Control Center ESP (for High and
Medium) does allow that bright line. If specific details related to the applicable protections are included in Guidance only, there will be

significant different interpretations. Exelon’s preference would be to see more specificity within the Standard language itself. For entities
without Electronic Security Perimeters, it is important to identify what end points need to be protected within the communication networks.
Implementation of Protections
1) Given proposed application to “inter-entity” communication networks, how will differences between entities be handled? For example:
a. If two entities take different approaches to encryption, how should that be resolved? Will there be dispute resolution of some kind?
b. What if one entity’s approach is considerably more expensive and raises questions on prudency? How should that be resolved, particularly if

utilities are in different states or have different rate structures that might not provide for the recovery of these costs?
c. If two entities have different opinions on whether their connecting communication network needs to be protected, whose view prevails?
i. Always the most conservative (protective) entity?
ii. Or is the Responsible Entity that identified the network as critical the only entity that needs to demonstrate compliance? If so, how can the

other entity be required to undertake the costs necessary to assist the first entity in demonstrating compliance? (In other words, if I don’t see a
network as critical, why and how can I be required to spend money to assist you in implementing expensive encryption for purposes of your
compliance?)
2) The guidance should expand on what is meant by “confidentiality” and “integrity” to ensure that auditors and Responsible Entities do not

have different understandings of what the Standard is intended to accomplish.
 The reference to NIST Special Publication 800-53A is helpful, but it is not clear whether or not the Standard is specifically incorporating the
definition of “integrity” contained in that publication. That publication also defines “confidentiality” but in a manner that includes personal
data not relevant to NERC compliance.
 If the reference to NIST Special Publication 800-53A is intended to guide implication of the Standard in other ways, the guidance should
explain how the NIST document is relevant. It appears to be focused on the assessment of confidentiality and integrity controls rather than
the design of such controls.

3) The guidance states that physical conduit “can be used,” but also suggests that conduit be supplemented by logical protections. Using conduit

with additional logical controls might be a good security practice, but the Standard should specify that the use of physical conduit is sufficient
to comply with the Standard. As written, it could be read that physical conduit, on its own, may not be sufficient for compliance.

4) Other than “site-to-site encryption” and “application layer encryption” are there other logical methods to protect data confidentiality and

integrity that should be described in the program? The guidance does not limit Responsible Entities to those methods, but it can help from an
audit perspective if the methods we use are described in the guidance.

9. The SDT uses the term “communication networks” throughout the draft language including an obligation to define the boundaries of such
communication networks. Does the SDT need to define the term for inclusion in the NERC Glossary of Terms? If so, please propose a
definition of “communication networks.”
Yes
No
Comments: To ensure there is clear understanding of what communication networks are intended to be protected, the term “communication networks”
should have a NERC defined definition. As written, the requirements and GT&B appear to commingle at what point of the “communication networks” are
protections to be afforded. For example, the requirement “1.1 Procedure(s) to identify the communication networks requiring protections”

obligation doesn’t provide sufficient understanding of how to make that identification. Is the communication network that is local to the
facility to be included, the communication network that is associated with the wide area network, or both. Moreover, requirement “1.2
Procedure(s) for defining the boundaries of communication networks transmitting data required for reliable operation identified in
1.1, if applicable” requires the entity to establish some boundary, but no clarity on how or what is an appropriate boundary. If an entity
choses the boundary at the Electronic Security Perimeter to another Electronic Security Perimeter only, would that sufficiently addresses the
security objective of the requirement?
The GT&B states that “The plan(s) should identify the applicable communication networks both within the entity’s footprint, and any
applicable networks between Responsible Entities.” This statement adds additional ambiguity as to what points of the communication
network are to be protected. If the Plan(s) are to take into account other networks “between Responsible Entities” does this also include the

telco provided networks? Depending on the solutions used, the intermediate communication networks are not a risk and are just the transport
layer for the encrypted data packets.

Additional comments received from Vivian Vo of APS (Q8)
No, AZPS respectfully submits that the draft language is not clear relative to the types of plans, procedures, and methods that are needed
for compliance therewith. In particular, AZPS has identified several revisions to the draft language that should be implemented to ensure
clarity and consistency relative to the obligation being described:
•

Evaluate and revise the introductory language to ensure that it is consistent with the content of the subparts;

•

Replace the term “communication networks” with the term “communication links;” and

•

Develop appropriate defined terms to ensure that the responsible entities have a clear and unambiguous scope and associated expectations
and obligations (e.g., the term “communication networks” and the scope of data to which these requirements are applicable).
AZPS recommends these revisions as they will further ensure that the protections required by the FERC directive are clear and unambiguous
and that protections are applied more uniformly across entities that communicate via the in-scope data links. Without such modifications,
ambiguity coupled with the inherent complexity of the processes and data that are in-scope will create unnecessary risk and diminish the
value and benefit of the protections implemented to the reliable operation of the BES.
AZPS recommends the following modifications to the draft language:
The Responsible Entity shall implement one or more documented plan(s) that achieve the security objective to protect confidentiality and
integrity of data required for reliable operation of the BES. The plan applies to data being transferred across Communication networksLinks
between Control Centers, both inter-entity and intra-entity, and that shall include each of the applicable parts below:

1.1
1.2
1.3

1.3.1
1.3.2

Procedure(s) to identify the communication networks requiring protections determine Sensitive BES Data transmitted between Control
Centers requiring protections;
Procedure(s) for defining the boundaries of Communication networksLinks transmitting Sensitive BES Data required for reliable operation
identifieddetermined in 1.1, if applicable;
Method(s) for protecting the confidentiality and integrity of data transmitted via these Communication networksLinks between Control
Centers as identifieddetermined in 1.1, where technically feasible. via one or more of the following methods per Communication Link
capability:
Encryption of the data prior to leaving the ESP or at the boundaries identified in 1.2, with decryption occurring at the boundary that the
receiving Control Center has identified in 1.2.
Monitoring the status of the Communication Links and issuing an alarm or alert in response to detected communication failures or potential
compromises to the personnel identified in the BES Cyber Security Incident response plan within 15 minutes of detection.

1.3.3

Implementation of an equally effective logical protection.
Additional comments received from Nathan Mitchell of APPA
Questions

1. The SDT asserts that the referenced data is already afforded protections at rest under existing CIP standards (CIP-003, 005, 007, etc.), is
perishable, and has a diminished need for protection over time. Do you agree with the SDT’s assertion? If you agree, please supply a
rationale to support the position.
Yes
No
Comments:
The referenced data while at rest is covered in the cited Standards. Consider that real-time SCADA data performance may be impacted by
disk encryption.
2. If you do not agree with the SDT’s assertion in Question 1, please identify the type of data, the risk posed at rest, and supply the rationale to
support the position.
Comments:
No comment to this question
3. Future enforceable Reliability Standards IRO-010-2 and TOP-003-3 identify “data required for reliable operation.” For example,
Requirement R1 of IRO-010-2 states:
R1. 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:
1.2. 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 and external network data, as deemed necessary by the Reliability Coordinator.
TOP-003-3 Requirements R1 & R2 also have similar requirements for BAs and TOPs.
Do you agree that outlining this approach for identifying “data required for reliable operation” in the Guidelines and Technical Basis is
sufficient; consequently, an additional definition of “sensitive BES data” or a requirement to identify “sensitive BES data” is not necessary? If
not, please explain.

Yes
No
Comments:
We agree with the basic approach of using TOP-003 and IRO-010 Standards to identify this data but needs to be limited to real time data.
We believe TOP-003 and IRO-010 include data that is not “real time” so would be outside this document’s scope. An example of data which
is out of scope includes data used for Operational Planning Analyses.
4. The SDT asserts that “availability” of inter-and intra-entity Control Center communication of data is being addressed in Project 2016-01
Modifications to TOP and IRO Standards, specifically Reliability Standards TOP-001-4 and IRO-002-5. The proposed standards require
redundant and diversely routed data exchange capabilities at a Responsible Entity’s primary Control Center. Do you agree that “availability”
is adequately addressed by these standards? If not, please provide rationale to support your position.
Yes
No
Comments:
Availability is adequately covered by other standards.

5. The SDT is proposing to develop a new CIP standard because the directives of FERC Order 822 related to the protection of communication
networks used to exchange sensitive BES data regardless of the entity’s size or impact level. Do you agree with the drafting of a new CIP
standard to address this issue? If you disagree and would prefer to include requirements in existing CIP Standards, such as CIP-003 and CIP005, please provide rationale and propose requirement language.
Yes
No
Comments:
There are concerns about the applicability section and how it will interact with the existing CIP Standards exemption 4.2.3.2. The
applicability section should limit the scope to only real time communication networks or data between Control Centers.
Would like additional guidance on the applicability of technologies like voice communication email, text messaging …

Consider including language for CIP Exceptional Circumstances
6. The SDT evaluated multiple approaches to addressing the directive. The approach proposed in this informal posting focuses on the
protection of communication links. An alternative approach could focus on the protection of the sensitive BES data itself. Do you agree with
the SDT’s approach to focus the draft language on the protection of communication links? If not, please provide rationale and propose
alternative language.
Yes
No
Comments:
We like the option to protect either the data or the links. We would like to see these options clearly defined within the requirements and
not just in the guidance. The Standard should be an outcome based Standard.
FERC Order 822 section 58 clarifies this scope as inter-Control Center and intra-Control Center communications. The guidance seems to
extend the scope beyond this by including references to DP’s and listing Data links without reference to Control Centers.
7. Do you agree with the security objective of the draft language? If not, please propose alternative language.
Yes
No
Comments:
We suggest “reliability and availability” replace “confidentiality and integrity” because EMS/SCADA systems are built on “reliability and
availability”.
8. Is it clear what types of plans, procedures, and methods are needed to meet the draft language? If not, please propose alternative
language.
Yes
No
Comments:

We like the option to protect either the data or the links. We would like to see these options clearly defined within the requirements and
not just in the guidance. Replace “communication networks” with “communication networks or BES reliability data”. Include in 1.1 that
this is for networks or data between Control Centers.
9. The SDT uses the term “communication networks” throughout the draft language including an obligation to define the boundaries of such
communication networks. Does the SDT need to define the term for inclusion in the NERC Glossary of Terms? If so, please propose a
definition of “communication networks.”
Yes
No
Comments:
Recommend a NO vote on defining “communication network”
But consider that the FERC Order Section 58 clarifies the focus and the scope on inter-Control Center and intra-Control Center
communications

CIP-012-1 – Cyber Security – Control Center Communication Networks

Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).

Description of Current Draft
This is the first draft of the proposed standard.
Completed Actions

Date

Standards Committee approved Standard Authorization Request
(SAR) for posting

March 9, 2016

SAR posted for comment

March 23 - April 21,
2016

SAR posted for comment

June 1 – June 30,
2016

Informal comment period

February 10- March
13, 2017

Anticipated Actions

Date

45-day formal comment period with additional ballot

TBD

10-day final ballot

TBD

Board

TBD

Draft 1 of CIP-012-1
June 2017 Page 1 of 8

CIP-012-1 – Cyber Security – Control Center Communication Networks

Upon Board adoption, the rationale boxes will be moved to the Supplemental Material Section.

A. Introduction
1.

Title: Cyber Security – Control Center Communication Networks

2.

Number: CIP-012-1

3.

Purpose: To protect confidentiality and integrity of data transmitted between Control
Centers required for reliable operation of the Bulk Electric System (BES).

4.

Applicability:
4.1. Functional Entities: For the purpose of the requirements contained herein, the
following list of functional entities will be collectively referred to as “Responsible
Entities.” For requirements in this standard where a specific functional entity or
subset of functional entities are the applicable entity or entities, the functional
entity or entities are specified explicitly.
4.1.1. Balancing Authority
4.1.2. Generator Operator
4.1.3. Generator Owner
4.1.4. Reliability Coordinator
4.1.5. Transmission Operator
4.1.6. Transmission Owner
4.2. Exemptions: The following are exempt from Reliability Standard CIP-012-1:
4.2.1. Cyber Assets at Facilities regulated by the Canadian Nuclear Safety
Commission.
4.2.2. The systems, structures, and components that are regulated by the
Nuclear Regulatory Commission under a cyber security plan pursuant to
10 C.F.R. Section 73.54.

5.

Effective Date: See Implementation Plan for CIP-012-1

B. Requirements and Measures
Rationale for Requirements R1 and R2: FERC Order No. 822 directed NERC to develop
modifications to the CIP Reliability Standards to require Responsible Entities to
implement controls to protect communication links and sensitive Bulk Electric System
(BES) data communicated between BES Control Centers. Reliability Standard CIP-012-1
responds to that directive, requiring Responsible Entities to develop a plan to protect the
confidentiality and integrity of sensitive data while being transmitted between Control
Centers. Responsible Entities use various means to communicate information between

Draft 1 of CIP-012-1
June 2017 Page 2 of 8

CIP-012-1 – Cyber Security – Control Center Communication Networks

Control Centers. The plan for protecting these communications is required for all impact
levels due to the inter-dependency of multiple impact levels.
The type of data in scope of CIP-012-1 is data used for Operational Planning Analyses,
Real-time Assessments, and Real-time monitoring. The terms Operational Planning
Analyses, Real-time Assessments, and Real-time used are defined in the Glossary of
Terms Used in NERC Reliability Standards and used in TOP-003 and IRO-010, among other
Reliability Standards.
There are differences between the plan(s) required to be developed and implemented for
CIP-012-1 and the protection required in CIP-006-6 Requirement R1 Part 1.10. CIP-012-1
Requirements R1 and R2 protect the applicable data during transmission between two
geographically separate Control Centers. CIP-006 Requirement R1 Part 1.10 protects
nonprogrammable communication components within an Electronic Security Perimeter
(ESP) but outside of a Physical Security Perimeter (PSP). The transmission of applicable
data between Control Centers takes place outside of an ESP. Therefore, the protection
contained in CIP-006-6 Requirement R1 Part 1.10 does not apply.
R1.

The Responsible Entity shall develop one or more documented plan(s) to mitigate the
risk of the unauthorized disclosure or modification of data used for Operational
Planning Analysis, Real-time Assessments, and Real-time monitoring while being
transmitted between Control Centers. This excludes oral communications. [Violation
Risk Factor: Medium] [Time Horizon: Operations Planning]
1.1. Risk mitigation shall be accomplished by one or more of the following actions:


Physically protecting the communication links transmitting the data;



Logically protecting the data during transmission; or



Using an equally effective method to mitigate the risk of unauthorized
disclosure or modification of the data.

Note: If the Responsible Entity does not have a Control Center or it does not transmit
the type of data specified in Requirement R1 of CIP-012-1 between two Control
Centers, the requirements in CIP-012-1 would not apply to that entity.
M1. Evidence may include, but is not limited to, documented plan(s) that meet the
security objective of Requirement R1.
R2.

The Responsible Entity shall implement the plan(s) specified in Requirement R1,
except under CIP Exceptional Circumstances.

M2. Evidence may include, but is not limited to, documentation to demonstrate
implementation of methods to mitigate the risk of the unauthorized disclosure or
modification of data in Requirement R1.

C. Compliance
Draft 1 of CIP-012-1
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CIP-012-1 – Cyber Security – Control Center Communication Networks

1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority”
means NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below
is shorter than the time since the last audit, the Compliance Enforcement
Authority may ask an entity to provide other evidence to show that it was
compliant for the full-time period since the last audit.
The applicable entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation.


The Responsible Entities shall keep data or evidence of each Requirement in
this Reliability Standard for three calendar years.



If a Responsible Entity is found non-compliant, it shall keep information
related to the non-compliance until mitigation is complete and approved or for
the time specified above, whichever is longer.



The Compliance Enforcement Authority (CEA) shall keep the last audit records
and all requested and submitted subsequent audit records.

1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers
to the identification of the processes that will be used to evaluate data or
information for the purpose of assessing performance or outcomes with the
associated Reliability Standard.

Draft 1 of CIP-012-1
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CIP-012-1 – Cyber Security – Control Center Communication Networks

Violation Severity Levels
Violation Severity Levels
R#

Lower VSL
R1.




N/A

Moderate VSL


N/A

High VSL

Severe VSL

N/A

The Responsible Entity failed
to document one or more
plan(s) that achieve the
security objective to mitigate
the risk of unauthorized
disclosure or modification of
data used for Operational
Planning Analysis, Real-time
Assessments, and Real-time
monitoring while being
transmitted, excluding oral
communication, between
Control Centers as specified
in Requirement R1.


R2.



N/A

Draft 1 of CIP-012-1
June 2017



N/A

N/A

The Responsible Entity failed
to implement its plan(s) to
mitigate the risk of
unauthorized disclosure or
modification of data used for
Operational Planning
Analysis, Real-time
Assessments, and Real-time

Page 5 of 8

CIP-012-1 – Cyber Security – Control Center Communication Networks

monitoring while being
transmitted, excluding oral
communication, between
Control Centers as specified
in Requirement R1, except
under CIP Exceptional
Circumstances.

D. Regional Variances
None.

E. Associated Documents
Implementation Plan.

Draft 1 of CIP-012-1
June 2017

Page 6 of 8

CIP-012-1 – Cyber Security – Control Center Communication Networks

Version History
Version

Date

1

TBD

Draft 1 of CIP-012-1
June 2017

Action

Respond to FERC Order No. 822

Change
Tracking

N/A

Page 7 of 8

CIP-012-1 Supplemental Material

Standard Attachments
None.

Draft 1 of CIP-012-1
June 2017

Page 8 of 8

Implementation Plan
Project 2016-02 Modifications to CIP Standards
Reliability Standard CIP-012-1
Applicable Standard


Reliability Standard CIP-012-1 - Cyber Security – Control Center Communication Networks

Requested Retirements


None

Prerequisite Standard
These standard(s) or definitions must be approved before the Applicable Standard becomes
effective:


None

Applicable Entities







Balancing Authority
Generator Operator
Generator Owner
Reliability Coordinator
Transmission Operator
Transmission Owner

Effective Date
Reliability Standard CIP-012-1 - Cyber Security – Control Center Communication Networks
Where approval by an applicable governmental authority is required, Reliability Standard CIP-012-1
shall become effective on the first day of the first calendar quarter that is twelve (12) calendar
months after the effective date of the applicable governmental authority’s order approving the
standard, or as otherwise provided for by the applicable governmental authority.
Where approval by an applicable governmental authority is not required, Reliability Standard CIP012-1 shall become effective on the first day of the first calendar quarter that is twelve (12) calendar
months after the date the standard is adopted by the NERC Board of Trustees, or as otherwise
provided for in that jurisdiction.

Unofficial Comment Form

Project 2016-02 Modifications to CIP Standards
CIP-012-1
Do not use this form for submitting comments. Use the electronic form to submit comments on
CIP-012-1 - Cyber Security – Control Center Communication Networks. The electronic form must be
submitted by 8 p.m. Eastern, Monday, September 11, 2017.
m. Eastern, Thursday, August 20, 2015
Additional information is available on the project page. If you have questions, contact Standards
Developers, Katherine Street (404-446-69702) or Mat Bunch (404-446-9785).
Background Information

On January 21, 2016, the Commission issued Order No. 822, approving seven CIP Reliability Standards and
new or modified definitions, and directing modifications to the CIP Reliability Standards. Among others,
the Commission directed NERC to “develop modifications to the CIP Reliability Standards to require
responsible entities to implement controls to protect, at a minimum, communication links and sensitive
bulk electric system data communicated between bulk electric system Control Centers in a manner that is
appropriately tailored to address the risks posed to the bulk electric system by the assets being protected
(i.e., high, medium, or low impact).” (Order 822, Paragraph 53)
The Project 2016-02 Standard Drafting Team (SDT) drafted Reliability Standard CIP-012-1 to require
Responsible Entities to implement controls to protect sensitive Bulk Electric System (BES) data and
communications links between BES Control Centers. Due to the sensitivity of the data being
communicated between the Control Centers, as defined in the NERC Glossary of Terms Used in Reliability
Standards, the standard applies to all impact levels (i.e., high, medium, or low impact).
The SDT drafted requirements allowing Responsible Entities to apply protection to the links, the data, or
both, to satisfy the security objective consistent with the capabilities of the Responsible Entity’s
operational environment. Requirement R1 requires Responsible Entities to document one or more plans
that protect Operational Planning Analysis, Real-time Assessment, and Real-time monitoring data while
being transmitted between Control Centers. The plan(s) must address how the Responsible Entity will
mitigate the risk of unauthorized disclosure or modification of the applicable data. Requirement R2
covers implementation of the plan developed according to Requirement R1.

Questions

1. Requirement R1: The SDT drafted CIP-012-1 Requirement R1 to meet the mandatory requirement
for the Responsible Entity to develop one or more documented plan(s) to mitigate the risk of the
unauthorized disclosure or modification of data used for Operational Planning Analysis, Real-time
Assessment, and Real-time monitoring data while being transmitted between Control Centers. Do
you agree with this revision? If not, please provide the basis for your disagreement and an
alternate proposal.
Yes
No
Comments:
2. Requirement R1: The SDT seeks comment on the need to scope sensitive BES data as it applies to
Operational Planning Analysis, Real-time Assessment, and Real-time monitoring. Do you agree
with scoping CIP-012-1 Requirement R1 in this manner? Please provide comment in support of
your response.
Yes
No
Comments:
3. Implementation Plan: The SDT revised the Implementation Plan such that the standard and NERC
Glossary terms are effective the first day of the first calendar quarter that is twelve (12) calendar
months after the effective date of the applicable governmental authority’s order approving the
standard, or as otherwise provided for by the applicable governmental authority. Do you agree
with this proposal? If you agree with the proposed implementation time period, please note the
actions you will take that require this amount of time to complete. If you think an alternate
implementation time period is needed – shorter or longer - please propose an alternate
implementation plan and provide a detailed explanation of actions and time needed to meet the
implementation deadline.
Yes
No
Comments:
4. The SDT believes proposed CIP-012-1 provides entities with flexibility to meet the reliability
objectives in a cost effective manner. Do you agree? If you do not agree, or if you agree but have
suggestions for improvement to enable more cost effective approaches, please provide your
recommendation and, if appropriate, technical justification.
Yes
No
Comments:

Unofficial Comment Form | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | July-September 2017

2

5. If you have additional comments on the proposed CIP-012-1 – Cyber Security -- Communication

Networks drafted in response to the FERC directive that you have not provided in response to the
questions above, please provide them here.
Comments:

Unofficial Comment Form | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | July-September 2017

3

Project 2016-02 Consideration of Issues and Directives
Federal Energy Regulatory Commission Order No. 822
June 21, 2017
Directives from Order 822
Paragraph
53

Directive Language
53. As discussed in detail below, however, the
Commission concludes that modifications to CIP-006-6
to provide controls to protect, at a minimum,
communication links and data communicated
between bulk electric system Control Centers are
necessary in light of the critical role Control Center
communications play in maintaining bulk electric
system reliability. Therefore, we adopt the NOPR
proposal and direct that NERC, pursuant to section
215(d)(5) of the FPA, develop modifications to the CIP
Reliability Standards to require responsible entities to
implement controls to protect, at a minimum,
communication links and sensitive bulk electric system
data communicated between bulk electric system
Control Centers in a manner that is appropriately
tailored to address the risks posed to the bulk electric
system by the assets being protected (i.e., high,
medium, or low impact).

Consideration of Issue or Directive
The Project 2016-02 Standard Drafting Team (SDT) drafted
Reliability Standard CIP-012-1 Requirement R1 to require
responsible entities to document one or more plan(s) to
mitigate the risk of the unauthorized disclosure or
modification of data used for Operational Planning Analysis,
Real-time Assessments, and Real-time monitoring while being
transmitted between Bulk Electric System (BES) Control
Centers. Requirement R2 requires implementation of the
documented plan(s). Due to the sensitivity of the data being
transmitted between the Control Centers, as defined in the
NERC Glossary of Terms Used in Reliability Standards, the SDT
created the standard and determined that it applies to all
impact levels of BES Cyber Systems (i.e., high, medium, or low
impact).
The SDT has drafted requirements allowing Responsible
Entities to apply protection to the links, the data, or both, to
satisfy the security objective of the Commission’s directive,
consistent with the capabilities of the Responsible Entity’s

Directives from Order 822
Paragraph

Directive Language

Consideration of Issue or Directive
operational environment. The directive language specifically
references CIP-006-6 which pertains to physical security
controls. CIP-006-6, Requirement R1, Part 1.10 focuses on
protecting the nonprogrammable communication components
between Cyber Assets within the same ESP for medium and
high impact BES Cyber Systems. The SDT asserts that most of
the communications contemplated by the Order are not within
the same ESP, and that CIP-006-6, Requirement R1, Part 1.10
would not be the appropriate location for this requirement.

54

54. NERC and other commenters recognize that interControl Center communications play a critical role in
maintaining bulk electric system reliability by, among
other things, helping to maintain situational awareness
and reliable bulk electric system operations through
timely and accurate communication between Control
Centers.59 We agree with this assessment. In order for
certain responsible entities such as reliability
coordinators, balancing authorities, and transmission
operators to adequately perform their reliability
functions, their associated control centers must be
capable of receiving and storing a variety of sensitive
bulk electric system data from interconnected entities.
Accordingly, we find that additional measures to protect
both the integrity and availability of sensitive bulk

Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

The SDT agrees that inter-Control Center communications play
a critical role in Bulk Electric System reliability. Responsible
Entities should therefore apply security measures to mitigate
the risk of the unauthorized disclosure or modification of data
used for Operational Planning Analysis, Real-time
Assessments, and Real-time monitoring, which the current CIP
Reliability Standards do not address. As such, the SDT has
defined requirements that are designed to protect the data
while it is being transmitted between inter-entity and intraentity Control Centers.
The SDT has drafted requirements allowing responsible
entities to apply protection to the links, the data, or both to
satisfy the security objective consistent with the capabilities of
the responsible entity’s operational environment.
2

Directives from Order 822
Paragraph

Directive Language

Consideration of Issue or Directive

warranted.60

electric system data are
We also
understand that the attributes of the data managed by
responsible entities could require different information
protection controls. 61 For instance, certain types of
reliability data will be sensitive to data manipulation
type attacks, while other types of reliability data will be
sensitive to eavesdropping type attacks aimed at
collecting operational information (such as line and
equipment ratings and impedances). NERC should
consider the differing attributes of bulk electric system
data as it assesses the development of appropriate
controls.
Footnotes:
59 NERC Comments at 20.
60 Protecting the integrity of bulk electric system data
involves maintaining and ensuring the accuracy and
consistency of inter-Control Center communications.
Protecting the availability of bulk electric system data
involves ensuring that required data is available when
needed for bulk electric system operations.
61 Moreover, in order for certain responsible entities to
adequately perform their Reliability Functions, the
associated control centers must be capable of receiving
and storing a variety of sensitive data as specified by the
Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

3

Directives from Order 822
Paragraph

55

Directive Language
IRO and TOP Standards. For instance, pursuant to
Reliability Standard TOP-003-3, Requirements R1, R3
and R5, a transmission operator must maintain a
documented specification for data and distribute its
data specification to entities that have data required by
the transmission operator’s Operational Planning
Analyses, Real-time Monitoring and Real-time
Assessments. Entities receiving a data specification must
satisfy the obligation of the documented specification.
55. With regard to NERC’s development of modifications
responsive to our directive, we agree with NERC and
other commenters that NERC should have flexibility in
the manner in which it addresses the Commission’s
directive. Likewise, we find reasonable the principles
outlined by NERC that protections for communication
links and sensitive bulk electric system data
communicated between bulk electric system Control
Centers: (1) should not have an adverse effect on
reliability, including the recognition of instances where
the introduction of latency could have negative results;
(2) should account for the risk levels of assets and
information being protected, and require protections
that are commensurate with the risks presented; and (3)
should be results-based in order to provide flexibility to

Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

Consideration of Issue or Directive

The SDT drafted Reliability Standard CIP-012-1 to establish
requirements to mitigate the risk of the unauthorized disclosure
or modification of data used for Operational Planning Analysis,
Real-time Assessments, and Real-time monitoring while being
transmitted between Control Centers. The SDT developed
objective-based rather than prescriptive requirements. This
approach will allow Responsible Entities flexibility in protecting
these communications networks and sensitive BES data in a
manner suited to each of their respective environments. It will
also allow Responsible Entities to implement protection that
considers the risks noted by the Commission. The SDT identified
a need to mitigate the risk of the unauthorized disclosure or
modification of data used for Operational Planning Analysis, Realtime Assessment, and Real-time monitoring regardless of asset
risk level. The proposal requires protection for all data used for
Operational Planning Analysis, Real-time Assessment, and Real4

Directives from Order 822
Paragraph

Directive Language
account for the range of technologies and entities
involved in bulk electric system communications.62

56

Footnote:
62 See NERC Comments at 20-21.
56. We disagree with the assertion of NIPSCO and
G&T Cooperatives that the risk posed by bulk electric
system communication networks does not justify the
costs of implementing controls. Communications
between Control Centers over such networks are
fundamental to the operations of the bulk electric
system, and the record here does not persuade us
that controls for such networks are not available at a
reasonable cost (through encryption or otherwise).
Nonetheless, we recognize that not all communication
network components and data pose the same risk to
bulk electric system reliability and may not require the
same level of protection. We expect NERC to develop
controls that reflect the risk posed by the asset or
data being protected, and that can be implemented in
a reasonable manner. It is important to recognize that
certain entities are already required to exchange
necessary real-time and operational planning data
through secured networks using a “mutually
agreeable security protocol,” regardless of the entity’s

Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

Consideration of Issue or Directive
time monitoring while being transmitted between Control
Centers.

The SDT noted the FERC reference to additional Reliability
Standards and the responsibilities to protect the data in
accordance with those standards (TOP-003-3 and IRO-010-2).
The SDT interpreted these references as examples of potentially
sensitive BES data and chose to base the CIP-012 requirements
on the data specifications in these standards. This consolidates
scoping and helps ensure that Responsible Entities mitigate the
risk of the unauthorized disclosure or modification of
Operational Planning Analysis, Real-time Assessment, and Realtime monitoring data, rather than leaving the scoping to
individual Responsible Entities.
The SDT drafted CIP-012-1 to address confidentiality and
integrity of data used for Operational Planning Analysis, Realtime Assessment, and Real-time monitoring. These are
accommodated by drafting the requirement to mitigate the risk
from unauthorized disclosure or modification. The SDT contends
that the availability of this data is already required by the
performance obligation of the Operating and Planning
Reliability Standards.
5

Directives from Order 822
Paragraph

Directive Language
level.63

size or impact
NERC’s response to the
directives in this Final Rule should identify the scope
of sensitive bulk electric system data that must be
protected and specify how the confidentiality,
integrity, and availability of each type of bulk electric
system data should be protected while it is being
transmitted or at rest.

58

62

Footnote:
63 See Reliability Standards TOP-003-3, Requirement
R5 and IRO-010-2, Requirement R3.
58. Several commenters sought clarification whether
Control Centers owned by multiple registered entities
would be included under the Commission’s proposal.
We clarify that the scope of the directed modifications
apply to Control Center communications from
facilities at all impact levels, regardless of ownership.
The directed modification should encompass
communication links and data for intra-Control Center
and inter-Control Center communications.
62. Several commenters addressed encryption and
latency. Based on the record in this proceeding, it is
reasonable to conclude that any lag in communication
speed resulting from implementation of protections
should only be measureable on the order of

Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

Consideration of Issue or Directive
The SDT drafted CIP-012-1 to address the data while being
transmitted. The SDT contends that this data is maintained
within BES Cyber Systems, and is afforded the protections of
CIP-003 through CIP-011.

The SDT created the standard and determined that it applies to
all impact levels of BES Cyber Systems (i.e., high, medium, or
low impact), regardless of ownership. The SDT defined
requirements that are designed to mitigate the risk of the
unauthorized disclosure or modification of data used for
Operational Planning Analysis, Real-time Assessment, and Realtime monitoring while being transmitted between inter-entity
and intra-entity BES Control Centers.
The SDT developed objective-based rather than prescriptive
requirements. This approach will allow Responsible Entities
flexibility in mitigating the risk of the unauthorized disclosure or
modification of data used for Operational Planning Analysis,

6

Directives from Order 822
Paragraph

Directive Language
milliseconds and, therefore, will not adversely impact
Control Center communications. Several commenters
raise possible technical implementation difficulties
with integrating encryption technologies into their
current communications networks. Such technical
issues should be considered by the standard drafting
team when developing modifications in response to
this directive, and may be resolved, e.g., by making
certain aspects of the revised CIP Standards eligible
for Technical Feasibility Exceptions.

Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

Consideration of Issue or Directive
Real-time Assessments, and Real-time monitoring in a manner
suited to each of their respective environments. It will also
allow Responsible Entities to implement protection that
considers the risks noted by the Commission.

7

Violation Risk Factor and Violation Severity Level Justifications
Project 2016-02 Modifications to CIP Standards
This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in CIP-012-1. Each requirement is assigned a VRF and a VSL. These elements support the determination of
an initial value range for the Base Penalty Amount regarding violations of requirements in FERC-approved Reliability Standards, as defined in
the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT applied the following NERC criteria and FERC Guidelines when
developing the VRFs and VSLs for the requirements.

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:


Emergency operations



Vegetation management



Operator personnel training



Protection systems and their coordination



Operating tools and backup facilities



Reactive power and voltage control



System modeling and data exchange



Communication protocol and facilities



Requirements to determine equipment ratings



Synchronized data recorders



Clearer criteria for operationally critical facilities



Appropriate use of transmission loading relief.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | July 2017

2

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.
Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.
Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.
Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | July 2017

3

NERC Criteria for Violation Severity Levels
VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL

Moderate VSL

The performance or product
measured almost meets the full
intent of the requirement.

The performance or product
measured meets the majority of
the intent of the requirement.

High VSL

The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet
some of the intent.

Severe VSL

The performance or product
measured does not
substantively meet the intent of
the requirement.

FERC Order of Violation Severity Levels
The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.
Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | July 2017

4

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justifications for CIP-012-1, Requirement R1

Proposed VRF

Medium

NERC VRF Discussion

A VRF of Medium was assigned to this requirement. Cyber security plans enable effective implementation
of the CIP standard’s requirements to mitigate the risk of the unauthorized disclosure or modification of
data used for Operational Planning Analysis, Real-time Assessments, and Real-time monitoring while being
transmitted between Control Centers.

FERC VRF G1 Discussion

N/A

Guideline 1- Consistency
with Blackout Report
FERC VRF G2 Discussion

N/A

Guideline 2- Consistency
within a Reliability Standard
FERC VRF G3 Discussion
Guideline 3- Consistency
among Reliability Standards
FERC VRF G4 Discussion
Guideline 4- Consistency
with NERC Definitions of
VRFs
FERC VRF G5 Discussion

The requirement complements CIP-005-1, Requirement R1, CIP-006-6, Requirement R1, and CIP-007-6,
Requirement R1 which are related to security of networks and communications components. The
proposed VRF is consistent with these related requirements.
Failure to have a cyber security plan would not, under Emergency, abnormal, or restorative conditions
anticipated by the preparations, be expected to adversely affect the electrical state or capability of the
Bulk Electric System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

N/A

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | July 2017

5

VRF Justifications for CIP-012-1, Requirement R1

Proposed VRF

Medium

Guideline 5- Treatment of
Requirements that Comingle More than One
Obligation
VSLs for CIP-012-1, Requirement R1

Lower


N/A

Moderate


N/A

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | July 2017

High
N/A

Severe
The Responsible Entity failed to
document one or more plan(s)
that achieve the security
objective to mitigate the risk of
the unauthorized disclosure or
modification of data used for
Operational
Planning Analysis, Real-time
Assessments, and Real-time
monitoring while being
transmitted, excluding oral
communication, between
Controls Centers as specified in
Requirement R1.

6

VSL Justifications for CIP-012-1 Requirements R1

FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency
in the Determination of
Penalties

The requirement is new. Therefore, the proposed VSL does not have the unintended consequence of
lowering the level of compliance.

The proposed VSL is binary and is classified as severe. The VSL does not use any ambiguous terminology,
thereby supporting uniformity and consistency in the determination of similar penalties for similar
violations.

Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement

The proposed VSL uses the same terminology as used in the associated requirement and is, therefore,
consistent with the requirement.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | July 2017

7

FERC VSL G4

The VSL is based on a single violation and not cumulative violations.

Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations

VRF Justifications for CIP-012-1, Requirement R2

Proposed VRF

Medium

NERC VRF Discussion

A VRF of Medium was assigned to this requirement. Implementation of required cyber security plans
enable effective implementation of the CIP standard’s requirements to mitigate the risk of the
unauthorized disclosure or modification of data used for Operational Planning Analysis, Real-time
Assessments, and Real-time monitoring while being transmitted between Control Centers.

FERC VRF G1 Discussion

N/A

Guideline 1- Consistency
with Blackout Report
FERC VRF G2 Discussion

N/A

Guideline 2- Consistency
within a Reliability Standard
FERC VRF G3 Discussion
Guideline 3- Consistency
among Reliability Standards
FERC VRF G4 Discussion

The requirement complements CIP-005-1, Requirement R1, CIP-006-6, Requirement R1, and CIP-007-6,
Requirement R1 which are related to security of networks and communications components. The
proposed VRF is consistent with these related requirements.
Failure to properly implement the cyber security plan would not, under Emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | July 2017

8

VRF Justifications for CIP-012-1, Requirement R2

Proposed VRF

Medium

Guideline 4- Consistency
with NERC Definitions of
VRFs

or capability of the Bulk Electric System, or the ability to effectively monitor, control, or restore the Bulk
Electric System.

FERC VRF G5 Discussion

N/A

Guideline 5- Treatment of
Requirements that Comingle More than One
Obligation
VSLs for CIP-012-1, Requirement R2

Lower
N/A

Moderate
N/A

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | July 2017

High
N/A

Severe
The Responsible Entity failed to
implement its plan to mitigate
the risk of the unauthorized
disclosure or modification of
data used for Operational,
Planning Analysis, Real-time
Assessments, and Real-time
monitoring while being
transmitted, excluding oral
communication, between
Controls Centers as specified in
Requirement R1, except under
CIP Exceptional Circumstances.

9

VSL Justifications for CIP-012-1 Requirement R2

FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency
in the Determination of
Penalties

The requirement is new. Therefore, the proposed VSL does not have the unintended consequence of
lowering the level of compliance.

The proposed VSL is binary and is classified as severe. The VSL does not use any ambiguous terminology,
thereby supporting uniformity and consistency in the determination of similar penalties for similar
violations.

Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement

The proposed VSL uses the same terminology as used in the associated requirement and is, therefore,
consistent with the requirement.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | July 2017

10

FERC VSL G4

The VSL is based on a single violation and not cumulative violations.

Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | July 2017

11

Reliability Standard Audit Worksheet1
CIP-012-1 – Cyber Security – Control Center Communication Networks
This section to be completed by the Compliance Enforcement Authority.
Audit ID:
Registered Entity:
NCR Number:
Compliance Enforcement Authority:
Compliance Assessment Date(s) 2:
Compliance Monitoring Method:
Names of Auditors:

Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
Registered name of entity being audited
NCRnnnnn
Region or NERC performing audit
Month DD, YYYY, to Month DD, YYYY
[On-site Audit | Off-site Audit | Spot Check]
Supplied by CEA

Applicability of Requirements
R1
R2

BA
X
X

DP

GO
X
X

GOP
X
X

PA/PC

RC
X
X

Legend:
Text with blue background:
Text entry area with Green background:
Text entry area with white background:

RP

RSG

TO
X
X

TOP
X
X

TP

TSP

Fixed text – do not edit
Entity-supplied information
Auditor-supplied information

NERC developed this Reliability Standard Audit Worksheet (RSAW) language in order to facilitate NERC’s and the Regional Entities’ assessment of a registered entity’s
compliance with this Reliability Standard. The NERC RSAW language is written to specific versions of each NERC Reliability Standard. Entities using this RSAW should
choose the version of the RSAW applicable to the Reliability Standard being assessed. While the information included in this RSAW provides some of the methodology
that NERC has elected to use to assess compliance with the requirements of the Reliability Standard, this document should not be treated as a substitute for the
Reliability Standard or viewed as additional Reliability Standard requirements. In all cases, the Regional Entity should rely on the language contained in the Reliability
Standard itself, and not on the language contained in this RSAW, to determine compliance with the Reliability Standard. NERC’s Reliability Standards can be found on
NERC’s website. Additionally, NERC Reliability Standards are updated frequently, and this RSAW may not necessarily be updated with the same frequency. Therefore,
it is imperative that entities treat this RSAW as a reference document only, and not as a substitute or replacement for the Reliability Standard. It is the responsibility
of the registered entity to verify its compliance with the latest approved version of the Reliability Standards, by the applicable governmental authority, relevant to its
registration status.
1

The RSAW may provide a non-exclusive list, for informational purposes only, of examples of the types of evidence a registered entity may produce or may be asked to
produce to demonstrate compliance with the Reliability Standard. A registered entity’s adherence to the examples contained within this RSAW does not necessarily
constitute compliance with the applicable Reliability Standard, and NERC and the Regional Entity using this RSAW reserve the right to request additional evidence from
the registered entity that is not included in this RSAW. This RSAW may include excerpts from FERC Orders and other regulatory referenceswhich are provided for ease
of reference only, and this document does not necessarily include all applicable Order provisions. In the event of a discrepancy between FERC Orders, and the language
included in this document, FERC Orders shall prevail.
2

Compliance Assessment Date(s): The date(s) the actual compliance assessment (on-site audit, off-site spot check, etc.) occurs.

DRAFT NERC Reliability Standard Audit Worksheet

Findings
(This section to be completed by the Compliance Enforcement Authority)
Req.
Finding
Summary and Documentation
R1
R2

Req.

Areas of Concern

Req.

Recommendations

Req.

Positive Observations

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft1_v4 Revision Date: August 7, 2017 RSAW Template: RSAW2017R3.0
2

Functions Monitored

DRAFT NERC Reliability Standard Audit Worksheet

Subject Matter Experts
Identify the Subject Matter Expert(s) responsible for this Reliability Standard.
Registered Entity Response (Required; Insert additional rows if needed):
SME Name
Title
Organization

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft1_v4 Revision Date: August 7, 2017 RSAW Template: RSAW2017R3.0
3

Requirement(s)

DRAFT NERC Reliability Standard Audit Worksheet

Registered Entity Response (Required):
Question 1: Does the Registered Entity own or operate a Control Center? ☐ Yes ☐ No
If no:
1. Provide evidence in the space that the Registered Entity does not own or operate one or more Control
Centers. This evidence may include, but is not limited to:
• Evidence that the Registered Entity does not own or operate a Control Center; or
• Evidence that the Registered Entity’s asset list does not contain a Control Center.
2. The remainder of this RSAW may be left blank.
If yes, continue with Question 2.
[Note: A separate spreadsheet or other document may be used. If so, provide the document reference below.]

Question 2: Is data used for Operational Planning Analysis, Real-time Assessments, or Real-time monitoring
transmitted between Control Centers at any time by any Control Center owned or operated by the Registered
Entity? ☐ Yes ☐ No
If no:
1. Provide evidence in the space below supporting this assertion. This evidence may include, but is not
limited to:
• Evidence demonstrating data used for Operational Planning Analysis, Real-time Assessments, and
Real-time monitoring is not transmitted between Control Centers at any time by any Control
Center owned or operated by the Registered Entity.
2. The remainder of this RSAW may be left blank.
If yes, continue with the remainder of this RSAW.
[Note: A separate spreadsheet or other document may be used. If so, provide the document reference below.]

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft1_v4 Revision Date: August 7, 2017 RSAW Template: RSAW2017R3.0
4

DRAFT NERC Reliability Standard Audit Worksheet

R1 Supporting Evidence and Documentation
R1.

The Responsible Entity shall develop one or more documented plan(s) to mitigate the risk of the unauthorized
disclosure or modification of data used for Operational Planning Analysis, Real-time Assessments, and Real-time
monitoring while being transmitted between Control Centers. This excludes oral communications. [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning]
1.1

Risk mitigation shall be accomplished by one or more of the following actions:
•

Physically protecting the communication links transmitting the data;

•

Logically protecting the data during transmission; or

•

Using an equally effective method to mitigate the risk of unauthorized disclosure or modification of
the data.

Note: If the Responsible Entity does not have a Control Center or it does not transmit the type of data
specified in Requirement R1 of CIP-012-1 between two Control Centers, the requirements in CIP-012-1
would not apply to that entity.
M1.

Evidence may include, but is not limited to, documented plan(s) that meet the security objective of Requirement
R1.

Registered Entity Response (Required):
Compliance Narrative:

Provide a brief explanation, in your own words, of how you comply with this Requirement. References to supplied
evidence, including links to the appropriate page, are recommended.

Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.
Relevant
Revision
Page(s)
or
Document
or
Description of Applicability
File Name
Document Title
Version
Date
Section(s)
of Document

Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft1_v4 Revision Date: August 7, 2017 RSAW Template: RSAW2017R3.0
5

DRAFT NERC Reliability Standard Audit Worksheet

Compliance Assessment Approach Specific to CIP-012-1, R1
This section to be completed by the Compliance Enforcement Authority
If the Registered Entity has answered “No” to either Question 1 or Question 2, verify:
• The Registered Entity does not own or operate a Control Center; or
• The Registered Entity does not transmit data used for Operational Planning Analysis, Real-time
Assessments, or Real-time monitoring at any time between Control Centers.
If the Registered Entity has answered “Yes” to Question 2, verify:
1. The entity has developed one or more documented plans to mitigate the risk of the
unauthorized disclosure or modification of data used for Operational Planning Analysis, Realtime Assessments, and Real-time monitoring while being transmitted between Control Centers;
2. The documented plan(s) collectively address all data used for Operational Planning Analysis,
Real-time Assessments, and Real-time monitoring transmitted between Control Centers; and
3. The documented plan(s) collectively accomplish risk mitigation by one or more of the following
actions:
• Physically protecting the communication links transmitting the data;
• Logically protecting the data during transmission; or
• Using an equally effective method to mitigate the risk of unauthorized disclosure or
modification of the data.
Note to Auditor:
1. Oral communications are not in scope for CIP-012-1.
Auditor Notes:

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft1_v4 Revision Date: August 7, 2017 RSAW Template: RSAW2017R3.0
6

DRAFT NERC Reliability Standard Audit Worksheet

R2 Supporting Evidence and Documentation
R2.

The Responsible Entity shall implement the plan(s) specified in Requirement R1, except under CIP Exceptional
Circumstances.

M2.

Evidence may include, but is not limited to, documentation to demonstrate implementation of methods to
mitigate the risk of the unauthorized disclosure or modification of data in Requirement R1.

Registered Entity Response (Required):
Compliance Narrative:

Provide a brief explanation, in your own words, of how you comply with this Requirement. References to supplied
evidence, including links to the appropriate page, are recommended.

Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.
Relevant
Revision
Page(s)
or
Document
or
Description of Applicability
File Name
Document Title
Version
Date
Section(s)
of Document

Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):

Compliance Assessment Approach Specific to CIP-012-1, R2
This section to be completed by the Compliance Enforcement Authority
If the Registered Entity has answered “Yes” to Question 2, verify with system-generated evidence
(where available) that the Registered Entity has implemented the plan(s) specified in Requirement R1,
except under CIP Exceptional Circumstances.
If the Responsible Entity has declared and responded to CIP Exceptional Circumstances, verify the
Responsible Entity has adhered to the applicable cyber security policies.
Note to Auditor:
The Responsible Entity may reference a separate set of documents to demonstrate its response to any
requirements impacted by CIP Exceptional Circumstances.

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft1_v4 Revision Date: August 7, 2017 RSAW Template: RSAW2017R3.0
7

DRAFT NERC Reliability Standard Audit Worksheet

Auditor Notes:

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft1_v4 Revision Date: August 7, 2017 RSAW Template: RSAW2017R3.0
8

DRAFT NERC Reliability Standard Audit Worksheet

Additional Information:
Reliability Standard
The full text of CIP-012-1 may be found on the NERC Web Site (www.nerc.com) under “Program Areas &
Departments”, “Reliability Standards.”
In addition to the Reliability Standard, there is an applicable Implementation Plan available on the NERC Web
Site.
In addition to the Reliability Standard, there is background information available on the NERC Web Site.
Capitalized terms in the Reliability Standard refer to terms in the NERC Glossary, which may be found on the
NERC Web Site.
Sampling Methodology
Sampling is essential for auditing compliance with NERC Reliability Standards since it is not always possible
or practical to test 100% of either the equipment, documentation, or both, associated with the full suite of
enforceable standards. The Sampling Methodology Guidelines and Criteria (see NERC website), or sample
guidelines, provided by the Electric Reliability Organization help to establish a minimum sample set for
monitoring and enforcement uses in audits of NERC Reliability Standards.
Regulatory Language
FERC Order 822 P53-56, 58, and 62
Selected Glossary Terms
The following Glossary terms are provided for convenience only. Please refer to the NERC web site for the
current enforceable terms.
CIP Exceptional Circumstance
A situation that involves or threatens to involve one or more of the following, or similar, conditions that
impact safety or BES reliability: a risk of injury or death; a natural disaster; civil unrest; an imminent or existing
hardware, software, or equipment failure; a Cyber Security Incident requiring emergency assistance; a
response by emergency services; the enactment of a mutual assistance agreement; or an impediment of large
scale workforce availability.
Control Center
One or more facilities hosting operating personnel that monitor and control the Bulk Electric System (BES) in
real-time to perform the reliability tasks, including their associated data centers, of: 1) a Reliability
Coordinator, 2) a Balancing Authority, 3) a Transmission Operator for transmission Facilities at two or more
locations, or 4) a Generator Operator for generation Facilities at two or more locations.
Operational Planning Analysis
An evaluation of projected system conditions to assess anticipated (pre-Contingency) and potential (postContingency) conditions for next-day operations. The evaluation shall reflect applicable inputs including, but
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft1_v4 Revision Date: August 7, 2017 RSAW Template: RSAW2017R3.0
9

DRAFT NERC Reliability Standard Audit Worksheet

not limited to, load forecasts; generation output levels; Interchange; known Protection System and Special
Protection System status or degradation; Transmission outages; generator outages; Facility Ratings; and
identified phase angle and equipment limitations. (Operational Planning Analysis may be provided through
internal systems or through third-party services.)
Real-time Assessment
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.)
Real-time
Present time as opposed to future time.

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft1_v4 Revision Date: August 7, 2017 RSAW Template: RSAW2017R3.0
10

DRAFT NERC Reliability Standard Audit Worksheet

Revision History for RSAW
Version
Draft1 v1
Draft1 v2
Draft1 v3

Date
07/28/2017
08/01/2017
08/02/2017

Reviewers
NERC Stds Group
RSAW Task Force
RSAW Task Force

Draft1 v4

08/07/2017

RSAW Tasf Force,
2016-02 SDT

Revision Description
New document
Modified Question to clarify applicability
Response to MRO comments. Moved Questions
1 and 2 above R1. Made text changes to Q1 and
to R2 Compliance Assessment Approach.
Response to TexasRE and SDT comments.
Clarified scope of Q1 to be data transmitted
between Control Centers. Removed extra space
from Auditor Notes.

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft1_v4 Revision Date: August 7, 2017 RSAW Template: RSAW2017R3.0
11

Standards Announcement
Reminder

Project 2016-02 Modifications to CIP Standards
Initial Ballot and Non-binding Poll Open through September 11, 2017
Now Available

An initial ballot for CIP-012-1 - Cyber Security – Control Center Communication Networks and nonbinding poll of the associated Violation Risk Factors and Violation Severity Levels are open through 8
p.m. Eastern, Monday, September 11, 2017
Balloting

Members of the ballot pools associated with this project can log in and submit their votes by accessing
the Standards Balloting and Commenting System (SBS) here. If you experience any difficulties in
navigating the SBS, contact Wendy Muller.
•

If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential error
messages, or system lock-out, contact NERC IT support directly at https://support.nerc.net/ (Monday
– Friday, 8 a.m. - 5 p.m. Eastern).

•

Passwords expire every 6 months and must be reset.

•

The SBS is not supported for use on mobile devices.

•

Please be mindful of ballot and comment period closing dates. We ask to allow at least 48 hours for
NERC support staff to assist with inquiries. Therefore, it is recommended that users try logging into
their SBS accounts prior to the last day of a comment/ballot period.

Next Steps

The ballot results will be announced and posted on the project page. The drafting team will review all
responses received during the comment period and determine the next steps of the project.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Standards Developers, Katherine Street at (404) 446-9702 or
Mat Bunch at (404) 446-9785.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement | TCA Ballot Open Reminder
Project 2016-02 Modifications to CIP Standards | January 16, 2017

2

Standards Announcement

Project 2016-02 Modifications to CIP Standards
CIP-012-1
Formal Comment Period Open through September 11, 2017
Ballot Pools Forming through August 25, 2017
Now Available

A 45-day formal comment period for CIP-012-1 - Cyber Security – Control Center Communication
Networks is open through 8 p.m. Eastern, Monday, September 11, 2017.
Commenting

Use the electronic form to submit comments. If you experience any difficulties using the electronic form,
contact Wendy Muller. An unofficial Word version of the comment form is posted on the project page.
Ballot Pools

Ballot pools are being formed through 8 p.m. Eastern, Friday, August 25, 2017. Registered Ballot
Body members may join the ballot pools here.
If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential error
messages, or system lock-out, contact NERC IT support directly at https://support.nerc.net/ (Monday
– Friday, 8 a.m. - 5 p.m. Eastern).
•

Passwords expire every 6 months and must be reset.

•

The SBS is not supported for use on mobile devices.

•

Please be mindful of ballot and comment period closing dates. We ask to allow at least 48
hours for NERC support staff to assist with inquiries. Therefore, it is recommended that users try
logging into their SBS accounts prior to the last day of a comment/ballot period.

Next Steps

An initial ballot for the standard and non-binding poll of the associated Violation Risk Factors and
Violation Severity Levels will be conducted September 1-11, 2017.

For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, Katherine Street (via email) or at (404) 446-9702 or Mat Bunch (via
email) or at (404) 446-9785.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | July-September, 2017

2

Index - NERC Balloting Tool

NERC Balloting Tool (/)

Page 1 of 19

Dashboard (/)

Users

Ballots

Comment Forms

Login (/Users/Login) / Register (/Users/Register)

BALLOT RESULTS
Comment: View Comment Results (/CommentResults/Index/102)
Ballot Name: 2016-02 Modifications to CIP Standards CIP-012-1 IN 1 ST
Voting Start Date: 9/1/2017 12:01:00 AM
Voting End Date: 9/11/2017 11:59:59 PM
Ballot Type: ST
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 248
Total Ballot Pool: 309
Quorum: 80.26
Weighted Segment Value: 42.74

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Negative
Fraction
w/
Comment

Segment:
1

80

1

24

0.393

37

0.607

0

1

18

Segment:
2

7

0.6

1

0.1

5

0.5

0

0

1

Segment:
3

73

1

24

0.429

32

0.571

0

3

14

Segment:
4

17

1

5

0.313

11

0.688

0

0

1

Segment:
5

73

1

16

0.276

42

0.724

0

2

13

Segment:
6

46

1

12

0.353

22

0.647

0

0

12

Segment:
7

2

0.1

1

0.1

0

0

0

0

1

Segment:
8

3

0.3

3

0.3

0

0

0

0

0

Segment:
9

1

0.1

1

0.1

0

0

0

0

0

1

0.1

0

0

1

Segment

Segment: 7
0.6
5
0.5
© 2018
NERC
Ver
4.2.1.0
Machine
Name:
ERODVSBSWB02
10

https://sbs.nerc.net/BallotResults/Index/212

Negative
Votes
w/o
Comment

Abstain

No
Vote

9/10/2018

Index - NERC Balloting Tool

Page 2 of 19

Segment

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Totals:

309

6.7

92

2.863

150

Negative
Fraction
w/
Comment

Negative
Votes
w/o
Comment

Abstain

No
Vote

3.837

0

6

61

BALLOT POOL MEMBERS
Show All

Segment

 entries

Organization

Search: Search

Voter

Designated
Proxy

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Negative

Comments
Submitted

1

Allete - Minnesota Power, Inc.

Jamie Monette

Affirmative

N/A

1

American Transmission
Company, LLC

Lauren Price

Negative

Comments
Submitted

1

APS - Arizona Public Service
Co.

Michelle
Amarantos

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

John Shaver

Negative

Third-Party
Comments

1

Associated Electric
Cooperative, Inc.

Mark Riley

Affirmative

N/A

1

Austin Energy

Thomas
Standifur

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Negative

Comments
Submitted

1

Basin Electric Power
Cooperative

David Rudolph

None

N/A

1

BC Hydro and Power Authority

Patricia
Robertson

None

N/A

Negative

Comments
Submitted

1

Berkshire Hathaway Energy Terry Harbour
MidAmerican Energy Co.
© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB02

https://sbs.nerc.net/BallotResults/Index/212

Joe Tarantino

9/10/2018

Index - NERC Balloting Tool

Segment

Page 3 of 19

Designated
Proxy

Voter

1

Bonneville Power
Administration

Kammy
RogersHolliday

Negative

Comments
Submitted

1

Brazos Electric Power
Cooperative, Inc.

Tony Kroskey

None

N/A

1

Cedar Falls Utilities

Adam Peterson

None

N/A

1

CenterPoint Energy Houston
Electric, LLC

John Brockhan

Negative

Comments
Submitted

1

Central Electric Power
Cooperative (Missouri)

Michael Bax

Affirmative

N/A

1

Central Hudson Gas & Electric
Corp.

Frank Pace

Negative

Comments
Submitted

1

City Utilities of Springfield,
Missouri

Michael Buyce

Affirmative

N/A

1

CMS Energy - Consumers
Energy Company

James
Anderson

Negative

Comments
Submitted

1

Con Ed - Consolidated Edison
Co. of New York

Daniel
Grinkevich

Affirmative

N/A

1

Dominion - Dominion Virginia
Power

Larry Nash

Negative

Comments
Submitted

1

Duke Energy

Doug Hils

Negative

Comments
Submitted

1

Edison International Southern California Edison
Company

Steven Mavis

Affirmative

N/A

1

Entergy - Entergy Services,
Inc.

Oliver Burke

None

N/A

1

Eversource Energy

Quintin Lee

Affirmative

N/A

1

Exelon

Chris Scanlon

Affirmative

N/A

1

FirstEnergy - FirstEnergy
Corporation

Karen Yoder

Affirmative

N/A

1

Great Plains Energy - Kansas
City Power and Light Co.

James McBee

Affirmative

N/A

1

Great River Energy

Gordon Pietsch

None

N/A

Alyson Slanover

Douglas Webb

Ballot

NERC
Memo

Organization

© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB02

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 4 of 19

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Hydro One Networks, Inc.

Payam
Farahbakhsh

Negative

Third-Party
Comments

1

Hydro-Qu?bec TransEnergie

Nicolas
Turcotte

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Laura Nelson

Negative

Comments
Submitted

1

Imperial Irrigation District

Jesus Sammy
Alcaraz

Negative

Comments
Submitted

1

International Transmission
Company Holdings
Corporation

Michael
Moltane

Negative

Third-Party
Comments

1

Lincoln Electric System

Danny Pudenz

None

N/A

1

Long Island Power Authority

Robert Ganley

None

N/A

1

Los Angeles Department of
Water and Power

faranak sarbaz

None

N/A

1

Lower Colorado River
Authority

Michael Shaw

Affirmative

N/A

1

M and A Electric Power
Cooperative

William Price

Affirmative

N/A

1

Manitoba Hydro

Mike Smith

Affirmative

N/A

1

MEAG Power

David Weekley

Negative

Third-Party
Comments

1

Memphis Light, Gas and
Water Division

Allan Long

None

N/A

1

Minnkota Power Cooperative
Inc.

Theresa Allard

Negative

Third-Party
Comments

1

Muscatine Power and Water

Andy Kurriger

Negative

Third-Party
Comments

1

N.W. Electric Power
Cooperative, Inc.

Mark Ramsey

Affirmative

N/A

1

National Grid USA

Michael Jones

Negative

Third-Party
Comments

1

Nebraska Public Power District

Jamison
Cawley

Negative

Third-Party
Comments

Stephanie
Burns

Scott Miller

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Segment

Organization

Page 5 of 19

Voter

Designated
Proxy

Ballot

NERC
Memo

1

New York Power Authority

Salvatore
Spagnolo

Negative

Comments
Submitted

1

NextEra Energy - Florida
Power and Light Co.

Mike ONeil

None

N/A

1

NiSource - Northern Indiana
Public Service Co.

Steve
Toosevich

Affirmative

N/A

1

Northeast Missouri Electric
Power Cooperative

Kevin White

Affirmative

N/A

1

OGE Energy - Oklahoma Gas
and Electric Co.

Terri Pyle

Negative

Third-Party
Comments

1

Ohio Valley Electric
Corporation

Scott
Cunningham

Negative

Third-Party
Comments

1

Omaha Public Power District

Doug
Peterchuck

None

N/A

1

Oncor Electric Delivery

Lee Maurer

None

N/A

1

OTP - Otter Tail Power
Company

Charles
Wicklund

Negative

Third-Party
Comments

1

Peak Reliability

Scott Downey

None

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Laurie Williams

Negative

Comments
Submitted

1

PPL Electric Utilities
Corporation

Brenda Truhe

Affirmative

N/A

1

PSEG - Public Service Electric
and Gas Co.

Joseph Smith

Affirmative

N/A

1

Public Utility District No. 1 of
Chelan County

Jeff Kimbell

None

N/A

1

Public Utility District No. 1 of
Snohomish County

Long Duong

Negative

Third-Party
Comments

1

Puget Sound Energy, Inc.

Theresa
Rakowsky

Negative

Comments
Submitted

1

Sacramento Municipal Utility
District

Arthur
Starkovich

Negative

Comments
Submitted

1

Salt River Project

Steven Cobb

Negative

Comments
Submitted

Tho Tran

Joe Tarantino

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Index - NERC Balloting Tool

Segment

Organization

Page 6 of 19

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Santee Cooper

Shawn Abrams

Negative

Comments
Submitted

1

SCANA - South Carolina
Electric and Gas Co.

Tom Hanzlik

Affirmative

N/A

1

Seattle City Light

Pawel Krupa

None

N/A

1

Seminole Electric Cooperative,
Inc.

Mark Churilla

Dawn Hamdorf

None

N/A

1

Sempra - San Diego Gas and
Electric

Martine Blair

Jeff Johnson

Abstain

N/A

1

Sho-Me Power Electric
Cooperative

Peter Dawson

Affirmative

N/A

1

Southern Company - Southern
Company Services, Inc.

Katherine
Prewitt

Negative

Comments
Submitted

1

Southern Indiana Gas and
Electric Co.

Steve
Rawlinson

None

N/A

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

Negative

Comments
Submitted

1

Tennessee Valley Authority

Howell Scott

Negative

Comments
Submitted

1

Tri-State G and T Association,
Inc.

Tracy Sliman

Affirmative

N/A

1

U.S. Bureau of Reclamation

Richard
Jackson

Negative

Comments
Submitted

1

Westar Energy

Kevin Giles

Negative

Third-Party
Comments

1

Western Area Power
Administration

sean erickson

Negative

Comments
Submitted

1

Xcel Energy, Inc.

Dean Schiro

Negative

Comments
Submitted

2

California ISO

Richard Vine

Negative

Comments
Submitted

2

Electric Reliability Council of
Texas, Inc.

Elizabeth
Axson

Negative

Comments
Submitted

Negative

Comments
Submitted

2

Independent Electricity System
Leonard Kula
Operator
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Index - NERC Balloting Tool

Segment

Organization

Page 7 of 19

Voter

Designated
Proxy

Ballot

NERC
Memo

2

ISO New England, Inc.

Michael Puscas

None

N/A

2

Midcontinent ISO, Inc.

Terry BIlke

Affirmative

N/A

2

New York Independent
System Operator

Gregory
Campoli

Negative

Third-Party
Comments

2

PJM Interconnection, L.L.C.

Mark Holman

Negative

Third-Party
Comments

3

AEP

Aaron Austin

Negative

Comments
Submitted

3

AES - Indianapolis Power and
Light Co.

Bette White

None

N/A

3

APS - Arizona Public Service
Co.

Vivian Vo

Affirmative

N/A

3

Arkansas Electric Cooperative
Corporation

Philip Huff

Affirmative

N/A

3

Associated Electric
Cooperative, Inc.

Todd Bennett

Affirmative

N/A

3

Austin Energy

W. Dwayne
Preston

Affirmative

N/A

3

Basin Electric Power
Cooperative

Jeremy Voll

None

N/A

3

BC Hydro and Power Authority

Hootan
Jarollahi

None

N/A

3

Berkshire Hathaway Energy MidAmerican Energy Co.

Annette
Johnston

Negative

Comments
Submitted

3

Bonneville Power
Administration

Rebecca
Berdahl

Negative

Comments
Submitted

3

Central Electric Power
Cooperative (Missouri)

Adam Weber

Affirmative

N/A

3

City of Farmington

Linda
JacobsonQuinn

None

N/A

3

City of Leesburg

Chris Adkins

Negative

Third-Party
Comments

3

City of Vero Beach

Ginny Beigel

Negative

Comments
Submitted

Brandon
McCormick

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Index - NERC Balloting Tool

Segment

Organization

Page 8 of 19

Voter

3

City Utilities of Springfield,
Missouri

Scott Williams

3

Cleco Corporation

Michelle Corley

3

Con Ed - Consolidated Edison
Co. of New York

3

Designated
Proxy

Ballot

NERC
Memo

Affirmative

N/A

Negative

Third-Party
Comments

Peter Yost

Affirmative

N/A

Cowlitz County PUD

Russell Noble

None

N/A

3

Duke Energy

Lee Schuster

Negative

Comments
Submitted

3

Edison International Southern California Edison
Company

Romel Aquino

Affirmative

N/A

3

Empire District Electric Co.

Kalem Long

None

N/A

3

Eversource Energy

Mark Kenny

Affirmative

N/A

3

Exelon

John Bee

Affirmative

N/A

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

Affirmative

N/A

3

Georgia System Operations
Corporation

Scott McGough

Negative

Comments
Submitted

3

Great Plains Energy - Kansas
City Power and Light Co.

Jessica Tucker

Affirmative

N/A

3

Great River Energy

Brian Glover

Negative

Third-Party
Comments

3

Hydro One Networks, Inc.

Paul
Malozewski

Negative

Third-Party
Comments

3

KAMO Electric Cooperative

Ted Hilmes

Affirmative

N/A

3

Lincoln Electric System

Jason Fortik

Negative

Third-Party
Comments

3

M and A Electric Power
Cooperative

Stephen Pogue

Affirmative

N/A

3

Manitoba Hydro

Karim AbdelHadi

None

N/A

3

MEAG Power

Roger Brand

Negative

Third-Party
Comments

Louis Guidry

Douglas Webb

Scott Miller

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 9 of 19

Voter

3

Modesto Irrigation District

Jack Savage

3

Muscatine Power and Water

3

Designated
Proxy
Nick Braden

Ballot

NERC
Memo

Negative

Third-Party
Comments

Seth
Shoemaker

Negative

Third-Party
Comments

National Grid USA

Brian
Shanahan

Negative

Third-Party
Comments

3

Nebraska Public Power District

Tony Eddleman

Negative

Third-Party
Comments

3

New York Power Authority

David Rivera

Negative

Comments
Submitted

3

NiSource - Northern Indiana
Public Service Co.

Aimee Harris

Affirmative

N/A

3

North Carolina Electric
Membership Corporation

doug white

Negative

Third-Party
Comments

3

Northeast Missouri Electric
Power Cooperative

Skyler
Wiegmann

None

N/A

3

NW Electric Power
Cooperative, Inc.

John Stickley

Affirmative

N/A

3

Ocala Utility Services

Randy Hahn

Negative

Third-Party
Comments

3

OGE Energy - Oklahoma Gas
and Electric Co.

Donald
Hargrove

Negative

Third-Party
Comments

3

OTP - Otter Tail Power
Company

Wendi Olson

Negative

Third-Party
Comments

3

Owensboro Municipal Utilities

Thomas Lyons

Affirmative

N/A

3

Platte River Power Authority

Jeff Landis

Abstain

N/A

3

PNM Resources - Public
Service Company of New
Mexico

Lynn Goldstein

Negative

Comments
Submitted

3

Portland General Electric Co.

Angela Gaines

Affirmative

N/A

3

PPL - Louisville Gas and
Electric Co.

Charles
Freibert

Affirmative

N/A

3

PSEG - Public Service Electric
and Gas Co.

Jeffrey Mueller

Affirmative

N/A

Scott Brame

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 10 of 19

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Public Utility District No. 1 of
Chelan County

Joyce Gundry

None

N/A

3

Puget Sound Energy, Inc.

Tim Womack

None

N/A

3

Rutherford EMC

Tom Haire

Abstain

N/A

3

Sacramento Municipal Utility
District

Nicole Looney

Negative

Comments
Submitted

3

Salt River Project

Rudy Navarro

Negative

Comments
Submitted

3

Santee Cooper

James Poston

Negative

Comments
Submitted

3

SCANA - South Carolina
Electric and Gas Co.

Clay Young

Affirmative

N/A

3

Seattle City Light

Tuan Tran

Negative

Comments
Submitted

3

Seminole Electric Cooperative,
Inc.

James Frauen

None

N/A

3

Sempra - San Diego Gas and
Electric

Bridget Silvia

Abstain

N/A

3

Sho-Me Power Electric
Cooperative

Jeff Neas

Affirmative

N/A

3

Silicon Valley Power - City of
Santa Clara

Val Ridad

None

N/A

3

Snohomish County PUD No. 1

Holly Chaney

None

N/A

3

Southern Company - Alabama
Power Company

R. Scott Moore

Negative

Comments
Submitted

3

Southern Indiana Gas and
Electric Co.

Fred Frederick

Affirmative

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

Marc
Donaldson

Negative

Comments
Submitted

3

TECO - Tampa Electric Co.

Ronald
Donahey

Negative

Comments
Submitted

3

Tennessee Valley Authority

Ian Grant

None

N/A

3

Tri-State G and T Association,
Inc.

Janelle Marriott
Gill

Affirmative

N/A

Joe Tarantino

Harold Sherrill

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9/10/2018

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Segment

Organization

Page 11 of 19

Voter

Designated
Proxy

Ballot

NERC
Memo

3

WEC Energy Group, Inc.

Thomas
Breene

Negative

Comments
Submitted

3

Westar Energy

Bo Jones

Negative

Third-Party
Comments

3

Xcel Energy, Inc.

Michael Ibold

Negative

Comments
Submitted

4

American Public Power
Association

Jack Cashin

None

N/A

4

Arkansas Electric Cooperative
Corporation

Alice Wright

Negative

Comments
Submitted

4

Austin Energy

Esther Weekes

Affirmative

N/A

4

City of Clewiston

Lynne Mila

Negative

Comments
Submitted

4

City Utilities of Springfield,
Missouri

John Allen

Affirmative

N/A

4

FirstEnergy - FirstEnergy
Corporation

Anthony Solic

Affirmative

N/A

4

Georgia System Operations
Corporation

Guy Andrews

Negative

Comments
Submitted

4

Indiana Municipal Power
Agency

Jack Alvey

Negative

Comments
Submitted

4

National Rural Electric
Cooperative Association

Barry Lawson

Affirmative

N/A

4

North Carolina Electric
Membership Corporation

John Lemire

Negative

Third-Party
Comments

4

Public Utility District No. 1 of
Snohomish County

John Martinsen

Negative

Third-Party
Comments

4

Sacramento Municipal Utility
District

Beth Tincher

Negative

Comments
Submitted

4

Seattle City Light

Hao Li

Negative

Comments
Submitted

4

Seminole Electric Cooperative,
Inc.

Michael Ward

Affirmative

N/A

Negative

Comments
Submitted

4

Tacoma Public Utilities
Hien Ho
(Tacoma, WA)
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Brandon
McCormick

Scott Berry

Scott Brame

Joe Tarantino

Shirley Eshbach

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 12 of 19

Voter

Designated
Proxy

Ballot

NERC
Memo

4

Utility Services, Inc.

Brian EvansMongeon

Negative

Comments
Submitted

4

WEC Energy Group, Inc.

Anthony
Jankowski

Negative

Comments
Submitted

5

Acciona Energy North America

George Brown

Negative

Comments
Submitted

5

AEP

Thomas Foltz

Negative

Comments
Submitted

5

Ameren - Ameren Missouri

Sam Dwyer

None

N/A

5

APS - Arizona Public Service
Co.

Linda
Henrickson

Affirmative

N/A

5

Arkansas Electric Cooperative
Corporation

Moses Harris

Negative

Comments
Submitted

5

Associated Electric
Cooperative, Inc.

Brad Haralson

Affirmative

N/A

5

Austin Energy

Jeanie Doty

Affirmative

N/A

5

Avista - Avista Corporation

Glen Farmer

None

N/A

5

Basin Electric Power
Cooperative

Mike Kraft

None

N/A

5

BC Hydro and Power Authority

Helen Hamilton
Harding

None

N/A

5

Boise-Kuna Irrigation District Lucky Peak Power Plant
Project

Mike Kukla

Negative

Third-Party
Comments

5

Bonneville Power
Administration

Francis Halpin

Negative

Comments
Submitted

5

BP Wind Energy North
America Inc.

Carla Holly

None

N/A

5

Choctaw Generation Limited
Partnership, LLLP

Rob Watson

None

N/A

5

Cleco Corporation

Stephanie
Huffman

Negative

Third-Party
Comments

5

CMS Energy - Consumers
Energy Company

David
Greyerbiehl

Negative

Comments
Submitted

Affirmative

N/A

5 - NERC Ver 4.2.1.0
Colorado
SpringsName:
Utilities
Jeff Icke
© 2018
Machine
ERODVSBSWB02

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Louis Guidry

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 13 of 19

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Con Ed - Consolidated Edison
Co. of New York

Dermot Smyth

Affirmative

N/A

5

Dairyland Power Cooperative

Tommy Drea

Negative

Third-Party
Comments

5

Dominion - Dominion
Resources, Inc.

Lou Oberski

Negative

Comments
Submitted

5

Duke Energy

Dale Goodwine

Negative

Comments
Submitted

5

Edison International Southern California Edison
Company

Thomas
Rafferty

Affirmative

N/A

5

EDP Renewables North
America LLC

Heather
Morgan

Negative

Comments
Submitted

5

Entergy - Entergy Services,
Inc.

Jaclyn Massey

Negative

Comments
Submitted

5

Exelon

Ruth Miller

Affirmative

N/A

5

FirstEnergy - FirstEnergy
Solutions

Robert Loy

Affirmative

N/A

5

Great Plains Energy - Kansas
City Power and Light Co.

Harold Wyble

Affirmative

N/A

5

Great River Energy

Preston Walsh

Negative

Third-Party
Comments

5

Gridforce Energy
Management, LLC

David
Blackshear

None

N/A

5

Hydro-Qu?bec Production

Normande
Bouffard

Abstain

N/A

5

JEA

John Babik

Affirmative

N/A

5

Kissimmee Utility Authority

Mike Blough

Negative

Third-Party
Comments

5

Lakeland Electric

Jim Howard

Negative

Third-Party
Comments

5

Lincoln Electric System

Kayleigh
Wilkerson

Negative

Third-Party
Comments

None

N/A

5

Los Angeles Department of
Glenn Barry
Water and Power
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Douglas Webb

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 14 of 19

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Manitoba Hydro

Yuguang Xiao

Affirmative

N/A

5

Massachusetts Municipal
Wholesale Electric Company

David Gordon

Negative

Comments
Submitted

5

MEAG Power

Steven Grego

Negative

Third-Party
Comments

5

Muscatine Power and Water

Neal Nelson

Negative

Third-Party
Comments

5

NB Power Corporation

Laura McLeod

Negative

Comments
Submitted

5

Nebraska Public Power District

Don Schmit

Negative

Third-Party
Comments

5

New York Power Authority

Erick Barrios

Negative

Comments
Submitted

5

NextEra Energy

Allen Schriver

None

N/A

5

NiSource - Northern Indiana
Public Service Co.

Sarah
Gasienica

Affirmative

N/A

5

North Carolina Electric
Membership Corporation

Robert Beadle

Negative

Third-Party
Comments

5

Northern California Power
Agency

Marty Hostler

Negative

Comments
Submitted

5

OGE Energy - Oklahoma Gas
and Electric Co.

John Rhea

Negative

Third-Party
Comments

5

Omaha Public Power District

Mahmood Safi

Negative

Third-Party
Comments

5

Ontario Power Generation Inc.

David
Ramkalawan

Affirmative

N/A

5

OTP - Otter Tail Power
Company

Cathy Fogale

Negative

Third-Party
Comments

5

Portland General Electric Co.

Ryan Olson

None

N/A

5

PPL - Louisville Gas and
Electric Co.

Dan Wilson

Affirmative

N/A

5

PSEG - PSEG Fossil LLC

Tim Kucey

Affirmative

N/A

5

Public Utility District No. 1 of
Chelan County

Haley Sousa

Negative

Comments
Submitted

Scott Miller

Scott Brame

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Segment

Organization

Page 15 of 19

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Public Utility District No. 1 of
Snohomish County

Sam Nietfeld

Negative

Third-Party
Comments

5

Puget Sound Energy, Inc.

Eleanor Ewry

Negative

Comments
Submitted

5

Sacramento Municipal Utility
District

Susan Oto

Negative

Comments
Submitted

5

Salt River Project

Kevin Nielsen

Negative

Comments
Submitted

5

Santee Cooper

Tommy Curtis

Negative

Comments
Submitted

5

SCANA - South Carolina
Electric and Gas Co.

Alyssa Hubbard

Affirmative

N/A

5

Seattle City Light

Mike Haynes

Negative

Comments
Submitted

5

Seminole Electric Cooperative,
Inc.

Brenda Atkins

None

N/A

5

Sempra - San Diego Gas and
Electric

Jerome Gobby

Abstain

N/A

5

Silicon Valley Power - City of
Santa Clara

Sandra
Pacheco

None

N/A

5

Southern Company - Southern
Company Generation

William D.
Shultz

Negative

Comments
Submitted

5

SunPower

Bradley Collard

None

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Chris Mattson

Negative

Comments
Submitted

5

Talen Generation, LLC

Donald Lock

Negative

Comments
Submitted

5

TECO - Tampa Electric Co.

R James
Rocha

Negative

Comments
Submitted

5

Tennessee Valley Authority

M Lee Thomas

Negative

Comments
Submitted

5

U.S. Bureau of Reclamation

Wendy Center

Negative

Comments
Submitted

5

WEC Energy Group, Inc.

Linda Horn

Negative

Comments
Submitted

Joe Tarantino

Andrey
Komissarov

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 16 of 19

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Xcel Energy, Inc.

Gerry Huitt

Negative

Comments
Submitted

6

APS - Arizona Public Service
Co.

Nicholas Kirby

None

N/A

6

Arkansas Electric Cooperative
Corporation

Bruce Walkup

None

N/A

6

Austin Energy

Andrew Gallo

Affirmative

N/A

6

Basin Electric Power
Cooperative

Paul Huettl

None

N/A

6

Berkshire Hathaway PacifiCorp

Sandra Shaffer

Affirmative

N/A

6

Bonneville Power
Administration

Andrew Meyers

Negative

Comments
Submitted

6

Cleco Corporation

Robert Hirchak

Negative

Third-Party
Comments

6

Con Ed - Consolidated Edison
Co. of New York

Robert Winston

Affirmative

N/A

6

Dominion - Dominion
Resources, Inc.

Sean Bodkin

Negative

Comments
Submitted

6

Duke Energy

Greg Cecil

Negative

Comments
Submitted

6

Edison International Southern California Edison
Company

Kenya Streeter

Affirmative

N/A

6

Entergy

Julie Hall

Negative

Comments
Submitted

6

Exelon

Becky Webb

Affirmative

N/A

6

FirstEnergy - FirstEnergy
Solutions

Ann Ivanc

Affirmative

N/A

6

Florida Municipal Power Pool

Tom Reedy

Brandon
McCormick

Negative

Comments
Submitted

6

Great Plains Energy - Kansas
City Power and Light Co.

Jim Flucke

Douglas Webb

Affirmative

N/A

6

Lincoln Electric System

Eric Ruskamp

Negative

Third-Party
Comments

Louis Guidry

© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB02

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 17 of 19

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Los Angeles Department of
Water and Power

Anton Vu

None

N/A

6

Luminant - Luminant Energy

Brenda
Hampton

Affirmative

N/A

6

Manitoba Hydro

Blair Mukanik

Affirmative

N/A

6

Modesto Irrigation District

James McFall

Negative

Third-Party
Comments

6

Muscatine Power and Water

Ryan Streck

Negative

Third-Party
Comments

6

NextEra Energy - Florida
Power and Light Co.

Silvia Mitchell

None

N/A

6

NiSource - Northern Indiana
Public Service Co.

Joe O'Brien

Affirmative

N/A

6

Northern California Power
Agency

Dennis Sismaet

Negative

Comments
Submitted

6

OGE Energy - Oklahoma Gas
and Electric Co.

Jerry Nottnagel

Negative

Third-Party
Comments

6

Omaha Public Power District

Joel Robles

None

N/A

6

Portland General Electric Co.

Daniel Mason

Affirmative

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

Affirmative

N/A

6

Public Utility District No. 1 of
Chelan County

Janis Weddle

Negative

Comments
Submitted

6

Public Utility District No. 2 of
Grant County, Washington

LeRoy
Patterson

None

N/A

6

Sacramento Municipal Utility
District

Jamie Cutlip

Negative

Comments
Submitted

6

Salt River Project

Bobby Olsen

None

N/A

6

Santee Cooper

Michael Brown

Negative

Comments
Submitted

6

Seattle City Light

Charles
Freeman

Negative

Comments
Submitted

6

Seminole Electric Cooperative,
Inc.

Trudy Novak

None

N/A

Nick Braden

Joe Tarantino

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Segment

Organization

Page 18 of 19

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Snohomish County PUD No. 1

Franklin Lu

None

N/A

6

Southern Company - Southern
Company Generation and
Energy Marketing

Jennifer Sykes

Negative

Comments
Submitted

6

Southern Indiana Gas and
Electric Co.

Brad Lisembee

None

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Rick Applegate

Negative

Comments
Submitted

6

Talen Energy Marketing, LLC

Jennifer
Hohenshilt

None

N/A

6

TECO - Tampa Electric Co.

Benjamin Smith

Negative

Comments
Submitted

6

Tennessee Valley Authority

Marjorie
Parsons

Negative

Comments
Submitted

6

WEC Energy Group, Inc.

Scott Hoggatt

Negative

Comments
Submitted

6

Westar Energy

Megan Wagner

Negative

Third-Party
Comments

6

Xcel Energy, Inc.

Carrie Dixon

Negative

Comments
Submitted

7

Exxon Mobil

Jay Barnett

None

N/A

7

Luminant Mining Company
LLC

Stewart Rake

Affirmative

N/A

8

David Kiguel

David Kiguel

Affirmative

N/A

8

Massachusetts Attorney
General

Frederick Plett

Affirmative

N/A

8

Roger Zaklukiewicz

Roger
Zaklukiewicz

Affirmative

N/A

9

Commonwealth of
Massachusetts Department of
Public Utilities

Donald Nelson

Affirmative

N/A

10

Midwest Reliability
Organization

Russel
Mountjoy

Affirmative

N/A

Affirmative

N/A

10

New York State Reliability
ALAN
Council
ADAMSON
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Segment

Organization

Page 19 of 19

Voter

Designated
Proxy

Ballot

NERC
Memo

10

Northeast Power Coordinating
Council

Guy V. Zito

Affirmative

N/A

10

ReliabilityFirst

Anthony
Jablonski

Affirmative

N/A

10

SERC Reliability Corporation

David Greene

Affirmative

N/A

10

Texas Reliability Entity, Inc.

Rachel Coyne

Negative

Comments
Submitted

10

Western Electricity
Coordinating Council

Steven
Rueckert

None

N/A

Previous

1

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Showing 1 to 309 of 309 entries

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NERC Balloting Tool (/)

Dashboard (/)

Page 1 of 17

Users

Ballots

Comment Forms

Login (/Users/Login) / Register (/Users/Register)

BALLOT RESULTS
Ballot Name: 2016-02 Modifications to CIP Standards CIP-012-1 Non-binding Poll IN 1 NB
Voting Start Date: 9/1/2017 12:01:00 AM
Voting End Date: 9/11/2017 11:59:59 PM
Ballot Type: NB
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 226
Total Ballot Pool: 290
Quorum: 77.93
Weighted Segment Value: 41.53
Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes

Negative
Fraction

Abstain

No
Vote

Segment:
1

75

1

21

0.447

26

0.553

11

17

Segment:
2

7

0.4

2

0.2

2

0.2

2

1

Segment:
3

70

1

19

0.442

24

0.558

13

14

Segment:
4

14

1

2

0.182

9

0.818

2

1

Segment:
5

69

1

13

0.302

30

0.698

9

17

Segment:
6

42

1

9

0.375

15

0.625

6

12

Segment:
7

2

0.1

1

0.1

0

0

0

1

Segment:
8

3

0.3

3

0.3

0

0

0

0

Segment:
9

1

0.1

1

0.1

0

0

0

0

Segment:
10

7

0.6

5

0.5

1

0.1

0

1

107

3.552

43

64

Segment

Totals:
290
6.5
76
2.948
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Page 2 of 17

BALLOT POOL MEMBERS
Show All

Segment

 entries

Organization

Search: Search

Voter

Designated
Proxy

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Negative

Comments
Submitted

1

American Transmission
Company, LLC

Douglas Johnson

None

N/A

1

APS - Arizona Public Service
Co.

Michelle
Amarantos

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

John Shaver

Negative

Comments
Submitted

1

Associated Electric
Cooperative, Inc.

Mark Riley

Affirmative

N/A

1

Austin Energy

Thomas
Standifur

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Negative

Comments
Submitted

1

Basin Electric Power
Cooperative

David Rudolph

None

N/A

1

BC Hydro and Power
Authority

Patricia
Robertson

None

N/A

1

Berkshire Hathaway Energy MidAmerican Energy Co.

Terry Harbour

Negative

Comments
Submitted

1

Bonneville Power
Administration

Kammy RogersHolliday

Negative

Comments
Submitted

1

Brazos Electric Power
Cooperative, Inc.

Tony Kroskey

None

N/A

1

Cedar Falls Utilities

Adam Peterson

None

N/A

Abstain

N/A

1

CenterPoint Energy Houston
John Brockhan
Electric,
LLC
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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 3 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Central Electric Power
Cooperative (Missouri)

Michael Bax

Affirmative

N/A

1

Central Hudson Gas &
Electric Corp.

Frank Pace

Affirmative

N/A

1

City Utilities of Springfield,
Missouri

Michael Buyce

Affirmative

N/A

1

Con Ed - Consolidated
Edison Co. of New York

Daniel Grinkevich

Affirmative

N/A

1

Dominion - Dominion Virginia
Power

Larry Nash

Abstain

N/A

1

Duke Energy

Doug Hils

Negative

Comments
Submitted

1

Edison International Southern California Edison
Company

Steven Mavis

Affirmative

N/A

1

Entergy - Entergy Services,
Inc.

Oliver Burke

None

N/A

1

Eversource Energy

Quintin Lee

Affirmative

N/A

1

Exelon

Chris Scanlon

Abstain

N/A

1

FirstEnergy - FirstEnergy
Corporation

Karen Yoder

Affirmative

N/A

1

Great Plains Energy - Kansas
City Power and Light Co.

James McBee

Affirmative

N/A

1

Great River Energy

Gordon Pietsch

None

N/A

1

Hydro One Networks, Inc.

Payam
Farahbakhsh

Negative

Comments
Submitted

1

Hydro-Qu?bec TransEnergie

Nicolas Turcotte

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Laura Nelson

Negative

Comments
Submitted

1

Imperial Irrigation District

Jesus Sammy
Alcaraz

Abstain

N/A

1

International Transmission
Company Holdings
Corporation

Michael Moltane

Negative

Comments
Submitted

None

N/A

1 - NERC Ver 4.2.1.0
Lincoln Machine
Electric System
Danny Pudenz
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Name: ERODVSBSWB02

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Alyson Slanover

Douglas Webb

Stephanie
Burns

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 4 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Long Island Power Authority

Robert Ganley

None

N/A

1

Los Angeles Department of
Water and Power

faranak sarbaz

None

N/A

1

Lower Colorado River
Authority

Michael Shaw

Affirmative

N/A

1

M and A Electric Power
Cooperative

William Price

Affirmative

N/A

1

Manitoba Hydro

Mike Smith

Affirmative

N/A

1

MEAG Power

David Weekley

Negative

Comments
Submitted

1

Memphis Light, Gas and
Water Division

Allan Long

None

N/A

1

Minnkota Power Cooperative
Inc.

Theresa Allard

Abstain

N/A

1

Muscatine Power and Water

Andy Kurriger

Negative

Comments
Submitted

1

N.W. Electric Power
Cooperative, Inc.

Mark Ramsey

Affirmative

N/A

1

National Grid USA

Michael Jones

Negative

Comments
Submitted

1

Nebraska Public Power
District

Jamison Cawley

Abstain

N/A

1

New York Power Authority

Salvatore
Spagnolo

Negative

Comments
Submitted

1

NextEra Energy - Florida
Power and Light Co.

Mike ONeil

None

N/A

1

NiSource - Northern Indiana
Public Service Co.

Steve Toosevich

Affirmative

N/A

1

Northeast Missouri Electric
Power Cooperative

Kevin White

Affirmative

N/A

1

OGE Energy - Oklahoma Gas
and Electric Co.

Terri Pyle

Negative

Comments
Submitted

1

Ohio Valley Electric
Corporation

Scott
Cunningham

Negative

Comments
Submitted

None

N/A

1 - NERC Ver 4.2.1.0
OmahaMachine
Public Power
District
Doug Peterchuck
© 2018
Name:
ERODVSBSWB02

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Scott Miller

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 5 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

1

OTP - Otter Tail Power
Company

Charles Wicklund

Negative

Comments
Submitted

1

Peak Reliability

Scott Downey

None

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Laurie Williams

Abstain

N/A

1

PPL Electric Utilities
Corporation

Brenda Truhe

Abstain

N/A

1

PSEG - Public Service
Electric and Gas Co.

Joseph Smith

Abstain

N/A

1

Public Utility District No. 1 of
Chelan County

Jeff Kimbell

None

N/A

1

Public Utility District No. 1 of
Snohomish County

Long Duong

Negative

Comments
Submitted

1

Puget Sound Energy, Inc.

Theresa
Rakowsky

Negative

Comments
Submitted

1

Sacramento Municipal Utility
District

Arthur Starkovich

Negative

Comments
Submitted

1

Salt River Project

Steven Cobb

Negative

Comments
Submitted

1

Santee Cooper

Shawn Abrams

Abstain

N/A

1

SCANA - South Carolina
Electric and Gas Co.

Tom Hanzlik

Affirmative

N/A

1

Seattle City Light

Pawel Krupa

None

N/A

1

Seminole Electric
Cooperative, Inc.

Mark Churilla

Dawn Hamdorf

None

N/A

1

Sempra - San Diego Gas and
Electric

Martine Blair

Jeff Johnson

Abstain

N/A

1

Sho-Me Power Electric
Cooperative

Peter Dawson

Affirmative

N/A

1

Southern Company Southern Company Services,
Inc.

Katherine Prewitt

Negative

Comments
Submitted

Negative

Comments
Submitted

1

Tacoma Public Utilities
John Merrell
(Tacoma, WA)
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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 6 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Tennessee Valley Authority

Howell Scott

Negative

Comments
Submitted

1

Tri-State G and T
Association, Inc.

Tracy Sliman

Affirmative

N/A

1

U.S. Bureau of Reclamation

Richard Jackson

Negative

Comments
Submitted

1

Westar Energy

Kevin Giles

Negative

Comments
Submitted

1

Western Area Power
Administration

sean erickson

Negative

Comments
Submitted

2

California ISO

Richard Vine

Negative

Comments
Submitted

2

Electric Reliability Council of
Texas, Inc.

Elizabeth Axson

Affirmative

N/A

2

Independent Electricity
System Operator

Leonard Kula

Affirmative

N/A

2

ISO New England, Inc.

Michael Puscas

None

N/A

2

Midcontinent ISO, Inc.

Terry BIlke

Abstain

N/A

2

New York Independent
System Operator

Gregory Campoli

Abstain

N/A

2

PJM Interconnection, L.L.C.

Mark Holman

Negative

Comments
Submitted

3

AEP

Aaron Austin

Negative

Comments
Submitted

3

AES - Indianapolis Power
and Light Co.

Bette White

None

N/A

3

APS - Arizona Public Service
Co.

Vivian Vo

Affirmative

N/A

3

Arkansas Electric
Cooperative Corporation

Philip Huff

Abstain

N/A

3

Associated Electric
Cooperative, Inc.

Todd Bennett

Affirmative

N/A

3

Austin Energy

W. Dwayne
Preston

Affirmative

N/A

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Index - NERC Balloting Tool

Segment

Organization

Page 7 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Basin Electric Power
Cooperative

Jeremy Voll

None

N/A

3

Berkshire Hathaway Energy MidAmerican Energy Co.

Annette Johnston

Negative

Comments
Submitted

3

Bonneville Power
Administration

Rebecca Berdahl

Negative

Comments
Submitted

3

Central Electric Power
Cooperative (Missouri)

Adam Weber

Affirmative

N/A

3

City of Farmington

Linda JacobsonQuinn

None

N/A

3

City of Leesburg

Chris Adkins

Negative

Comments
Submitted

3

City of Vero Beach

Ginny Beigel

Negative

Comments
Submitted

3

City Utilities of Springfield,
Missouri

Scott Williams

Affirmative

N/A

3

Cleco Corporation

Michelle Corley

Abstain

N/A

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Affirmative

N/A

3

Cowlitz County PUD

Russell Noble

None

N/A

3

Duke Energy

Lee Schuster

Negative

Comments
Submitted

3

Edison International Southern California Edison
Company

Romel Aquino

Affirmative

N/A

3

Eversource Energy

Mark Kenny

Affirmative

N/A

3

Exelon

John Bee

Abstain

N/A

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

Affirmative

N/A

3

Georgia System Operations
Corporation

Scott McGough

Negative

Comments
Submitted

3

Great Plains Energy - Kansas
City Power and Light Co.

Jessica Tucker

Affirmative

N/A

3

Great River Energy

Brian Glover

Negative

Comments
Submitted

© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB02

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Brandon
McCormick

Louis Guidry

Douglas Webb

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 8 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Hydro One Networks, Inc.

Paul Malozewski

Negative

Comments
Submitted

3

KAMO Electric Cooperative

Ted Hilmes

Affirmative

N/A

3

Lincoln Electric System

Jason Fortik

Abstain

N/A

3

M and A Electric Power
Cooperative

Stephen Pogue

Affirmative

N/A

3

Manitoba Hydro

Karim Abdel-Hadi

None

N/A

3

MEAG Power

Roger Brand

Scott Miller

Negative

Comments
Submitted

3

Modesto Irrigation District

Jack Savage

Nick Braden

Abstain

N/A

3

Muscatine Power and Water

Seth Shoemaker

Negative

Comments
Submitted

3

National Grid USA

Brian Shanahan

Negative

Comments
Submitted

3

Nebraska Public Power
District

Tony Eddleman

Abstain

N/A

3

New York Power Authority

David Rivera

Negative

Comments
Submitted

3

NiSource - Northern Indiana
Public Service Co.

Aimee Harris

Affirmative

N/A

3

North Carolina Electric
Membership Corporation

doug white

Negative

Comments
Submitted

3

Northeast Missouri Electric
Power Cooperative

Skyler Wiegmann

None

N/A

3

NW Electric Power
Cooperative, Inc.

John Stickley

Affirmative

N/A

3

Ocala Utility Services

Randy Hahn

Negative

Comments
Submitted

3

OGE Energy - Oklahoma Gas
and Electric Co.

Donald Hargrove

Negative

Comments
Submitted

3

OTP - Otter Tail Power
Company

Wendi Olson

Negative

Comments
Submitted

3

Owensboro Municipal Utilities

Thomas Lyons

Affirmative

N/A

Abstain

N/A

3 - NERC Ver 4.2.1.0
Platte River
Power
Authority
Jeff Landis
© 2018
Machine
Name:
ERODVSBSWB02

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Scott Brame

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 9 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

3

PNM Resources - Public
Service Company of New
Mexico

Lynn Goldstein

Abstain

N/A

3

Portland General Electric Co.

Angela Gaines

Affirmative

N/A

3

PPL - Louisville Gas and
Electric Co.

Charles Freibert

None

N/A

3

PSEG - Public Service
Electric and Gas Co.

Jeffrey Mueller

Abstain

N/A

3

Public Utility District No. 1 of
Chelan County

Joyce Gundry

None

N/A

3

Puget Sound Energy, Inc.

Tim Womack

None

N/A

3

Rutherford EMC

Tom Haire

Abstain

N/A

3

Sacramento Municipal Utility
District

Nicole Looney

Negative

Comments
Submitted

3

Salt River Project

Rudy Navarro

Negative

Comments
Submitted

3

Santee Cooper

James Poston

Abstain

N/A

3

SCANA - South Carolina
Electric and Gas Co.

Clay Young

Affirmative

N/A

3

Seattle City Light

Tuan Tran

None

N/A

3

Seminole Electric
Cooperative, Inc.

James Frauen

None

N/A

3

Sempra - San Diego Gas and
Electric

Bridget Silvia

Abstain

N/A

3

Sho-Me Power Electric
Cooperative

Jeff Neas

Affirmative

N/A

3

Silicon Valley Power - City of
Santa Clara

Val Ridad

None

N/A

3

Snohomish County PUD No.
1

Holly Chaney

None

N/A

3

Southern Company Alabama Power Company

R. Scott Moore

Negative

Comments
Submitted

3

Tacoma Public Utilities
(Tacoma, WA)

Marc Donaldson

Negative

Comments
Submitted

Joe Tarantino

Harold Sherrill

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Index - NERC Balloting Tool

Segment

Organization

Page 10 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

3

TECO - Tampa Electric Co.

Ronald Donahey

Negative

Comments
Submitted

3

Tennessee Valley Authority

Ian Grant

None

N/A

3

Tri-State G and T
Association, Inc.

Janelle Marriott
Gill

Affirmative

N/A

3

WEC Energy Group, Inc.

Thomas Breene

Negative

Comments
Submitted

3

Westar Energy

Bo Jones

Negative

Comments
Submitted

3

Xcel Energy, Inc.

Michael Ibold

Abstain

N/A

4

American Public Power
Association

Jack Cashin

None

N/A

4

Austin Energy

Esther Weekes

Affirmative

N/A

4

City of Clewiston

Lynne Mila

Negative

Comments
Submitted

4

City Utilities of Springfield,
Missouri

John Allen

Affirmative

N/A

4

Georgia System Operations
Corporation

Guy Andrews

Negative

Comments
Submitted

4

Indiana Municipal Power
Agency

Jack Alvey

Scott Berry

Negative

Comments
Submitted

4

North Carolina Electric
Membership Corporation

John Lemire

Scott Brame

Negative

Comments
Submitted

4

Public Utility District No. 1 of
Snohomish County

John Martinsen

Negative

Comments
Submitted

4

Sacramento Municipal Utility
District

Beth Tincher

Negative

Comments
Submitted

4

Seattle City Light

Hao Li

Negative

Comments
Submitted

4

Seminole Electric
Cooperative, Inc.

Michael Ward

Abstain

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

Negative

Comments
Submitted

4

Utility Services, Inc.

Brian Evans-

Abstain

N/A

Brandon
McCormick

Joe Tarantino

Shirley Eshbach

Mongeon
© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB02

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Index - NERC Balloting Tool

Segment

Organization

Page 11 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

4

WEC Energy Group, Inc.

Anthony
Jankowski

Negative

Comments
Submitted

5

Acciona Energy North
America

George Brown

None

N/A

5

AEP

Thomas Foltz

Negative

Comments
Submitted

5

Ameren - Ameren Missouri

Sam Dwyer

None

N/A

5

APS - Arizona Public Service
Co.

Linda Henrickson

Affirmative

N/A

5

Associated Electric
Cooperative, Inc.

Brad Haralson

Affirmative

N/A

5

Austin Energy

Jeanie Doty

Affirmative

N/A

5

Avista - Avista Corporation

Glen Farmer

None

N/A

5

Basin Electric Power
Cooperative

Mike Kraft

None

N/A

5

BC Hydro and Power
Authority

Helen Hamilton
Harding

None

N/A

5

Boise-Kuna Irrigation District Lucky Peak Power Plant
Project

Mike Kukla

Negative

Comments
Submitted

5

Bonneville Power
Administration

Francis Halpin

Negative

Comments
Submitted

5

BP Wind Energy North
America Inc.

Carla Holly

None

N/A

5

Choctaw Generation Limited
Partnership, LLLP

Rob Watson

None

N/A

5

Cleco Corporation

Stephanie
Huffman

Abstain

N/A

5

CMS Energy - Consumers
Energy Company

David
Greyerbiehl

Negative

Comments
Submitted

5

Colorado Springs Utilities

Jeff Icke

Affirmative

N/A

5

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

5

Dairyland Power Cooperative

Tommy Drea

Negative

Comments
Submitted

© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB02

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Louis Guidry

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 12 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Dominion - Dominion
Resources, Inc.

Lou Oberski

Negative

Comments
Submitted

5

Duke Energy

Dale Goodwine

Negative

Comments
Submitted

5

Edison International Southern California Edison
Company

Thomas Rafferty

Affirmative

N/A

5

EDP Renewables North
America LLC

Heather Morgan

Negative

Comments
Submitted

5

Entergy - Entergy Services,
Inc.

Jaclyn Massey

Negative

Comments
Submitted

5

Exelon

Ruth Miller

Abstain

N/A

5

FirstEnergy - FirstEnergy
Solutions

Robert Loy

Affirmative

N/A

5

Great Plains Energy - Kansas
City Power and Light Co.

Harold Wyble

Affirmative

N/A

5

Great River Energy

Preston Walsh

Negative

Comments
Submitted

5

Hydro-Qu?bec Production

Normande
Bouffard

Abstain

N/A

5

JEA

John Babik

Affirmative

N/A

5

Kissimmee Utility Authority

Mike Blough

Negative

Comments
Submitted

5

Lakeland Electric

Jim Howard

Negative

Comments
Submitted

5

Lincoln Electric System

Kayleigh
Wilkerson

Abstain

N/A

5

Los Angeles Department of
Water and Power

Glenn Barry

None

N/A

5

Manitoba Hydro

Yuguang Xiao

Affirmative

N/A

5

Massachusetts Municipal
Wholesale Electric Company

David Gordon

Abstain

N/A

5

MEAG Power

Steven Grego

Negative

Comments
Submitted

Douglas Webb

Scott Miller

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 13 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Muscatine Power and Water

Neal Nelson

Negative

Comments
Submitted

5

NB Power Corporation

Laura McLeod

Negative

Comments
Submitted

5

Nebraska Public Power
District

Don Schmit

Abstain

N/A

5

New York Power Authority

Erick Barrios

Negative

Comments
Submitted

5

NextEra Energy

Allen Schriver

None

N/A

5

NiSource - Northern Indiana
Public Service Co.

Sarah Gasienica

Affirmative

N/A

5

Northern California Power
Agency

Marty Hostler

Negative

Comments
Submitted

5

OGE Energy - Oklahoma Gas
and Electric Co.

John Rhea

Negative

Comments
Submitted

5

Omaha Public Power District

Mahmood Safi

Negative

Comments
Submitted

5

Ontario Power Generation
Inc.

David
Ramkalawan

Affirmative

N/A

5

OTP - Otter Tail Power
Company

Cathy Fogale

Negative

Comments
Submitted

5

Portland General Electric Co.

Ryan Olson

None

N/A

5

PPL - Louisville Gas and
Electric Co.

JULIE
HOSTRANDER

None

N/A

5

PSEG - PSEG Fossil LLC

Tim Kucey

Abstain

N/A

5

Public Utility District No. 1 of
Chelan County

Haley Sousa

Negative

Comments
Submitted

5

Public Utility District No. 1 of
Snohomish County

Sam Nietfeld

Negative

Comments
Submitted

5

Puget Sound Energy, Inc.

Eleanor Ewry

Negative

Comments
Submitted

5

Sacramento Municipal Utility
District

Susan Oto

Negative

Comments
Submitted

5

Salt River Project

Kevin Nielsen

Negative

Comments
Submitted

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Joe Tarantino

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 14 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Santee Cooper

Tommy Curtis

Abstain

N/A

5

SCANA - South Carolina
Electric and Gas Co.

Alyssa Hubbard

Affirmative

N/A

5

Seattle City Light

Mike Haynes

Negative

Comments
Submitted

5

Seminole Electric
Cooperative, Inc.

Brenda Atkins

None

N/A

5

Sempra - San Diego Gas and
Electric

Jerome Gobby

Abstain

N/A

5

Silicon Valley Power - City of
Santa Clara

Sandra Pacheco

None

N/A

5

Southern Company Southern Company
Generation

William D. Shultz

Negative

Comments
Submitted

5

SunPower

Bradley Collard

None

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Chris Mattson

Negative

Comments
Submitted

5

Talen Generation, LLC

Matthew
McMillan

None

N/A

5

TECO - Tampa Electric Co.

Frank L Busot

None

N/A

5

Tennessee Valley Authority

M Lee Thomas

None

N/A

5

U.S. Bureau of Reclamation

Wendy Center

Negative

Comments
Submitted

5

Westar Energy

Laura Cox

Negative

Comments
Submitted

6

APS - Arizona Public Service
Co.

Nicholas Kirby

None

N/A

6

Arkansas Electric
Cooperative Corporation

Bruce Walkup

None

N/A

6

Austin Energy

Andrew Gallo

Affirmative

N/A

6

Basin Electric Power
Cooperative

Paul Huettl

None

N/A

6

Berkshire Hathaway PacifiCorp

Sandra Shaffer

Affirmative

N/A

Andrey
Komissarov

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 15 of 17

Voter

6

Cleco Corporation

Robert Hirchak

6

Con Ed - Consolidated
Edison Co. of New York

6

Designated
Proxy
Louis Guidry

Ballot

NERC
Memo

Abstain

N/A

Robert Winston

Affirmative

N/A

Dominion - Dominion
Resources, Inc.

Sean Bodkin

Negative

Comments
Submitted

6

Duke Energy

Greg Cecil

Negative

Comments
Submitted

6

Edison International Southern California Edison
Company

Kenya Streeter

Affirmative

N/A

6

Entergy

Julie Hall

Negative

Comments
Submitted

6

Exelon

Becky Webb

Abstain

N/A

6

FirstEnergy - FirstEnergy
Solutions

Ann Ivanc

Affirmative

N/A

6

Florida Municipal Power Pool

Tom Reedy

Brandon
McCormick

Negative

Comments
Submitted

6

Great Plains Energy - Kansas
City Power and Light Co.

Jim Flucke

Douglas Webb

Affirmative

N/A

6

Lincoln Electric System

Eric Ruskamp

Abstain

N/A

6

Los Angeles Department of
Water and Power

Anton Vu

None

N/A

6

Luminant - Luminant Energy

Brenda Hampton

Abstain

N/A

6

Manitoba Hydro

Blair Mukanik

Affirmative

N/A

6

Muscatine Power and Water

Ryan Streck

Negative

Comments
Submitted

6

NextEra Energy - Florida
Power and Light Co.

Silvia Mitchell

None

N/A

6

NiSource - Northern Indiana
Public Service Co.

Joe O'Brien

Affirmative

N/A

6

Northern California Power
Agency

Dennis Sismaet

Negative

Comments
Submitted

6

OGE Energy - Oklahoma Gas
and Electric Co.

Jerry Nottnagel

Negative

Comments
Submitted

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Index - NERC Balloting Tool

Segment

Organization

Page 16 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Omaha Public Power District

Joel Robles

None

N/A

6

Portland General Electric Co.

Daniel Mason

Affirmative

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

None

N/A

6

Public Utility District No. 1 of
Chelan County

Janis Weddle

Negative

Comments
Submitted

6

Public Utility District No. 2 of
Grant County, Washington

LeRoy Patterson

None

N/A

6

Sacramento Municipal Utility
District

Jamie Cutlip

Negative

Comments
Submitted

6

Salt River Project

Bobby Olsen

None

N/A

6

Santee Cooper

Michael Brown

Abstain

N/A

6

Seattle City Light

Charles Freeman

Negative

Comments
Submitted

6

Seminole Electric
Cooperative, Inc.

Trudy Novak

None

N/A

6

Snohomish County PUD No.
1

Franklin Lu

None

N/A

6

Southern Company Southern Company
Generation and Energy
Marketing

Jennifer Sykes

Negative

Comments
Submitted

6

Tacoma Public Utilities
(Tacoma, WA)

Rick Applegate

Negative

Comments
Submitted

6

Talen Energy Marketing, LLC

Jennifer
Hohenshilt

None

N/A

6

TECO - Tampa Electric Co.

Benjamin Smith

Negative

Comments
Submitted

6

Tennessee Valley Authority

Marjorie Parsons

Abstain

N/A

6

WEC Energy Group, Inc.

Scott Hoggatt

Negative

Comments
Submitted

6

Westar Energy

Megan Wagner

Negative

Comments
Submitted

7

Exxon Mobil

Jay Barnett

None

N/A

Joe Tarantino

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Segment

Organization

Page 17 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

7

Luminant Mining Company
LLC

Stewart Rake

Affirmative

N/A

8

David Kiguel

David Kiguel

Affirmative

N/A

8

Massachusetts Attorney
General

Frederick Plett

Affirmative

N/A

8

Roger Zaklukiewicz

Roger
Zaklukiewicz

Affirmative

N/A

9

Commonwealth of
Massachusetts Department
of Public Utilities

Donald Nelson

Affirmative

N/A

10

Midwest Reliability
Organization

Russel Mountjoy

Affirmative

N/A

10

New York State Reliability
Council

ALAN
ADAMSON

Affirmative

N/A

10

Northeast Power
Coordinating Council

Guy V. Zito

Affirmative

N/A

10

ReliabilityFirst

Anthony
Jablonski

Affirmative

N/A

10

SERC Reliability Corporation

David Greene

Affirmative

N/A

10

Texas Reliability Entity, Inc.

Rachel Coyne

Negative

Comments
Submitted

10

Western Electricity
Coordinating Council

Steven Rueckert

None

N/A

Previous

1

Next

Showing 1 to 290 of 290 entries

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Standards Announcement

Project 2016-02 Modifications to CIP Standards
CIP-012-1
Formal Comment Period Open through September 11, 2017
Ballot Pools Forming through August 25, 2017
Now Available

A 45-day formal comment period for CIP-012-1 - Cyber Security – Control Center Communication
Networks is open through 8 p.m. Eastern, Monday, September 11, 2017.
Commenting

Use the electronic form to submit comments. If you experience any difficulties using the electronic form,
contact Wendy Muller. An unofficial Word version of the comment form is posted on the project page.
Ballot Pools

Ballot pools are being formed through 8 p.m. Eastern, Friday, August 25, 2017. Registered Ballot
Body members may join the ballot pools here.
If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential error
messages, or system lock-out, contact NERC IT support directly at https://support.nerc.net/ (Monday
– Friday, 8 a.m. - 5 p.m. Eastern).
•

Passwords expire every 6 months and must be reset.

•

The SBS is not supported for use on mobile devices.

•

Please be mindful of ballot and comment period closing dates. We ask to allow at least 48
hours for NERC support staff to assist with inquiries. Therefore, it is recommended that users try
logging into their SBS accounts prior to the last day of a comment/ballot period.

Next Steps

An initial ballot for the standard and non-binding poll of the associated Violation Risk Factors and
Violation Severity Levels will be conducted September 1-11, 2017.

For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, Katherine Street (via email) or at (404) 446-9702 or Mat Bunch (via
email) or at (404) 446-9785.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | July-September, 2017

2

Comment Report
Project Name:

2016-02 Modifications to CIP Standards | CIP-012-1

Comment Period Start Date:

7/27/2017

Comment Period End Date:

9/11/2017

Associated Ballots:

2016-02 Modifications to CIP Standards CIP-012-1 IN 1 ST

There were 81 sets of responses, including comments from approximately 207 different people from approximately 139 companies
representing 10 of the Industry Segments as shown in the table on the following pages.

Questions
1. Requirement R1: The SDT drafted CIP-012-1 Requirement R1 to meet the mandatory requirement for the Responsible Entity to develop one
or more documented plan(s) to mitigate the risk of the unauthorized disclosure or modification of data used for Operational Planning
Analysis, Real-time Assessment, and Real-time monitoring data while being transmitted between Control Centers. Do you agree with this
revision? If not, please provide the basis for your disagreement and an alternate proposal.

2. Requirement R1: The SDT seeks comment on the need to scope sensitive BES data as it applies to Operational Planning Analysis, Realtime Assessment, and Real-time monitoring. Do you agree with scoping CIP-012-1 Requirement R1 in this manner? Please provide comment
in support of your response.

3. Implementation Plan: The SDT revised the Implementation Plan such that the standard and NERC Glossary terms are effective the first day
of the first calendar quarter that is twelve (12) calendar months after the effective date of the applicable governmental authority’s order
approving the standard, or as otherwise provided for by the applicable governmental authority. Do you agree with this proposal? If you agree
with the proposed implementation time period, please note the actions you will take that require this amount of time to complete. If you think
an alternate implementation time period is needed – shorter or longer - please propose an alternate implementation plan and provide a
detailed explanation of actions and time needed to meet the implementation deadline.

4. The SDT believes proposed CIP-012-1 provides entities with flexibility to meet the reliability objectives in a cost effective manner. Do you
agree? If you do not agree, or if you agree but have suggestions for improvement to enable more cost effective approaches, please provide
your recommendation and, if appropriate, technical justification.

5. If you have additional comments on the proposed CIP-012-1 – Cyber Security -- Communication Networks drafted in response to the FERC
directive that you have not provided in response to the questions above, please provide them here.

Organization
Name
FirstEnergy FirstEnergy
Corporation

Brandon
McCormick

Name

Aaron
Ghodooshim

Brandon
McCormick

Segment(s)

3

Region

RF

FRCC

Group Name Group Member
Name

Group
Group
Member
Member
Organization Segment(s)

FirstEnergy
Corporation

Aaron
Ghdooshim

FirstEnergy FirstEnergy
Corporation

4

RF

Aubrey Short

FirstEnergy FirstEnergy
Corporation

1

RF

Theresa Ciancio FirstEnergy FirstEnergy
Corporation

3

RF

Robert Loy

FirstEnergy FirstEnergy
Solutions

5

RF

Ann Ivanc

FirstEnergy FirstEnergy
Solutions

6

RF

Tim Beyrle

City of New
4
Smyrna
Beach Utilities
Commission

FRCC

Jim Howard

Lakeland
Electric

5

FRCC

Lynne Mila

City of
Clewiston

4

FRCC

Javier Cisneros Fort Pierce
Utilities
Authority

3

FRCC

Randy Hahn

Ocala Utility
Services

3

FRCC

Don Cuevas

Beaches
Energy
Services

1

FRCC

Jeffrey
Partington

Keys Energy
Services

4

FRCC

Tom Reedy

Florida
Municipal
Power Pool

6

FRCC

Steven
Lancaster

Beaches
Energy
Services

3

FRCC

FMPA

Group
Member
Region

Tennessee
Valley
Authority

Duke Energy

Brian Millard

1,3,5,6

Colby Bellville 1,3,5,6

SERC

FRCC,RF,SERC

Tennessee
Valley
Authority

Mike Blough

Kissimmee
Utility
Authority

5

FRCC

Chris Adkins

City of
Leesburg

3

FRCC

Ginny Beigel

City of Vero
Beach

3

FRCC

Scott, Howell D. Tennessee
Valley
Authority

1

SERC

Grant, Ian S.

Tennessee
Valley
Authority

3

SERC

Thomas, M. Lee Tennessee
Valley
Authority

5

SERC

Parsons,
Marjorie S.

Tennessee
Valley
Authority

6

SERC

Duke Energy

1

RF

Duke Energy

3

FRCC

Dale Goodwine Duke Energy

5

SERC

Greg Cecil

Duke Energy

6

RF

Joseph
DePoorter

Madison Gas
& Electric

3,4,5,6

MRO

Larry Heckert

Alliant Energy 4

MRO

Amy Casucelli

Xcel Energy

1,3,5,6

MRO

Michael
Brytowski

Great River
Energy

1,3,5,6

MRO

Jodi Jensen

Western Area 1,6
Power
Administration

MRO

Kayleigh
Wilkerson

Lincoln
Electric
System

1,3,5,6

MRO

Mahmood Safi

Omaha Public 1,3,5,6
Power District

MRO

Brad Parret

Minnesota
Powert

1,5

MRO

Terry Harbour

MidAmerican
Energy
Company

1,3

MRO

Duke Energy Doug Hils
Lee Schuster

MRO

Dana Klem

1,2,3,4,5,6

MRO

MRO NSRF

SERC
Reliability
Corporation

David Greene 10

SERC

Con Ed Dermot Smyth 5
Consolidated
Edison Co. of
New York

NPCC

Seattle City
Light

WECC

Santee
Cooper

Ginette
Lacasse

1,3,4,5,6

James Poston 3

SERC CIPC

Con Edison

Tom Breene

Wisconsin
3,5,6
Public Service
Corporation

MRO

Jeremy Voll

Basin Electric 1
Power
Cooperative

MRO

Kevin Lyons

Central Iowa
Power
Cooperative

1

MRO

Mike Morrow

Midcontinent
ISO

2

MRO

Bill Peterson

SERC RRO

10

SERC

Mike Hagee

SERC RRO

10

SERC

SERC CIPC

Various

1,2,5,9

SERC

Dermot Smyth

Con Edison
Company of
New York

1,3,5,6

NPCC

Edward Bedder Orange &
Rockland
Seattle City
Light Ballot
Body

Santee
Cooper

NPCC

Pawel Krupa

Seattle City
Light

1

WECC

Hao Li

Seattle City
Light

4

WECC

Bud (Charles)
Freeman

Seattle City
Light

6

WECC

Mike Haynes

Seattle City
Light

5

WECC

Michael Watkins Seattle City
Light

1,4

WECC

Faz Kasraie

Seattle City
Light

5

WECC

John Clark

Seattle City
Light

6

WECC

Tuan Tran

Seattle City
Light

3

WECC

Laurrie
Hammack

Seattle City
Light

3

WECC

Rene' Free

Santee
Cooper

1

SERC

Rodger Blakely Santee
Cooper

1

SERC

Chris Jimenez

1

SERC

Santee
Cooper

Lower
Colorado
River
Authority

Michael Shaw 1

Southern
Pamela
Company Hunter
Southern
Company
Services, Inc.

Eversource
Energy

Northeast
Power
Coordinating
Council

Quintin Lee

Ruida Shu

1,3,5,6

LCRA
Compliance

SERC

1

1,2,3,4,5,6,7,8,9,10 NPCC

Southern
Company

Eversource
Group

Troy Lee

Santee
Cooper

1

SERC

Tom Abrams

Santee
Cooper

1

SERC

Jennifer
Richards

Santee
Cooper

1

SERC

Stony Martin

Santee
Cooper

1

SERC

Glenn Stephens Santee
Cooper

1

SERC

Tom Perry

1

SERC

Teresa Cantwell LCRA

1

Texas RE

Dixie Wells

LCRA

5

Texas RE

Michael Shaw

LCRA

6

Texas RE

Katherine
Prewitt

Southern
1
Company
Services, Inc.

SERC

R. Scott Moore

Alabama
Power
Company

3

SERC

William D.
Shultz

Southern
Company
Generation

5

SERC

Jennifer G.
Sykes

Southern
Company
Generation
and Energy
Marketing

6

SERC

Timothy Reyher Eversource
Energy

5

NPCC

Mark Kenny

Eversource
Energy

3

NPCC

Northeast
Power
Coordinating
Council

10

NPCC

New
Brunswick
Power

2

NPCC

Wayne Sipperly New York
Power
Authority

4

NPCC

RSC no Con- Guy V. Zito
Edison and
Dominion
Randy
MacDonald

Santee
Cooper

Glen Smith

Dominion Dominion

Sean Bodkin

6

Dominion

Entergy
Services

4

NPCC

Brian Robinson Utility
Services

5

NPCC

Bruce Metruck

New York
Power
Authority

6

NPCC

Alan Adamson

New York
State
Reliability
Council

7

NPCC

Edward Bedder Orange &
Rockland
Utilities

1

NPCC

David Burke

3

NPCC

Michele Tondalo UI

1

NPCC

Laura Mcleod

NB Power

1

NPCC

Michael
Schiavone

National Grid

1

NPCC

Michael Jones

National Grid

3

NPCC

David
Ramkalawan

Ontario Power 5
Generation
Inc.

NPCC

Quintin Lee

Eversource
Energy

1

NPCC

Kathleen
Goodman

ISO-NE

2

NPCC

Greg Campoli

NYISO

2

NPCC

Silvia Mitchell

NextEra
6
Energy Florida Power
and Light Co.

NPCC

Paul
Malozewski

Hydro One
3
Networks, Inc.

NPCC

Sylvain
Clermont

Hydro Quebec 1

NPCC

Helen Lainis

IESO

2

NPCC

Chantal Mazza

Hydro Quebec 2

NPCC

Connie Lowe

Dominion Dominion

NA - Not
Applicable

Orange &
Rockland
Utilities

3

Resources,
Inc.

Colorado
Springs
Utilities

Southwest
Power Pool,
Inc. (RTO)

Resources,
Inc.

Shannon Fair 1,3,5,6

Shannon
Mickens

2

Colorado
Springs
Utilities

SPP RE

Lou Oberski

Dominion Dominion
Resources,
Inc.

5

NA - Not
Applicable

Larry Nash

Dominion 1
Dominion
Virginia Power

NA - Not
Applicable

Kaleb Brimhall

Colorado
Springs
Utilities

5

WECC

Charlie Morgan Colorado
Springs
Utilities

3

WECC

Shawna Speer

Colorado
Springs
Utilities

1

WECC

Shannon Fair

Colorado
Springs
Utilities

6

WECC

Southwest
Power Pool
Inc.

2

SPP RE

Deborah
McEndaffer

Midwest
Energy, Inc.

NA - Not
Applicable

SPP RE

Don Schmit

Nebraska
Public Power
District

5

SPP RE

Louis Guidry

Cleco
Corporation

1,3,5,6

SPP RE

Robert Hirchak

Cleco
Corporation

6

SPP RE

Marty Paulk

Cleco
Corporation

1,3,5,6

SPP RE

3

SPP RE

SPP
Shannon
Standards
Mickens
Review Group

Michelle Corley Cleco
Corporation
Robert Gray

Board of
NA - Not
Public Utilities Applicable

SPP RE

Ron Spicer

EDP
Renewables

NA - Not
Applicable

SPP RE

Steven Keller

Southwest
Power Pool

2

SPP RE

Laura Cox

Westar
Energy

5

SPP RE

PPL Shelby Wade
Louisville Gas
and Electric
Co.

PSEG

Sheranee
Nedd

3,5,6

1,3,5,6

ACES Power Warren Cross 1,3,4,5
Marketing

RF,SERC

NPCC,RF

Louisville Gas Charles Freibert
and Electric
Company and
Kentucky
Utilities
Dan Wilson
Company

PSEG REs

PPL 3
Louisville Gas
and Electric
Co.

SERC

PPL 5
Louisville Gas
and Electric
Co.

SERC

Linn Oelker

PPL 6
Louisville Gas
and Electric
Co.

SERC

Tim Kucey

PSEG - PSEG 5
Fossil LLC

RF

Karla Jara

PSEG Energy 6
Resources
and Trade
LLC

RF

Jeffrey Mueller

PSEG - Public 3
Service
Electric and
Gas Co

RF

Joseph Smith

PSEG - Public 1
Service
Electric and
Gas Co

RF

MRO,RF,SERC,SPP ACES
Arizona Electric AEPC
RE,Texas
Standards
Power
RE,WECC
Collaborators Cooperative,
Inc.

1

WECC

Hoosier Energy HE
Rural Electric
Cooperative,
Inc.

1

RF

Sunflower
Electric Power
Corporation

SEPC

1

SPP RE

Rayburn
RCEC
Country Electric
Cooperative

3

SPP RE

Old Dominion
Electric
Cooperative

ODEC

3,4

SERC

Brazos Electric
Power
Cooperative,
Inc.

BRAZOS

1,5

Texas RE

Southern
Maryland
Electric
Cooperative

SMECO

3

RF

North Carolina
Electric
Membership
Corporation

NCEMC

3,4,5

SERC

Central Iowa
Power
Cooperative

CIPCO

1

MRO

East Kentucky
Power
Cooperative

EKPC

1,3

SERC

4

RF

Buckeye Power, BUCK
Inc.

1. Requirement R1: The SDT drafted CIP-012-1 Requirement R1 to meet the mandatory requirement for the Responsible Entity to develop one
or more documented plan(s) to mitigate the risk of the unauthorized disclosure or modification of data used for Operational Planning
Analysis, Real-time Assessment, and Real-time monitoring data while being transmitted between Control Centers. Do you agree with this
revision? If not, please provide the basis for your disagreement and an alternate proposal.
Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer

No

Document Name
Comment
The term “transmitted between Control Centers” is not clear. Dominion is concerned that the demarcation point between Control Centers is unclear and
could cause confusion? A second concern is the potential reliability gap created by the lack of a clarification on whether internal Control Center
communications networks are considered to be part of the transmission of data, or if only external communications between entities qualify as
transmission data?
Likes

0

Dislikes

0

Response

George Brown - Acciona Energy North America - 5
Answer

No

Document Name
Comment
The term “plan” is misleading in this context. A “plan” is more analogous to the development of a project that has actions to achieve a result by specific
date; similar to an implementation plan for a NERC Reliability Standard.
If it was the intention of the SDT to require a Responsible Entity to have a documented set of requirements to protect the sensitive BES data transmitted
between the Control Centers then the term “policy” would be more appropriate. A policy is interpreted to be more dynamic and ongoing throughout the
lifetime of the requirement. Additionally, as cyber security technology is constantly changing and evolving, a policy would allow for a definite course of
action for a Responsible Entity to protect sensitive BES data transmitted between the Control Centers.
Likes

0

Dislikes

0

Response

Joe Tarantino - Joe Tarantino On Behalf of: Arthur Starkovich, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Beth Tincher, Sacramento
Municipal Utility District, 4, 1, 5, 6, 3; Jamie Cutlip, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Kevin Smith, Balancing Authority of
Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Susan Oto, Sacramento Municipal Utility District, 4, 1,
5, 6, 3; - Joe Tarantino

Answer

No

Document Name
Comment

It is an overwhelming task to differentiate what is or what isn’t confidential communication data over data links between Control
Centers. As such, it is recommended that ALL data transmitted between Control Center be protected. The standards should just address all
data communication between control centers. Technologies such as encryption are generally implemented by link, not communication
type.
Likes

0

Dislikes

0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer

No

Document Name
Comment
The IESO agrees with the creation of a new standard, rather than expanding CIP-003, CIP-005 and/or CIP-006 requirements to provide new controls
over physical communication links. Specifically, the IESO commends the SDT for recognizing that not all utilities own or control their own physical
communications links.
The IESO offers the following comments and recommendations.
•

R1. For data used for Operational Planning Analysis, Real-time Assessments, and Real-time monitoring, as documented by a Reliability
Coordinator, Transmission Operator, or Balancing Authority, the Responsible Entity shall develop one or more documented plan(s) to mitigate
the risk of the unauthorized disclosure or modification of the data while it is being transmitted between Control Centers. This excludes oral
communications, regardless of transport means.

•

The note to R1 concerning the existence of a Control Center or specified data should be a dealt with in Section 4 – Applicability part of the
Standard. This would eliminate the need for this to be discussed as part of the RSAW.

•

Recommend that it be clarified whether this is a standalone Standard similar to CIP-014 or if it is intended to define the scope of applicable
systems to be protected under CIP-003 thru CIP-011.

•

In order to evaluate the extent and kind of obligation involved, the definition of between control centers needs to be clearer with regard to the
communication link. The Standard should address the proper demarcation points for obligation to show implementation and compliance. To
clearly define the obligation of Responsible Entities, the required plan should include identification of the demarcation points. Information is also
needed on the explicit agreements required on each end of the physical communication link to arrange and identify such demarcation. Where
there is disagreement on how protections are to be applied between two or more Responsible Entities, what is the arbitration process to resolve
these disagreements?

•

How is the situation handled where a Responsible Entity (e.g., an RC) is receiving information from a third-party provider that is aggregating and
submitting data on behalf of one or more Responsible Entities (e.g., a TOP)? What is the identification of the demarcation points? In reading the
standard, it does not appear that the connection to the third-party provider is in scope since they are not a Responsible Entity or even registered

with NERC. The same situation may be present for entities that use an outsourced data center provider. The question is also relevant for the
data that is provided to regulatory agencies that are not bound by CIP Standards.
Likes

2

Dislikes

Hydro One Networks, Inc., 1, Farahbakhsh Payam; Hydro One Networks, Inc., 3, Malozewski Paul
0

Response

Dermot Smyth - Con Ed - Consolidated Edison Co. of New York - 5, Group Name Con Edison
Answer

No

Document Name
Comment
The scope of the term “data” is unclear. Does “data” apply to all data or just machine to machine (e.g. automated) communications? If it is all data
would emails/ftp/etc. be in scope?
Likes

0

Dislikes

0

Response

Brandon McCormick - Brandon McCormick On Behalf of: Ginny Beigel, City of Vero Beach, 3; Lynne Mila, City of Clewiston, 4; Tom Reedy,
Florida Municipal Power Pool, 6; - Brandon McCormick, Group Name FMPA
Answer

No

Document Name
Comment
FMPA does not agree with the revision of Requirement 1 (R1) because the obligation is not clear. The R1 note - “If the Responsible Entity does not
have a Control Center or it does not transmit the type of data specified in Requirement R1 of CIP-012-1 between two Control Centers, the requirements
in CIP-012-1 would not apply to that entity.”- should be in the Section 4 Applicability. This would eliminate the need for this to be discussed as part of
the RSAW.
In order to evaluate the extent and kind of obligation involved with R1, the phrase “transmitted between two control centers,” needs to be clearer. FMPA
believes that there should be more clarity or identification on the demarcation points of the link being protected.
Both TOP-003 and IRO-010 have a requirement that there be a mutually agreeable security protocol. It is not clear why a new standard needs to be
developed to address this same issue. The SDT should consider modifying TOP-003 and IRO-010 if these standards do not provide adequate language
to meet Order No. 822’s concerns.
Likes

0

Dislikes
Response

0

Frank Pace - Central Hudson Gas & Electric Corp. - 1
Answer

No

Document Name
Comment
There is a lack of language within the Requirement that specifies the demarcation point for compliance between applicable Control Centers.
Likes

0

Dislikes

0

Response

Donald Lock - Talen Generation, LLC - 5
Answer

No

Document Name
Comment
The applicability of the expression, “between Control Centers,” does not appear to be restricted to transmittals between Control Centers owned by a
single entity; exchanges between GO and TO/TOP Control Centers would be covered also, for example. This makes sense as regards achieving a high
degree of security, but could create confusion regarding who is responsible for inter-entity transmittals. CIP-012-1 should state that GO/GOP
obligations for inter-entity exchanges between Control Centers are fulfilled if they follow the data specifications provided by the other party (ref. IRO010-2 and TOP-003-3).
Likes

0

Dislikes

0

Response

David Rivera - New York Power Authority - 3
Answer

No

Document Name
Comment
1. The Note to R1 concerning the existence of a Control Center or specified data should be a dealt with in Section 4 – Applicability. This would
eliminate the need for this to be discussed as part of the RSAW.
2. In order to evaluate the extent and kind of obligation involved, the definition of between control centers needs to be more clear with regard to
the communication link. What are the demarcation points for obligation to show compliance?
3. Request clarification does the 15 minute impact CIP-002 identification of BES Cyber Systems affect the applicability of CIP-012?
Likes

0

Dislikes

0

Response

Philip Huff - Arkansas Electric Cooperative Corporation - 3
Answer

No

Document Name
Comment
The Requirement should only permit the option to logically protect the data during transmission or at least remove the explicit options to physically
protect the data. We understand the Requirement is consistent with CIP-006 R1.10, but this Requirement addresses communication lines within the
same facility, and for which physical protection is possible. Cryptography is the only mechanism available to protect data across geographically
dispersed Control Centers. Stating other options is confusing and has a strong potential to guide the industry toward ineffective solutions.
However, if the intent is to allow physical protection of communications of Control Centers in the same geographical location, then make it clear in the
Technical Guidelines the scenarios and alternative solutions the drafters had in mind.
Likes

0

Dislikes

0

Response

Jennifer Hohenshilt - Talen Energy Marketing, LLC - 6
Answer

No

Document Name
Comment
The applicability of the expression, “between Control Centers,” does not appear to be restricted to transmittals between Control Centers owned by a
single entity; exchanges between GO and TO/TOP Control Centers would be covered also, for example. This makes sense as regards achieving a high
degree of security, but could create confusion regarding who is responsible for inter-entity transmittals. CIP-012-1 should state that GO/GOP
obligations for inter-entity exchanges between Control Centers are fulfilled if they follow the data specifications provided by the other party (ref. IRO010-2 and TOP-003-3).
Likes

0

Dislikes

0

Response

Dana Klem - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO NSRF
Answer
Document Name

No

Comment
As mentioned by the SDT, FERC directs that “…require responsible entities to implement controls to protect, at a minimum, communication links and
sensitive bulk electric system data communicated between bulk electric system Control Centers…”. First, having a plan does not add to the reliability of
protecting said data. This is an unwarranted layer of compliance that is not needed. Everything does not need a plan in order to be
protected. Recommend that R1 be written in parallel to the FERC directive, which does not require a plan (per the SDTs Consideration of Issues and
Directives).
If “Plan” is maintained in CIP-012-1 then, the SDT should explain what is meant by having a Plan? Per CIP-003-6 it states, The terms program and plan
are sometimes used in place of documented processes where it makes sense and is commonly understood. For example, documented processes
describing a response are typically referred to as plans (i.e., incident response plans and recovery plans). Likewise, a security plan can describe an
approach involving multiple procedures to address a broad subject matter. Is a plan the template document which is used throughout our Standards or
is it a set of controls that show that the data is being protected per R1? The NSRF does not understand why a Plan is needed when the data is being
protected by physical or electronic means. If a Plan is required, then all the Plan is going to say is that the cabling that transfers data is in a protected
conduit (or other means) between Control Centers.
Secondly, The NSRF questions why the SDT is not in line with the FERC Order to “…protect …data…” but the proposed R1 states to “…mitigate the
risk of unauthorized disclosure or modification of data…”?
R1 should be rewritten to state: “The responsible entity shall have controls (or other understandable words) in place to protect against the unauthorized
disclosure or modification of BES data used for Operational Planning Analysis, Real-time Assessments, and Real-time monitoring while being
transmitted between BES Control Centers. This excludes oral communications”. Please note that the word “BES” is needed within R1 regardless of it
our proposed rewrite is accepted or not.
Likes

0

Dislikes

0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

No

Document Name
Comment
Texas RE appreciates the Standard Drafting Team’s (SDT) efforts to develop a workable approach to mitigate the risk of unauthorized disclosure or
modification of certain categories of Control Center communications. However, Texas RE is concerned that the proposed CIP-012-1 R1 does not fully
satisfy the directives established by the Federal Energy Regulatory Commission (FERC) in FERC Order No. 822. Texas RE is likewise concerned that
the proposed CIP-012-1 may not adequately address third-party entities handling sensitive data between Control Centers in the Texas RE region.

First, throughout its discussion concerning new requirements for protecting Control Center communications, FERC emphasized that additional
protections were required to protect both the “integrity and availability of sensitive bulk electric system data.” FERC Order No. 822, P. 54. FERC made
clear that this involved, at a minimum, two discrete actions. First, FERC stressed that entities should implement controls to protect the physical
communications links transmitting sensitive data between Control Centers. Second, FERC noted that the sensitive data itself needed to be protected to
ensure its accuracy and consistency. In issuing the directive underpinning this rulemaking, FERC stated: “we adopt the NOPR proposal and direct that
NERC . . . develop modifications to the CIP Reliability Standards to require responsible entities to implement controls to protect, at a minimum,

communications links and sensitive bulk electric system data communicated between bulk electric system Control Centers . . . FERC Order No. 822, P.
53 (emphasis added).

FERC made it clear that protections should apply to both communication links and sensitive data. However, the proposed draft of CIP-012-1 R1
potentially applies only to physical protections for communications links or to logical protections for data during its transmission. That is, responsible
entities could simply elect to plan and implement physical protections for communications links. This would “mitigate” the risk of an unauthorized
disclosure or modification of data using one of the delineated methods. As such, the responsible entity would potentially be compliant with the Standard
without proposing or implementing any logical protections for sensitive data during its transmission. This appears counter to FERC’s intent to protect
“both the integrity and availability of sensitive bulk electric system data.” FERC Order No. 822, P. 54.

Second, Texas RE is concerned that the proposed CIP-012-1 standard may result in confusion, particularly among Generation Operators with Control
Centers subject to the standard regarding the scope of their compliance obligations or, alternatively, may inadvertently result in a significant reliability
gap given the structure of the ERCOT market. In ERCOT, generators do not communicate directly with the regional Reliability Coordinator
(ERCOT). Instead, generators are required to communicate through designated entities known as Qualified Scheduling Entities (QSEs). In many
instances, these QSEs are third-party entities. Within the NERC regulatory construct, Generator Operators have delegated certain NERC compliance
functions to these entities, including providing data used for Operational Planning Analysis, Real-time Assessments, and Real-time
monitoring. Critically, Generator Operators remain responsible for all compliance obligations associated with QSE activities in the ERCOT region.

In light of this market and regulatory framework, Texas RE interprets the proposed draft of CIP-012-1 to likewise require Generator Operators
possessing Control Centers to take steps to mitigate the risk of unauthorized data disclosures at every step along the communication chain between its
Control Center and the ERCOT Control Center, including steps to protect this data at third-party intermediary QSEs. Otherwise, the proposed draft of
CIP-012-1 would result in a significant reliability gap as QSE communications links and data passing from the QSE to ERCOT could be potentially
unsecure. Given this fact, Generator Operators will likely need to take steps to ensure that their third-party QSEs have accorded designated sensitive
data appropriate protections, which could in turn require incorporating such requirements into QSE agreements or other steps. Texas RE requests the
SDT clarify that communications between QSEs (or equivalent in other Regions) and the RC are subject to CIP-012-1 requirements and that
Responsible Entities must take steps to address mitigate the risk of unauthorized data disclosures for these communications as well in order to ensure
that Responsible Entities have sufficient notice of these compliance obligations.
Likes

0

Dislikes

0

Response

Alice Wright - Arkansas Electric Cooperative Corporation - 4
Answer

No

Document Name

2016-02_CIP-012-1_Comment_Form_07272017-AECC Comments.pdf

Comment
See attachment
Likes
Dislikes

0
0

Response

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer

No

Document Name
Comment
See APPA Comments.
Likes

0

Dislikes

0

Response

James Poston - Santee Cooper - 3, Group Name Santee Cooper
Answer

No

Document Name
Comment
Recommend removing “Operational Planning Analysis” from this requirement. Operational Planning Analysis is not Real-time data and would not affect
the BES within 15 minutes. The TOP-003-3 Standard currently requires a mutually agreeable security protocol for sharing of data required for
Operational Planning Analyses.
Likes

0

Dislikes

0

Response

Marty Hostler - Northern California Power Agency - 5
Answer

No

Document Name
Comment
NCPA does not feel CIP-012-1 is needed as both TOP-003 R5 and IRO-010 R3 require Registered Entities (REs) to use a mutually agreeable security
protocol. The SDT should consider modifying TOP-003 and IRO-010 if these standards do not provide adequate language to meet Order No. 822’s
concerns. Also please refer to other APPA, TAPs, and Utility Services comments.
Likes
Dislikes

0
0

Response

Dennis Sismaet - Northern California Power Agency - 6
Answer

No

Document Name
Comment
NCPA does not feel CIP-012-1 is needed as both TOP-003 R5 and IRO-010 R3 require Registered Entities (REs) to use a mutually agreeable security
protocol. The SDT should consider modifying TOP-003 and IRO-010 if these standards do not provide adequate language to meet Order No. 822’s
concerns. Also please refer to other APPA, TAPs, and Utility Services comments.
Likes

0

Dislikes

0

Response

David Gordon - Massachusetts Municipal Wholesale Electric Company - 5
Answer

No

Document Name
Comment
The applicability section of the Standard should specify that the requirements only apply to entities with Control Centers. This would allow the
elimination of the note to R1 and would simplify the ERO monitoring process.
Likes

0

Dislikes

0

Response

Heather Morgan - EDP Renewables North America LLC - 5
Answer

No

Document Name
Comment
What does, “Physically protecting the communication links transmitting the data,” mean? A Registered Entity is able to physically protect its end point,
but is not able to physically protect the communication link for the entire communication link. Please define “logical protection” to provide clarification for
entities for implementation and compliance oversight.

What does, “Using an equally effective method to mitigate the risk of unauthorized disclosure or modification of the data” mean?
Likes

0

Dislikes

0

Response

Quintin Lee - Eversource Energy - 1, Group Name Eversource Group
Answer

No

Document Name
Comment
The Purpose section of CIP-012-1 adds the need to protect the confidentiality of data which is out of Scope of FERC order 822. Although it is
recognized that the SDT is not limited to just FERC orders, adding need to protect the confidentiality of data does not add reliability if the data is being
protected per CIP-012-1 R1.

Likes

0

Dislikes

0

Response

Aaron Austin - AEP - 3
Answer

No

Document Name
Comment
AEP suggests that a new requirement(s) be added to establish a hierarchy for REs that requires entities at the top with the most risk to set
the communications security protocols. And, modify the existing R1 to require REs to have plans that follow the protocols set by the entities
identified in the new requirement(s).
Likes

0

Dislikes

0

Response

Nicolas Turcotte - Hydro-Qu?bec TransEnergie - 1
Answer
Document Name

No

Comment
1. The Note to R1 concerning the existence of a Control Center or specified data should be a dealt with in Section 4 – Applicability. This would
eliminate the need for this to be discussed as part of the RSAW.
2. In order to evaluate the extent and kind of obligation involved, the definition of between control centers needs to be more clear with regard to
the communication link. What are the demarcation points for obligation to show compliance?
3. Request clarification does the 15 minute impact CIP-002 identification of BES Cyber Systems affect the applicability of CIP-012?
4. Concerns exist with the relationships regarding implementation of CIP-012 with other NERC Standards such as IRO, TOP, CIP-006 R1 Part1.10
Likes

0

Dislikes

0

Response

Lona Calderon - Salt River Project - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
SRP requests the SDT consider differentiating requirements for Control Center communications within an entity from those for Control Center
communications between entities. Because data being sent for TOP-003 and IRO-010 traverses over the ICCP network maintained by a carrier, entities
cannot provide physical protections for communication of this data from end to end. In this case, protecting the confidentiality and integrity can only be
done through encryption. However, since no one utility owns the hardware end to end on the ICCP network, site to site encryption cannot be
implemented. The only options available would be application layer encryption or transport layer encryption utilizing IEC 62351-4 Secure ICCP.
For IRO-010 data, the RC in the Western Interconnect requires real-time data to be sent every 10 seconds. Likewise, For TOP-003 data, SRP is
required to send and receive real-time data every 10 seconds to and from various other entities on the ICCP network within the Western Interconnect. It
is unclear the amount of latency that may be added or amount of computing resources required to encrypt and decrypt this data every 10 seconds.
Additionally, the RC would be receiving this data from all applicable utilities in the Western Interconnect. If all entities encrypt and send data every 10
seconds, it is unclear how much latency would be added and computing resources would be required by the RC to decrypt the large amount data. It is
also unclear how the added latency would affect the real-time operations of the Bulk Electric System. IRO and TOP data specification changes may be
necessary to address delays in data due to latency, or process/procedure changes to mitigate effects on real-time operations. SRP suggests performing
a study or survey to determine how much data is being sent and received and what the effects would be from the added latency and the amount of extra
computing resources required.
SRP requests clarification on the exclusion of oral communications. Additionally, SRP suggests the exclusion for oral communications be expanded to
also exclude electronic mail.
SRP requests clarification for what would be accepted as physical security either in the measures or Technical Rationale and Justification. SRP also
requests clarification of what equally effective methods are in the measures or Technical Rationale and Justification.
Likes
Dislikes

0
0

Response

Thomas Breene - WEC Energy Group, Inc. - 3
Answer

No

Document Name
Comment
As mentioned by the SDT, FERC directs that “…require responsible entities to implement controls to protect, at a minimum, communication links and
sensitive bulk electric system data communicated between bulk electric system Control Centers…”. First, having a plan does not add to the reliability of
protecting said data. This is an unwarranted layer of compliance that is not needed. Everything does not need a plan in order to be
protected. Recommend that R1 be written in parallel to the FERC directive, which does not require a plan (per the SDTs Consideration of Issues and
Directives).

If “Plan” is maintained in CIP-012-1 then, the SDT should explain what is meant by having a Plan? Per CIP-003-6 it states, The terms program and plan
are sometimes used in place of documented processes where it makes sense and is commonly understood. For example, documented processes
describing a response are typically referred to as plans (i.e., incident response plans and recovery plans). Likewise, a security plan can describe an
approach involving multiple procedures to address a broad subject matter. Is a plan the template document which is used throughout our Standards or
is it a set of controls that show that the data is being protected per R1? We do not understand why a Plan is needed when the data is being protected
by physical or electronic means. If a Plan is required, then all the Plan is going to say is that the cabling that transfers data is in a protected conduit (or
other means) between Control Centers.

Secondly, we question why the SDT is not in line with the FERC Order to “…protect …data…” but the proposed R1 states to “…mitigate the risk of
unauthorized discloser or modification of data…”?

R1 should be rewritten to state: “The responsible entity shall have controls (or other understandable words) in place to protect against the unauthorized
disclosure or modification of BES data used for Operational Planning Analysis, Real-time Assessments, and Real-time monitoring while being
transmitted between BES Control Centers. This excludes oral communications”. Please note that the word “BES” is needed within R1 regardless of it
our proposed rewrite is accepted or not.
Likes

0

Dislikes

0

Response

Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer
Document Name
Comment

No

Xcel Energy agrees with and support the comments submitted by the MRO Standards Review Forum (NSRF) in regards to this question.
Likes

0

Dislikes

0

Response

Russell Noble - Cowlitz County PUD - 3
Answer

No

Document Name
Comment
Cowlitz PUD supports the comments submitted by APPA.
Likes

0

Dislikes

0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Con-Edison and Dominion
Answer

No

Document Name
Comment
·
The Note to R1 concerning the existence of a Control Center or specified data should be a dealt with in Section 4 – Applicability. This would
eliminate the need for this to be discussed as part of the RSAW.

·
In order to evaluate the extent and kind of obligation involved, the definition of between control centers needs to be clearer with regard to the
communication link. What are the demarcation points for obligation to show compliance?

·

Request clarification does the 15 minutes impact CIP-002 identification of BES Cyber Systems affect the applicability of CIP-012?

Likes

0

Dislikes
Response

0

Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer

No

Document Name
Comment
ERCOT ISO signs on to the ITC SWG comments:
The ITC SWG agrees with the creation of a new standard, rather than expanding CIP-003, CIP-005 and/or CIP-006 requirements to provide new
controls over physical communication links. Specifically, the ITC SWG commends the SDT for recognizing that not all utilities own or control their own
physical communications links.
The ITC SWG offers the following comments and recommendations.
•

R1. For data used for Operational Planning Analysis, Real-time Assessments, and Real-time monitoring, as documented by a Reliability
Coordinator, Transmission Operator, or Balancing Authority, the Responsible Entity shall develop one or more documented plan(s) to mitigate
the risk of the unauthorized disclosure or modification of the data while it is being transmitted between Control Centers. This excludes oral
communications, regardless of transport means.

•

The note to R1 concerning the existence of a Control Center or specified data should be a dealt with in Section 4 – Applicability part of the
Standard. This would eliminate the need for this to be discussed as part of the RSAW.

•

Recommend that it be clarified whether this is a standalone Standard similar to CIP-014 or if it is intended to define the scope of applicable
systems to be protected under CIP-003 thru CIP-011.

•

In order to evaluate the extent and kind of obligation involved, the definition of between control centers needs to be clearer with regard to the
communication link. The Standard should address the proper demarcation points for obligation to show implementation and compliance. To
clearly define the obligation of Responsible Entities, the required plan should include identification of the demarcation points. Information is also
needed on the explicit agreements required on each end of the physical communication link to arrange and identify such demarcation. Where
there is disagreement on how protections are to be applied between two or more Responsible Entities, what is the arbitration process to resolve
these disagreements?

•

How is the situation handled where a Responsible Entity (e.g., an RC) is receiving information from a third-party provider that is aggregating and
submitting data on behalf of one or more Responsible Entities (e.g., a TOP)? What is the identification of the demarcation points? In reading the
standard, it does not appear that the connection to the third-party provider is in scope since they are not a Responsible Entity or even registered
with NERC. The same situation may be present for entities that use an outsourced data center provider. The question is also relevant for the
data that is provided to regulatory agencies that are not bound by CIP Standards.

Likes

0

Dislikes

0

Response

Marc Donaldson - Tacoma Public Utilities (Tacoma, WA) - 3
Answer
Document Name

No

Comment
Tacoma Power suuports the commetns of APPA
Likes

0

Dislikes

0

Response

sean erickson - Western Area Power Administration - 1
Answer

No

Document Name

Project 2016-02_CIP-012-1_NSRF Final.docx

Comment
WAPA agrees with the comments submitted by the NSRF (attached)
Likes

0

Dislikes

0

Response

Theresa Rakowsky - Puget Sound Energy, Inc. - 1
Answer

No

Document Name
Comment
See APPA Comments.
Likes

0

Dislikes

0

Response

Jack Cashin - American Public Power Association - 4
Answer
Document Name
Comment

No

APPA does not agree with the revision of Requirement 1 (R1) because the obligation is not clear. The R1 note - “If the Responsible Entity does not
have a Control Center or it does not transmit the type of data specified in Requirement R1 of CIP-012-1 between two Control Centers, the requirements
in CIP-012-1 would not apply to that entity.”- should be in the Section 4 Applicability. This would eliminate the need for this to be discussed as part of
the RSAW.
Evaluation of the extent and kind of obligation involved with R1, requires a clearer phrase than, “transmitted between two control centers.” Public power
believes that there should be more clarity or identification on the demarcation points of the link being protected.
Both TOP-003 and IRO-010 have a requirement that there be a mutually agreeable security protocol. It is not clear why a new standard needs to be
developed to address this same issue. The SDT should consider modifying TOP-003 and IRO-010 if these standards do not provide adequate language
to meet Order No. 822’s concerns.
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Lan Nguyen - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
CenterPoint Energy Houston Electric, LLC (“CenterPoint Energy”) recommends adding more clarification on the scope of the term “communication
links.” Data used for Operational Planning Analysis (OPA), Real-time Assessments (RTA), and Real-time monitoring (RTM) is collected based on an
Entity-issued data specification, per TOP-003-3 and IRO-010-2. This data is collected through a medium referred to as “data exchange capability,” as
required by TOP-001-4 (Requirements R19 and R20) as well as IRO-002-5 (Requirements R1 and R2).
OPA data is typically not transmitted via a communication link, and OPA data presents lower risk to operations than real-time telemetry data exchanged
via ICCP communication links between Control Centers. The systems used to transmit the OPA data can be located outside Control Centers and are
not considered BES Cyber Systems since they do not impact the Bulk Electric System within 15 minutes. Thus, CenterPoint Energy believes OPA data
should not be within the scope of Requirement R1.
In addition to removing OPA from Requirement R1, CenterPoint Energy recommends revising Requirement R1 to include the term “inter and intra
Control Center communication links.” This revision aligns with the language in Federal Energy Regulatory Commission (“FERC”) Order No. 822. The
proposed revised language is below:
“The Responsible Entity shall develop one or more documented plan(s) to mitigate the risk of the unauthorized disclosure or modification of data used
for Real-time Assessments and Real-time monitoring while being transmitted between inter and intra Control Centers communication links. This
excludes oral communications.”
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Warren Cross - ACES Power Marketing - 1,3,4,5 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Standards Collaborators

Answer

No

Document Name
Comment
(1) We agree with the direction of the requirement, however, the wording of the “one of more of” phrase seems to be in conflict with the intention of
physical and logical protection. How can you protect the data without physical security, and how can you ensure data integrity without logical
protection? The “one or more of” reference should be stricken.

(2) We recommend the addition of wording that clearly excludes Low impact Entities from compliance with this requirement. Would a low impact
control room which communicates with a Control Center be out of scope?

(3) We propose moving the compliance applicability note that follows Requirement R1 to the applicability section of the standard, particularly Section
4.2 Exemptions.
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Michael Puscas - ISO New England, Inc. - 2
Answer

No

Document Name
Comment
In order to evaluate the extent and kind of obligation involved, the definition of between control centers needs to be clearer with regard to the
communication link. What are the demarcation points for obligation to show compliance? Should there be explicit agreements with each end of the
communication link to arrange such demarcation? How should responsible entities deal with third parties involved with trust relationships in
communication links (i.e. telecommunications providers managing routers)?
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David Greyerbiehl - CMS Energy - Consumers Energy Company - 5
Answer
Document Name
Comment

No

The requirement as written does not provide clear definition on what type of data needs to be protected, and how exactly the physical/logical protection
approach should be accomplished.
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Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
BPA appreciates the revisions that the SDT has made based on industry feedback on the SAR.
BPA reiterates its position as documented in our SAR comments that CIP-012-1 is not necessary.
Alternate proposal #1: The objectives can be met by coordinating with existing standards such as CIP-003 and CIP-005.
If CIP-012-1 moves forward, there are areas requiring clarification. FERC Order No. 822 requires implementation of controls to protect, at a minimum,
communication links AND sensitive BES data communicated between BES Control Centers. However, the SDT is providing latitude to protect
communication links, data or both. If it is an “AND” as stated in Order No. 822, it is not always technically feasible to implement both controls to protect
communication links and sensitive BES data communicated between BES Control Centers.
Points of discussion:
Implementation of controls to protect the data:
•

Encryption may not be feasible due to availability concerns. (e.g., failure of encryption keys or latency problems with encryption for availability
requirements.)

Implementation of controls on communication links:
•

The use of the term communication links may be broadly interpreted and difficult to audit.

•

It may not be technically feasible to implement physical controls, for example:
o

on fiber optic cable on power lines

o

on a common carrier system where the links are unknown

o

for wireless communications - how does an entity physically protect the air between endpoints?

Additionally, entities and common carriers use a variety of media to carry traffic, and will undoubtedly use traffic shaping to maintain service levels:
routing becomes unpredictable; each packet could take a different route from point A to B.

If an entity owns the communication network from end to end, this is still a problem. Modern routing protocols will try to deliver packets over a system
with inoperable equipment, severed links, etc. The only remedy is to physically protect the entire communication system in advance of system faults to
satisfy CIP-012. If one packet traverses a link due to a system fault that is not protected – it would be a violation.
If FERC agrees with the SDT’s proposal of allowing the entity the latitude to protect the data, communication links or both, BPA believes the security
objective will not be met. BPA recommends placing controls on the data AND end points where technically feasible. However BPA recommends
moving R1.1 to a Technical Guidance, considering there are multiple implementation methods for controls on data and end points.
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James Anderson - CMS Energy - Consumers Energy Company - 1
Answer

No

Document Name
Comment
The requirement as written does not provide clear definition on what type of data need to be protected, and how exactly the physical/logical protection
approach should be accomplished by an entity.
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Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer

No

Document Name
Comment
Utility Services does not agree with the revision of Requirement 1 (R1) because the obligation is not clear. The R1 note - “If the Responsible Entity does
not have a Control Center or it does not transmit the type of data specified in Requirement R1 of CIP-012-1 between two Control Centers, the
requirements in CIP-012-1 would not apply to that entity.”- should be in the Section 4 Applicability. This would eliminate the need for this to be
discussed as part of the RSAW.

In order to evaluate the extent and kind of obligation involved with R1, the phrase “transmitted between two control centers”, needs to be clearer. Public
power believes that there should be more clarity or identification on the demarcation points of the link being protected.

Both TOP-003 and IRO-010 have a requirement that there be a mutually agreeable security protocol. It is not clear why a new standard needs to be
developed to address this same issue. The SDT should consider modifying TOP-003 and IRO-010 if these standards do not provide adequate language
to meet Order No. 822’s concerns.

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Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer

No

Document Name
Comment
Southern Company has concerns with the phrase “data used for Operational Planning Analysis, Real-time Assessments, and Real-time monitoring” in
CIP-012 R1. We understand this is a direct quote from TOP-003 R1 and IRO-010 R1 and the intent is for this phrase to point to the data specification
required by those standards. We understand there is a paragraph to this effect in the Technical Rationale document which is not a binding
document. Our concern is that the requirement says “data used for…” and without a stronger bind to the IRO and TOP standards we believe this opens
the scope of CIP-012 to yet another data definition exercise rather than a specific requirement to protect an already defined data specification while that
data is being transferred between Control Centers.
The draft RSAW for R1 puts this concern in writing. It does not instruct the auditor to use the specifications from TOP-003/IRO-010 Requirement 1 and
verify that this previously defined data is protected while being transferred between Control Centers. Instead it requires the auditor to verify
“The documented plan(s) collectively address all data used for Operational Planning Analysis, Real-time Assessments, and Real-time monitoring
transmitted between Control Centers”
It then includes glossary definitions for two of those terms. The auditor is instructed to look at two definitions, determine a definition of the undefined
“Real-time monitoring”, and then verify that all such data is protected. This effort alone dwarfs the true purpose of the standard which is protecting
those communications links over which BES Control Centers communicate system status with each other in real time.
We suggest an alternative to resolve this issue. First, we suggest that a data centric approach is problematic for these and other reasons and we
strongly suggest a more technical approach that focuses CIP-012 on securing communication sessions and/or links based on their destination. For
example, data that is leaving the ESP or LEAP of a Control Center that has a destination address of an ESP or LEAP at another Control Center should
be encrypted. That is very distinct and concrete and much simpler to implement and demonstrate and we believe is in line with FERC Order 822,
paragraph 60 where the Commission outlines the reliability gap to be addressed.
If this alternative is not acceptable, we suggest that R1 be modified to make the previously defined data specification the noun rather than “data used
for…”. Additionally, we suggest removing “Operational Planning Analysis” from the first paragraph of R1 as Operational Planning Analysis data does
not impact the BES within 15 minutes.
For example: “The Responsible Entity shall develop one or more documented plan(s) to mitigate the risk of the unauthorized disclosure or modification
of data used for Real-time Assessments and Real-time monitoring as specified by the Reliability Coordinator or Transmission Operator while such
data is being transmitted between Control Centers. This excludes oral communications.”
We also strongly suggest, based on questions in the draft RSAW, that the SDT consider moving any language relating to applicability to the
Applicability section of the standard rather than having a note in the requirement language. With the inclusion of the note in the requirement, we notice

the draft RSAW starts with questions for all the responsible entities that do not have Control Centers to prove the negative, which should instead defer
any auditor to the compliance auditing process of CIP-002-5.1.
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Ronald Donahey - TECO - Tampa Electric Co. - 3
Answer

No

Document Name
Comment
Tampa Electric Company suggests that the SDT provide additional instruction within the standard to address the requirements and implications for BA’s
that serve as the BA for other entities in the BA’s service area. It would be helpful to understand the BA’s responsibility to mitigate the risk of
unauthorized disclosure or modification of data used for the analysis, assessment and monitoring. In addition, does this standard extend to
communications between a Registered Entities and the Reliability Coordinators such as FRCC’s RC in relation to communication between Control
Centers?
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Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

No

Document Name
Comment
The SPP Standards Review Group has reviewed documentation and have developed some concerns in reference to Requirement R1. The CIP Version
5 Transition Advisory Group (V5TAG) identified specific issues with the CIP Version 5 standard language that caused difficulty in implementation of the
requirements. This requirement or a supplemental to CIP-005 needs to clarify the 4.2.3.2 exemption phrase “between discrete Electronic Security
Perimeters.” When there is not an ESP at the location, consider clarity that the communication equipment considered out of scope is the same
communication equipment that would be considered out of scope if it were between two ESPs or a single ESP. This should be address either in this
standard, as an Exemption added or requirement added to CIP-005-6.
Here is proposed language for the Exemption:
4.2.3. Exemptions: The following are exempt from Standard CIP

‐002‐ 5.1:

4.2.3.1. Cyber Assets at Facilities regulated by the Canadian Nuclear Safety
Commission.

4.2.3.2. Exemption of Communication Equipment that is owned and operated by a Third Party Communication Carrier or its equivalent is exempted from
the CIP standards that is communicating between system end points
Cyber Assets associated with communication networks and data (striking this information)
communication links between discrete Electronic Security Perimeters. (striking this information)
Or added to CIP-005-6 R1

CIP-005-5 Table R1 – Electronic Security Perimeter
Part
1.6
Applicable

High Impact BES Cyber Systems and their associated:
•

PCA

Medium Impact BES Cyber Systems with External Routable Connectivity and their associated:
•

PCA

Requirements
For defined ESPs that use wide-area communications networks (e.g. ESPs that span multiple geographic locations), Cyber Assets associated with
communication networks and data communication links used to facilitate the ESP and owned by a third party are exempt from the CIP Reliability
Standards provided that the communications traversing across these Cyber Assets are encrypted. The Cyber Assets that encrypt and decrypt the
communications are EACMS.
Measures
An example of evidence may include, but is not limited to, network diagrams showing all communication networks, vendor owned equipment, and
encryption/decryption Cyber Assets.
There are two major reasons for addressing this issue listed above. 1) This was identified by the V5TAG group and can be easily fixed with one of the
two suggestions listed above. Reason 2) is because Registered Entities may expand their ESP’s to cover both control centers to handle R1.1 in
regards of:
•

Logically protecting the data during transmission; or (Provide example or measures)

•

Using a measurements to mitigate the risk of unauthorized disclosure or modification of the data.

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Response

Wendy Center - U.S. Bureau of Reclamation - 5
Answer

No

Document Name
Comment
Reclamation recommends the SDT use the term “documented processes” consistently throughout the CIP standards. Pursuant to CIP-003-6,
The terms program and plan are sometimes used in place of documented processes where it makes sense and is commonly understood. For example,
documented processes describing a response are typically referred to as plans (i.e., incident response plans and recovery plans). Likewise, a security
plan can describe an approach involving multiple procedures to address a broad subject matter.

Reclamation disagrees that having a plan adds to the reliability of protecting data used for Operational Planning Analysis, Real-time Assessment, and
Real-time monitoring. A plan is an unwarranted layer of compliance that is not needed. Reclamation recommends that R1 be written in parallel with the
FERC Order 822, which directed the development of controls to protect communication links and data. Reclamation recommends R1 could be rewritten
to state: “The responsible entity shall have documented processes in place to mitigate the risk of the unauthorized disclosure or modification of BES
data used for Operational Planning Analysis, Real-time Assessments, and Real-time monitoring while being transmitted between BES Control Centers.
This excludes oral communications.” Reclamation recommends that the word “BES” be added to R1 regardless of whether the SDT accepts the rest of
the above proposed language.

If the requirement for a plan is retained, Reclamation recommends the SDT clarify what is meant by having a plan and how a plan is different from a
documented process.

Reclamation recommends using the following definitions of “plan” and “process:”
Plan: Written account of intended future course of action (scheme) aimed at achieving specific goal(s) or objective(s) within a specific timeframe. It
explains in detail what needs to be done, when, how, and by whom, and often includes best case, expected case, and worst case scenarios. See also
planning.

Process: Sequence of interdependent and linked procedures which, at every stage, consume one or more resources (employee time, energy,
machines, money) to convert inputs (data, material, parts, etc.) into outputs. These outputs then serve as inputs for the next stage until a known goal or
end result is reached.
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Scott Berry - Scott Berry On Behalf of: Jack Alvey, Indiana Municipal Power Agency, 1, 4; - Scott Berry

Answer

No

Document Name
Comment
We have attached our comments in the last question for the definition of Control Center. We are recommending changes to this definition.
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Lauren Price - American Transmission Company, LLC - 1
Answer

No

Document Name
Comment
ATC believes the language should be in better alignment with the directives of the FERC order to establish a plan and implement controls to address
the risks posed to the BES. ATC also believes the requirement language should be less prescriptive as it relates to data types. ATC believes the
Requirement language must allow an appropriate level of flexibility for Registered Entities to identify and document the risks posed to the BES and the
corresponding data to assure implemented controls are (and remain) commensurate with risk. The requirement should be focused on the achievement
and ongoing sustainability of the security objective in order to permit adaption of their plan(s) and the associated implemented controls such that they
are designed to effectively address the current and emerging risks posed to BES Control Center assets and information as the threat landscape
changes. Some potential language for consideration is:
“R1. For sensitive Bulk Electric System (BES) data communicated between BES Control Centers, Responsible Entities shall establish and implement
one or more documented plans that collectively identifies and addresses:
R1.1. the communication links capable and purposed for the transport of BES data between BES Control Centers
R1.2. the risks posed to the BES from the transport of the BES data between BES Control Centers
R1.2. the BES data subject to the risk
R1.3. the protective measures and security practices designed and implemented to mitigate the identified risks.
R1.4. the process and cycle to review and update the plan(s) to maintain alignment with risks posed
BES data excludes oral communications.”
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James Gower - Entergy - NA - Not Applicable - SERC

Answer

No

Document Name
Comment
The standard as drafted explicitly excludes oral communications, but does not consider forms of written communication (email, chat, etc) that could
communicate the same type of information that an oral communication could. These written instructions are commonly outside of SCADA systems and
are on corporate systems, and this standard would require physical or logical controls on those systems for communications that may traverse these
systems. The standard should specify the protection of “operational data”, “BCS Data”, or some other term to clarify protection of data outside of
instructions, or provide data validation (i.e verify emails by phone) as an acceptable control.

Additionally, Entergy has concerns over expanding the scope of protection from “real-time” as defined in other CIP standards and through existing CIP
definitions, to require the protection of Operational Planning Analysis data that is outside of the “real-time” horizon. Requests additional clarity regarding
whether the protection is required for data that is used to an input to Operational Planning Analysis, or also includes Operational Planning Analysis data
outputs. The Technical Justification and Rationale document seems to imply it is data inputs as it calls out data believed to already be within BES Cyber
Systems.
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Guy Andrews - Georgia System Operations Corporation - 4
Answer

No

Document Name
Comment
•
•
•
•
•

•

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GSOC (Georgia Systems Operations Corporation) requests that the Standards Drafting team provide formal CIP-012 Guidance and Technical
Basis (GTB) or Implementation Guidance, either within the Standard or as separate documentation. This is crucial for an entity’s understanding
of how to meet the compliance objective of a new Standard.
GSOC requests clarification regarding:
he applicability of the Standard to TOs. This Standard should apply only TOs who own or operate Control Centers. An example of modifying
the applicability can be found in MOD-025-2.
the precise nature of Operator-to-Operator communications. “Oral Communications” are excluded. However, EOP-008 (Emergency Operating)
Plans often specify using cell/text/email while in mid-failover to the backup site. Would these types of communications also be excluded?
The Rationale talks about “CIP-012-1 Requirements R1 and R2 protections for applicable data during transmission between two
geographically separate Control Centers.” However, the requirements themselves don’t seem to make that same distinction. Since the
definition of a “Control Center” includes associated data centers, this could lead to the application of this Standard, for example, to a facility that
houses 2 control centers side-by-side (one with a data center downstairs). GSOC requests that the Drafting Team provide more information
about the Rationale, as it relates to geographical location and proximity of Control Centers, and corresponding language of the Requirements.
CIP-012 includes protections for data while being transmitted between Control Centers. However, Control Centers are facilities and do not
transmit data. Does this include only data transmitted between BES Cyber Systems associated with a Control Center or data transmitted by
certified System Operators?
0
0

Response

Laura McLeod - NB Power Corporation - 5
Answer

No

Document Name
Comment
TOP-003/IRO-010 both require applicable entities have mutual agreement on security protocols. This mutual agreement requirement text of
TOP-003/IRO-010 may limit or prevent an entity from following its documented plans of CIP-012-1 R1 should, as an example, either entity
change its security protocols.
One approach is to also include the requirement for mutual agreement within CIP-12-1 and/or be more prescriptive in how an entity complies
with CIP-012-1 R1 including coordination between entities.
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Annette Johnston - Berkshire Hathaway Energy - MidAmerican Energy Co. - 3
Answer

No

Document Name
Comment
We do not agree with two separate requirements, one for a plan and one to implement. We recommend following precedent in the other CIP standards,
for example, CIP-004-011. The obligation can be accomplished with one requirement, such as follows, with the caveat of concerns expressed in
question 1 about what data is covered.
The Responsible Entity shall implement one or more documented processes(s) to mitigate the risk of the unauthorized disclosure or modification of data
used for Operational Planning Analysis, Real-time Assessments, and Real-time monitoring while being transmitted between Control Centers, except
under CIP Exceptional Circumstances . This excludes oral communications. Risk mitigation shall be accomplished by one or more of the following
actions: (follow with the four bullets).
Delete R2.
With one requirement, the note could be simpler by not referencing "R1 of CIP-012-1" and "CIP-012-1." See following.
Note: If the Responsible Entity does not have a Control Center or it does not transmit the type of data specified in this Requirement between two Control
Centers, this Requirement would not apply to that entity.

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Terry Harbour - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1
Answer

No

Document Name
Comment
See MidAmerican Energy Company comments.
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Laurie Williams - PNM Resources - Public Service Company of New Mexico - 1
Answer

No

Document Name
Comment
The requirement is too general and would likely not yield consistent compliance among entities and would result in inconsistent auditing of compliance.
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Response

Lynn Goldstein - PNM Resources - Public Service Company of New Mexico - 3
Answer

No

Document Name
Comment
The requirement is too general and would likely not yield consistent compliance among entities and would result in inconsistent auditing of compliance
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Response

Haley Sousa - Public Utility District No. 1 of Chelan County - 5
Answer

No

Document Name
Comment
CHPD requests clarification be added to the Technical Rationale for acceptable means of physically protecting communications links and identifying
equally effective methods to mitigate risk.
CHPD requests that the exclusion for oral communications be extended to electronic mail.
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Janis Weddle - Public Utility District No. 1 of Chelan County - 6
Answer

No

Document Name
Comment
CHPD requests clarification be added to the Technical Rationale for acceptable means of physically protecting communications links and identifying
equally effective methods to mitigate risk.
CHPD requests that the exclusion for oral communications be extended to electronic mail.
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David Greene - SERC Reliability Corporation - 10, Group Name SERC CIPC
Answer

No

Document Name

3B-2016-02_CIP-012-1_Unofficial_Comment_Form_CIPC.docx

Comment

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Brian Millard - Tennessee Valley Authority - 1,3,5,6 - SERC, Group Name Tennessee Valley Authority
Answer

Yes

Document Name
Comment
TVA agrees, providing the proposed definition of Control Center is adopted.
TVA notes that in many cases some types of operational planning analysis data is housed in systems not classified as BES Cyber Systems and may
not reside within an ESP. A documented plan provides a mechanism to identify and document flows of BES sensitive data that do not originate from
within an ESP nor pass through an EAP.
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Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

Yes

Document Name
Comment
IPC does not agree with the need for mandatory requirements. IPC evaluates risks and develops strategies to mitigates those risks, including those
associated with communication infrastructure and data transmission. Risks can change, and the implementation of static regulatory obligations that are
not flexibly written can make it more difficult to adapt.
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Response

Anthony Jablonski - ReliabilityFirst - 10
Answer

Yes

Document Name
Comment
Even though ReliabilityFirst votes in the affirmative, ReliabilityFirst provides the following comments for consideration:

1. Requirement R1 –

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i.

CIP-012-1 refers to data as outlined in NERC standards TOP-003-3 and IRO-010-2 that are required to be protected. ReliabilityFirst
understands these types of data can vary based on entity function and what data is needed. From a compliance monitoring perspective,
it may be difficult to verify what the entity is protecting versus what actually should be protected. ReliabilityFirst requests the SDT to
consider putting a list of typical data that should be protected per the standard and include it in a guideline document or rationale
section.

ii.

The standard, as written, states “Risk mitigation shall be accomplished by one or more of the following actions: Physically protecting
the communication links transmitting the data; Logically protecting the data during transmission; or Using an equally effective method to
mitigate the risk of unauthorized disclosure or modification of the data.” Since this is data in transit (over the “air”) ReliabilityFirst
inquires on how one provides physical protections? In addition to this, the selection of encryption cyphers, and key lengths are not
required. ReliabilityFirst suggests to place some language about encryption in a “technical basis”, explaining that there are different
cyphers, some better than others, and after weighing the pros and cons of different cyphers and key lengths recommend the use of siteto-site IPV6 encapsulation with a specific cypher and key length.

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Chris Scanlon - Exelon - 1
Answer

Yes

Document Name
Comment
Exelon agrees with the approach of the latest revision, which provides latitude to protect the communication links, the data, or both, to satisfy the
security objective consistent with the capabilities of the Responsible Entity’s operational environment.
We do, however, question the placement of the “Note” portion within R1. The Note applies not just to R1, but to CIP-012-1 as a whole. Is there a
reason for not including this under Section 4 Applicability, as an exemption?
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Vivian Vo - APS - Arizona Public Service Co. - 3
Answer

Yes

Document Name

2016-02 Modifications to CIP Standards CIP-012-1 - Answer to Question 1.docx

Comment

Please see the attached document for Arizona Public Service Co.'s answer to Question 1.
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Barry Lawson - National Rural Electric Cooperative Association - 4
Answer

Yes

Document Name
Comment
NRECA agrees with the construct of the standard and its requirements, but not the scope of sensitive BES data as detailed in the response to question
2.
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Shelby Wade - PPL - Louisville Gas and Electric Co. - 3,5,6 - SERC, Group Name Louisville Gas and Electric Company and Kentucky Utilities
Company
Answer

Yes

Document Name
Comment
We support SERC's comments.
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David Ramkalawan - Ontario Power Generation Inc. - 5
Answer
Document Name
Comment

Yes

OPG has concerns with potential issues arising from communication links not owned by entity.
Potential issues can also occur when the communication is performed between the CC belonging to different entities; how is the demarcation point
determined.
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Mark Riley - Associated Electric Cooperative, Inc. - 1
Answer

Yes

Document Name
Comment
AECI agrees with the construct of the standard and its requirements, but not the scope of sensitive BES data as detailed in the response to question 2.
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RoLynda Shumpert - SCANA - South Carolina Electric and Gas Co. - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment

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Response

Nicholas Lauriat - Network and Security Technologies - 1
Answer
Document Name
Comment

Yes

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Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment

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Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Answer

Yes

Document Name
Comment

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Response

Shannon Fair - Colorado Springs Utilities - 1,3,5,6, Group Name Colorado Springs Utilities
Answer

Yes

Document Name
Comment

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0

Response

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 3, Group Name FirstEnergy Corporation

Answer

Yes

Document Name
Comment

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0

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0

Response

Jesus Sammy Alcaraz - Imperial Irrigation District - 1
Answer

Yes

Document Name
Comment

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0

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0

Response

Sheranee Nedd - PSEG - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer

Yes

Document Name
Comment

Likes

1

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PSEG - PSEG Fossil LLC, 5, Kucey Tim
0

Response

Michael Shaw - Lower Colorado River Authority - 1, Group Name LCRA Compliance
Answer

Yes

Document Name
Comment

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0

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0

Response

Douglas Webb - Douglas Webb On Behalf of: Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., 3, 5, 1, 6; James McBee,
Great Plains Energy - Kansas City Power and Light Co., 3, 5, 1, 6; Jessica Tucker, Great Plains Energy - Kansas City Power and Light Co., 3,
5, 1, 6; Jim Flucke, Great Plains Energy - Kansas City Power and Light Co., 3, 5, 1, 6; - Douglas Webb
Answer

Yes

Document Name
Comment

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0

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0

Response

Richard Vine - California ISO - 2
Answer
Document Name
Comment
The California ISO supports the comments of the Security Working Group (SWG).
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0

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Response

0

2. Requirement R1: The SDT seeks comment on the need to scope sensitive BES data as it applies to Operational Planning Analysis, Realtime Assessment, and Real-time monitoring. Do you agree with scoping CIP-012-1 Requirement R1 in this manner? Please provide comment
in support of your response.
Terry Harbour - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1
Answer

No

Document Name
Comment
See MidAmerican Energy Company comments.
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0

Response

Annette Johnston - Berkshire Hathaway Energy - MidAmerican Energy Co. - 3
Answer

No

Document Name
Comment
The FERC directive refers to "sensitive bulk electric system data" and directs NERC to "identify the scope of sensitive build electric system data." The
FERC directive also acknowledges that certain entities are already required to exchange necessary real-time and operational planning data through
secured networks using mutually agreeable security protocol.
Draft Requirement 1 refers to "data used for Operational Planning Analysis, Real-time Assessments, and Real-time monitoring." We agree with other
commenters that these references require revision. Further, we ask the SDT to consider scoping sensitive data explicitly to information exchanged
between Control Centers' BES Cyber Systems. This corresponds to SDT's assertation that "this data resides within BES Cyber Systems, and while at
rest is protected by CIP-003 through CIP-011." It also corresponds to FERC's recognition of mutually agreeable security protocol networks referenced
above.
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0

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0

Response

Laura McLeod - NB Power Corporation - 5
Answer
Document Name
Comment

No

Since Operational Planning Analysis is not real-time data and since planning data/information is generally scrutinized when performing
analysis the risk of acting on corrupted data (entry error or unauthorized disclosure/modification) is low.
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0

Response

Mark Riley - Associated Electric Cooperative, Inc. - 1
Answer

No

Document Name
Comment
AECI contends that data used for Operational Planning Analysis (OPA) is not sensitive BES data and does not have a 15 minute impact on the reliable
operation of the BES. The CIP standards focus on span of control of BES Cyber Systems and their impact to the reliable operation of the BES. Data
used for Real-time Assessments and Real-time monitoring can immediately impact the reliable operation of the BES, but data used for OPA has no
such impact. AECI requests that the SDT remove OPA from R1 due to not impacting the reliable operation of the BES.
Likes

0

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0

Response

James Gower - Entergy - NA - Not Applicable - SERC
Answer

No

Document Name
Comment
Entergy has concerns over expanding the scope of protection from “real-time” as defined in other CIP standards and through existing CIP definitions, to
require the protection of Operational Planning Analysis data that is outside of the “real-time” horizon.
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0

Response

Wendy Center - U.S. Bureau of Reclamation - 5
Answer
Document Name

No

Comment
Reclamation recommends adding “BES” data to the language as stated above in question 1.
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0

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0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

No

Document Name
Comment
The SPP Standards Review Group has a concern that the scope doesn’t provide the appropriate coverage of the BES data. We would like to propose
some new language to address those potential concerns. First of all, a “plan” does not necessarily mean the data is protected. According to the
Rationale section FERC is looking for controls to protect these communication links. It should also be clarified that this is “BES” data.
The SDT, in the Technical Rationale and Justification document acknowledges TOP-003-3 and IRO-010-2 “provides consistent scoping of identified
data” [R1 section: Alignment with IRO and TOP Standards”]. We believe that the data specifications under TOP-003-3 R1 and IRO-010-2 R1 correctly
scope the data to be protected; however the current R1 only leaves us with three defined terms for scoping. These 3 defined terms were already used
to scope the data specifications under TOP-003-3 R1 and IRO-010-2 R1. CIP-012-1 R1 should reference to TOP-003-1 R1 and IRO-010-2 R1. We
realize that it is not the preferred method to reference another Standard; however since CIP-012 is classified as a CIP Standard, and not an Operations
and Planning Standard which would be the correct classification, CIP auditors may expand the data to be protected based solely on definitions. In order
to properly scope CIP-012, it should reference the TOP-003 and IRO-010 Standards.
R1 should be re-written: “The Responsible Entity shall have controls in place to mitigate the risk of the unauthorized disclosure or modification of BES
data identified under entity developed data specifications in TOP-003-3 R1 for applicable entities and IRO-010-2 R1 for applicable entities; while such
data is being transmitted between BES Control Centers. This excludes oral communications.”
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0

Response

Ronald Donahey - TECO - Tampa Electric Co. - 3
Answer

No

Document Name
Comment
Please provide additional clarification on the protection of load forecasting data as it may not consistently be included as a separate BES Cyber System.
Likes

0

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0

Response

Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer

No

Document Name
Comment
As per the concern noted in response to question 1, we agree that either further clarification on the scope of the data is needed so it is clear the data in
question has already been scoped and is in specifications that are required by IRO-010 and TOP-003, or the SDT should consider setting aside a “datacentric” approach and focus protections on a more technical solution regardless of the data being transmitted between Control Center ESPs and
LEAPs.
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0

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0

Response

Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer

No

Document Name
Comment
Utility Services does not agree with the scope of the CIP-012-1 R1 as it applies to Operational Planning Analysis, Real-time Assessment, and Real-time
monitoring. Since Operational Planning Analysis data would not meet the 15-minute impact criteria used in the identification of BES Cyber Systems,
this data would only be required to be protected as it is being transmitted between Control Centers. This inconsistency between the data systems
identified by CIP-012-1 and those identified in other CIP standards may cause the unintended expansion of scope of the CIP Standards.

Public power believes applying controls to the Operational Planning Analysis data may reduce the current ability of entities to share this data which may
cause a reduction in BES reliability. Not all of this data goes from Control Center to Control Center but may go to (or from) a location outside of a
Control Center and therefore would not be in scope of the drafted CIP-012 standard. USI suggests removing the Operational Planning and Analysis
data from the scope of this standard.

If the Operational Planning and Analysis data must be retained in the Standard, then USI believes that an exemption for the communication of
Operational Planning and Analysis data by email should be put in place. This would be similar to the exemption that exists for voice communication.
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0
0

Response

James Anderson - CMS Energy - Consumers Energy Company - 1
Answer

No

Document Name
Comment
The requirement suggested data are different from those protected in other CIP standards. This may cause confusion in the future by calling it a CIP
standard.
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0

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0

Response

David Greyerbiehl - CMS Energy - Consumers Energy Company - 5
Answer

No

Document Name
Comment
The requirement suggested data are different from those protected in other CIP standards. This may cause confusion in the future by calling it a CIP
standard.
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0

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0

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Warren Cross - ACES Power Marketing - 1,3,4,5 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Standards Collaborators
Answer

No

Document Name
Comment
We disagree with the inclusion of Operational Planning Analysis (OPA) based on its NERC definition, as these evaluations are assessed on anticipated
and potential conditions for next-day operations and outside the 15-minute impact on the reliable BES operations. The inclusion of OPA is
unnecessary and the technical basis does not support it being in scope because it is not impacting the BES in real time.
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0
0

Response

Lan Nguyen - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
CenterPoint Energy believes not all data included in OPA, RTA, and RTM is sensitive BES data. CenterPoint Energy recommends the SDT narrow the
scope further to only sensitive BES data. Some inputs into OPAs, RTAs, and RTMs (e.g. forecast type data, modeling data such as Facility Ratings,
phase angle limitations, etc.) should not be included in the scope of this project. On a situational basis, some telemetry and outage information would
also not be considered sensitive BES data.
CenterPoint Energy further recommends that OPA data be completely removed from the scope of CIP-012-1. CenterPoint Energy does not deem this
data to be considered sensitive BES data, nor does this data carry the significance of actual Real-time data used for RTAs and RTM.
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0

Response

Jack Cashin - American Public Power Association - 4
Answer

No

Document Name
Comment
APPA does not agree with the scope of the CIP-012-1 R1 as it applies to Operational Planning Analysis, Real-time Assessment, and Real-time
monitoring. Since Operational Planning Analysis data would not meet the 15-minute impact criteria used in the identification of BES Cyber Systems, this
data would only be required to be protected as it is being transmitted between Control Centers. This inconsistency between the data systems identified
by CIP-012-1 and those identified in other CIP standards may cause the unintended expansion of scope of the CIP Standards.
Public power believes applying controls to the Operational Planning Analysis data may reduce the current ability of entities to share this data which may
cause a reduction in BES reliability. Not all of this data goes from Control Center to Control Center but may go to (or from) a location outside of a
Control Center and therefore would not be in scope of the drafted CIP-012 standard. APPA suggests removing the Operational Planning and Analysis
data from the scope of this standard.
If the Operational Planning and Analysis data must be retained in the Standard, then APPA believes that an exemption for the communication of
Operational Planning and Analysis data by email should be put in place. This would be similar to the exemption that exists for voice communication.
An important consideration with respect to scope and data protection, is the impact encryption may have on the data being considered within the scope
of the standard. As SRP communicates in their comments: until the implications are understood about the amount of data being considered for the
standard and the impact of encryption on latency and computing resources, the scope may be over-reaching. Therefore, APPA believes that the
scoping for the standard does not sufficiently take these factors into account.
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0

Response

Theresa Rakowsky - Puget Sound Energy, Inc. - 1
Answer

No

Document Name
Comment
See APPA Comments.
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0

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0

Response

Marc Donaldson - Tacoma Public Utilities (Tacoma, WA) - 3
Answer

No

Document Name
Comment
Tacoma Power supports the comments of APPA
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0

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0

Response

Jesus Sammy Alcaraz - Imperial Irrigation District - 1
Answer

No

Document Name
Comment
While we agree with the SDTs approach to align with TOP-003 and IRO-010, we feel that technologies such as encryption or physical protection are
generally implemented by link, not communication type.
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0

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0

Russell Noble - Cowlitz County PUD - 3
Answer

No

Document Name
Comment
Cowlitz PUD supports the comments submitted by APPA.
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0

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0

Response

Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer

No

Document Name
Comment
Xcel Energy is concerned with the inclusion of BES data used for Operation Planning Analysis that does not have a 15 minute impact on the Bulk
Electric System. The inclusion of Operational Planning Assessment data would bring corporate communication links, such as corporate email, into the
scope of NERC Standards.
We are also concerned with the language in Requirement R1.1 which states that a method of risk mitigation could be done by "Physically protecting the
communication links transmitting data." Xcel Energy believes that the proposed standard does not define what physical controls would be sufficient to
mitigate the undefined risk of "unauthorized disclosure of modification of data." Many communication devices owned by Xcel Energy reside in company
facilities that have several layers of physical protection. However, once communication links leave our enclosures and ownership purview, physical
protection would be difficult at best, largely unknown, and impossible to enforce. The implementation of physical controls only covers a small section of
the medium for the data and does not actually protect the data itself. As one of three options; if an organization elects to impement physical controls it
would still leave a gap in data integrity and add little benefit with excessive administrative burden.
Xcel Energy respectfully proposes the recommendation for physcial protection to be removed and require logical controls such as encryption, firewalls,
information protection release standards and password requirements. Logical controls would more sufficiently protect the data itself end-to-end. We
suggest the following edits to R1;
The Responsible Entity shall develop and implement controls [strikethrough: one or more documented plan(s)] to mitigate the risk of the unauthorized
disclosure of or modification to BES data used for Operational Planning Analysis, Real-time Assessments, and Real-time monitoring while being
transmitted between Control Centers and which could have an adverse impact on the BES within 15 minutes. This excludes verbal
communications. [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]
1.1. Risk mitigation shall be accomplished by one or more of the following actions:
•

[strikethrough: Physically protecting the communication links transmitting the data;]

•

Logically protect[strikethrough:ing] the data during transmission; or

•

Use[strikethrough:ing] an equally effective method to mitigate the risk of unauthorized disclosure or modification of the data.

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Response

Thomas Breene - WEC Energy Group, Inc. - 3
Answer

No

Document Name
Comment
The SDT needs to add “BES” data into the language as recommended above in question 1. The “BES data” to be protected should be identified as that
“BES data” which can have an impact via high and medium BES Cyber Systems within 15 minutes. In other words, this level of protection should be
limited to High and Medium Control Centers and only that data which could put Real-time operations at risk.
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0

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0

Response

Lona Calderon - Salt River Project - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
SRP agrees this data should be protected. However, after further discussions within SRP and with other entities in the industry, it is clear no one in the
industry can state or has an understanding of the implications encryption would have on reliable operation of the BES and the data within this scope.
Until a survey or evaluation is performed to understand the amount of data this scope applies to and the impact of encryption on latency and computing
resources, the scope may be over-reaching. As such, the manner used for scoping does not adequately take these factors into account.
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0

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0

Response

Barry Lawson - National Rural Electric Cooperative Association - 4
Answer
Document Name
Comment

No

NRECA contends that data used for Operational Planning Analysis (OPA) is not sensitive BES data and does not have a 15 minute impact on the
reliable operation of the BES. The CIP standards focus on span of control of BES Cyber Systems and their impact to the reliable operation of the
BES. Data used for Real-time Assessments and Real-time monitoring can immediately impact the reliable operation of the BES, but data used for OPA
has no such impact. We request that the SDT remove OPA from R1 due to not impacting the reliable operation of the BES.
Likes

0

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0

Response

Aaron Austin - AEP - 3
Answer

No

Document Name
Comment
AEP suggests that “Operational Planning and Analysis” be removed from R1.
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0

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0

Response

Quintin Lee - Eversource Energy - 1, Group Name Eversource Group
Answer

No

Document Name
Comment
The Purpose section of CIP-012-1 adds the need to protect the confidentiality of data which is out of Scope of FERC order 822. Although it is
recognized that the SDT is not limited to just FERC orders, adding need to protect the confidentiality of data does not add reliability if the data is being
protected per CIP-012-1 R1.

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Response

Vivian Vo - APS - Arizona Public Service Co. - 3
Answer

No

Document Name
Comment
AZPS respectfully submits that achieving a consensus regarding categorization of data as sensitive across all three interconnections will be difficult – if
not impossible – to achieve. The sensitivity of the same data can vary drastically between interconnections and entities within each
interconnections. For example, a piece of information that AZPS considers critical and sensitive to its real-time assessments may be viewed as
insignificant to another entity. Additionally, certain markets require publication of data that other markets would consider sensitive. Hence, any
attempted categorization may conflict with regulatory requirements in Open Access Transmission Tariffs, Market Protocols, state and federal
regulations, etc. that obligate entities to disclose and/or that require confidentiality and that are already effective.
Furthermore, such a classification may not matter in practice. The reality is that data flows to Control Centers across a limited number of
communication channels. Consider a simplified control center that uses only ICCP for real-time monitoring and assessment, with only half of the data
transmitted across that channel being considered “sensitive.” It is unlikely that any entity would reasonably determine that it should separate out the
sensitive data for protection and leave the non-sensitive data unprotected. It is more likely that they would, instead, protect the entire communication
channel. Consequently, AZPS does not support the need or see any benefit to an effort focused on scoping sensitive BES data. Instead, it
recommends that responsible entities retain the authority to designate specific data or communication links as “sensitive.”
Finally, in the event that the SDT determines a need to scope sensitive BES data, AZPS suggests striking the term “Operational Planning Analysis” from
the requirement and limiting the data considered as sensitive to that data which is subject to the NERC Operating Reliability Data (ORD)
Agreement. The NERC ORD Agreement is intended to ensure the confidentiality of sensitive data and the definition of Operating Reliability Data and
associated obligations included therein are clear, well-established, and well-understood by industry. Importantly, the definition of ORD excludes
“Operational Planning Analysis,” signaling that such data has not, historically, been considered as “sensitive.” Moreover, the Operational Planning
Analysis occurs in the next day horizon, providing entities with time to receive and review data prior to use and, where data is suspect, request
verification of data or, where data is not timely received, request that such data be re-transmitted. For these reasons, the data utilized in Operational
Planning Analyses has extremely limited impact on reliability, which is highly dependent on accurate, appropriate real-time data. Hence, protecting data
used in real-time assessment and monitoring as has been required by the NERC ORD Agreement for years is appropriate and the scope of such data
has already been evaluated for sensitivity and confidentiality. In summary, if the SDT is compelled to scope sensitive data, to ensure consistency,
AZPS recommends that the SDT interpret “sensitive BES data” as encompassing data used in Real-time Assessment and Real-time monitoring only
and utilize the NERC ORD Agreement as its primary reference.
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Dennis Sismaet - Northern California Power Agency - 6
Answer

No

Document Name
Comment
NCPA does not agree with the scope of the CIP-012-1 as it applies to Operational Planning Analysis, Real-time Assessment, and Real-time
monitoring. Since Operational Planning Analysis data would not meet the 15-minute impact criteria used in the identification of BES Cyber Systems,
this data would only be required to be protected as it is being transmitted between Control Centers. This inconsistency between the data systems
identified by CIP-012-1 and those identified in other CIP standards may cause the unintended expansion of scope of the CIP Standards. Also see other
APPA and Utility Services/TAPs comments.
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0

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0

Response

Marty Hostler - Northern California Power Agency - 5
Answer

No

Document Name
Comment
NCPA does not agree with the scope of the CIP-012-1 as it applies to Operational Planning Analysis, Real-time Assessment, and Real-time
monitoring. Since Operational Planning Analysis data would not meet the 15-minute impact criteria used in the identification of BES Cyber Systems,
this data would only be required to be protected as it is being transmitted between Control Centers. This inconsistency between the data systems
identified by CIP-012-1 and those identified in other CIP standards may cause the unintended expansion of scope of the CIP Standards. Also see other
APPA and Utility Services/TAPs comments.
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0

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0

Response

James Poston - Santee Cooper - 3, Group Name Santee Cooper
Answer

No

Document Name
Comment
Recommend removing “Operational Planning Analysis” from this requirement. Operational Planning Analysis is not Real-time data and would not affect
the BES within 15 minutes. The TOP-003-3 Standard currently requires a mutually agreeable security protocol for sharing of data required for
Operational Planning Analyses.
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0

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0

Response

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer
Document Name
Comment
See APPA Comments.

No

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0

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0

Response

Alice Wright - Arkansas Electric Cooperative Corporation - 4
Answer

No

Document Name
Comment
See attachment
Likes

0

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0

Response

Dana Klem - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO NSRF
Answer

No

Document Name
Comment
The SDT needs to add “BES” data into the language as recommended above in question 1.
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0

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0

Response

Jennifer Hohenshilt - Talen Energy Marketing, LLC - 6
Answer

No

Document Name
Comment
The question is unclear.
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0
0

Response

Philip Huff - Arkansas Electric Cooperative Corporation - 3
Answer

No

Document Name
Comment
Please provide additional guidance on the scope of the information. The Standards from which the scope derives does not provide guidance, and the
expansion of scope in CIP-012-1 to all Control Centers necessitates the need for more specific guidance.
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0

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0

Response

Donald Lock - Talen Generation, LLC - 5
Answer

No

Document Name
Comment
The question is unclear.
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0

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0

Response

Brandon McCormick - Brandon McCormick On Behalf of: Ginny Beigel, City of Vero Beach, 3; Lynne Mila, City of Clewiston, 4; Tom Reedy,
Florida Municipal Power Pool, 6; - Brandon McCormick, Group Name FMPA
Answer

No

Document Name
Comment
APPA does not agree with the scope of the CIP-012-1 R1 as it applies to Operational Planning Analysis, Real-time Assessment, and Real-time
monitoring. Since Operational Planning Analysis data would not meet the 15-minute impact criteria used in the identification of BES Cyber Systems,
this data would only be required to be protected as it is being transmitted between Control Centers. This inconsistency between the data systems
identified by CIP-012-1 and those identified in other CIP standards may cause the unintended expansion of scope of the CIP Standards.
FMPA believes applying controls to the Operational Planning Analysis data may reduce the current ability of entities to share this data which may cause
a reduction in BES reliability. Not all of this data goes from Control Center to Control Center but may go to (or from) a location outside of a Control

Center and therefore would not be in scope of the drafted CIP-012 standard. APPA suggests removing the Operational Planning and Analysis data
from the scope of this standard.
If the Operational Planning and Analysis data must be retained in the Standard, then APPA believes that an exemption for the communication of
Operational Planning and Analysis data by email should be put in place. This would be similar to the exemption that exists for voice communication.

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0

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0

Response

Joe Tarantino - Joe Tarantino On Behalf of: Arthur Starkovich, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Beth Tincher, Sacramento
Municipal Utility District, 4, 1, 5, 6, 3; Jamie Cutlip, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Kevin Smith, Balancing Authority of
Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Susan Oto, Sacramento Municipal Utility District, 4, 1,
5, 6, 3; - Joe Tarantino
Answer

No

Document Name
Comment

We are concerned because unauthorized alteration of Operational Planning Analysis data does not pose a threat to the BES. This more
appropriately addressed by TOP 010-1 reliability standard regarding the quality of the data. We note that Operational Planning Data is not
real time data, as such we ask the STD to treat communicating Operational Planning Data Email exempt similar to the oral
communication.
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0

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Response

George Brown - Acciona Energy North America - 5
Answer

No

Document Name
Comment
The requirement as written does not meet the criteria as outlined in the document titled “Ten Benchmarks of an Excellent Reliability Standard”,
benchmark 8. Clear Language. As the SDT stated in the rationale, the data in scope is the data as specified in TOP-003-3 and IRO-010-2. If this is in
fact the case then the SDT should draw a clear and unambiguous line to these standards within the requirement. The addition of such language will
also prevent unintentional scope reach.
Suggested language should be something to the following effect:

R1.2 The Responsible Entity, as applicable to its registered function, shall consider the data used for Operational Planning Analysis, Real-time
Assessments, and Real-time monitoring to be the data as specified in:
•

NERC Reliability Standard IRO-010-2, Requirement R1 and,

•

NERC Reliability Standard TOP-003-3 — Operational Reliability Data, Requirement R1 and Requirement R2.

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Response

Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer

No

Document Name
Comment
Dominion asserts that data used for Operational Planning Analysis is often an ad-hoc report by exception (e.g., this line will be out or this unit will be derated) and because this data is often collected by a stand-alone system it can often be entered by several people within an organization and from
several locations. Dominion is unclear on whether the entity expected to track which data is specifically entered from within a Control Center as
opposed to from an office external to the Control Center. Many stand-alone systems are web-based and use https for all transactions. It is unclear what
would qulaify as adequate evidence and that tracking locations and persons entering the information is not necessary.
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Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

No

Document Name
Comment
Duke Energy has concerns about the decision to add Operational Planning Analysis information to the scope of the data protected by this standard.
Currently, the scope of the CIP standards primarily focuses on real-time data, and bringing in Operational Planning Analysis pushes the scope of CIP
standards to include Day Ahead. Also, in some instances, Operational Planning Analyses can be performed by a 3rd party or require data transmitted
between entities via 3rd party tools. How would these affect be impacted by the applicability of the standard? Extending the CIP scope to apply to Day
Ahead data is a departure, and could broaden the view of what tools (possibly including web-based tools?) could fall under CIP scope.
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0

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0

RoLynda Shumpert - SCANA - South Carolina Electric and Gas Co. - 1,3,5,6 - SERC
Answer

No

Document Name
Comment
If there is the need to scope sensitive BES data as it applies to Operational Planning Analysis, Real-time Assessment, and Real-time monitoring, it
should all be scoped as data of the High Impact BES Cyber Systems.
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0

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0

Response

Lynn Goldstein - PNM Resources - Public Service Company of New Mexico - 3
Answer

No

Document Name
Comment

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0

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0

Response

Lauren Price - American Transmission Company, LLC - 1
Answer

No

Document Name
Comment

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0

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0

Response

David Greene - SERC Reliability Corporation - 10, Group Name SERC CIPC
Answer

No

Document Name

3B-2016-02_CIP-012-1_Unofficial_Comment_Form_CIPC.docx

Comment

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0

Response

sean erickson - Western Area Power Administration - 1
Answer

No

Document Name
Comment

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0

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0

Response

Guy Andrews - Georgia System Operations Corporation - 4
Answer

Yes

Document Name
Comment
We request clarification on the inclusion of data used for Operational Planning Analysis. This data does not have a 15 minute impact on the Bulk
Electric System. This data is also typically exchanged between operations engineering staff who would not be considered to be a Control Center.
Likes

0

Dislikes

0

Response

Michael Shaw - Lower Colorado River Authority - 1, Group Name LCRA Compliance
Answer
Document Name
Comment

Yes

Please provide guidance on whether or not email is in scope as a communication medium.
Likes

0

Dislikes

0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
However, BPA questions the inclusion of Operational Planning Analysis.
Likes

0

Dislikes

0

Response

Sheranee Nedd - PSEG - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer

Yes

Document Name
Comment
RC, TOP and BA functional entities develop and disseminate specifications for the BES data they need to conduct Operational Planning Analysis, Realtime Assessment, and Real-time monitoring, in NERC ‘693’ reliability standards TOP-003 and IRO-010. Relevant peer RCs/TOPs/BAs and others
(GOs; GOPs; TOs; LSEs; DPs) are required by these standards to meet these data specifications. The scope of data subject to R1 is (or should be)
thereby understood to be the data that entities both (i) specify in observance of these standards and (ii) transmit between the entity’s and others’ Control
Centers.
Likes

1

Dislikes

PSEG - PSEG Fossil LLC, 5, Kucey Tim
0

Response

Chris Scanlon - Exelon - 1
Answer
Document Name
Comment

Yes

Exelon agrees that aligning with TOP-003-3 and IRO-010-2 is helpful for scoping CIP-012-1, and promotes consistent application of the NERC
Standards.
Likes

0

Dislikes

0

Response

David Rivera - New York Power Authority - 3
Answer

Yes

Document Name
Comment
No Comment
Likes

0

Dislikes

0

Response

Dermot Smyth - Con Ed - Consolidated Edison Co. of New York - 5, Group Name Con Edison
Answer

Yes

Document Name
Comment
Same comment as question #1 above.
Likes

0

Dislikes

0

Response

Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

Yes

Document Name
Comment
In the event mandatory standards are imposed, the scope should be limited to data that have well-defined terms.

Likes

0

Dislikes

0

Response

Brian Millard - Tennessee Valley Authority - 1,3,5,6 - SERC, Group Name Tennessee Valley Authority
Answer

Yes

Document Name
Comment
TVA agrees that the entity needs to know what information is classified as BES sensitive data as it relates to operational planning analysis, real-time
assessment, and real-time monitoring. In many cases some types of operational planning analysis data is housed in systems not classified as BES
Cyber Systems and may not reside within an ESP.
Likes

0

Dislikes

0

Response

Janis Weddle - Public Utility District No. 1 of Chelan County - 6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Douglas Webb - Douglas Webb On Behalf of: Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., 3, 5, 1, 6; James McBee,
Great Plains Energy - Kansas City Power and Light Co., 3, 5, 1, 6; Jessica Tucker, Great Plains Energy - Kansas City Power and Light Co., 3,
5, 1, 6; Jim Flucke, Great Plains Energy - Kansas City Power and Light Co., 3, 5, 1, 6; - Douglas Webb
Answer

Yes

Document Name
Comment

Likes
Dislikes

0
0

Response

Haley Sousa - Public Utility District No. 1 of Chelan County - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Laurie Williams - PNM Resources - Public Service Company of New Mexico - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Michael Puscas - ISO New England, Inc. - 2
Answer
Document Name

Yes

Comment

Likes

0

Dislikes

0

Response

Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Con-Edison and Dominion
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Nicolas Turcotte - Hydro-Qu?bec TransEnergie - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Heather Morgan - EDP Renewables North America LLC - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 3, Group Name FirstEnergy Corporation
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

David Gordon - Massachusetts Municipal Wholesale Electric Company - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Shannon Fair - Colorado Springs Utilities - 1,3,5,6, Group Name Colorado Springs Utilities
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

Frank Pace - Central Hudson Gas & Electric Corp. - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Nicholas Lauriat - Network and Security Technologies - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE does not have comments on this question.
Likes

0

Dislikes

0

Response

Richard Vine - California ISO - 2
Answer
Document Name
Comment
The California ISO supports the comments of the Security Working Group (SWG).
Likes

0

Dislikes
Response

0

3. Implementation Plan: The SDT revised the Implementation Plan such that the standard and NERC Glossary terms are effective the first day
of the first calendar quarter that is twelve (12) calendar months after the effective date of the applicable governmental authority’s order
approving the standard, or as otherwise provided for by the applicable governmental authority. Do you agree with this proposal? If you agree
with the proposed implementation time period, please note the actions you will take that require this amount of time to complete. If you think
an alternate implementation time period is needed – shorter or longer - please propose an alternate implementation plan and provide a
detailed explanation of actions and time needed to meet the implementation deadline.
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

No

Document Name
Comment
Duke Energy disagrees with the proposed 12 month Implementation Plan. Certain aspects of achieving compliance with this standard (for example,
implementing end to end encryption) would, in some instances, take a significant amount of time to put in place to due to the significance of the impact
of these changes on critical systems. Further, applying these protections between Control Centers owned by more than one Responsible Entity will
involve significant coordination, and additional time would be necessary to develop a shared understanding of existing technical limitations, develop
agreements, and implement those new approaches for compliance. Duke Energy suggests that a phased implementation plan would be appropriate
given the action necessary. We encourage the drafting team to consider an Implementation Plan of 12 months for R1. This would give time for the
Responsible Entity to assess the Control Centers that are in its scope, decide on a method of protection, and involve any additional parties that may be
necessary. We suggest a minimum of 24 months for the implementation date for R2 (implementing the plan developed in R1).
Likes

0

Dislikes

0

Response

Brian Millard - Tennessee Valley Authority - 1,3,5,6 - SERC, Group Name Tennessee Valley Authority
Answer

No

Document Name
Comment
TVA does not agree that twelve months is sufficient time to coordinate with other entities to agree on and implement protection
mechanisms. Implementation may require coordination of plans across a large and/or diverse group of entities employing a variety of protective
measures. TVA suggests 18-24 months would be a more realistic implementation period.
Likes

0

Dislikes

0

Response

Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

No

Document Name
Comment
Changes take time to evaluate and implement. The communication lines will have to be inventoried and evaluated. The data traveling across these lines
will have to be inventoried and evaluated to ensure entities can evidence that they are protecting the itemized list of data included in the wording of R1
(Operational Planning Analysis, Real-time Assessment, and Real-time monitoring). Other activities that would need to occur for successful
implementation would include preparation and delivery of guidance by regulatory bodies, communication and coordination with partner entities,
configuration, and testing. At minimum, an 18-month implementation plan would be appropriate.
Likes

0

Dislikes

0

Response

Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer

No

Document Name
Comment
Dominion asserts that budgets, resources, and other events between separate entities may require periods greater than 12 months. Dominion
recommends that the implementation period be revised to 24 months.In addition, the time required to develop (R1), and then successfully implement
(R2) would take longer than 12 months from the start date. 24 months should allow sufficient time to accomplish implementation of both requirements.
Likes

0

Dislikes

0

Response

George Brown - Acciona Energy North America - 5
Answer

No

Document Name
Comment
This standard will require a collaborative effort between Control Centers of the various applicable Functional Entities to achieve the securities as
required. As such, it may not feasible for some entities to implement these securities within 12 months. For example, a Reliability Coordinator (RC)
Control Center will have contact with the Control Centers of several Balancing Authorities (BA), Generator Operators (GOP), Transmission Operators
(TOP), Transmission Owners (TO) and other RCs. If a particular RC is unable to support the implementation of the securities as required in NERC
CIP-012-1 then there will be a cascading and unnecessary non-compliance effect among the other Functional Entities that have Control Centers that
transmit and receive this sensitive BES data with this particular RC’s Control Center. A phase-in approach may be more appropriate for NERC CIP012-1, based on schedules created using the Function Entity reliability hierarchy structure.
Likes

0

Dislikes

0

Response

Joe Tarantino - Joe Tarantino On Behalf of: Arthur Starkovich, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Beth Tincher, Sacramento
Municipal Utility District, 4, 1, 5, 6, 3; Jamie Cutlip, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Kevin Smith, Balancing Authority of
Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Susan Oto, Sacramento Municipal Utility District, 4, 1,
5, 6, 3; - Joe Tarantino
Answer

No

Document Name
Comment

For complex entities the identification and agreement on communication protocols and architecture may require extensive testing and
learning. We recommend at least 18 months due to the quantity of details and logistics.

Likes

0

Dislikes

0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer

No

Document Name
Comment
The IESO also encourages the drafting team to make the requirement forward-looking in regards to contracts currently in place. Provisions should be
set for legacy contracts including grandfathering of existing agreements and equipment. Implementation of controls involving telecommunications
providers will require coordination and scheduling to align to the providers’ resource availability and reduce adverse impact on reliability. This should not
require renewal and renegotiation of existing contracts until they reach the end of the existing contract period.
It should be noted that it is difficult to determine suitability of the implementation timeline when there are open questions about the viability of available
solutions for adequate protections.
More time is necessary to allow for coordination with a large number of parties. This will require budgeting, planning, and scheduling with external
resources for implementation. It will also require significant testing and validation by parties on both ends of a connection.
The IESO recommends a phased implementation with defined milestones similar to CIP-014. Consider the following:

•

For creation of the plan, 12 months should be allowed to (1) conduct an impact assessments, (2) identify the approach to be included in the
plan, (3) implementation milestones, and (4) implementation schedule. This could identify the communication links that have protections
currently in place. The plan could also include identifying all links and protections requiring changes to address service contracts and related
relationships to adjust for new protections. The plan could then be approved by an appropriate entity.

•

For implementation of the plan, additional time should be allowed for budgeting, planning, and scheduling with external resources. This includes
planning with other Responsible Entities as well as telecommunications providers.

Likes

2

Dislikes

Hydro One Networks, Inc., 1, Farahbakhsh Payam; Hydro One Networks, Inc., 3, Malozewski Paul
0

Response

Brandon McCormick - Brandon McCormick On Behalf of: Ginny Beigel, City of Vero Beach, 3; Lynne Mila, City of Clewiston, 4; Tom Reedy,
Florida Municipal Power Pool, 6; - Brandon McCormick, Group Name FMPA
Answer

No

Document Name
Comment
FMPA does not agree with the implementation proposal timeline. The time to implement R1 (develop a plan) should be 12 months from the time of the
order.
Due to technical complexity, agreements (outsourced and between registered entities), procurement, contracts and coordination between registered
entities (and provisioning of private networks), FMPA requests that the SDT consider the following options for R2 implementation:
•

additional 24 months allowed to undertake implementation,

•

using a phased implementation over a five or longer year period, or

•

in recognition that there is the potential for several existing contracts will have to be replaced (and associated equipment) that affected contracts
be grandfathered until new and or, replacements can be put in place.

Likes

0

Dislikes

0

Response

Frank Pace - Central Hudson Gas & Electric Corp. - 1
Answer
Document Name
Comment

No

It would appear that the proposed implementation period is too short; however, it is difficult to determine if a demarcation point for compliance is not
specified within the language of the Requirement.
Likes

0

Dislikes

0

Response

Donald Lock - Talen Generation, LLC - 5
Answer

No

Document Name
Comment
The 12-month period provided in the implementation plan should be at least doubled. Developing a clear understanding of what is required could take
some time, and to then scope the project, obtain bids and budget approval, receive materials and implement in whatever portion of the year remains
may prove impractical.
Likes

0

Dislikes

0

Response

David Rivera - New York Power Authority - 3
Answer

No

Document Name
Comment
1. The time to implement R1 (develop plan) could be 12 months from time of order. For implementation of R2 there should be an additional 24
months allowed to undertake implementation. This would include identifying all links and protections, with changes needed to address
communications service contracts and related relationships to adjust for new protections. This would also involve inventory of data to comply
with identification of all data transmitted between control centers.
2. Due to technical complexity, agreements (outsourced and between Entities), procurement, contracts and coordination between Entities (and
provisioning of private networks), request that the SDT also consider the following option for R2 implementation:
i. a phased implementation over a five or longer year period, or
ii. to avoid impacting reliability, existing contracts, equipment, etc be grandfathered until new / replacements are in place.
Likes

0

Dislikes

0

Response

Jennifer Hohenshilt - Talen Energy Marketing, LLC - 6

Answer

No

Document Name
Comment
The 12-month period provided in the implementation plan should be at least doubled. Developing a clear understanding of what is required could
take some time, and to then scope the project, obtain bids and budget approval, receive materials and implement in whatever portion of the year
remains may prove impractical.
Likes

0

Dislikes

0

Response

Dana Klem - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO NSRF
Answer

No

Document Name
Comment
The 12 month time period may only work for Entities who are vertically intergraded. The flow of applicable BES data within CIP-012-1 can be viewed as
a “spider web” of data transfer for large RC foot-prints. With this being said, there may be non-compliance issues when one side of the data
transference is protected and the other side is not. The SDT should propose a phased in approach to protecting data. A five (5) year implementation
plan will allow entities to fund these projects. This is especially important to small entities. Per the NERC Guidance concerning “Phase Implementation
Plans with Completion Percentages
(http://www.nerc.com/pa/comp/guidance/CMEPPracticeGuidesDL/CMEP_Practice_Guide_Phased_Implementation_Completion_Percentages.pdf)
please state that the CIP-012-1 does not fall under this guidance.
Likes

0

Dislikes

0

Response

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer

No

Document Name
Comment
See APPA Comments.
Likes
Dislikes

0
0

Response

James Poston - Santee Cooper - 3, Group Name Santee Cooper
Answer

No

Document Name
Comment
Recommend a 2 year Implementation Plan Period. For some entities, it may take a significant amount of time to agree on communication protocols and
architecture with neighboring systems. Time is also needed to troubleshoot and test each connection point.
Likes

0

Dislikes

0

Response

Marty Hostler - Northern California Power Agency - 5
Answer

No

Document Name
Comment
NCPA does not agree with the implementation proposal timeline. Due to technical complexity, agreements (outsourced and between REs),
procurement, contracts and coordination between REs (and provisioning of private networks), NCPA requests that the SDT consider the following
options for R2 implementation:

•

additional 24 months allowed to undertake implementation,

•

using a phased implementation over a five or longer year period, or

•

in recognition that there is the potential for several existing contracts will have to be replaced (and associated equipment) that affected contracts
be grandfathered until new and or, replacements can be put in place.

Likes

0

Dislikes

0

Response

Dennis Sismaet - Northern California Power Agency - 6
Answer
Document Name

No

Comment
NCPA does not agree with the implementation proposal timeline. Due to technical complexity, agreements (outsourced and between REs),
procurement, contracts and coordination between REs (and provisioning of private networks), NCPA requests that the SDT consider the following
options for R2 implementation:

•

additional 24 months allowed to undertake implementation,

•

using a phased implementation over a five or longer year period, or

•

in recognition that there is the potential for several existing contracts will have to be replaced (and associated equipment) that affected contracts
be grandfathered until new and or, replacements can be put in place.

Likes

0

Dislikes

0

Response

Vivian Vo - APS - Arizona Public Service Co. - 3
Answer

No

Document Name
Comment
The proposed implementation plan does not consider complexities associated with implementing technical solutions reliant on inter-entity coordination
and agreement. The proposed implementation plan does not recognize the prerequisite of mutual agreement between entities regarding a compatible
technical solution or the time necessary to complete such prerequisite. Moreover, it does not appear to contemplate a potential need for dispute
resolution when a transmitting entity and receiving entity cannot agree on a solution. Finally, any implementation, testing, etc. can only occur once the
mutually agreed-upon solution has been identified, budgeted, and procured. For these reasons, AZPS proposes extending the implementation plan to
at least twenty-four (24) calendar months. Two years would likely allot adequate time to identify, agree upon, and procure appropriate technical
solutions in coordination with other entities.
Likes

0

Dislikes

0

Response

David Gordon - Massachusetts Municipal Wholesale Electric Company - 5
Answer
Document Name
Comment

No

The Implementation Plan should be modified to allow 24 months for the implementation phase (R2) due to the potential impact resulting from the
necessity of redesigning communications architectures for secure communications between Control Centers.
Likes

0

Dislikes

0

Response

Heather Morgan - EDP Renewables North America LLC - 5
Answer

No

Document Name
Comment
Generator Operator Control Centers are required to follow specifications pursuant to the requirements outlined by RCs, ISO,s RTOs, BAs, and TOPs.
To ensure GOP’s are able to properly carry out requirements for all of these parties and CIP-012-2, CIP-012-2’s Implementation Plan should be phased
in similar to IRO-010, and TOP-003. Otherwise, GOP Control Centers will not be able to properly plan for any requirements delivered by the
interconnecting authorities as a result of this Standard.

Likes

0

Dislikes

0

Response

Quintin Lee - Eversource Energy - 1, Group Name Eversource Group
Answer

No

Document Name
Comment
Request changing 12 months to 18 months in the implentation plan to allow time to make any required changes including design, procurement, CIP
assesment and deployment.
Likes

0

Dislikes

0

Response

Aaron Austin - AEP - 3
Answer

No

Document Name
Comment
AEP suggests that the implementation time frame should be extended to at least 24 months to allow for activities such as coordination,
budgeting, procurement, implementation and testing.
Likes

0

Dislikes

0

Response

Barry Lawson - National Rural Electric Cooperative Association - 4
Answer

No

Document Name
Comment
NRECA asserts that smaller entities may need to procure equipment and implement technical controls that are not currently in place. The
implementation of the plan(s) detailed in requirement R1 could be impacted by budget cycles, procurement processes, and third party vendor
availability. NRECA recommends that the implementation plan be revised to allow 12 months for the development of the plan in requirement R1 and 24
months for the implementation.
Likes

0

Dislikes

0

Response

Nicolas Turcotte - Hydro-Qu?bec TransEnergie - 1
Answer

No

Document Name
Comment
Hydro Québec is in agreement with TFIST’s comments below in regards to taking into consideration technical complexities and coordination between
entities; however we suggest that the documented plan in R1 include an implementation plan with deadlines not exceeding 36 months, rather than a
prescribed delay for implementing R2. Furthermore, clarifications are requested in regards to the question“please note the actions you will take that
require this amount of time to complete.
1. The time to implement R1 (develop plan) could be 12 months from time of order. For implementation of R2 there should be an additional 24
months allowed to undertake implementation. This would include identifying all links and protections, with changes needed to address
communications service contracts and related relationships to adjust for new protections. This would also involve inventory of data to comply
with identification of all data transmitted between control centers.

2. Due to technical complexity, agreements (outsourced and between Entities), procurement, contracts and coordination between Entities (and
provisioning of private networks), request that the SDT consider:
a )a phased implementation over a five or longer year period, or b) to avoid impacting reliability, that existing contracts, equipment, etc stay in place.
New contracts / equipment will need to follow this new Standard.
Likes

0

Dislikes

0

Response

Lona Calderon - Salt River Project - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
SRP requests 24 calendar months due to the complex details and logistics associated with implementation. The Impact from encryption is unknown.
Because the data is being sent in real-time, it is difficult to test how encryption will affect reliability.
More research and evaluation is required to understand the implications encryption will have as it may require architecture changes to account for the
extra computing resources required. Additionally, time is required to budget for funds in order to support any required infrastructure improvements
required.
Likes

0

Dislikes

0

Response

Thomas Breene - WEC Energy Group, Inc. - 3
Answer

No

Document Name
Comment
The 12 month time period may only work for Entities who are vertically intergraded. The flow of applicable BES data within CIP-012-1 can be viewed as
a “spider web” of data transfer for large RC foot-prints. With this being said, there may be non-compliance issues when one side of the data
transference is protected and the other side is not. The SDT should propose a phased in approach to protecting data. A five (5) year implementation
plan will allow entities to fund these projects. This is especially import to small entities. Per the NERC Guidance concerning “Phase Implementation
Plans with Completion Percentages
(http://www.nerc.com/pa/comp/guidance/CMEPPracticeGuidesDL/CMEP_Practice_Guide_Phased_Implementation_Completion_Percentages.pdf)
please state that the CIP-012-1 does not fall under this guidance.
Likes
Dislikes

0
0

Response

Russell Noble - Cowlitz County PUD - 3
Answer

No

Document Name
Comment
Cowlitz PUD supports the comments submitted by APPA.
Likes

0

Dislikes

0

Response

Jesus Sammy Alcaraz - Imperial Irrigation District - 1
Answer

No

Document Name
Comment
We recommend at least 18 months due to the quantity of details and logistics.
Likes

0

Dislikes

0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Con-Edison and Dominion
Answer

No

Document Name
Comment
·
The time to implement R1 (develop plan) could be 12 months from time of order. For implementation of R2 there should be an additional 24
months allowed to undertake implementation. This would include identifying all links and protections, with changes needed to address communications
service contracts and related relationships to adjust for new protections. This would also involve inventory of data to comply with identification of all
data transmitted between control centers.
·
Due to technical complexity, agreements (outsourced and between Entities), procurement, contracts and coordination between Entities (and
provisioning of private networks), request that the SDT also consider the following option for R2 implementation:

a.

a phased implementation over a five or longer year period, or

b.

to avoid impacting reliability, existing contracts, equipment, etc. be grandfathered until new / replacements are in place.

Likes

0

Dislikes

0

Response

Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer

No

Document Name
Comment
ERCOT ISO signs on to the ITC SWG comments:
The ITC SWG also encourages the drafting team to make the requirement forward-looking in regards to contracts currently in place. Provisions should
be set for legacy contracts including grandfathering of existing agreements and equipment. Implementation of controls involving telecommunications
providers will require coordination and scheduling to align to the providers’ resource availability and reduce adverse impact on reliability. This should not
require renewal and renegotiation of existing contracts until they reach the end of the existing contract period.
It should be noted that it is difficult to determine suitability of the implementation timeline when there are open questions about the viability of available
solutions for adequate protections.
More time is necessary to allow for coordination with a large number of parties. This will require budgeting, planning, and scheduling with external
resources for implementation. It will also require significant testing and validation by parties on both ends of a connection.
The ITC SWG recommends a phased implementation with defined milestones similar to CIP-014. Consider the following:
•

For creation of the plan, 12 months should be allowed to (1) conduct an impact assessments, (2) identify the approach to be included in the
plan, (3) implementation milestones, and (4) implementation schedule. This could identify the communication links that have protections
currently in place. The plan could also include identifying all links and protections requiring changes to address service contracts and related
relationships to adjust for new protections. The plan could then be approved by an appropriate entity.

•

For implementation of the plan, additional time should be allowed for budgeting, planning, and scheduling with external resources. This includes
planning with other Responsible Entities as well as telecommunications providers.

Likes

0

Dislikes

0

Response

Shelby Wade - PPL - Louisville Gas and Electric Co. - 3,5,6 - SERC, Group Name Louisville Gas and Electric Company and Kentucky Utilities
Company

Answer

No

Document Name
Comment
We support SERC's comments.
Likes

0

Dislikes

0

Response

Marc Donaldson - Tacoma Public Utilities (Tacoma, WA) - 3
Answer

No

Document Name
Comment
Tacoma Power supports the comments of APPA
Likes

0

Dislikes

0

Response

Theresa Rakowsky - Puget Sound Energy, Inc. - 1
Answer

No

Document Name
Comment
PSE believes a 24 month implementation period and/or phased implementation approach is appropriate due to required coordination between
registered entities, potential need for renegotiation of contracts and/or agreements with other entities, and potential for significant technical complexity
for implementation.
Likes

0

Dislikes

0

Response

Jack Cashin - American Public Power Association - 4
Answer

No

Document Name
Comment
APPA does not agree with the implementation proposal timeline. The time to implement R1 (develop a plan) should be 12 months from the time of the
order.
Due to technical complexity, agreements (outsourced and between registered entities), procurement, contracts and coordination between registered
entities (and provisioning of private networks), APPA requests that the SDT consider the following options for R2 implementation:
• additional 24 months allowed to undertake implementation,
• using a phased implementation over a five or longer year period
•

in recognition that there is the potential for several existing contracts will have to be replaced (and associated equipment) that affected contracts
be grandfathered until new and or, replacements can be put in place.

Likes

0

Dislikes

0

Response

Lan Nguyen - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
CenterPoint Energy recommends the effective date for CIP-012-1 to be 24 months after FERC approval. For instances where applicable data is being
transmitted between Control Centers owned by two or more separate Responsible Entities, additional time is needed to coordinate plans and develop
agreements to ensure adequate protection is applied.
Likes

0

Dislikes

0

Response

Warren Cross - ACES Power Marketing - 1,3,4,5 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Standards Collaborators
Answer
Document Name
Comment

No

New entities that are impacted by the new definition should be treated as “newly identified CIP facilities” and should be given the standard 18 month
implementation period. Not the proposed 12 month implementation period. Budgetary cycles would need to be considered and an additional reason for
the 18 months.
Likes

0

Dislikes

0

Response

Sheranee Nedd - PSEG - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer

No

Document Name
Comment
PSEG Supports the NPCC comments.
Likes

1

Dislikes

PSEG - PSEG Fossil LLC, 5, Kucey Tim
0

Response

Michael Puscas - ISO New England, Inc. - 2
Answer

No

Document Name
Comment
The time to implement the first requirement (develop plan) could be 12 months from time of order. For implementation of the plan, however (R2) there
should be an additional 12 months allowed to undertake implementation. This would include identifying all links and protections, with changes needed
to address communications service contracts and related relationships to adjust for new protections.
Likes

0

Dislikes

0

Response

David Greyerbiehl - CMS Energy - Consumers Energy Company - 5
Answer
Document Name
Comment

No

Twelve calendar months for implementation may not be sufficient, twenty-four calendar months should be recommended.
Likes

0

Dislikes

0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
BPA requests clarification about what “Physically protecting the communication links transmitting the data” in section 1.1 means. If it means protecting
the data at the source (at the Control Center), the implementation period is acceptable. BPA will be required to update customer agreements during the
implementation period.
If it means the data must be protected throughout the transmission, it would seem that could only be accomplished with encryption. For cases where the
existing equipment is not capable of encryption, BPA cannot propose an implementation timeline or solution other than technically feasible exception.
Likes

0

Dislikes

0

Response

James Anderson - CMS Energy - Consumers Energy Company - 1
Answer

No

Document Name
Comment
Twelve calendar months for implementation may not be sufficient, twenty-four calendar months should be recommended.
Likes

0

Dislikes

0

Response

Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer
Document Name

No

Comment
Utility Services does not agree with the implementation proposal timeline. The time to implement R1 (develop a plan) should be 12 months from the
time of the order.

Due to technical complexity, agreements (outsourced and between registered entities), procurement, contracts and coordination between registered
entities (and provisioning of private networks), UTILITY SERVICES requests that the SDT consider the following options for R2 implementation:

·

additional 24 months allowed to undertake implementation,

·

using a phased implementation over a five or longer year period, or

·
in recognition that there is the potential for several existing contracts will have to be replaced (and associated equipment) that affected contracts
be grandfathered until new and or, replacements can be put in place.
Likes

0

Dislikes

0

Response

Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer

No

Document Name
Comment
Southern Company feels that 12 months is not enough time to implement the Standard as currently written. Implementation of the proposed methods of
compliance could embark entities on budget and procurement processes to acquire new, upgraded, or revamped hardware, software, or other physical
components at existing sites, and this can be a lengthy process. Southern recommends at least a 24 month or greater implementation
timeframe. Southern agrees with comments provided by other commenters that the complexity of the technology solutions to be implemented, the
number of interconnecting lines to secure, connection point testing, and coordination requirements with external stakeholders are additional factors
supporting a 2 year implementation period.
Likes

0

Dislikes

0

Response

Ronald Donahey - TECO - Tampa Electric Co. - 3
Answer
Document Name

No

Comment
If additional contracts/agreements are required to address a plan for other entities, Registered Entities may need a longer time to implement the plan
(Requirement R2). Tampa Electric Company recommends an 18 month timeframe for Requirement 2.
Likes

0

Dislikes

0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

No

Document Name
Comment
The Standard Review Group has a concern that all Implementation needs may not be met in a timely fashion at the twelve (12) calendar month time
frame. We would recommend that the drafting team extends the deadline to eighteen (18) calendar months. Due to technological changes needed to
secure the data and collaboration between sending and receiving party, we feel more time is needed to implement the standard.
Likes

0

Dislikes

0

Response

Wendy Center - U.S. Bureau of Reclamation - 5
Answer

No

Document Name
Comment
Eighteen calendar months after the approval of the control center definition and the CIP-012-1 standard to allow entities time to evaluate the impact of
the changes effected by the new standard and implement an appropriate response.
Likes

0

Dislikes

0

Response

James Gower - Entergy - NA - Not Applicable - SERC
Answer
Document Name

No

Comment
Cannot support at this time until additional clarity is given to requirements for written communications outside of operational data and for Operational
Planning Analysis data. If corporate systems require protection that could greatly affect implementation timelines. Additionally, the twelve month window
may fall outside of yearly budget planning, compressing project planning timelines.
Likes

0

Dislikes

0

Response

Mark Riley - Associated Electric Cooperative, Inc. - 1
Answer

No

Document Name
Comment
AECI asserts that smaller entities may need to procure equipment and implement technical controls that are not currently in place. The implementation
of the plan(s) detailed in requirement R1 could be impacted by budget cycles, procurement processes, and third party vendor availability. AECI
recommends that the implementation plan be revised to allow 12 months for the development of the plan in requirement R1 and 24 months for the
implementation
Likes

0

Dislikes

0

Response

Guy Andrews - Georgia System Operations Corporation - 4
Answer

No

Document Name
Comment
•

Additional time would be required to plan, budget, and implement this Standard. Further, only allowing 12 months for implementation may limit
the technology solutions that may be implemented to only those that can be accomplished with minimal planning and testing. GSOC requests
twenty-four months.

Likes

0

Dislikes

0

Response

Annette Johnston - Berkshire Hathaway Energy - MidAmerican Energy Co. - 3
Answer

No

Document Name
Comment
At least three years is needed in order to coordinate with other entities, including specification, design, budgeting, implementation and testing.
Likes

0

Dislikes

0

Response

Terry Harbour - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1
Answer

No

Document Name
Comment
See MidAmerican Energy Company comments.
Likes

0

Dislikes

0

Response

Haley Sousa - Public Utility District No. 1 of Chelan County - 5
Answer

No

Document Name
Comment
The coordination time required to perform a migration to secure communications protocols is expected to take longer than the schedule presented by
the SDT. CHPD recommends at least twenty-four (24) calendar months to implement communication updates and implement other available protection
measures.
Likes

0

Dislikes

0

Response

Janis Weddle - Public Utility District No. 1 of Chelan County - 6
Answer
Document Name

No

Comment
The coordination time required to perform a migration to secure communications protocols is expected to take longer than the schedule presented by
the SDT. CHPD recommends at least twenty-four (24) calendar months to implement communication updates and implement other available protection
measures.
Likes

0

Dislikes

0

Response

sean erickson - Western Area Power Administration - 1
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

David Greene - SERC Reliability Corporation - 10, Group Name SERC CIPC
Answer

No

Document Name

3B-2016-02_CIP-012-1_Unofficial_Comment_Form_CIPC.docx

Comment

Likes

0

Dislikes

0

Response

Lauren Price - American Transmission Company, LLC - 1
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Answer

Yes

Document Name
Comment
A region-wide agreement may be difficult to develop and execute in a year. Tri-State believes 18 months would be more appropriate.
Likes

0

Dislikes

0

Response

Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer

Yes

Document Name
Comment
Xcel Energy believes that the Implementation Plan would allow sufficient time for our operating companies to implement required controls specified in
the language of CIP-012-1. However, Xcel Energy would require coordination from up to 25 other Responsible Entities is communicates BES data with
and cannot speak to their abilities. Any agreements in coordination between entities would need to go through a legal review process, which could take
more than 12 months to formalize and implement. A 24 month implementation period may be more feasible given the legal review challenges that
would inevitably occur.
Likes

0

Dislikes

0

Response

David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment
OPG has some concerns and recommends a graded approach implementation over a longer period of time. The communications links requiring
protections will require inventory; this will be a complex task for the RC.

The recommended 12 months may be sufficient for the inventory, however we also need to determine the applicable solution and agree on the solution
with another entities.
Likes

0

Dislikes

0

Response

Laura McLeod - NB Power Corporation - 5
Answer

Yes

Document Name
Comment
See 1 above. Note that additional time may be required to reach consensus between entities when establishing security protocols.
Likes

0

Dislikes

0

Response

Douglas Webb - Douglas Webb On Behalf of: Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., 3, 5, 1, 6; James McBee,
Great Plains Energy - Kansas City Power and Light Co., 3, 5, 1, 6; Jessica Tucker, Great Plains Energy - Kansas City Power and Light Co., 3,
5, 1, 6; Jim Flucke, Great Plains Energy - Kansas City Power and Light Co., 3, 5, 1, 6; - Douglas Webb
Answer

Yes

Document Name
Comment
The company will review current systems and protections to identify if further action is required to protect the communications links between control
centers as set forth in the approved Standard.
Likes

0

Dislikes

0

Response

RoLynda Shumpert - SCANA - South Carolina Electric and Gas Co. - 1,3,5,6 - SERC
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

Nicholas Lauriat - Network and Security Technologies - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Dermot Smyth - Con Ed - Consolidated Edison Co. of New York - 5, Group Name Con Edison
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Philip Huff - Arkansas Electric Cooperative Corporation - 3
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Shannon Fair - Colorado Springs Utilities - 1,3,5,6, Group Name Colorado Springs Utilities
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Alice Wright - Arkansas Electric Cooperative Corporation - 4
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Chris Scanlon - Exelon - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Michael Shaw - Lower Colorado River Authority - 1, Group Name LCRA Compliance
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

Laurie Williams - PNM Resources - Public Service Company of New Mexico - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Lynn Goldstein - PNM Resources - Public Service Company of New Mexico - 3
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Richard Vine - California ISO - 2
Answer
Document Name
Comment
The California ISO supports the comments of the Security Working Group (SWG).
Likes

0

Dislikes
Response

0

Kristine Ward - Seminole Electric Cooperative, Inc. - 1,2,4,5,6 - FRCC
Answer
Document Name
Comment
SECI would like examples of evidence so we know how to proceed
Likes

0

Dislikes

0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
This question implies there are NERC Glossary terms in the Implementation Plan. There are no NERC Glossary terms in the CIP-012-1 Implementation
Plan.

Texas RE does not oppose the enforcement timelines set forth in the proposed Implementation Plan. However, Texas RE respectfully requests that the
SDT provide a specific justification for any proposed implementation timeframes, as well as any revisions to the timeframes as currently proposed. The
goal is to ensure there are no issues with the implementation plan such as not having an initial performance date where one is needed or not including
information for new facilities such as the instance that led to an errata change in the PRC-023-4 implementation plan. These issues cause confusion
and ambiguity for both registered entities and Regional Entities upon enforcement of the standard.
Likes

0

Dislikes

0

Response

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 3, Group Name FirstEnergy Corporation
Answer
Document Name
Comment
FirstEnergy recommends adjusting the Implementation Plan time period to become effective the first day of the first calendar quarter that is
eighteen (18) calendar months after the effective date of the applicable governmental authority’s order approving the standard. The

additional time will be needed to ensure that the implementation of any new technology (e.g. encryption) does not impact reliability of the
BES.
Likes

0

Dislikes
Response

0

4. The SDT believes proposed CIP-012-1 provides entities with flexibility to meet the reliability objectives in a cost effective manner. Do you
agree? If you do not agree, or if you agree but have suggestions for improvement to enable more cost effective approaches, please provide
your recommendation and, if appropriate, technical justification.
Janis Weddle - Public Utility District No. 1 of Chelan County - 6
Answer

No

Document Name
Comment
CHPD cannot determine if the objectives may be accomplished in a cost-effective manner until further clarification is provided for physical or other
equally effective protection measures and the request for electronic mail exclusion is added. CHPD also has concerns with vendor availability, with
respect to the system software implementation that will be required for all entities industry-wide. The comments provided by other entities to develop an
industry-wide encryption specification is appealing and CHPD believes that would provide a better method for achieving the desired intra-entity security.
Likes

0

Dislikes

0

Response

Haley Sousa - Public Utility District No. 1 of Chelan County - 5
Answer

No

Document Name
Comment
CHPD cannot determine if the objectives may be accomplished in a cost-effective manner until further clarification is provided for physical or other
equally effective protection measures and the request for electronic mail exclusion is added. CHPD also has concerns with vendor availability, with
respect to the system software implementation that will be required for all entities industry-wide. The comments provided by other entities to develop an
industry-wide encryption specification is appealing and CHPD believes that would provide a better method for achieving the desired intra-entity security.
Likes

0

Dislikes

0

Response

Laura McLeod - NB Power Corporation - 5
Answer
Document Name
Comment

No

See 2 above.
Likes

0

Dislikes

0

Response

James Gower - Entergy - NA - Not Applicable - SERC
Answer

No

Document Name
Comment
Cannot agree with the flexibility and cost effectiveness until additional clarity is given to requirements for written communications outside of operational
data and Operational Planning Analysis. If corporate systems require protection that could greatly affect potential cost.
Likes

0

Dislikes

0

Response

Ronald Donahey - TECO - Tampa Electric Co. - 3
Answer

No

Document Name
Comment
Until industry is able to determine the extent of information to be protected extends beyond the real-time 15 minute time frame, we are not able to agree
with the statement regarding cost-effective manner.
Likes

0

Dislikes

0

Response

Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Document Name
Comment

No

The cost of implementing the intended protections, as they are understood by Southern, will be prohibitive. See the response to Question 1 as the
primary driver for our disagreement with this question, as well as other supporting information provided in response to Question 3.
Likes

0

Dislikes

0

Response

James Anderson - CMS Energy - Consumers Energy Company - 1
Answer

No

Document Name
Comment
More flexibility and less guidance could lead to inconsistency on requirement implementation among different entities.
Likes

0

Dislikes

0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
If it means the data must be protected throughout the transmission, it would seem that could only be accomplished with encryption. For cases where the
existing equipment is not capable of encryption, replacement will be costly and implementation lengthy.
Likes

0

Dislikes

0

Response

David Greyerbiehl - CMS Energy - Consumers Energy Company - 5
Answer
Document Name
Comment

No

More flexibiity and less guidance could lead to inconsistency on requirement implentation among different entities.
Likes

0

Dislikes

0

Response

Michael Puscas - ISO New England, Inc. - 2
Answer

No

Document Name
Comment
To fully assess the logistics and costs associated with compliance, some guidance or specification of boundaries of communications links involved
would be required for entities to complete assessment of impacts to their operations.
Likes

0

Dislikes

0

Response

Warren Cross - ACES Power Marketing - 1,3,4,5 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Standards Collaborators
Answer

No

Document Name
Comment
(1) The standard doesn’t directly address the Inter-Control Center Communications Protocol (ICCP) for exchanging data between control centers or
utilities. Will those ICCP servers and supportive infrastructure need to be upgraded or replaced with data encryption capabilities to support compliance
with this standard?

(2) The standard doesn’t provide any direction as to what is the level of physical and logical protection that is mandatory. We ask the SDT to develop
guidance to clarify this ambiguity and identify how all entities can achieve a minimum level of compliance.
Likes

0

Dislikes

0

Response

Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2

Answer

No

Document Name
Comment
ERCOT ISO signs on to the ITC SWG comments:
In addition to the comments provided in response to question 3, the SWG offers these comments regarding cost effectiveness. Open Source options to
satisfy the requirement to protect communication links and sensitive bulk electric system data communicated between bulk electric systems Control
Centers are limited. Few options generally translated to high vendor leverage, which could lead to high implementation costs. It is unclear how or
whether costs could be shared among participants in the network. Architectural changes to support these requirements should be spread out over
several years. Plus there will be business impacts.
Likes

0

Dislikes

0

Response

Lona Calderon - Salt River Project - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
SRP needs more detail on what would be acceptable as physical security to determine if the standard provides adequate flexibility. Also, as stated in
response to question 3, significant capital may need to be budgeted in order to implement architecture improvements to address the required computing
resources for encrypting and decrypting of data. Additionally, SRP agrees with LPPC’s comment that an industry-wide initiative for an encryption
specification may be a more cost-effective approach than a new standard.
Likes

0

Dislikes

0

Response

Aaron Austin - AEP - 3
Answer

No

Document Name
Comment
AEP believes that most entities are at the mercy of what Balancing Authorities and Reliability Coordinators will require. This coupled with
the fact that data for Operational Planning and Analysis is included, flexibility may lead to variability and as such makes it only a
presumption that solutions will be cost effective.
Likes

0

Dislikes

0

Response

Dennis Sismaet - Northern California Power Agency - 6
Answer

No

Document Name
Comment
NCPA does not agree that the standard provides entities with the flexibility to implement the standard cost-effectively and offers these further
suggestions. To fully assess the logistics and costs associated with compliance, some guidance or specification of boundaries of communications links
involved would be required for entities to complete assessment of impacts to their operations. In addition, architectural changes should be spread out
over several budget cycles (years).
Likes

0

Dislikes

0

Response

Marty Hostler - Northern California Power Agency - 5
Answer

No

Document Name
Comment
NCPA does not agree that the standard provides entities with the flexibility to implement the standard cost-effectively and offers these further
suggestions. To fully assess the logistics and costs associated with compliance, some guidance or specification of boundaries of communications links
involved would be required for entities to complete assessment of impacts to their operations. In addition, architectural changes should be spread out
over several budget cycles (years).
Likes

0

Dislikes

0

Response

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer
Document Name
Comment
See APPA Comments.

No

Likes

0

Dislikes

0

Response

Alice Wright - Arkansas Electric Cooperative Corporation - 4
Answer

No

Document Name
Comment
See attachment
Likes

0

Dislikes

0

Response

Philip Huff - Arkansas Electric Cooperative Corporation - 3
Answer

No

Document Name
Comment
Please see our comments to Question 1. The additional flexibility in this context has the potential to cause more confusion when selecting a
mechanisms to secure the data.
Likes

0

Dislikes

0

Response

David Rivera - New York Power Authority - 3
Answer

No

Document Name
Comment
1. To fully assess the logistics and costs associated with compliance, some guidance or specification of boundaries of communications links
involved would be required for entities to complete assessment of impacts to their operations.
2. Architectural changes should be spread out over several budget cycles (years). Plus there will be business impacts. See comments to Q3
Likes

0

Dislikes

0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer

No

Document Name
Comment
In addition to the comments provided in response to question 3, the IESO offers these comments regarding cost effectiveness. Open Source options to
satisfy the requirement to protect communication links and sensitive bulk electric system data communicated between bulk electric systems Control
Centers are limited. Few options generally translated to high vendor leverage, which could lead to high implementation costs. It is unclear how or
whether costs could be shared among participants in the network. Architectural changes to support these requirements should be spread out over
several years. Plus there will be business impacts.
Likes

2

Dislikes

Hydro One Networks, Inc., 1, Farahbakhsh Payam; Hydro One Networks, Inc., 3, Malozewski Paul
0

Response

Joe Tarantino - Joe Tarantino On Behalf of: Arthur Starkovich, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Beth Tincher, Sacramento
Municipal Utility District, 4, 1, 5, 6, 3; Jamie Cutlip, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Kevin Smith, Balancing Authority of
Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Susan Oto, Sacramento Municipal Utility District, 4, 1,
5, 6, 3; - Joe Tarantino
Answer

No

Document Name
Comment

It may be more cost effective if an industry wide initiative is conducted with encryption specifications.

Likes

0

Dislikes

0

Response

Laura Nelson - IDACORP - Idaho Power Company - 1
Answer
Document Name

No

Comment
There will likely be additional costs associated with administrative overhead, hardware, and software, as well as costs associated with monitoring the
performance of the implemented solutions.
Likes

0

Dislikes

0

Response

Brian Millard - Tennessee Valley Authority - 1,3,5,6 - SERC, Group Name Tennessee Valley Authority
Answer

No

Document Name
Comment
TVA suggests additional guidance is needed to identify examples of acceptable standard security mechanisms for exchanging data between
entities. Without clearer guidance some entities may out of an abundance of caution spend beyond what is necessary to mitigate this risk, or expend
unnecessary effort determining a mutual security mechanism.
Likes

0

Dislikes

0

Response

Lauren Price - American Transmission Company, LLC - 1
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Terry Harbour - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1
Answer
Document Name
Comment

Yes

See MidAmerican Energy Company comments.
Likes

0

Dislikes

0

Response

Annette Johnston - Berkshire Hathaway Energy - MidAmerican Energy Co. - 3
Answer

Yes

Document Name
Comment
The three bullets are constructive.
Likes

0

Dislikes

0

Response

Guy Andrews - Georgia System Operations Corporation - 4
Answer

Yes

Document Name
Comment
no comments
Likes

0

Dislikes

0

Response

David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment
OPG recommends further collaboration to further enhance the cost effectiveness. Solution implementation will require collaboration when the
communication link is between CC belonging to different entities. There is also the issue of agreed solution; for example the stronger the protection

implemented the higher the budgetary costs. If this may not be an issue for the RC it can be an issue for a small entity required to report to the RC via
these communication links.
Likes

0

Dislikes

0

Response

Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment
Utility Services agrees that the standard provides entities with the flexibility to implement the standard cost-effectively and offers these further
suggestions. To fully assess the logistics and costs associated with compliance, some guidance or specification of boundaries of communications links
involved would be required for entities to complete assessment of impacts to their operations. In addition, architectural changes should be spread out
over several budget cycles (years).
Likes

0

Dislikes

0

Response

Sheranee Nedd - PSEG - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer

Yes

Document Name
Comment
PSEG supports the NPCC comments.
Likes

1

Dislikes

PSEG - PSEG Fossil LLC, 5, Kucey Tim
0

Response

Marc Donaldson - Tacoma Public Utilities (Tacoma, WA) - 3
Answer
Document Name
Comment

Yes

Tacoma Power supports the comments of APPA
Likes

0

Dislikes

0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Con-Edison and Dominion
Answer

Yes

Document Name
Comment
·
To fully assess the logistics and costs associated with compliance, some guidance or specification of boundaries of communications links
involved would be required for entities to complete assessment of impacts to their operations.
·

Architectural changes should be spread out over several budget cycles (years), and there will be business impacts. See comments to Q3

Likes

0

Dislikes

0

Response

Russell Noble - Cowlitz County PUD - 3
Answer

Yes

Document Name
Comment
Cowlitz PUD supports the comments submitted by APPA.
Likes

0

Dislikes

0

Response

Thomas Breene - WEC Energy Group, Inc. - 3
Answer
Document Name
Comment

Yes

Thank you for adding the third bullet of R1.
Likes

0

Dislikes

0

Response

Nicolas Turcotte - Hydro-Qu?bec TransEnergie - 1
Answer

Yes

Document Name
Comment
1. To fully assess the logistics and costs associated with compliance, some guidance or specification of boundaries of communications links
involved would be required for entities to complete assessment of impacts to their operations.
2. Architectural changes should be spread out over several budget cycles (years). Plus there will be business impacts. See comments to Q3.
Likes

0

Dislikes

0

Response

Heather Morgan - EDP Renewables North America LLC - 5
Answer

Yes

Document Name
Comment
None at this time
Likes

0

Dislikes

0

Response

Vivian Vo - APS - Arizona Public Service Co. - 3
Answer
Document Name
Comment

Yes

While the Standard is sufficiently flexible for an individual responsible entity, it leaves a potential chasm between different entities’ interpretation of costeffective approaches. A top-tier utility’s impression of a cost effective approach may not match a smaller neighbor’s idea of a cost effective
approach. Such a disparity could encumber both large and small entities with disparate concerns that complicate negotiation and agreement on
appropriate solutions.
Likes

0

Dislikes

0

Response

Chris Scanlon - Exelon - 1
Answer

Yes

Document Name
Comment
Exelon agrees with the approach used in CIP-012-1, which allows each Registered Entity to analyze risk and use discretion in determining the best risk
mitigation implementation for protecting transmission of applicable data.
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0

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Dana Klem - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO NSRF
Answer

Yes

Document Name
Comment
Thank you for adding the third bullet of R1
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0

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Dermot Smyth - Con Ed - Consolidated Edison Co. of New York - 5, Group Name Con Edison
Answer
Document Name
Comment

Yes

To fully assess the logistics and costs associated with compliance, some guidance or specification of boundaries of communications links involved
should be provided so that entities can perform an assessment of impacts to their operations.

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0

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Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment
Duke Energy agrees that the language provided in R1 appears to provide a Responsible Entity flexibility in how it may implement the standard, but
concern exists in the amount of protection options given. Additional documentation such as Implementation Guidance including additional suggestions
for implementation may give entities more options to consider, while still keeping the flexibility of determining what is the most suitable method of
protection for said entity.
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0

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Douglas Webb - Douglas Webb On Behalf of: Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., 3, 5, 1, 6; James McBee,
Great Plains Energy - Kansas City Power and Light Co., 3, 5, 1, 6; Jessica Tucker, Great Plains Energy - Kansas City Power and Light Co., 3,
5, 1, 6; Jim Flucke, Great Plains Energy - Kansas City Power and Light Co., 3, 5, 1, 6; - Douglas Webb
Answer

Yes

Document Name
Comment

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0

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0

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Laurie Williams - PNM Resources - Public Service Company of New Mexico - 1
Answer

Yes

Document Name
Comment

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0

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0

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Wendy Center - U.S. Bureau of Reclamation - 5
Answer

Yes

Document Name
Comment

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0

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0

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Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

Yes

Document Name
Comment

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0

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0

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Michael Shaw - Lower Colorado River Authority - 1, Group Name LCRA Compliance
Answer

Yes

Document Name
Comment

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0
0

Response

David Greene - SERC Reliability Corporation - 10, Group Name SERC CIPC
Answer

Yes

Document Name
Comment

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0

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0

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Lan Nguyen - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

Yes

Document Name
Comment

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0

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0

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Theresa Rakowsky - Puget Sound Energy, Inc. - 1
Answer

Yes

Document Name
Comment

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0

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0

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sean erickson - Western Area Power Administration - 1
Answer
Document Name

Yes

Comment

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0

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Shelby Wade - PPL - Louisville Gas and Electric Co. - 3,5,6 - SERC, Group Name Louisville Gas and Electric Company and Kentucky Utilities
Company
Answer

Yes

Document Name
Comment

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0

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0

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Jesus Sammy Alcaraz - Imperial Irrigation District - 1
Answer

Yes

Document Name
Comment

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0

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0

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Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer

Yes

Document Name
Comment

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0
0

Response

Quintin Lee - Eversource Energy - 1, Group Name Eversource Group
Answer

Yes

Document Name
Comment

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0

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0

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Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 3, Group Name FirstEnergy Corporation
Answer

Yes

Document Name
Comment

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0

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0

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David Gordon - Massachusetts Municipal Wholesale Electric Company - 5
Answer

Yes

Document Name
Comment

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0

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0

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James Poston - Santee Cooper - 3, Group Name Santee Cooper
Answer
Document Name

Yes

Comment

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0

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0

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Shannon Fair - Colorado Springs Utilities - 1,3,5,6, Group Name Colorado Springs Utilities
Answer

Yes

Document Name
Comment

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0

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0

Response

Jennifer Hohenshilt - Talen Energy Marketing, LLC - 6
Answer

Yes

Document Name
Comment

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0

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0

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Donald Lock - Talen Generation, LLC - 5
Answer

Yes

Document Name
Comment

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0

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0

Frank Pace - Central Hudson Gas & Electric Corp. - 1
Answer

Yes

Document Name
Comment

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0

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0

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George Brown - Acciona Energy North America - 5
Answer

Yes

Document Name
Comment

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0

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0

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Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Answer

Yes

Document Name
Comment

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0

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0

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Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer
Document Name
Comment

Yes

Likes

0

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0

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Nicholas Lauriat - Network and Security Technologies - 1
Answer

Yes

Document Name
Comment

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0

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0

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RoLynda Shumpert - SCANA - South Carolina Electric and Gas Co. - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment

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0

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0

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Jack Cashin - American Public Power Association - 4
Answer
Document Name
Comment
APPA agrees that the standard provides entities with the flexibility to implement the standard cost-effectively and offers these further suggestions. To
fully assess the logistics and costs associated with compliance, some guidance or specification of boundaries of communications links involved would
be required for entities to complete assessment of impacts to their operations. In addition, architectural changes should be spread out over several
budget cycles (years).
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0

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Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE does not have comments on this questions.
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0

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Richard Vine - California ISO - 2
Answer
Document Name
Comment
The California ISO supports the comments of the Security Working Group (SWG).
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0

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0

5. If you have additional comments on the proposed CIP-012-1 – Cyber Security -- Communication Networks drafted in response to the FERC
directive that you have not provided in response to the questions above, please provide them here.
Richard Vine - California ISO - 2
Answer
Document Name
Comment
The California ISO supports the comments of the Security Working Group (SWG).
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Brian Millard - Tennessee Valley Authority - 1,3,5,6 - SERC, Group Name Tennessee Valley Authority
Answer
Document Name
Comment
TVA notes that the requirement language focuses on the risk of unauthorized disclosure or modification of data. In an operational environment the
integrity and availability legs of the CIA triad are more critical than the confidentiality. TVA suggests consider revising to focus on ensuring the integrity
and availability of the data.
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Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer
Document Name
Comment
Applicability:
Based on the first 2 questions in the proposed RSAW requiring entities to prove that the standard does not apply to them, could the Applicability section
of the standard be modified to indicate that the standard only applies to those specific registered entities (e.g., GOPs and TOs) that maintain Control
Centers AND transmit data between Control Centers?

Additionally, the proposed standard does not provide a sufficient level of detail on how entities should work together to handle security concerns across
a communication network. The standard should clearly identify where the obligations for protecting data in a communication network start and end per
entity.
Technical Rationale:
Does the TO field asset box on page # 5 of Technical Rationale and Justification for CIP-012-1 document include TO Control Centers? If no, where are
TO Control Centers represented ?
Implementation Guidance:
CIP-012 R2 requires the Responsible Entity to implement on or more documented plan(s) to mitigate the risk of the unauthorized disclosure or
modification of applicable data whish being transmitted between Control Centers. Without implementation guidance describing how to accomplish this
risk mitigation either physically protecting the communication links transmitting the data or logically protecting the data during transmission; or some
other equally effective means it is difficult to predict the amount of time that would be required to implement this requirement part and therefore we
cannot assume the 12 months prescribed in the proposed implementation plan is adequate.
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Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Answer
Document Name
Comment
If the region is responsible for the system, what does the entity have to do for compliance? All entities would have to coordinate with the region on a
solution. The solution may require additional equipment to be installed. A region-wide formal agreement may be difficult to develop and execute in a
year.
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0

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0

Response

Anthony Jablonski - ReliabilityFirst - 10
Answer
Document Name
Comment
Even though ReliabilityFirst votes in the affirmative, ReliabilityFirst provides the following comments for consideration:
1. Requirement R2

i.

Requirement R2 of the Standard does not identify a “reasonable” timeline for implementing the plan identified in R1. This lack of time
determinant could lead to prolonged and needless delay in implementing the required protections.

ii.

Requirement R2 uses the phrase “CIP Exceptional Circumstances”. The intent is “to protect confidentiality and integrity of data
transmitted between Control Centers required for reliable operation of the Bulk Electric System (BES).”

ReliabilityFirst questions if using the phrase “CIP Exceptional Circumstances” is appropriate here. The definition of CIP Exceptional
Circumstance is defined as “A situation that involves or threatens to involve one or more of the following, or similar, conditions that
impact safety or BES reliability: a risk of injury or death; a natural disaster; civil unrest; an imminent or existing hardware, software, or
equipment failure; a Cyber Security Incident requiring emergency assistance; a response by emergency services; the enactment of a
mutual assistance agreement; or an impediment of large scale workforce availability.” ReliabilityFirst believes CIP Exceptional
Circumstances criteria are not relative to data transmission.
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George Brown - Acciona Energy North America - 5
Answer
Document Name
Comment
1- Generator Operators within the ERCOT footprint who are not also a Qualified Scheduling Entity (QSE) will not be able to comply with the standard as
written if their Control Center transmits and receives the data as specified in Requirement R1.
Within the ERCOT footprint the sensitive BES data transmitted between the Control Centers of the Balancing Authority (BA), Transmission Operator
(TOP), Reliability Coordinator (RC) and Generator Operator (GOP) is submitted through the QSE (Assume that ERCOT is acting as the RC, BA and/or
TOP for particular GOP and that GOP is not also a QSE). The QSE is not a recognized NERC Functional Entity and as such would not be subject to
adhering to NERC Reliability Standards. Therefore it would not be possible for a GOP to protect the sensitive BES data that is transmitted to and from
the Control Center of the QSE and ERCOT that ultimately is either being sent or received by the GOP Control Center. NERC CIP-012-1, as written,
does not account for this ERCOT nuance.
2 - Pursuant to NERC CIP-012-1, §4 Applicability, this standard is applicable to the Generator Owner. However, the proposed definition of Control
Center, exempts the Generator Owner as it only speaks to the Generator Operator’s Control Center. NERC CIP-012-1 should not be applicable to the
Generator Owner.
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Joe Tarantino - Joe Tarantino On Behalf of: Arthur Starkovich, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Beth Tincher, Sacramento
Municipal Utility District, 4, 1, 5, 6, 3; Jamie Cutlip, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Kevin Smith, Balancing Authority of

Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Susan Oto, Sacramento Municipal Utility District, 4, 1,
5, 6, 3; - Joe Tarantino
Answer
Document Name
Comment

We seek clarification in the standard verbiage that the intent of this standard applies to inter control center communication. In addition, it
would be beneficial to have guidance on key management and inter utility agreements particularly as it pertains to coordination for
encryption of data between 3rd parties and compliance impacts on reliability.
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0

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Response

Leonard Kula - Independent Electricity System Operator - 2
Answer
Document Name
Comment
The IESO asserts that the proposed standard does not make clear how entities should work together when addressing security concerns across a
communication network link. If both entities work with CIP Standard assumptions on both ends of a communication network, some support for joint
handling of issues could be made clear. However, if only one entity is CIP-compliant for a given link, the current standard draft does not make clear the
extent of protection expected for the data. The Standard should provide more information on the ownership of obligations for protecting the entire link
It is unclear whether the addition of CIP-012 affects the exemptions of communication networks in any of the applicability sections of other standards
(CIP-002 through CIP-011). The IESO requests clarification that CIP-012 fills in some of the gap created the CIP-002 – CIP-011 third party
telecommunications exemption (4.2.3.2. Cyber Assets associated with communication networks and data communication links between discrete
Electronic Security Perimeters.)
It has been ten years since the SANDIA report (“Secure ICCP Considerations and Recommendations”), the only detailed report on this subject which
could be considered close having entered mainstream awareness in the industry. Today, as ten years ago, Secure ICCP is not a viable choice for
utilities, if only due to limited community experience and vendor support, not to mention the complexities of key management. The transition strategies
that SANDIA discusses – Layer 3 protection using IPsec and Layer 2 protection with hardware encryption – remain today’s target solutions.
IPsec is a viable alternative. Over MPLS, IPsec could secure GRE tunnels between CE routers. Challenges with this approach include the possibility of
having to hire a third party to manage certificates and IPsec links, especially for ISOs that do not manage their own MPLS networks.
The IESO position on security architecture is that business transactions (such as ICCP) should not be tightly coupled with encryption
technologies. Solutions should prefer network overlays versus security extensions to a protocol (such as Secure ICCP or DNP3 SA).
The security architecture should prefer least-latent encryption solutions at the Ethernet or IP layers of the network stack. MACsec (802.1AE) models
the spirit of an optimal solution within a metro area – could it scale wider?
The IESO’s overall position on Secure ICCP is that it represents too much reliability risk. The IESO is concerned about the lack of open standards and
protocols available to meet the confidentiality and integrity security objectives of CIP-012. Assuming that a solution involves encryption, the only two

open standards and protocols that can meet the CIP-012 security objectives are IPsec and TLS. The potential for vendor leverage in such a small open
solution space is large. Vendor-managed MPLS networks, typical among utilities, already entrench high annual telecommunication costs in utility
budgets. Security vendors continue to benefit from the expense of establishing layered cyber defenses. Open Source solutions provide a cost and
agility refuge from this lopsided value chain without compromising defense layers. The trend toward managed services makes the cost problem worse
for utilities, especially in the context of insufficiently evaluated risk. Vendor leverage only grows given the practical consideration that all the
communicating parties in a WAN of connected real-time Control Centers would need to adopt a common solution in order to minimize complexity and
cost.
Likes

2

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Hydro One Networks, Inc., 1, Farahbakhsh Payam; Hydro One Networks, Inc., 3, Malozewski Paul
0

Response

Dermot Smyth - Con Ed - Consolidated Edison Co. of New York - 5, Group Name Con Edison
Answer
Document Name
Comment
CIP-012-1 should be aligned with TOP-003-3. Data security is already required in TOP-003-3 R5. Only data that is stipulated in the TOP-003-3 R1 data
specification for Operational Planning Analysis, Real-time Assessment, and Real-time monitoring should be in scope for CIP-012.
The proposed standard does not make clear how entities should work together when addressing security concerns across a communication network
link. Some guidance regarding joint handling of communication links would be helpful. Where does the obligation for protecting a link per entity start and
end?
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0

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0

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Brandon McCormick - Brandon McCormick On Behalf of: Ginny Beigel, City of Vero Beach, 3; Lynne Mila, City of Clewiston, 4; Tom Reedy,
Florida Municipal Power Pool, 6; - Brandon McCormick, Group Name FMPA
Answer
Document Name
Comment
FMPA believes that the proposed standard does not make clear how entities should work together when addressing security concerns across a
communication network link. Some support for joint handling of issues should be made clear.
FMPA believes that an Implementation Guidance document should be developed and include guidance on possible determination of the security
method used being developed at the regional or RC level. This may facilitate a more cost-effective approach. Moreover, the Implementation Guidance
could also address the entities evidence needed when they are following what was determined by the Region, RC or ISO.
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0

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0

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David Rivera - New York Power Authority - 3
Answer
Document Name
Comment
The proposed standard does not make clear how entities should work together when addressing security concerns across a communication network
link. Some support for joint handling of issues could be made clear. Where does the obligation for protecting a link per entity start and end?
Note: These comments are equivalent to those submitted by the NPCC/TFIST group, except for changes in the Yes/No answers.
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Dana Klem - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO NSRF
Answer
Document Name
Comment
1. The NSRF questions the use of “Real-time monitoring” as an applicable object within R1. “Real-time” is defined as “present time as opposed to
future time”. Which our industry understands and without the word “monitoring” being defined, may lead to misinterpretation by responsible entities and
CEAs, alike. The word “monitoring” may mean ALL monitoring of an entity’s entire SCADA system. It should be the “monitoring” of BES data, only, that
is required for Operational Planning Analysis and Real-time Assessments.
2. The Applicability section states, “For requirements in this standard where a specific functional entity or subset of functional entities are the applicable
entity or entities, the functional entity or entities are specified explicitly”. This proposed Standard does not specify any specific entities and we
recommend that this is removed.
3. The NSRF has concerns with the proposed definition of Control Center. The largest issue is the last paragraph concerning a Generating
Operator. The use of the word “capability” is ambiguous and will confuse Registered Entities and CEAs, a like. The SDT should consider the approved
Applicability within PER-005-2 part 4.1.5.1, which reads:
Dispatch personnel at a centrally located dispatch center who receive direction from the Generator Operator’s Reliability Coordinator, Balancing
Authority, Transmission Operator, or Transmission Owner, and may develop specific dispatch instructions for plant operators under their control. This
personnel does not include plant operators located at a generator plant site or personnel at a centrally located dispatch center who relay dispatch
instructions without making any modifications.
This aligns with current and understood wording of PER-005-2.

4. Are the noted “Real-time reliability related- tasks” within the proposed definition, the same “Real-time Reliability-related task prescribed in PER-0052? If so, please state this in your consideration of comments document and within your guidance document.
5. The NSRF believes that data associated with Operational Planning Analyses (OPA), Real-time monitoring (RTm), and Real-time Assessments (RTA)
are predicated on other Standards and protection of data is required but all three areas (OPA, RTm, and RTA) are not subject equally to the Applicable
Entities noted in CIP-012-1. Per IRO-010-2, R1, the RC is to document its specifications necessary for OPA, RTm, and RTA. Per TOP-003-3, R1 the
TOP is to document its specifications necessary for OPA, RTm, and RTA. Per TOP-003-3, R2, the BA is to document its specifications necessary for
analysis functions and RTm, only. The SDT, in the Technical Rationale and Justification document, acknowledges TOP-003 and IRO-010 “provides
consistent scoping of identified data” [R1 section: Alignment with IRO and TOP Standards”]. The SDT should quantify that the data to be protected is
the data associated with the Applicable entities with IRO-010-2 and TOP-003-3. With doing this, the SDT will articulate what the entity is to perform what
analysis and what “data” is to be protected, based on already approved NERC Reliability Standards. By clearly identifying (and linking) the data to be
protected from the data specifications developed under Standards TOP-003 and IRO-010, there is no room for interpretation of what “data” is to be
protected.
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Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Although the FERC order specifies data between Control Centers, Texas RE notes that there is OPA, RTA, Real-time monitoring data that is not
between control centers. For example, Distribution Providers provide BES sensitive data but would not be subject the standard. Also there are
numerous GOPs that do not have a control center per the definition that provide BES sensitive data which also would not subject to CIP-012-1. Texas
RE is concerned this creates a reliability gap since these scenarios would not be covered under the proposed draft of CIP-012-1.

Although Texas RE does not oppose a CIP Exceptional Circumstances exception from the implementation requirements set forth in CIP-012-1 R2,
Texas RE requests that the SDT provide a rationale for why such an exception is appropriate. In particular, it is unclear why certain CIP exception
conditions, such as an imminent hardware failure, should necessarily trigger a relaxation of physical security protections for communications links
transmitted sensitive data in all circumstances.
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0

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Response

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer
Document Name

Comment
See APPA Comments.
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0

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0

Response

Chris Scanlon - Exelon - 1
Answer
Document Name
Comment
N/A
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0

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0

Response

Marty Hostler - Northern California Power Agency - 5
Answer
Document Name
Comment
Refer to APPA, TAPs, and Utility Services comments.
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0

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0

Response

Dennis Sismaet - Northern California Power Agency - 6
Answer
Document Name
Comment

Refer to APPA, TAPs, and Utility Services comments.
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0

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Response

Vivian Vo - APS - Arizona Public Service Co. - 3
Answer
Document Name
Comment
AZPS reiterates its comments provided in response to Requirement R1 regarding clear delineation of responsibilities between receiving and transmitting
entities. Because the potential impacts of a receiving entity not appropriately implementing the technology needed for decryption or use of protected
data sent by a transmitting entity lie outside of the proposed Requirement R1 in real-time data and assessment obligations, placement of the obligations
for Requirement R1 on the transmitting is appropriate and reduces the potential for double jeopardy and/or “waterfall” non-compliance events. Hence,
AZPS suggests that it is appropriate to place the obligation for Requirement R1 on the transmitting entity.
Finally, AZPS reiterates the NERC ORD as a reference guide and resource regarding the scope of this standard and sensitive data generally. The
NERC ORD Agreement has long maintained an accepted, well-established definition for sensitive reliability data. That definition does not include data
utilized in the Operational Planning Horizon and, for the reasons discussed above, AZPS asserts that the inclusion of Operational Planning Analysis in
Requirement R1 extends the scope of BES sensitive data without attendant benefit to reliability. AZPS recommends the deletion of Operational
Planning Analysis from Requirement R1 to allow the Requirement to remain consistent with well-established, well understood precedent as set forth in
the NERC ORD Agreement.

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0

Response

Quintin Lee - Eversource Energy - 1, Group Name Eversource Group
Answer
Document Name
Comment
Clarification needed – Does 'data used for Operational Planning Analysis, Real-time Assessments, and Real-time monitoring ' include Generator Unit
Commitment Data and/or transmission and generator outages which are posted publicly?
Likes
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0

Response

Aaron Austin - AEP - 3
Answer
Document Name

CIP-012-1 – Cyber Security -Communication Networks Diagram.doc

Comment
AEP suggests these should be added to the diagram as clearly in scope.

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0

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0

Response

Barry Lawson - National Rural Electric Cooperative Association - 4
Answer
Document Name
Comment
NRECA appreciates the continuing efforts of the SDT.
Likes

0

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0

Response

Nicolas Turcotte - Hydro-Qu?bec TransEnergie - 1
Answer
Document Name
Comment
The proposed standard does not make clear how entities should work together when addressing security concerns across a communication network
link. Some support for joint handling of issues could be made clear. Where does the obligation for protecting a link per entity start and end?

Likes

0

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0

Response

Lona Calderon - Salt River Project - 1,3,5,6 - WECC
Answer
Document Name
Comment
One challenge associated with CIP-012-1 is industry-wide coordination would be necessary to successfully implement encryption.
In addition to adding latency, encryption adds burden for ongoing maintenance and management for an encryption program. SRP agrees with LPPC
that guidance is needed on key management and inter utility agreements pertaining to coordination for encryption of data and impacts on real-time
operation of the Bulk Electric System.
Likes

0

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0

Response

Thomas Breene - WEC Energy Group, Inc. - 3
Answer
Document Name
Comment
1. We question the use of “Real-time monitoring” as an applicable object within R1. “Real-time” is defined as “present time as opposed to future
time”. Which our industry understands and without the word “monitoring” being defined, may lead to misinterpretation by responsible entities and CEAs,
alike. The word “monitoring” may mean ALL monitoring of an entity’s entire SCADA system. It should be the “monitoring” of BES data, only, that is
required for Operational Planning Analysis and Real-time Assessments.

2. The Applicability section states, “For requirements in this standard where a specific functional entity or subset of functional entities are the applicable
entity or entities, the functional entity or entities are specified explicitly”. This proposed Standard does not specify any specific entities and recommend
that this be removed.

3. We have concerns with the proposed definition of Control Center. The largest issue is the last paragraph concerning a Generating Operator. The
use of the word “capability” is ambiguous and will confuse Registered Entities and CEAs, a like. The SDT should consider the approved Applicability
within PER-005-2 part 4.1.5.1, which reads:

Dispatch personnel at a centrally located dispatch center who receive direction from the Generator Operator’s Reliability Coordinator, Balancing
Authority, Transmission Operator, or Transmission Owner, and may develop specific dispatch instructions for plant operators under their control. These
personnel do not include plant operators located at a generator plant site or personnel at a centrally located dispatch center who relay dispatch
instructions without making any modifications.

This aligns with current and understood wording of PER-005-2.

4. Are the noted “Real-time reliability related- tasks” within the proposed definition, the same “Real-time Reliability-related task prescribed in PER-0052? If so, please state this in your consideration of comments document and within your guidance document.

5. We believe that data associated with Operational Planning Analyses (OPA), Real-time monitoring (RTm), and Real-time Assessments (RTA) are
predicated on other Standards and protection of data is required but all three areas (OPA, RTm, and RTA) are not subject equally to the Applicable
Entities noted in CIP-012-1. Per IRO-010-2, R1, the RC is to document its specifications necessary for OPA, RTm, and RTA. Per TOP-003-3, R1 the
TOP is to document its specifications necessary for OPA, RTm, and RTA. Per TOP-003-3, R2, the BA is to document its specifications necessary for
analysis functions and RTm, only. The SDT, in the Technical Rationale and Justification document acknowledges TOP-003 and IRO-010 “provides
consistent scoping of identified data” [R1 section: Alignment with IRO and TOP Standards”]. The SDT should quantify that the data to be protected is
the data associated with the Applicable entities with IRO-010-2 and TOP-003-3. With doing this, the SDT will articulate what the entity is to preform what
analysis and what “data” is to be protected, based on already approved NERC Reliability Standards. By clearly identifying (and linking) the data to be
protected from the data specifications developed under Standards TOP-003 and IRO-010, there is no room for interpretation of what “data” is to be
protected.
Likes

0

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0

Response

Russell Noble - Cowlitz County PUD - 3
Answer
Document Name
Comment
Although Cowlitz PUD agrees with the intent of the proposed standard, we are concerned the protective measures developed by entities could have
unintended consequences. In particular, there is concern encryption could unacceptably slow data transmission.
Likes

0

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0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Con-Edison and Dominion

Answer
Document Name
Comment
·
The proposed standard does not make clear how entities should work together when addressing security concerns across a communication
network link. Some support for joint handling of issues could be made clear. Where does the obligation for protecting a link per entity start and end?
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Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer
Document Name
Comment
ERCOT ISO signs on to the ITC SWG comments:
The ITC SWG asserts that the proposed standard does not make clear how entities should work together when addressing security concerns across a
communication network link. If both entities work with CIP Standard assumptions on both ends of a communication network, some support for joint
handling of issues could be made clear. However, if only one entity is CIP-compliant for a given link, the current standard draft does not make clear the
extent of protection expected for the data. The Standard should provide more information on the ownership of obligations for protecting the entire link.
It is unclear whether the addition of CIP-012 affects the exemptions of communication networks in any of the applicability sections of other standards
(CIP-002 through CIP-011). The SWG requests clarification that CIP-012 fills in some of the gap created the CIP-002 – CIP-011 third party
telecommunications exemption (4.2.3.2. Cyber Assets associated with communication networks and data communication links between discrete
Electronic Security Perimeters.)
It has been ten years since the SANDIA report (“Secure ICCP Considerations and Recommendations”), the only detailed report on this subject which
could be considered close having entered mainstream awareness in the industry. Today, as ten years ago, Secure ICCP is not a viable choice for
utilities, if only due to limited community experience and vendor support, not to mention the complexities of key management. The transition strategies
that SANDIA discusses – Layer 3 protection using IPsec and Layer 2 protection with hardware encryption – remain today’s target solutions.
WECC, and specifically the WECC DEMSWG (Data Exchange and EMS Working Group) has been working with Pacific Northwest National Laboratory
(PNNL) for some time on a new evaluation of Secure ICCP. PNNL recently completed their work and presented the results to DEMSWG in 2016. The
PNNL study functionally succeeded but with enough limitations that PNNL was prompted to conclude that it would be difficult to make a business case
for implementing Secure ICCP when other solutions are available.
IPsec is a viable alternative. Over MPLS, IPsec could secure GRE tunnels between CE routers. Challenges with this approach include the possibility of
having to hire a third party to manage certificates and IPsec links, especially for ISOs that do not manage their own MPLS networks.
The ITC SWG position on security architecture is that business transactions (such as ICCP) should not be tightly coupled with encryption
technologies. Solutions should prefer network overlays versus security extensions to a protocol (such as Secure ICCP or DNP3 SA).

The security architecture should prefer least-latent encryption solutions at the Ethernet or IP layers of the network stack. MACsec (802.1AE) models
the spirit of an optimal solution within a metro area – could it scale wider?
The ITC SWG’s overall position on Secure ICCP is that it represents too much reliability risk. The ITC SWG is concerned about the lack of open
standards and protocols available to meet the confidentiality and integrity security objectives of CIP-012. Assuming that a solution involves encryption,
the only two open standards and protocols that can meet the CIP-012 security objectives are IPsec and TLS. The potential for vendor leverage in such
a small open solution space is large. Vendor-managed MPLS networks, typical among utilities, already entrench high annual telecommunication costs
in utility budgets. Security vendors continue to benefit from the expense of establishing layered cyber defenses. Open Source solutions provide a cost
and agility refuge from this lopsided value chain without compromising defense layers. The trend toward managed services makes the cost problem
worse for utilities, especially in the context of insufficiently evaluated risk. Vendor leverage only grows given the practical consideration that all the
communicating parties in a WAN of connected real-time Control Centers would need to adopt a common solution in order to minimize complexity and
cost.
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Marc Donaldson - Tacoma Public Utilities (Tacoma, WA) - 3
Answer
Document Name
Comment
Tacoma Power supports the comments of APPA
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Theresa Rakowsky - Puget Sound Energy, Inc. - 1
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Document Name
Comment
n/a
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Jack Cashin - American Public Power Association - 4
Answer
Document Name
Comment
APPA believes that the proposed standard does not make clear how entities should work together when addressing security concerns across a
communication network link. Some support for joint handling of issues should be made clear.
Public power believes that an Implementation Guidance document should be developed and include guidance on possible determination of the security
method used being developed at the regional or RC level. This may facilitate a more cost-effective approach. Moreover, the Implementation Guidance
could also address the entities evidence needed when they are following what was determined by the Region, RC or ISO.

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Lan Nguyen - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer
Document Name
Comment
The STD should consider changing the title of the CIP-012-1 requirement to “CIP-012-1-Cyber Security – Control Center Communication Links” to align
with the language in FERC Order No. 822 and the language in Requirement R1. The current use of the term “Networks” may be misleading because it
implies a broader scope of communication.
Additionally, the violation severity levels (VSL) for this requirement is limited to “Severe”. CenterPoint Energy recommends that Requirement R1 VSL
be “Moderate” to “High” due to the fact that Requirement R1 is a documentation requirement.
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David Greene - SERC Reliability Corporation - 10, Group Name SERC CIPC
Answer
Document Name
Comment

NA
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Warren Cross - ACES Power Marketing - 1,3,4,5 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Standards Collaborators
Answer
Document Name
Comment
We thank you for this opportunity to provide these comments.
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Sheranee Nedd - PSEG - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer
Document Name
Comment
PSEG supports the NPCC comments.
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PSEG - PSEG Fossil LLC, 5, Kucey Tim
0

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Michael Puscas - ISO New England, Inc. - 2
Answer
Document Name
Comment
Comments:

•

The proposed standard does not make clear how entities should work together when addressing security concerns across a communication
network link. If both entities work with CIP Standard assumptions on both ends of a communication network, some support for joint handling of
issues could be made clear. However, if only one entity is CIP-compliant for a given link, the current standard draft does not make clear the
extent of protection expected for the data. Where does the obligation for protecting a link per entity start and end?

•

Does the addition of CIP-012 affect the exemptions of communication networks in any of the applicability sections of other standards (CIP-002
through CIP-011)?

•

While the CIP standards should emphasize outcomes and allow entities to achieve specific security objectives in many ways, protections
applied to communications should be evaluated with due consideration of the context in which people, processes and technology are applied to
establish a given security protection. Demonstration of risk mitigation should include assessment of not just technology and process to provide
protection, but also the diversity and severity of threats present in a given context (e.g. the difference between dedicated communication links
as opposed to broadly shared communications infrastructure). Particular technology and process applied in a context with fewer or lower
likelihood threats should be preferred over the same technology and process in a context with more or greater likelihood threats (i.e. greater
overall risk). Simply specifying that some (how much?) risk mitigation should be applied by means that include physical, logical and possibly
other means leads to insufficient conditions for establishing compliance both for the responsible entity and anyone reviewing compliance for that
entity. Entities should consider not only that risk mitigation should take place, but also the thresholds for residual risk that should be considered
acceptable for such communication.

•

It should be noted that in a recent report from the National Infrastructure Advisory Council (NIAC) to the DHS and President of the United
States, the NIAC recommended that separate communication networks be used for critical communications (reference
https://www.dhs.gov/publication/niac-securing-cyber-assets-addressing-urgent-cyber-threats-critical-infrastructure-final, report page 3, first
recommendation).

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Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name
Comment
BPA suggests adding the verbiage “where technically feasible” to the requirements, in order to implement controls where appropriate, based on the
technology (as discussed in Q1) and risk.
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Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer
Document Name

Comment
Utility Services believes that the proposed standard does not make clear how entities should work together when addressing security concerns across a
communication network link. Some support for joint handling of issues should be made clear.

Utility Services believes that an Implementation Guidance document should be developed and include guidance on possible determination of the
security method used being developed at the regional or RC level. This may facilitate a more cost-effective approach. Moreover, the Implementation
Guidance could also address the entities evidence needed when they are following what was determined by the Region, RC or ISO.

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Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Document Name
Comment
If the SDT retains a data-centric approach, we believe the time element is very important and is correctly captured in the requirement with the phrase
“while being transmitted between Control Centers.” We encourage the SDT to retain this language. We note the RSAW drops the time element and
just says “transmitted between”. The time element is very important, as data transmitted between Control Centers a year ago is not the focus of this
standard. This will, ideally, be reflected in the Standard itself, as well as the Technical Rationale and the RSAW, for clarity.
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David Ramkalawan - Ontario Power Generation Inc. - 5
Answer
Document Name
Comment
OPG understands the focus is on protection of data communication between control centers but would like to clarify that it is not being required to verify
integrity of data from it’s origination points to the point where it’s first aggregated at a control center, as this would be a substantially more difficult and
costly requirement to achieve.

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Ronald Donahey - TECO - Tampa Electric Co. - 3
Answer
Document Name
Comment
Tampa Electric appreciates the efforts of the Standards Drafting Team in developing protections for Communication Networks. We have concerns that
the scope of the standard regarding data protection (based on IRO-010 and TOP-003) extends the requirement to data/information that is not currently
required to be protected at the level of a High Impact BES Cyber System. This approach does not match the intent and protections of all other NERC
CIP standards.
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Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer
Document Name
Comment
The SPP Standards Review Group recommends the drafting team verifies and confirms that the NERC defined terms ‘Operational Planning Analyses’,
‘Real-time Assessments’, and ‘Real-time’ (mentioned in the Rationale Section in reference to Requirement R1) are defined and properly aligned with
the Rules of Procedure (RoP) documentation. We have a concern that if the terms aren’t properly defined and aligned in both documents that this could
lead to potential interpretation issues for future projects. During the verification process, should the drafting team discover that there is supporting
evidence to SPP’s concerns, we would recommend the drafting team developing a Standard Authorization Request (SAR) to help ensures that both
documents have consistency in the definition of the terms mentioned.
The SPP Standard Review Group would ask the drafting team to provide clarity on why the RoP is not mentioned in the Implementation Plan like the
NERC Glossary of Terms. From our perspective, the RoP and the definitions, it contains have the same significance that the Glossary of Terms have in
reference to the industry defined terms.

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Wendy Center - U.S. Bureau of Reclamation - 5
Answer
Document Name
Comment
Reclamation recommends the SDT define the term “Real-time monitoring” in the NERC Glossary of Terms.

The Applicability section states, “For requirements in this standard where a specific functional entity or subset of functional entities are the applicable
entity or entities, the functional entity or entities are specified explicitly.” No Requirements in this proposed Standard explicitly specify a functional entity
or entities; therefore, Reclamation also recommends that this sentence be removed.
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Scott Berry - Scott Berry On Behalf of: Jack Alvey, Indiana Municipal Power Agency, 1, 4; - Scott Berry
Answer
Document Name

2016-02_Unofficial_Comment_Form_Control_Center_Definition_08142017.docx

Comment
IMPA is attaching its comments for Control Center. The feedback/survey sheet is not linked to this vote. Our Control Center survey response is
attached.
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Lauren Price - American Transmission Company, LLC - 1
Answer
Document Name
Comment
Not Applicable
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Laura McLeod - NB Power Corporation - 5
Answer
Document Name
Comment
No additional comments.
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Haley Sousa - Public Utility District No. 1 of Chelan County - 5
Answer
Document Name
Comment
Implementing industry-wide secure communication is a significant coordination challenge for entities and their associated vendors. The increase in
security also brings increased complexity, maintenance, and failure potential that may negatively impact the reliable operation of the BES. As a result,
coordination for encryption key management will become an essential activity and CHPD would, similar to other entity comments, appreciate guidance
for these activities.
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Douglas Webb - Douglas Webb On Behalf of: Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., 3, 5, 1, 6; James McBee,
Great Plains Energy - Kansas City Power and Light Co., 3, 5, 1, 6; Jessica Tucker, Great Plains Energy - Kansas City Power and Light Co., 3,
5, 1, 6; Jim Flucke, Great Plains Energy - Kansas City Power and Light Co., 3, 5, 1, 6; - Douglas Webb
Answer
Document Name
Comment
None.
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Janis Weddle - Public Utility District No. 1 of Chelan County - 6
Answer
Document Name
Comment
Implementing industry-wide secure communication is a significant coordination challenge for entities and their associated vendors. The increase in
security also brings increased complexity, maintenance, and failure potential that may negatively impact the reliable operation of the BES. As a result,
coordination for encryption key management will become an essential activity and CHPD would, similar to other entity comments, appreciate guidance
for these activities.
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Comments from David Greene, SERC
Questions

1. Requirement R1: The SDT drafted CIP-012-1 Requirement R1 to meet the mandatory requirement for the Responsible Entity to develop one or
more documented plan(s) to mitigate the risk of the unauthorized disclosure or modification of data used for Operational Planning Analysis,
Real-time Assessment, and Real-time monitoring data while being transmitted between Control Centers. Do you agree with this revision? If
not, please provide the basis for your disagreement and an alternate proposal.
Yes
No
Comments:
•

Revise R1. First paragraph, remove “Operational Planning Analysis”
Rationale: Operational Planning Analysis data does not impact the BES within 15 minutes. The systems handling Operational Planning
Analysis data are typically separate from the systems performing real-time BES analysis/control.
The data involved with Operational Planning is “theoretical”, e.g., requests to take a line out of service or de-rate a generation unit. If an
event occurs in real-time to trip a line or de-rate a unit, information is immediately conveyed via a mechanism other than Operational
Planning data.

Because the Operational Planning data is requesting permission to do something, the request will be validated by other measures – e.g.,
permission to take the line out of service/de-rate the unit, followed (later) by switching orders to take the line out of service or revised bid
into the generation market indicating the unit will only provide the de-rated output.
Thus, because it does not directly impact the reliable operation of the BES and cross-checks are already built into the data process, stringent
controls for data transfer is not required.
2. Requirement R1: The SDT seeks comment on the need to scope sensitive BES data as it applies to Operational Planning Analysis, Real-time
Assessment, and Real-time monitoring. Do you agree with scoping CIP-012-1 Requirement R1 in this manner? Please provide comment in
support of your response.
Yes
No
Comments:
•

Revise R1. First paragraph, remove “Operational Planning Analysis”
Rationale: Operational Planning Analysis data does not impact the BES within 15 minutes. The systems handling Operational Planning
Analysis data are typically separate from the systems performing real-time BES analysis/control.
The data involved with Operational Planning is “theoretical”, e.g., requests to take a line out of service or de-rate a generation unit. If an
event occurs in real-time to trip a line or de-rate a unit, information is immediately conveyed via a mechanism other than Operational
Planning data.
Because the Operational Planning data is requesting permission to do something, the request will be validated by other measures – e.g.,
permission to take the line out of service/de-rate the unit, followed (later) by switching orders to take the line out of service or revised bid
into the generation market indicating the unit will only provide the de-rated output.
Thus, because it does not directly impact the reliable operation of the BES and cross-checks are already built into the data process,
stringent controls for data transfer is not required.

3. Implementation Plan: The SDT revised the Implementation Plan such that the standard and NERC Glossary terms are effective the first day of
the first calendar quarter that is twelve (12) calendar months after the effective date of the applicable governmental authority’s order
approving the standard, or as otherwise provided for by the applicable governmental authority. Do you agree with this proposal? If you agree
with the proposed implementation time period, please note the actions you will take that require this amount of time to complete. If you think
an alternate implementation time period is needed – shorter or longer - please propose an alternate implementation plan and provide a
detailed explanation of actions and time needed to meet the implementation deadline.
Yes

No
Comments:
•

Alternate Implementation Period: 2 Year Implementation Plan Period
Rationale: There are a number of factors to consider, and all affect the time required to implement, to include the following:
o Complexity of the technology solutions to be implemented,
o Number of interconnecting lines to secure,
o Troubleshooting/testing at each connection point, and
o Coordination requirements with external stakeholders

4. The SDT believes proposed CIP-012-1 provides entities with flexibility to meet the reliability objectives in a cost effective manner. Do you
agree? If you do not agree, or if you agree but have suggestions for improvement to enable more cost effective approaches, please provide
your recommendation and, if appropriate, technical justification.
Yes
No
Comments:
5. If you have additional comments on the proposed CIP-012-1 – Cyber Security -- Communication Networks drafted in response to the FERC
directive that you have not provided in response to the questions above, please provide them here.
Comments: NA
Comments from Vivian Vo, APS
Questions

1. Requirement R1: The SDT drafted CIP-012-1 Requirement R1 to meet the mandatory requirement for the Responsible Entity to develop one or
more documented plan(s) to mitigate the risk of the unauthorized disclosure or modification of data used for Operational Planning Analysis,
Real-time Assessment, and Real-time monitoring data while being transmitted between Control Centers. Do you agree with this revision? If
not, please provide the basis for your disagreement and an alternate proposal.
Yes
No
Comments:
AZPS respectfully submits that, as written, the allocation of responsibilities between transmitting and receiving entities is unclear. Delineation
of these responsibilities is essential because a receiving entity has no control over the behavior, implementation, and/or lack of

implementation of third-party entities and cannot prevent third-party entities from transmitting unprotected data. As written, Requirement
R1 could be construed as holding both the transmitting and receiving entity responsible where the transmitting entity fails to implement its
plan. The receiving entity would only be aware/in receipt of the protected or unprotected data once it is transmitted by the transmitting
entity. At which point, the potential for non-compliance has already occurred. Accordingly, because the data emanates from the transmitting
entity, the data protection obligation should emanate from the transmitting entity.
For this reason, Requirement R1 should not hold receiving entities responsible for receiving data from another entity that failed to implement
its plan. Responsibility for CIP-012-1 R1 should be placed clearly upon the transmitting entity and AZPS requests that the SDT modify
Requirement R1 to ensure that there is a clear allocation of responsibilities between the transmitting and receiving entities. AZPS submits for
consideration by the SDT a revised Requirement R1 below with language clarifying the allocation of responsibilities
R1. The Responsible Entity shall develop one or more documented plan(s) to mitigate the risk of the unauthorized disclosure or
modification of data used for Operational Planning Analysis, Real-time Assessments, and Real-time monitoring while being
transmitted when transmitting data from one Control Center to another Control Center between Control Centers. This excludes oral
communications. [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]
The above proposed revisions clarify allocation of responsibilities without compromising on the level of required protection and while
maintaining recognition that meaningful, logically protected communication that can be decrypted for use by the receiving entity requires
bilateral agreement between the transmitting entity and receiving entity.
Comments from Scott Berry, Indiana Municipal Power Agency
Proposed Definition of “Control Center”
Revised Definition:
One or more facilities, including their associated data centers, that monitor and control the Bulk Electric System (BES) and host operating
personnel who perform Real-time reliability-related tasks of: 1) a Reliability Coordinator, 2) a Balancing Authority, 3) a Transmission Operator for
Transmission Facilities at two or more locations, or 4) a Generator Operator for generation Facilities at two or more locations.
For Reliability Coordinators, Balancing Authorities, and Transmission Operators, the operating personnel above are System Operators.
For Transmission Owners performing the Real-time reliability-related tasks of a Transmission Operator, the operating personnel above consist of
personnel, excluding field switching personnel, who can act independently to operate or direct the operation of the Transmission Owner’s Bulk
Electric System Transmission Facilities in Real-time.
For Generator Operators, the operating personnel above consist of dispatch personnel at a centrally located dispatch center who receive direction
from the Generator Operator’s Reliability Coordinator, Balancing Authority, Transmission Operator, or Transmission Owner, and have the
capability to develop specific dispatch instructions for plant operators under their control. These personnel do not include plant operators located
at a generator plant site or personnel at a centrally located dispatch center who relay dispatch instructions without making any modifications.

Redline Definition:
One or more facilities, including their associated data centers, that monitor and control the Bulk Electric System (BES) and host hosting operating
personnel that monitor and control the Bulk Electric System (BES) in real-time to who perform the Real-time reliability-related tasks, including
their associated data centers, of: 1) a Reliability Coordinator, 2) a Balancing Authority, 3) a Transmission Operator for Transmission Facilities at two
or more locations, or 4) a Generator Operator for generation Facilities at two or more locations.
For Reliability Coordinators, Balancing Authorities, and Transmission Operators, the operating personnel above are System Operators.
For Transmission Owners performing the Real-time reliability-related tasks of a Transmission Operator, the operating personnel above consist of
personnel, excluding field switching personnel, who can act independently to operate or direct the operation of the Transmission Owner’s Bulk
Electric System Transmission Facilities in Real-time.
For Generator Operators, the operating personnel above consist of dispatch personnel at a centrally located dispatch center who receive direction
from the Generator Operator’s Reliability Coordinator, Balancing Authority, Transmission Operator, or Transmission Owner, and have the
capability to develop specific dispatch instructions for plant operators under their control. These personnel do not include plant operators located
at a generator plant site or personnel at a centrally located dispatch center who relay dispatch instructions without making any modifications.
Currently Approved Definition:
One or more facilities hosting operating personnel that monitor and control the Bulk Electric System (BES) in real-time to perform the reliability
tasks, including their associated data centers, of: 1) a Reliability Coordinator, 2) a Balancing Authority, 3) a Transmission Operator for transmission
Facilities at two or more locations, or 4) a Generator Operator for generation Facilities at two or more locations.

Project 2016-02
Modifications to CIP
Standards
Consideration of Comments for CIP-012-1
Initial Comment Period
October 27, 2017

Introduction
On January 21, 2016, the Federal Energy Regulatory Commission (FERC) issued Order No.
822 Revised Critical Infrastructure Protection Reliability Standards. In this order, FERC approved
revisions to version 5 of the CIP standards. To address concerns identified in Order 822, FERC
directed the development of modifications to the CIP Reliability Standards to require responsible
entities to implement controls to protect, at a minimum, communication links and sensitive bulk
electric system data communicated between bulk electric system Control Centers in a manner
that is appropriately tailored to address the risks posed to the bulk electric system by the assets
being protected (i.e., high, medium, or low impact).
The standard drafting team for Project 2016-02 developed an initial draft of proposed Reliability
Standard CIP-012-1 to address the FERC directive and posted it for an initial 45-day comment
period and ballot from July 27, 2017 through September 11, 2017. The SDT appreciates industry
comments on the proposed Reliability Standard. The SDT considered the comments submitted
during the initial posting of the proposed Reliability Standard, and revised the draft standard
based on those comments. Additionally, the SDT conducted substantial outreach during the
revision process, through in-person meetings, conference calls, and stakeholder organization
presentations.

Summary Response to Comments
The SDT has carefully reviewed each stakeholder comment and has revised language where
suggested changes are consistent with SDT intent and industry consensus. Also, several
commenters suggested non-substantive language changes. The SDT has carefully considered each
of these comments and has made revisions to further clarify the language. The SDT also made
several changes to clarify the language and align it more closely with SDT intent and industry
consensus. The SDT reviewed and responded to each comment in summary form below.
There were 81 sets of responses, including comments from approximately 207 different people
from approximately 139 companies representing the 10 Industry Segments as shown in the table
on the following pages. All comments submitted can be reviewed in their original format on the
project page.
Our goal is to give every comment serious consideration in this process. If you feel that your
comment has been overlooked, or was insufficiently addressed, please let us know by contacting
the Senior Director, Standards and Education, Howard Gugel (via email) or at (404) 446‐9693.

Consideration of Comments | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | October 27, 2017

2

Consideration of Comments – Summary Responses
Question 1: CIP-012-1 Requirement R1
Summary Response

1. Requirement R1: The SDT drafted CIP-012-1 Requirement R1 to meet the mandatory
requirement for the Responsible Entity to develop one or more documented plan(s) to mitigate
the risk of the unauthorized disclosure or modification of data used for Operational Planning
Analysis, Real-time Assessment, and Real-time monitoring data while being transmitted between
Control Centers. Do you agree with this revision? If not, please provide the basis for your
disagreement and an alternate proposal.

Move Note to Applicability Section
Several stakeholders expressed concerns about applicability type language in a note contained
within Requirement 1 (R1). The Requirement R1 note provides: “If the Responsible Entity does
not have a Control Center or it does not transmit the type of data specified in Requirement R1 of
CIP-012-1 between two Control Centers, the requirements in CIP-012-1 would not apply to that
entity.” Certain commenters stated that the note should be in the Applicability section and
thereby eliminate the need for this to be discussed as part of the RSAW.
SDT Response: The SDT revised the proposed Reliability Standard to remove the note from
Requirement R1 and included the following in the Applicability section for Functional Entities:
“that own or operate a Control Center.”

Demarcation Point
Several commenters expressed that in order to evaluate the extent and kind of obligation
involved with Requirement R1, the phrase “transmitted between two control centers,” needs to
be clarified. Clarification should include identification of the demarcation points of the link being
protected.
One commenter noted that in many cases some types of operational planning analysis data is
housed in systems not classified as BES Cyber Systems and may not reside within an ESP. The
commenter stated that a documented plan provides a mechanism to identify and document
flows of BES sensitive data that do not originate from within an ESP nor pass through an EAP.
At least one commenter expressed concerns with potential issues arising from communication
links not owned by a Responsible Entity, as well as with the determination of demarcation points
when the communication is performed between Control Centers belonging to different
Responsible Entities.
More than one commenter noted that to evaluate the extent and kind of obligation involved, the
definition of ‘between control centers’ needs to be clearer where pertaining to communication
Consideration of Comments | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | October 27, 2017

3

links. They also commented that the Reliability Standard should address the proper demarcation
points to show implementation and compliance. The commenters further noted that to clearly
define the obligation of Responsible Entities, the required plan should include identification of
the demarcation points, and information on the explicit agreements required on each end of the
physical communication link to arrange and identify the demarcation. As an example, the
commenters noted that where there is disagreement on how protection should be applied
between two or more Responsible Entities, there is no process to resolve those disagreements.
They also asked how the identification of demarcation points should be resolved when a
Responsible Entity (e.g., a Reliability Coordinator) is receiving information from a third-party
provider that is aggregating and submitting data on behalf of one or more Responsible Entities
(e.g., a Transmission Operator). The commenters further noted that it does not appear that the
proposed Reliability Standard addresses connection to the third-party provider, since they are
not a Responsible Entity or even registered with NERC. The commenters further assert that the
same situation may be present for Responsible Entities that use an outsourced data center
provider for data provided to regulatory agencies that are not subject to CIP Standards.
SDT Response: The SDT incorporated the concept of demarcation points into the proposed draft
of CIP-012-1 to clarify where protection must begin and can terminate. The SDT also included
provisions allowing the Responsible Entity to choose these points based on what works most
effectively in the Responsible Entity’s environment.

Email Communication Should Be Excluded
Some commenters requested the exclusion for oral communications be extended to electronic
mail. At least one commenter noted the precise nature of Operator-to-Operator
communications, pointing out that “Oral Communications” are excluded. However, EOP-008
(Emergency Operating) Plans often specify using cell/text/email while in mid-failover to the
backup site. The commenter asked whether or not those types of communications are intended
to be excluded.
SDT Response: The SDT contends that if sensitive bulk electric system data is being transmitted
via email, then those emails should be protected in some manner. Confidentiality and integrity
concerns for this data exist regardless of data transmission means.

Plan Approach
Several commenters noted that having a plan does not add to the reliability of protecting
applicable data, suggesting that having a plan is an unwarranted layer of compliance. At least
one commenter asserted that, if a “plan” approach is maintained in CIP-012-1, the SDT should
clarify their understanding of that Plan. That commenter provided CIP-003-6 as an example.
At least one commenter indicated that the term “plan” is more analogous to the development
of a project that has actions to achieve a result by specific date; similar to an implementation
plan for a NERC Reliability Standard. The commenter suggested that if it was the intention of the
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SDT to require a Responsible Entity to have a documented set of requirements to protect the
sensitive BES data transmitted between the Control Centers then the term “policy” would be
more appropriate. The commenter stated that a policy is interpreted to be more dynamic and
ongoing throughout the lifetime of the requirement. The commenter adds that as cyber security
technology is constantly changing and evolving, a policy would provide a definitive course of
action for a Responsible Entity to protect sensitive BES data transmitted between the Control
Centers.
SDT Response: The SDT contends that a plan will help a Responsible Entity ensure that all of the
appropriate data is protected as required by draft CIP-012-1. Presenting this protection in an
organized fashion, using a plan, will not only aid compliance efforts but will also help
Responsible Entities ensure that the protection employed is optimal for their environments.
The SDT notes that Responsible Entities can use a pre-existing plan or plans to satisfy CIP-0121. This requirement structure is consistent with the language in the NERC Drafting Team
Reference Manual.

Guidance Needed
More than one commenter requested that the SDT provide formal guidance for proposed
Reliability Standard CIP-012-1. At least one commenter asserted that this is crucial for a
Responsible Entity’s understanding of how to meet the compliance objective of a new Reliability
Standard.
One commenter noted that CIP-012-1 refers to data as outlined in NERC standards TOP-003-3
and IRO-010-2 that require protection. The commenter expressed the understanding that these
types of data can vary based on Responsible Entity function and what data is needed. The
commenter further notes that from a compliance monitoring perspective, it may be difficult to
verify what the Responsible Entity is protecting versus what actually should be protected. The
commenter requested that the SDT consider providing a list of typical data that should be
protected per the standard and include it in guidance material. Another commenter noted that
it is an overwhelming task to differentiate what are or are not confidential communications data
over data links between Control Centers. Consequently, it is recommended that ALL data
transmitted between Control Centers be protected. The standards should only address all data
communication between control centers. Technologies such as encryption are generally
implemented by link, not communication type.
More than one commenter requested that guidance language be provided for acceptable means
of physically protecting communications links and identifying effective methods to mitigate risk.
SDT Response: The SDT appreciates all of the comments and suggestions, and will consider the
appropriate mechanism by which to provide guidance for each of the issues identified.

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Q1 Additional Comments
More than one commenter stated that the language in the proposed Reliability Standard should
be in better alignment with the directives of the FERC order to establish a plan and implement
controls to address the risks posed to the BES. At least one commenter noted that FERC
emphasized that additional protection was required to protect both the “integrity and availability
of sensitive bulk electric system data,” FERC Order No. 822, P. 54. That commenter also noted
that FERC made clear that this involved, at a minimum, two discrete actions: 1) that entities
should implement controls to protect the physical communications links transmitting sensitive
data between Control Centers; 2) that the sensitive data itself needed to be protected to ensure
its accuracy and consistency. The commenter further stated that in issuing the directive
subsequent to this rulemaking, FERC stated: “we adopt the NOPR proposal and direct that NERC
. . . develop modifications to the CIP Reliability Standards to require responsible entities to
implement controls to protect.”
At least one commenter inquired as to why the FERC Order requires “. . . protect . . . data . . .”
but the proposed R1 states to “. . . mitigate the risk of unauthorized disclosure or modification of
data . . .”
SDT Response: The SDT asserts that the proposed CIP-012-1 Standard is in alignment with the
directives in FERC Order No. 822 and has provided a Consideration of Issues and Directives
document explaining its rationale. The SDT has established the security objective in
Requirement R1 to address the Commission’s directive on protecting the confidentiality
(unauthorized disclosure) and integrity (unauthorized modification) of the data being
transmitted.
At least one commenter expressed agreement with the creation of a new standard, rather than
expanding CIP-003, CIP-005 and/or CIP-006 requirements to provide new controls over physical
communication links.
SDT Response: The SDT thanks you for your support.
Another commenter requested that the SDT consider differentiating requirements for Control
Center communications within a Responsible Entity from those for Control Center
communications between different Responsible Entities. The commenter noted that data being
sent for Reliability Standards TOP-003 and IRO-010 traverse the ICCP network maintained by a
carrier, and Responsible Entities cannot provide physical protection for communication of this
data from end to end. The commenter further stated that in the case of communications
between different Responsible Entities, protecting the confidentiality and integrity can only be
done through encryption. Since no single utility owns the hardware end to end on the ICCP
network, site to site encryption cannot be implemented. The only options available would be
application layer encryption or transport layer encryption utilizing IEC 62351-4 Secure ICCP. The
commenter also noted that latency issues may occur from such data encryption.

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SDT Response: The FERC Order specifically notes that the protection of sensitive BES data
transmitted between Control Centers should be implemented for both inter- and intra-entity
transmissions of data. The SDT intentionally did not restrict the language to Control Centers
owned by a single Responsible Entity for this reason. Following the data specifications in the
IRO and TOP standards would not be enough to fulfill this Order, unless appropriate controls
are also included. The SDT cannot comment on specifics as to whether certain practices fulfill
a Responsible Entity's compliance obligations.
More than one commenter noted that both TOP-003 and IRO-010 have a requirement that there
be a mutually agreeable security protocol, and asked for the reason a new standard should be
developed. The commenter further suggested the SDT consider modifying TOP-003 and IRO-010
if these standards do not provide adequate language to meet Order No. 822’s concerns.
SDT Response: The SDT asserts that it is less confusing to keep all security-related requirements
within the CIP family of standards. Also, the use of "mutually agreeable security protocol”
does not encompass the intent of the Commission's Order, particularly around protecting the
confidentiality and integrity of sensitive bulk electric system data. It is the position of the SDT
that proposed CIP-012-1 and the TOP/IRO Requirements referred to in the comment
complement one another.
At least one commenter suggested the addition of new requirement(s) to establish a hierarchy
that requires Responsible Entities with the highest risk to set the communications security
protocols. The commenter further suggested that Requirement R1 require Responsible Entities
to have plans that follow the protocols set by the Responsible Entities higher in the hierarchical
order.
SDT Response: It is the position of the SDT that it is appropriate to require the same protection
for sensitive BES data while being transmitted between Control Centers, regardless of the
impact level of the Control Center. The SDT has added a requirement part for coordination of
responsibilities where multiple Responsible Entities are involved in the data transmission.
One commenter stated that proposed Reliability Standard CIP-012-1 is not necessary, and
provided alternative proposals to address the risks by way of existing Reliability Standards such
as CIP-003 and CIP-005.
SDT Response: The SDT determined that a new Reliability Standard is needed due to the
interaction between all impact levels of BES Cyber Systems (i.e. high, medium, and low).
At least one commenter expressed disagreement with the use of two separate requirements,
one for a plan and one to implement. That same commenter referred to CIP-004-011 as an
example.
SDT Response: The SDT thanks you for your comment; however, the SDT elects to retain two
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separate requirements.
One commenter pointed out that the Rationale discusses “CIP-012-1 Requirements R1 and R2
protection for applicable data during transmission between two geographically separate Control
Centers;” The commenter asserted, however, that the requirements themselves don’t seem to
make that same distinction. The commenter stated that since the definition of a “Control Center”
includes associated data centers, this could, for example, lead to the application of the proposed
Reliability Standard to a facility that houses two control centers side-by-side (one with a data
center downstairs). The commenter requested that the SDT provide more information about the
rationale relative to geographical location and proximity of Control Centers, and corresponding
language of the Requirements.
SDT Response: The SDT modified Requirement R1 to address data “transmitted between any
Control Centers”. This is irrespective of location and inclusive of the data centers as noted in
the definition of Control Center.
One commenter noted that CIP-012-1 includes protection for data while being transmitted
between Control Centers, and points out that Control Centers are facilities and do not transmit
data. The commenter asked whether or not only data transmitted between BES Cyber Systems
associated with a Control Center are included, or does it also include data transmitted by certified
System Operators?
SDT Response: The SDT notes that data centers are included in the definition of Control Center.
The data centers are traditionally the facilities that transmit the data. The data to be protected
is Real-time Assessment and Real-time monitoring and control data transmitted between any
Control Center.
At least one commenter stated that it is an overwhelming task to differentiate what is or what
isn’t confidential communications data over data links between Control Centers. The commenter
recommended that all data transmitted between Control Centers be protected. The commenter
further stated that technologies such as encryption are generally implemented by link, not
communication type.
SDT Response: It is the position of the SDT that, in an establishing a plan for draft CIP-012-1,
the Responsible Entity is not restricted to only protecting the data noted in the comment. If a
Responsible Entity can achieve the security objective by protecting data on a larger scale, the
Responsible Entity may do so.
One commenter noted that the Requirements should only permit the option to logically protect
the data during transmission or at least remove the explicit options to physically protect the data,
since physical protection is generally only available to address communication lines within the
same facility. The commenter states that cryptography is the only mechanism available to protect

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data across geographically dispersed Control Centers, and that presenting other options is
confusing and has a strong potential to guide the industry toward ineffective solutions.
SDT Response: If an entity's environment is suited to use logical controls to protect the data as
specified in CIP-012-1, they may do so. The same is the case if an entity’s environment is suited
for physical controls. This option is presented in case an entity decides, based on their
environment, to use physical means in their protection scheme.
At least one commenter suggested that the SDT provide additional instruction within the
Reliability Standard to address the requirements and implications for Balancing Authorities that
serve as the Balancing Authority for other Responsible Entities. The commenter adds that it
would be helpful to understand the Balancing Authority’s responsibility to mitigate the risk of
unauthorized disclosure or modification of data used for the analysis, assessment, and
monitoring. The commenter also asked whether or not the Reliability Standard requirement for
communications between control centers extends to communications between Responsible
Entities and the Reliability Coordinators.
SDT Response: The SDT has drafted Requirement R1 to address data transmitted between
Control Centers, including Reliability Coordinators, Balancing Authorities, and those they are
interconnected with. The SDT has added a requirement part for coordination of responsibilities
where multiple Responsible Entities are involved in the data transmission.
At least one commenter expressed concerns regarding the SDT addressing the CIP Version 5
Transition Advisory Group (V5TAG) identified issues with the CIP Version 5 Reliability Standard
language that caused difficulty in implementation of the requirements. The commenter notes
that the requirements, or another mechanism supplemental to CIP-005, needs to clarify the
4.2.3.2 exemption phrase “between discrete Electronic Security Perimeters.”
SDT Response: The SDT thanks you for your comment. The SDT will be looking into addressing
the v5TAG items noted in the near future. The SDT drafted CIP-012-1 without a dependency on
an Electronic Security Perimeter for two reasons. First, the draft CIP-012-1 applies to
Responsible Entities with high, medium, and/or low impact Control Centers. Since not all
impact levels have defined Electronic Security Perimeters, CIP-012-1 is not based on them.
Secondly, the Commission did not make note of Electronic Security Perimeters in Order 822, but
rather that requirements are needed for Responsible Entities to protect sensitive BES data
transmitted between Control Centers. The SDT will look into specifying demarcation points of
where this protection would originate and terminate to clarify.

Question 2: CIP-012-1 Requirement R1 Scope
Summary Response
2. Requirement R1: The SDT seeks comment on the need to scope sensitive BES data as it applies
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to Operational Planning Analysis, Real-time Assessment, and Real-time monitoring. Do you agree
with scoping CIP-012-1 Requirement R1 in this manner? Please provide comment in support of
your response.

Data used for Operational Planning Analysis should not be
considered sensitive BES data.
Several commenters stated that data used for Operational Planning Analysis does not have a
fifteen (15) minute impact on the reliability of the BES and should not be considered sensitive
BES data. At least one commenter inquired if the 15-minute impact applicable to CIP-002
identification of BES Cyber Systems affects the applicability of CIP-012-1.
SDT Response: The SDT concluded that Operational Planning Analysis data, if rendered
unavailable, degraded, or misused, would not adversely impact the reliable operation of the
BES within 15 minutes of the activation or exercise of the compromise as detailed in CIP-0025.1a. The SDT has revised the data in scope of proposed Reliability Standard CIP-012-1 to
include only Real-time Assessment and Real-time monitoring and control data. The terms Realtime Assessments and Real-time used are defined in the Glossary of Terms Used in NERC
Reliability Standards and used in TOP-003 and IRO-010, among other Reliability Standards.

Directly reference the data specification requirements in IRO-010
and TOP-003
At least one commenter stated that aligning proposed Reliability Standard CIP-012-1 with TOP003-3 and IRO-010-2 is helpful for scoping CIP-012-1, and promotes consistent application of the
NERC Standards.
Several commenters recommended proposed Reliability Standard CIP-012-1 include a direct
reference to the data specification requirements in IRO-010 and TOP-003.
One commenter stated that the requirement as written does not meet the criteria as outlined in
the document titled “Ten Benchmarks of an Excellent Reliability Standard.” The same commenter
suggested that the SDT should draw a clear and unambiguous line to IRO-010 and TOP-003 within
the CIP-012-1 requirement.
SDT Response: The SDT appreciates the comment but elects to use the defined terms from the
Glossary of Terms used in NERC Reliability Standards to identify sensitive Bulk Electric System
(BES) data, rather than directly referencing other Reliability Standards. The SDT discussed
referencing the two applicable standards in the requirement language and determined that a
number of issues could arise by directly referencing applicable IRO/TOP requirements. Possible
issues include but are not limited to applicability issues and the required coordination of future
revisions of the IRO/TOP standards and proposed Reliability Standard CIP-012-1.

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Impact of encryption on system performance
More than one commenter noted that in addition to adding latency, encryption adds the burden
of ongoing maintenance and management for an encryption program. The commenters also
stated that guidance is needed on key management and inter utility agreements pertaining to
coordination for encryption of data and impacts on real-time operation of the Bulk Electric
System.
SDT Response: The SDT contends that the applicable data is not used for time sensitive
protection or control functions, such as communications using protocol IEC TR-61850-90-5 RGOOSE. The SDT asserts that technical solutions are available to address the security objective
of the proposed requirement without hindering operational performance. The SDT intends to
provide guidance for proposed Reliability Standard CIP-012-1. Additionally, should further
guidance prove necessary, stakeholders may work with pre-certified entities to develop
Implementation Guidance that may be submitted for ERO endorsement.

Data Type
One commenter asked whether or not “data used for Operational Planning Analysis, Real-time
Assessments, and Real-time monitoring” includes Generator Unit Commitment Data and/or
transmission and generator outages which are posted publicly.
More than one commenter stated that the requirement suggested data that are different from
the data protected in other CIP standards, asserting that this may cause confusion in the future
by calling it a CIP standard.
SDT Response: The SDT noted the reference in FERC Order No. 822 to additional Reliability
Standards and the responsibilities to protect the data in accordance with those standards (TOP003-3 and IRO-010-2). The SDT used these references to drive the identification of sensitive BES
data and based proposed Reliability Standard CIP-012-1 on the data specifications in these
standards. The SDT asserts that the data referenced by FERC Order No. 822 includes Real-time
Assessment and Real-time monitoring and control data. The terms Real-time Assessments and
Real-time used are defined in the Glossary of Terms Used in NERC Reliability Standards and
used in TOP-003 and IRO-010, among other Reliability Standards. This data is inherently
different than BES Cyber System Information. However, the security objective to protect the
confidentiality and integrity of this data while being transmitted between Control Centers
should reside in a Critical Infrastructure Protection Standard to be responsive to FERC Order No.
822.

Encrypt the link, not the data
Several commenters suggested that proposed Reliability Standard CIP-012-1 include language to
require encrypting the link, not the data. The commenters note that technologies such as
encryption or physical protection are generally implemented by link, not communication type.
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Several commenters also suggested that further clarification on the scope of the data is needed
to clarify that the data in question has already been scoped and is in specifications that are
required by IRO-010 and TOP-003. The commenters also state that the SDT should consider doing
away with a “data-centric” approach and focus protection on a more technical solution
regardless of the type of data being transmitted between Control Center Electronic Security
Perimeters and Low Impact Electronic Access Points.
SDT Response: The SDT has written the requirement to allow flexibility as to how to implement
this requirement. This includes addressing the security objective without being prescriptive in
the protections to be applied. The SDT noted the reference in FERC Order No. 822 to additional
Reliability Standards and the responsibilities to protect the data in accordance with those
standards (TOP-003 and IRO-010). The SDT used these references to drive the identification of
sensitive BES data and based Reliability Standard CIP-012-1 on the data specifications in these
standards. This approach provides consistent scoping of identified data, and does not require
each entity to devise its own list or inventory of this data. Many Responsible Entities are
required to provide this data under agreements executed with their Reliability Coordinator,
Balancing Authority, or Transmission Operator, often without benefit of knowing how those
entities use that data.

Add "BES" - to the R1 requirement language
At least one commenter noted that the FERC directive refers to “sensitive bulk electric system
data” and directs NERC to “identify the scope of sensitive Bulk Electric System data,” The
commenter also states that the FERC directive also acknowledges that certain entities are already
required to exchange necessary real-time and operational planning data through secured
networks using mutually agreeable security protocol. At least one commenter requested the SDT
consider scoping sensitive data explicitly to information exchanged between Control Centers'
BES Cyber Systems. The commenters assert that the suggestion corresponds to the SDT's
statement that “this data resides within BES Cyber Systems, and while at rest is protected by CIP003 through CIP-011,” and also corresponds to FERC's recognition of mutually agreeable security
protocol networks referenced above. Also, at least one commenter stated that the entity needs
to know what information is classified as BES sensitive data as it relates to operational planning
analysis, real-time assessment, and real-time monitoring. The commenter notes that in many
cases some types of operational planning analysis data is housed in systems not classified as BES
Cyber Systems and may not reside within an Electronic Security Perimeter.
SDT Response: The SDT asserts that Real-time Assessment and Real-time monitoring and
control data may not be limited to BES data. Please reference IRO-010-2, R1, Part 1.1, “1.1. A
list of data and information needed by the Reliability Coordinator to support its Operational
Planning Analyses, Real-time monitoring, and Real-time Assessments including non-BES data
and external network data, as deemed necessary by the Reliability Coordinator.” The SDT
further asserts that certain configurations exist where the demarcation point may not be a BES
Cyber System. A scenario could exist where a router within a Physical Security Perimeter, but
external to the Electronic Security Perimeter, encrypts the communication link between two
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Control Centers. The router would not be categorized as a BES Cyber System, but the
configuration would meet the security objective by implementing a combination of physical
protection of the router and logical protection of the data.

Q2 Additional Comments
At least one commenter requested the SDT provide additional clarification on the protection of
load forecasting data as it may not consistently be included as a separate BES Cyber System.
SDT Response: The SDT modified proposed Reliability Standard CIP-012-1, Requirement R1 to
only apply to Real Time Assessment and Real Time monitoring and control data.

Question 3: Implementation Plan
Summary Response
3. Implementation Plan: The SDT revised the Implementation Plan such that the standard and
NERC Glossary terms are effective the first day of the first calendar quarter that is twelve (12)
calendar months after the effective date of the applicable governmental authority’s order
approving the standard, or as otherwise provided for by the applicable governmental authority.
Do you agree with this proposal? If you agree with the proposed implementation time period,
please note the actions you will take that require this amount of time to complete. If you think an
alternate implementation time period is needed – shorter or longer - please propose an alternate
implementation plan and provide a detailed explanation of actions and time needed to meet the
implementation deadline.

Increase Implementation Time Period
Several commenters stated that additional time would be required to plan, budget, and
implement proposed Reliability Standard CIP-012-1, and recommended Implementation time
periods ranging from greater than twelve (12) months to 60 months.
More than one commenter noted that there are a number of factors to consider, and all affect
the time required to implement. These factors include: 1) complexity of the technology solutions
to be implemented; 2) number of interconnecting lines to secure; 3) troubleshooting/testing at
each connection point; and 4) coordination requirements with external stakeholders, including
coordination of plans across a large and/or diverse group of entities employing a variety of
protective measures. At least one commenter cited the potential impact of having to redesign
communications architectures for secure communications between Control Centers as rationale
for extending the Implementation time period. Another commenter noted that smaller entities
may need to procure equipment and implement technical controls that are not currently in place.
The commenter further stated that the implementation of the plan(s) detailed in Requirement
R1 could be impacted by budget cycles, procurement processes, and third party vendor
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availability. At least one commenter suggested that modifications to the definition of Control
Center may bring new Responsible Entities under the scope of CIP-012-1. The new Control
Centers should be treated as “newly identified CIP facilities” and should be given an eighteen (18)
month implementation period.
SDT Response: The SDT carefully considered all comments and concluded that many factors
should be considered to determine an implementation period. These factors include complexity
of technology solutions, quantity of telecommunications lines requiring controls and
coordination with other Responsible Entities/solution providers. The SDT concluded that a
twenty-four (24) month implementation period is appropriate.

Phased Implementation
Several commenters stated that proposed Reliability Standard CIP-012-1 will require a
collaborative effort between Responsible Entities to achieve the required security for
communications between Control Centers. They go on to state that it may not feasible for some
Responsible Entities to implement the required security protection within 12 months. At least
one commenter suggested that a phased approach may be more appropriate for proposed
Reliability Standard CIP-012-1, based on schedules created using the Responsible Entity
reliability hierarchy structure. As an example, at least one commenter noted that a Reliability
Coordinator (RC) Control Center will have contact with the Control Centers of several Balancing
Authorities (BA), Generator Operators (GOP), Transmission Operators (TOP), Transmission
Owners (TO), and other RCs. If the first particular RC is unable to implement the protection
required by NERC CIP-012-1 then there will be a cascading and unnecessary non-compliance
effect among the other Responsible Entities interconnected with this particular RC’s Control
Center.
At least one commenter noted that applying protection between Control Centers owned by more
than one Responsible Entity will involve significant coordination. Additional time would be
necessary to develop a shared understanding of existing technical limitations, develop
agreements, and implement those new approaches to achieve compliance. That same
commenter indicated that additional time would allow the Responsible Entity to identify Control
Centers that are in scope, decide on a method of protection, and involve any additional necessary
parties.
One commenter noted the potential for replacement of equipment under existing contracts and
requested that the affected contracts be exempted until new agreements can be put in place. A
commenter further suggested that implementation of controls with telecommunications
providers will require coordination and scheduling to align with the providers’ resource
availability and protect against any adverse impact on reliability. The commenter also suggests
that renewal and renegotiation of existing contracts should not be required until they reach their
expiration date.
SDT Response: The SDT carefully weighed a phased implementation plan for Requirement R1
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and Requirement R2 of proposed Reliability Standard CIP-012-1. The SDT concluded, however,
that such a plan with a monitored deadline for each of the requirements would add
unnecessary complexity. Therefore, the SDT has concluded a twenty-four (24) month deadline
would sufficiently meet the needs of industry.

Q3 Additional Comments
At least one commenter stated that Question 3 in the comment form implies there are NERC
Glossary terms in the Implementation Plan, and states that there are no NERC Glossary terms in
the proposed Implementation Plan for proposed Reliability Standard CIP-012-1.
SDT Response: The SDT agrees that there are not terms from the Glossary of Terms used in
NERC Reliability Standards used in the proposed Implementation Plan for proposed Reliability
Standard CIP-012-1.
One commenter requested that the SDT provide a specific justification for any proposed
implementation timeframes, as well as for any revisions to the timeframes that are currently
proposed. That same commenter requested that the SDT ensure there are no issues with the
implementation plan, such as not having an initial performance date where one is needed, or not
including information for new facilities, the commenter included an errata change in the PRC023-4 implementation plan as an example.
SDT Response: The SDT has based the twenty-four (24) month implementation timeline on the
comments received in the initial 45-day comment period and ballot from July 27, 2017 through
September 11, 2017. Since there are no requirements that actions be performed on a defined
frequency, there is no need to define an initial performance date.

Question 4: Cost Effectiveness
Summary Response
4. The SDT believes proposed CIP-012-1 provides entities with flexibility to meet the reliability
objectives in a cost effective manner. Do you agree? If you do not agree, or if you agree but have
suggestions for improvement to enable more cost effective approaches, please provide your
recommendation and, if appropriate, technical justification.

Insufficient Information at this Time
Several commenters agreed that proposed Reliability Standard CIP-012-1 provides Responsible
Entities with the flexibility to implement the standard cost-effectively and offered further
suggestions to fully assess the logistics and costs associated with compliance. For example, some
guidance or specification of boundaries for communications links involved would be required for
entities to complete assessment of impacts to their operations.
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Several commenters asserted that they cannot determine if the objectives may be accomplished
in a cost-effective manner until further clarification is provided for physical or other equally
effective protective measures and until the request for electronic mail exclusion is added. At
least one commenter also noted concerns with vendor availability, regarding system software
implementation that will be required for all entities industry-wide.
At least one commenter requested clarification that there is no requirement to verify integrity of
data from its origin point to the point where it is first aggregated at a control center. The
commenter states that this would make compliance with this requirement substantially more
difficult and costly to achieve.
At least one commenter stated that for entities to fully assess the logistics, costs and
operational impacts associated with compliance, some guidance or specification of boundaries
of communications links involved would be required. One commenter stated that until industry
is able to determine how much of the information requiring protection extends beyond the
fifteen-minute time frame, the entity is not able to agree with the statement regarding costeffective manner.
A commenter expressed concern that while the Standard is sufficiently flexible for an individual
responsible entity, it leaves a potential gap between different Responsible Entities’
interpretations of cost-effective approaches. The commenter noted that a large utility’s view of
cost effectiveness may not match a smaller neighbor’s view of cost effectiveness. Such disparity
could encumber agreement between the parties.
At least one commenter stated that the standard doesn’t directly address the Inter-Control
Center Communications Protocol (ICCP) for exchanging data between control centers or utilities.
The commenter asked whether or not those ICCP servers and supportive infrastructure need to
be upgraded or replaced with data encryption capabilities to support compliance with this
standard.
One commenter stated that the standard doesn’t provide any direction regarding the level of
physical and logical protection that is mandatory. The commenter requested that the SDT
develop guidance to clarify this ambiguity and identify how all entities can achieve a minimum
level of compliance.
SDT Response: Thank you for your comments. The SDT recognizes that it is difficult to ascertain
the level of cost effectiveness prior to implementation. The SDT has attempted to address cost
effectiveness concerns by providing entities the latitude to determine the most appropriate
implementation for their environment that meets the security objective rather than prescribing
a specific approach to compliance. In cases where multiple entities are involved, the standard
provides an obligation to identify the responsibilities of each of the organizations, but provides
the organizations the latitude to determine the best approach for their environments so long
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16

as the sensitive Bulk Electric System data is protected while being transmitted between Control
Centers.

Cost Prohibitive
Several commenters asserted that there will likely be additional costs associated with
administrative overhead, hardware, and software, as well as costs associated with monitoring
the performance of the implemented solutions.
More than one commenter also noted that, Open Source options to satisfy the requirement to
protect communication links and sensitive bulk electric system data communicated between
Control Centers are limited. The commenters contend that fewer options generally translate to
high vendor bargaining power, which could lead to high implementation costs. Those
commenters also stated that it is unclear how or whether costs could be shared among
participants in the network, and that architectural changes to support these requirements should
be spread out over several years.
A commenter stated that security vendors continue to benefit from the expense of establishing
layered cyber defenses, and that Open Source solutions provide a cost and agility refuge from
this lopsided value chain without compromising defense layers. The commenter went on to state
that the trend toward managed services makes the cost problem worse for utilities, especially in
the context of insufficiently evaluated risk. The commenter further stated that vendor leverage
only grows given the practical consideration that all the communicating parties in a WAN of
connected real-time Control Centers would need to adopt a common solution in order to
minimize complexity and cost.
SDT Response: Thank you for your comments. The SDT attempted to address cost effectiveness
concerns by allowing entities the latitude to determine the most appropriate implementation
for their environment that meets the security objective rather than prescribing a specific
approach to compliance. The SDT is also proposing to lengthen the implementation plan to 24
months, which will allow entities additional time for any necessary changes to support these
requirements.

Q4 Additional Comments
At least one commenter expressed agreement with the approach used in proposed Reliability
Standard CIP-012-1 that allows each Registered Entity to analyze risk and use discretion in
determining the best risk mitigation implementation for protecting transmission of applicable
data.
SDT Response: Thank you for your support.

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17

Question 5: Additional Comments
Summary Response

5. If you have additional comments on the proposed CIP-012-1 – Cyber Security -- Communication
Networks drafted in response to the FERC directive that you have not provided in response to the
questions above, please provide them here.
Many of the comments provided for Question 5 were provided and responded to in other
questions.

Applicability
One commenter asked whether or not the Applicability section of proposed Reliability Standard
CIP-012-1 may be modified to indicate that the standard only applies to those specific registered
entities (e.g., GOPs and TOs) that maintain Control Centers AND transmit data between Control
Centers.
One commenter stated that the Applicability section states, “For requirements in this standard
where a specific functional entity or subset of functional entities are the applicable entity or
entities, the functional entity or entities are specified explicitly,” while asserting that no
Requirements in proposed Reliability Standard CIP-012-1 explicitly specify a functional entity or
entities. That same commenter recommended the SDT remove the language quoted in the
comment above.
A commenter stated that, pursuant to proposed Reliability Standard CIP-012-1, §4 Applicability,
this standard is applicable to the Generator Owner, while noting that the proposed definition
of Control Center exempts the Generator Owner as it only speaks to the Generator Operator’s
Control Center. The commenter further asserted that proposed Reliability Standard CIP-012-1
should not be applicable to the Generator Owner.
SDT Response: The SDT modified the applicability of the Standard as, “The requirements in this
standard apply to the following functional entities, referred to as “Responsible Entities,” that
own or operate a Control Center.” The SDT intends for the standard to include Generator
Owners and Transmission Owners that own or operate a Control Center. The Control Center
definition as written addresses the reliability tasks of an RC, BA, TOP, and GOP irrespective of
registration. The SDT thanks you for the comments and is continuing to work on possible
revisions to the definition to address these and other concerns.

CEC
At least one commenter questioned if using the phrase “CIP Exceptional Circumstances” is
appropriately used in Requirement R2, since the intent is “to protect confidentiality and integrity
of data transmitted between Control Centers required for reliable operation of the Bulk Electric

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18

System (BES).” That same commenter asserts that CIP Exceptional Circumstances criteria are not
relative to data transmission.
Another commenter requested that the SDT provide a rationale for including the phrase “CIP
Exceptional Circumstances” in Requirement R2. That same commenter further stated that, in
particular, it is unclear why certain CIP exception conditions, such as an imminent hardware
failure, should necessarily trigger a relaxation of physical security protections for
communications links transmitting sensitive data in all circumstances.
SDT Response: The SDT drafted the requirement with the understanding that there may be
instances where a Responsible Entity may not be able to maintain compliance with the
requirement as a result of a CIP Exceptional Circumstance. Responsible Entities may need to
use alternate, as-yet-unidentified data transmission methods as a result of a CIP Exceptional
Circumstance event. This allowance will enable Responsible Entities to focus on reliability
without the risk of a compliance issue.

Control Center Definition
Several commenters expressed concerns with the proposed definition of Control Center,
particularly identifying the last paragraph concerning a Generating Operator. At least one
commenter stated that the use of the word “capability” is ambiguous and will confuse Registered
Entities and Compliance Enforcement Authorities, and suggested the SDT consider the approved
Applicability within PER-005-2 part 4.1.5.1.
SDT Response: The SDT thanks you for the comments and is continuing to work on possible
revisions to the definition to address these concerns and others.

Coordination with other Entities
More than one commenter stated that the proposed standard does not make clear how entities
should work together when addressing security concerns across a communication network link,
and stating that, if both entities work with CIP Standard assumptions on both ends of a
communication network, some support for joint handling of issues could be made
clear; however, if only one entity is CIP-compliant for a given link, the current standard draft does
not make clear the extent of protection expected for the data. The commenter further asked
where the obligation for protecting a link per entity starts and ends.
At least one commenter stated that the proposed standard does not provide a sufficient level of
detail on how entities should work together to handle security concerns across a communication
network. The commenter suggested that the standard should clearly identify where the
obligations for protecting data in a communication network start and end per entity.
One commenter noted that, if the region is responsible for the system, all entities would have to
coordinate with the region on a solution, and that the solution may require additional equipment
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19

to be installed. The commenter further stated that a region-wide formal agreement may be
difficult to develop and execute in a year.
At least one commenter stated that implementing industry-wide secure communications is a
significant coordination challenge for entities and their associated vendors. The commenter
further stated that increases in security bring increased complexity, maintenance, and failure
potential that may negatively impact the reliable operation of the BES. The commenter stated
that, as a result, coordination for encryption key management will become an essential activity
and guidance would be appreciated by stakeholders for these activities.
SDT Response: The SDT agrees with these concerns and has modified the requirement to
include, “Identification of roles and responsibilities of each Responsible Entity for applying
security protection to the transmission of Real-time Assessment and Real-time monitoring and
control data between Control Centers, when the Control Centers are owned or operated by
different Responsible Entities.” This requires entities to participate in this coordination while
maintaining flexibility on implementation of this requirement. The SDT has also modified the
Implementation Plan to allow twenty-four (24) months to accomplish these tasks.

Exclusion in CIP-002 thru CIP-011
More than one commenter indicated that it is unclear whether the addition of proposed
Reliability Standard CIP-012-1 affects the exemptions of communication networks in any of the
applicability sections of other standards (CIP-002 through CIP-011). At least one commenter
requested clarification that proposed Reliability Standard CIP-012-1 fills in some of the gap that
the commenter asserted was created by the CIP-002 – CIP-011 third party telecommunications
exemption (4.2.3.2. Cyber Assets associated with communication networks and data
communication links between discrete Electronic Security Perimeters).
SDT Response: The SDT does not intend for CIP-012 to modify the list of Cyber Assets managed
under CIP-002 thru CIP-011. The SDT acknowledges that the Cyber Assets secured under CIP002 thru CIP-011 are under the control of the Responsible Entity. The telecom equipment listed
in the exemptions of these standards is to exclude equipment not under the management of
the Response Entity. However, under CIP-012, the Responsible Entity does have the capability
to protect the data that is transmitted across the equipment not under its control.

Implementation Guidance
Several commenters stated that Implementation Guidance for proposed Reliability Standard CIP012-1 would be helpful.
At least one commenter suggested that without implementation guidance describing how to
accomplish the required risk mitigation, it is difficult to predict the amount of time that would be
required to implement this requirement part. The commenter added that they cannot assume
the twelve (12) months prescribed in the proposed implementation plan is adequate.
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20

At least one commenter indicated that it would be beneficial to have guidance on key
management and inter-utility agreements particularly as it pertains to coordination for
encryption of data between third parties and compliance impacts on reliability.
At least one commenter suggested guidance on the possible determination of the security
method used being developed at the regional or Reliability Coordinator level to facilitate a more
cost-effective approach. That same commenter also noted that Implementation Guidance could
also address the entity evidence needed when an entity is following what was determined by the
Region, Reliability Coordinator, or Independent System Operator.
SDT Response: The SDT is developing implementation guidance to be submitted for ERO
endorsement. Specific implementation examples are being identified.

Link to IRO and TOP standards
Several commenters requested the SDT link the data to be protected from the data specifications
developed under Standards TOP-003 and IRO-010, so there will be no ambiguity as to what “data”
is to be protected.
At least one commenter stated that data associated with Operational Planning Analyses (OPA),
Real-time monitoring (RTm), and Real-time Assessments (RTA) are predicated on other Standards
and protection of data is required but all three areas (OPA, RTm, and RTA) are not subject equally
to the Applicable Entities noted in CIP-012-1. That same commenter stated that the SDT, in the
Technical Rationale and Justification document acknowledges TOP-003 and IRO-010 “provides
consistent scoping of identified data” Based on this, the commenter suggested the SDT quantify
the data to be protected is the data associated with the Applicable entities with IRO-010-2 and
TOP-003-3. The commenter asserted that, by doing so, the SDT will articulate what analysis the
entity is to preform and what “data” is to be protected, based on already approved NERC
Reliability Standards.
SDT Response: The SDT agrees with the concerns notes and had modified Requirement R1
to only apply to Real-time Assessment and Real-time monitoring and control data. The SDT
has compared the applicability of TOP-003-3 and IRO-010-1. The SDT has determined
CIP-012-1 should not apply to Distribution Providers, since it is unlikely they own or operate a
Control Center.

Scope of data
Several commenters expressed concern with the phrase “Real-time monitoring” as used in
proposed Reliability Standard Requirement R1, since “Real-time” is defined as “present time as
opposed to future time.” One commenter stated that the word “monitoring” may mean ALL
monitoring of an entity’s entire SCADA system; however, it should be the “monitoring” of only
BES data that is required for Operational Planning Analysis and Real-time Assessments.
At least once commenter stated that proposed Reliability Standard CIP-012-1 should be aligned
with TOP-003-3, as data security is already required in TOP-003-3 Requirement R5. The
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commenter further states that only data that is stipulated in the TOP-003-3 Requirement R1 data
specification for Operational Planning Analysis, Real-time Assessment, and Real-time monitoring
should be in scope for proposed Reliability Standard CIP-012-1.
One commenter stated that the NERC ORD may serve as a reference guide and resource
regarding the scope of this standard and sensitive data generally, since the NERC ORD Agreement
has long maintained an accepted, well-established definition for sensitive reliability data. That
same commenter stated that the definition does not include data used in the Operational
Planning Horizon and, for the reasons discussed above, asserts that the inclusion of Operational
Planning Analysis in proposed Reliability Standard CIP-012-1 Requirement R1 extends the scope
of BES sensitive data without attendant benefit to reliability. The commenter further
recommended the deletion of Operational Planning Analysis from proposed Reliability Standard
CIP-012-1, Requirement R1, to allow the Requirement to remain consistent with well-established,
well understood precedent as set forth in the NERC ORD Agreement.
One commenter expressed concern that the scope of the standard regarding data protection
(based on IRO-010 and TOP-003) extends the requirement to data/information that is not
currently required to be protected at the level of a High Impact BES Cyber System, and asserted
that this approach does not match the intent and protections of all other NERC CIP standards.
SDT Response: The SDT does not agree with the need to define the term “Real-time
monitoring”. The SDT has modified Requirement R1 to apply to Real-time Assessment and Realtime monitoring and control data. This is to be consistent with the Control Center definition
which says "One or more facilities hosting operating personnel that monitor and control the
Bulk Electric System (BES) in real-time.” The SDT does not intend for CIP-012 to modify the list
of Cyber Assets managed under CIP-002 thru CIP-011. The SDT acknowledges that the Cyber
Assets secured under CIP-002 thru CIP-011 are under the control of the Responsible Entity. The
communication networks and data communication links listed in the exemptions of these
standards is to exclude equipment not under the management of the Response Entity.
However, under CIP-012, the Responsible Entity does have the capability to protect the data
that is transmitted across the equipment not under their control.

Q5 Additional Comments
One commenter states that the requirement language of proposed Reliability Standard CIP-0121 focuses on the risk of unauthorized disclosure or modification of data, and notes that, in an
operational environment the integrity and availability legs of the CIA triad are more critical than
the confidentiality. The commenter suggested the SDT consider revising the proposed Reliability
Standard to focus on ensuring the integrity and availability of the data.
SDT Response: The timelines for making data available through required submissions are
defined within the TOP and IRO Reliability Standards. Responsible Entities are required to
submit the data in order to maintain compliance with the TOP and IRO Standards. The SDT does
not see the need to add to this obligation with CIP-012.
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A commenter stated that Reliability Standard CIP-012-1, Requirement R2 does not identify a
“reasonable” timeline for implementing the plan identified in R1, and asserted that the lack of a
timeline could lead to prolonged and needless delay in implementing the required protections.
SDT Response: The SDT has also modified the Implementation Plan to allow twenty-four (24)
months to accomplish these tasks.
One commenter requested clarification in the standard verbiage that the intent of this standard
applies to inter control center communication.
SDT Response: The intent of the SDT is to apply the requirements to communications between
Control Centers owned or operated by the same entity (intra-entity) or by different distinct
entities (inter-entity).
At least one commenter asserted that Generator Operators within the ERCOT footprint who are
not also Qualified Scheduling Entities (QSE) will not be able to comply with the standard as
written if their Control Center transmits and receives the data as specified in proposed Reliability
Standard CIP-012-1, Requirement R1. The commenter further stated that, within the ERCOT
footprint, the sensitive BES data transmitted between the Control Centers of the Balancing
Authority (BA), Transmission Operator (TOP), Reliability Coordinator (RC) and Generator
Operator (GOP) are submitted through the QSE (Assume that ERCOT is acting as the RC, BA
and/or TOP for particular GOP and that GOP is not also a QSE), and that the QSE is not a
recognized NERC Functional Entity and as such would not be subject to adhering to NERC
Reliability Standards. The commenter further stated that it would not be possible for a GOP to
protect the sensitive BES data that is transmitted to and from the Control Center of the QSE and
ERCOT that ultimately is either being sent or received by the GOP Control Center. NERC CIP-0121, as written, does not account for this ERCOT nuance.
SDT Response: CIP-012-1 is applicable to NERC-registered Generator Operators and Generator
Owners. Responsible Entities are to ensure that Real-time Assessment and Real-time
monitoring and control data is protected throughout the transmission between each Control
Center, regardless of any other third party in the middle of the transmission of the data. To
address the concerns with coordination between Responsible Entities, modified the
requirement to include, “Identification of responsibilities, when Control Centers are owned or
operated by different Responsible Entities, for applying the security protection of the
transmission of Real-time Assessment and Real-time monitoring and control data”. This
requires entities to participate in this coordination while maintaining flexibility on
implementation of this requirement. The SDT has also modified the Implementation Plan to
allow twenty-four (24) months to accomplish these tasks.
A commenter stated that if the SDT retains a data-centric approach, the commenter considers
the time element very important and correctly captured in the requirement with the phrase
“while being transmitted between Control Centers,” and the commenter encouraged the SDT to
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retain this language. The commenter stated the RSAW for proposed Reliability Standard CIP-0121 does not include a time element and just says “transmitted between.”
SDT Response: The SDT thanks you for your comment and has retained this concept.
One commenter stated that simply specifying that some risk mitigation should be applied by
means that include physical, logical and possibly other means leads to insufficient conditions ‘’
for establishing compliance both for the responsible entity and anyone reviewing compliance for
that entity. The commenter further states that entities should consider not only that risk
mitigation should take place, but also the thresholds for residual risk that should be considered
acceptable for such communication.
SDT Response: The SDT thanks you for your comment and agrees with the advice noted.
At least one commenter requested that the SDT verify and confirm that the Glossary of Terms
Used in NERC Reliability Standards defined terms ‘Operational Planning Analyses’, ‘Real-time
Assessments’, and ‘Real-time’ (mentioned in the Rationale Section in reference to Requirement
R1) are defined and properly aligned with the Rules of Procedure (RoP) documentation. That
same commenter requested the SDT provide clarity on why the RoP is not mentioned in the
Implementation Plan like the NERC Glossary of Terms. The commenter stated that the RoP, and
the definitions it contains, have the same significance that the Glossary of Terms have in
reference to the industry defined terms.
SDT Response: The SDT deliverables are the Standard, Implementation Plan, and definitions to
be included in the NERC Glossary of Terms Used in Reliability Standards. The SDT does not have
the ability to modify the Rules of Procedure.
One commenter stated that, although the FERC order specifies data between Control Centers,
there is OPA, RTA, and Real-time monitoring data that is not exchanged between control
centers. As examples, the commenter stated that Distribution Providers provide BES sensitive
data that would not be subject the standard, and that there are numerous GOPs that do not
have a control center per the definition that provide BES sensitive data which also would not
subject to proposed Reliability Standard CIP-012-1. The commenter then expressed concern that
the aforementioned condition creates a reliability gap since these scenarios would not be
covered under the current draft of proposed Reliability Standard CIP-012-1.
SDT Response: Consistent with FERC Order No. 822, paragraph 58, the SDT intends for CIP-012
to “encompass communication links and data for intra-Control Center and inter-Control Center
communications.” The Standard does not apply to data transmitted between any other types
of BES assets.
More than one commenter noted concerns with the use of Secure ICCP and offered thoughts on
the use of alternate security protection.

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A commenter noted National Infrastructure Advisory Council (NIAC) recommendation to
separate communication networks be used for critical communications.
SDT Response: The SDT acknowledges these concerns and drafted the requirement to allow
flexibility on implementation of this requirement. This includes addressing the security
objective without being prescriptive in the protections to be applied.
One commenter asked about the representation of TO Control Centers, particularly inquiring
whether or not the TO field asset box on page # 5 of Technical Rationale and Justification for
CIP-012-1 document includes TO Control Centers.
SDT Response: Please see response to comments for the Technical Rational document.
A commenter suggested the SDT include the phrase “where technically feasible” to proposed
Reliability Standard CIP-012-1.
SDT Response: The SDT does not agree with the need for the phrase “where technically
feasible”. The requirement has been written to allow flexibility on implementation of this
requirement. This includes addressing the security objective without being prescriptive in the
protections to be applied.
One commenter expressed concern that the protective measures developed by entities for
proposed Reliability Standard CIP-012-1 could have unintended consequences, particularly
identifying a concern that encryption could unacceptably slow data transmission.
SDT Response: The SDT acknowledges these concerns and drafted the requirement to allow
flexibility on implementation of this requirement. This includes addressing the security
objective without being prescriptive in the protections to be applied.
At least one commenter suggested the SDT change the title of the CIP-012-1 requirement to “CIP012-1-Cyber Security – Control Center Communication Links” to align with the language in FERC
Order No. 822 and the language in proposed Reliability Standard CIP-012-1, Requirement R1. The
commenter asserts that the current use of the term “Networks” may be misleading because it
implies a broader scope of communication.
SDT Response: The title has been changed to, “Cyber Security – Communications between
Control Centers”.
One commenter stated that industry-wide coordination would be necessary to successfully
implement encryption for proposed Reliability Standard CIP-012-1.
SDT Response: The SDT modified the requirement to include, “Identification of roles and
responsibilities of each Responsible Entity for applying security protection to the transmission

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of Real-time Assessment and Real-time monitoring and control data between Control Centers,
when the Control Centers are owned or operated by different Responsible Entities.” This
requires entities to participate in this coordination while maintaining flexibility on
implementation of this requirement. The SDT has also modified the Implementation Plan to
allow twenty-four (24) months to accomplish these tasks.
A commenter recommended that proposed Reliability Standard CIP-012-1, Requirement R1 VSL
be “Moderate” to “High” due to the fact that Requirement R1 is a documentation requirement.
SDT Response: The SDT has modified the VSLs to be varying in degree. It should be noted that
if a requirement has a single VSL, the VSL must be severe.

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26

Consideration of Comments
Project Name:

2016-02 Modifications to CIP Standards | CIP-012-1

Comment Period Start Date: 7/27/2017
Comment Period End Date:

9/11/2017

Associated Ballot:

2016-02 Modifications to CIP Standards CIP-012-1 IN 1 ST

There were 81 sets of responses, including comments from approximately 207 different people from approximately 139
companies representing the 10 Industry Segments as shown in the table on the following pages.
All comments submitted can be reviewed in their original format on the project page.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give every comment serious
consideration in this process. If you feel that your comment has been overlooked, or was insufficiently addressed, please let us
know by contacting the Senior Director, Standards and Education, Howard Gugel (via email) or at (404) 446‐9693.

Consideration of Comments | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | October 27, 2017

27

Questions

1. Requirement R1: The SDT drafted CIP-012-1 Requirement R1 to meet the mandatory requirement for the Responsible Entity to
develop one or more documented plan(s) to mitigate the risk of the unauthorized disclosure or modification of data used for
Operational Planning Analysis, Real-time Assessment, and Real-time monitoring data while being transmitted between Control
Centers. Do you agree with this revision? If not, please provide the basis for your disagreement and an alternate proposal.
2. Requirement R1: The SDT seeks comment on the need to scope sensitive BES data as it applies to Operational Planning Analysis,
Real-time Assessment, and Real-time monitoring. Do you agree with scoping CIP-012-1 Requirement R1 in this manner? Please provide
comment in support of your response.
3. Implementation Plan: The SDT revised the Implementation Plan such that the standard and NERC Glossary terms are effective the
first day of the first calendar quarter that is twelve (12) calendar months after the effective date of the applicable governmental
authority’s order approving the standard, or as otherwise provided for by the applicable governmental authority. Do you agree with
this proposal? If you agree with the proposed implementation time period, please note the actions you will take that require this
amount of time to complete. If you think an alternate implementation time period is needed – shorter or longer - please propose an
alternate implementation plan and provide a detailed explanation of actions and time needed to meet the implementation deadline.
4. The SDT believes proposed CIP-012-1 provides entities with flexibility to meet the reliability objectives in a cost effective manner. Do
you agree? If you do not agree, or if you agree but have suggestions for improvement to enable more cost effective approaches, please
provide your recommendation and, if appropriate, technical justification.
5. If you have additional comments on the proposed CIP-012-1 – Cyber Security -- Communication Networks drafted in response to the
FERC directive that you have not provided in response to the questions above, please provide them here.

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The Industry Segments are:

1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities

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29

Organization
Name

Name

FirstEnergy - Aaron
3
FirstEnergy Ghodooshim
Corporation

Brandon
McCormick

Brandon
McCormick

Segment(s)

Region
RF

FRCC

Consideration of Comments | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | October 27, 2017

Group
Group Name
Member Name
FirstEnergy Aaron
Corporation Ghdooshim

FMPA

Group
Group
Member
Member
Organization Segment(s)

Group
Member
Region

FirstEnergy FirstEnergy
Corporation

4

RF

Aubrey Short

FirstEnergy FirstEnergy
Corporation

1

RF

Theresa
Ciancio

FirstEnergy FirstEnergy
Corporation

3

RF

Robert Loy

FirstEnergy FirstEnergy
Solutions

5

RF

Ann Ivanc

FirstEnergy FirstEnergy
Solutions

6

RF

Tim Beyrle

City of New
4
Smyrna Beach
Utilities
Commission

FRCC

Jim Howard

Lakeland
Electric

5

FRCC

Lynne Mila

City of
Clewiston

4

FRCC

30

Organization
Name

Name

Segment(s)

Region

Consideration of Comments | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | October 27, 2017

Group
Group Name
Member Name

Group
Group
Member
Member
Organization Segment(s)

Group
Member
Region

Javier Cisneros Fort Pierce
Utilities
Authority

3

FRCC

Randy Hahn

Ocala Utility
Services

3

FRCC

Don Cuevas

Beaches
Energy
Services

1

FRCC

Jeffrey
Partington

Keys Energy
Services

4

FRCC

Tom Reedy

Florida
Municipal
Power Pool

6

FRCC

Steven
Lancaster

Beaches
Energy
Services

3

FRCC

Mike Blough

Kissimmee
Utility
Authority

5

FRCC

Chris Adkins

City of
Leesburg

3

FRCC

Ginny Beigel

City of Vero
Beach

3

FRCC

31

Organization
Name
Tennessee
Valley
Authority

Name

Segment(s)

Brian Millard 1,3,5,6

Duke Energy Colby Bellville 1,3,5,6

Region
SERC

FRCC,RF,SERC

Group
Group Name
Member Name
Tennessee
Valley
Authority

Dana Klem

1,2,3,4,5,6

MRO

Tennessee
Valley
Authority

1

SERC

Grant, Ian S.

Tennessee
Valley
Authority

3

SERC

Thomas, M.
Lee

Tennessee
Valley
Authority

5

SERC

Parsons,
Marjorie S.

Tennessee
Valley
Authority

6

SERC

Duke Energy

1

RF

Duke Energy

3

FRCC

Dale Goodwine Duke Energy

5

SERC

Greg Cecil

Duke Energy

6

RF

Joseph
DePoorter

Madison Gas
& Electric

3,4,5,6

MRO

Larry Heckert

Alliant Energy 4

MRO

Amy Casucelli

Xcel Energy

1,3,5,6

MRO

Michael
Brytowski

Great River
Energy

1,3,5,6

MRO

Duke Energy Doug Hils

Consideration of Comments | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | October 27, 2017

MRO NSRF

Group
Member
Region

Scott, Howell
D.

Lee Schuster

MRO

Group
Group
Member
Member
Organization Segment(s)

32

Organization
Name

Name

Segment(s)

Region

Consideration of Comments | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | October 27, 2017

Group
Group Name
Member Name

Group
Group
Member
Member
Organization Segment(s)

Group
Member
Region

Jodi Jensen

Western Area 1,6
Power
Administration

MRO

Kayleigh
Wilkerson

Lincoln
Electric
System

1,3,5,6

MRO

Mahmood Safi Omaha Public 1,3,5,6
Power District

MRO

Brad Parret

1,5

MRO

Terry Harbour MidAmerican 1,3
Energy
Company

MRO

Tom Breene

Wisconsin
3,5,6
Public Service
Corporation

MRO

Jeremy Voll

Basin Electric 1
Power
Cooperative

MRO

Kevin Lyons

Central Iowa
Power
Cooperative

1

MRO

Mike Morrow

Midcontinent 2
ISO

MRO

Minnesota
Powert

33

Organization
Name

Name

Segment(s)

Region

SERC
David Greene 10
Reliability
Corporation

SERC

Con Ed Dermot
Consolidated Smyth
Edison Co. of
New York

5

NPCC

Seattle City
Light

1,3,4,5,6

Ginette
Lacasse

Group
Group Name
Member Name
SERC CIPC

Con Edison

Group
Group
Member
Member
Organization Segment(s)

Bill Peterson

SERC RRO

10

SERC

Mike Hagee

SERC RRO

10

SERC

SERC CIPC

Various

1,2,5,9

SERC

1,3,5,6

NPCC

Dermot Smyth Con Edison
Company of
New York
Edward Bedder Orange &
Rockland

WECC

Consideration of Comments | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | October 27, 2017

Seattle City
Light Ballot
Body

Group
Member
Region

NPCC

Pawel Krupa

Seattle City
Light

1

WECC

Hao Li

Seattle City
Light

4

WECC

Bud (Charles)
Freeman

Seattle City
Light

6

WECC

Mike Haynes

Seattle City
Light

5

WECC

Michael
Watkins

Seattle City
Light

1,4

WECC

Faz Kasraie

Seattle City
Light

5

WECC

John Clark

Seattle City
Light

6

WECC

34

Organization
Name

Santee
Cooper

Name

Segment(s)

Region

James Poston 3

Lower
Colorado
River
Authority

Michael Shaw 1

Southern
Company Southern

Pamela
Hunter

1,3,5,6

Group
Group Name
Member Name

Santee
Cooper

LCRA
Compliance

SERC

Consideration of Comments | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | October 27, 2017

Southern
Company

Group
Group
Member
Member
Organization Segment(s)

Group
Member
Region

Tuan Tran

Seattle City
Light

3

WECC

Laurrie
Hammack

Seattle City
Light

3

WECC

Rene' Free

Santee Cooper 1

SERC

Rodger Blakely Santee Cooper 1

SERC

Chris Jimenez

Santee Cooper 1

SERC

Troy Lee

Santee Cooper 1

SERC

Tom Abrams

Santee Cooper 1

SERC

Jennifer
Richards

Santee Cooper 1

SERC

Stony Martin

Santee Cooper 1

SERC

Glenn
Stephens

Santee Cooper 1

SERC

Tom Perry

Santee Cooper 1

SERC

Teresa
Cantwell

LCRA

1

Texas RE

Dixie Wells

LCRA

5

Texas RE

Michael Shaw LCRA

6

Texas RE

Katherine
Prewitt

1

SERC

Southern
Company
Services, Inc.

35

Organization
Name

Name

Segment(s)

Region

Group
Group Name
Member Name

Company
Services, Inc.

Eversource
Energy

Quintin Lee

Northeast
Ruida Shu
Power
Coordinating
Council

1

1,2,3,4,5,6,7,8,9,10 NPCC

Consideration of Comments | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | October 27, 2017

Eversource
Group

Group
Group
Member
Member
Organization Segment(s)

Group
Member
Region

R. Scott Moore Alabama
Power
Company

3

SERC

William D.
Shultz

Southern
Company
Generation

5

SERC

Jennifer G.
Sykes

Southern
Company
Generation
and Energy
Marketing

6

SERC

Timothy
Reyher

Eversource
Energy

5

NPCC

Mark Kenny

Eversource
Energy

3

NPCC

Northeast
Power
Coordinating
Council

10

NPCC

Randy
MacDonald

New
Brunswick
Power

2

NPCC

Wayne
Sipperly

New York
Power
Authority

4

NPCC

RSC no Con- Guy V. Zito
Edison and
Dominion

36

Organization
Name

Name

Segment(s)

Region

Group
Group Name
Member Name
Glen Smith

Consideration of Comments | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | October 27, 2017

Group
Group
Member
Member
Organization Segment(s)
Entergy
Services

Group
Member
Region

4

NPCC

Brian Robinson Utility Services 5

NPCC

Bruce Metruck New York
Power
Authority

6

NPCC

Alan Adamson New York
State
Reliability
Council

7

NPCC

Edward Bedder Orange &
Rockland
Utilities

1

NPCC

David Burke

Orange &
Rockland
Utilities

3

NPCC

Michele
Tondalo

UI

1

NPCC

Laura Mcleod

NB Power

1

NPCC

Michael
Schiavone

National Grid 1

NPCC

Michael Jones National Grid 3

NPCC

37

Organization
Name

Dominion Dominion
Resources,
Inc.

Name

Sean Bodkin

Segment(s)

Region

6

Consideration of Comments | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | October 27, 2017

Group
Group Name
Member Name

Dominion

Group
Group
Member
Member
Organization Segment(s)

Group
Member
Region

David
Ramkalawan

Ontario Power 5
Generation
Inc.

NPCC

Quintin Lee

Eversource
Energy

1

NPCC

Kathleen
Goodman

ISO-NE

2

NPCC

Greg Campoli

NYISO

2

NPCC

Silvia Mitchell NextEra
6
Energy Florida Power
and Light Co.

NPCC

Paul
Malozewski

Hydro One
3
Networks, Inc.

NPCC

Sylvain
Clermont

Hydro Quebec 1

NPCC

Helen Lainis

IESO

2

NPCC

Chantal Mazza Hydro Quebec 2

NPCC

Connie Lowe

Dominion Dominion
Resources,
Inc.

3

NA - Not
Applicable

Lou Oberski

Dominion Dominion

5

NA - Not
Applicable

38

Organization
Name

Name

Segment(s)

Region

Group
Group Name
Member Name

Group
Group
Member
Member
Organization Segment(s)

Group
Member
Region

Resources,
Inc.
Larry Nash

Colorado
Springs
Utilities

Shannon Fair 1,3,5,6

Southwest Shannon
Power Pool, Mickens
Inc. (RTO)

2

Colorado
Springs
Utilities

SPP RE

Consideration of Comments | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | October 27, 2017

SPP
Standards
Review
Group

Dominion 1
Dominion
Virginia Power

NA - Not
Applicable

Kaleb Brimhall Colorado
Springs
Utilities

5

WECC

Charlie Morgan Colorado
Springs
Utilities

3

WECC

Shawna Speer Colorado
Springs
Utilities

1

WECC

Shannon Fair

Colorado
Springs
Utilities

6

WECC

Shannon
Mickens

Southwest
Power Pool
Inc.

2

SPP RE

Deborah
McEndaffer

Midwest
Energy, Inc.

NA - Not
Applicable

SPP RE

Don Schmit

Nebraska
Public Power
District

5

SPP RE

39

Organization
Name

Name

Segment(s)

Region

Group
Group Name
Member Name
Louis Guidry

PPL Louisville
Gas and
Electric Co.

Shelby Wade 3,5,6

RF,SERC

Consideration of Comments | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | October 27, 2017

Group
Group
Member
Member
Organization Segment(s)
Cleco
Corporation

Group
Member
Region

1,3,5,6

SPP RE

Robert Hirchak Cleco
Corporation

6

SPP RE

Marty Paulk

Cleco
Corporation

1,3,5,6

SPP RE

Michelle
Corley

Cleco
Corporation

3

SPP RE

Robert Gray

Board of
NA - Not
Public Utilities Applicable

SPP RE

Ron Spicer

EDP
Renewables

NA - Not
Applicable

SPP RE

Steven Keller

Southwest
Power Pool

2

SPP RE

Laura Cox

Westar Energy 5

SPP RE

Louisville Gas Charles
and Electric Freibert
Company
and Kentucky Dan Wilson
Utilities
Company

PPL - Louisville 3
Gas and
Electric Co.

SERC

PPL - Louisville 5
Gas and
Electric Co.

SERC

Linn Oelker

PPL - Louisville 6
Gas and
Electric Co.

SERC

40

Organization
Name
PSEG

Name
Sheranee
Nedd

Segment(s)
1,3,5,6

ACES Power Warren Cross 1,3,4,5
Marketing

Region
NPCC,RF

Group
Group Name
Member Name
PSEG REs

Group
Group
Member
Member
Organization Segment(s)

Tim Kucey

PSEG - PSEG
Fossil LLC

5

RF

Karla Jara

PSEG Energy 6
Resources and
Trade LLC

RF

Jeffrey Mueller PSEG - Public
Service
Electric and
Gas Co

3

RF

Joseph Smith

1

RF

1

WECC

Hoosier Energy HE
Rural Electric
Cooperative,
Inc.

1

RF

Sunflower
SEPC
Electric Power
Corporation

1

SPP RE

PSEG - Public
Service
Electric and
Gas Co

MRO,RF,SERC,SPP ACES
Arizona Electric AEPC
RE,Texas
Standards
Power
RE,WECC
Collaborators Cooperative,
Inc.

Consideration of Comments | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | October 27, 2017

Group
Member
Region

41

Organization
Name

Name

Segment(s)

Region

Group
Group Name
Member Name

Group
Group
Member
Member
Organization Segment(s)

Rayburn
Country
Electric
Cooperative

RCEC

3

SPP RE

Old Dominion
Electric
Cooperative

ODEC

3,4

SERC

Brazos Electric BRAZOS
Power
Cooperative,
Inc.

1,5

Texas RE

Southern
Maryland
Electric
Cooperative

3

RF

North Carolina NCEMC
Electric
Membership
Corporation

3,4,5

SERC

Central Iowa
Power
Cooperative

1

MRO

1,3

SERC

SMECO

CIPCO

East Kentucky EKPC
Power
Cooperative

Consideration of Comments | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | October 27, 2017

Group
Member
Region

42

Organization
Name

Name

Segment(s)

Region

Group
Group Name
Member Name
Buckeye
Power, Inc.

Consideration of Comments | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | October 27, 2017

Group
Group
Member
Member
Organization Segment(s)
BUCK

4

Group
Member
Region
RF

43

1. Requirement R1: The SDT drafted CIP-012-1 Requirement R1 to meet the mandatory requirement for the Responsible Entity to
develop one or more documented plan(s) to mitigate the risk of the unauthorized disclosure or modification of data used for
Operational Planning Analysis, Real-time Assessment, and Real-time monitoring data while being transmitted between Control
Centers. Do you agree with this revision? If not, please provide the basis for your disagreement and an alternate proposal.
Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer

No

Document Name
Comment
The term “transmitted between Control Centers” is not clear. Dominion is concerned that the demarcation point between Control
Centers is unclear and could cause confusion? A second concern is the potential reliability gap created by the lack of a clarification on
whether internal Control Center communications networks are considered to be part of the transmission of data, or if only external
communications between entities qualify as transmission data?
Likes

0

Dislikes

0

Response
George Brown - Acciona Energy North America - 5
Answer

No

Document Name
Comment

Consideration of Comments | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | October 27, 2017

44

The term “plan” is misleading in this context. A “plan” is more analogous to the development of a project that has actions to achieve a
result by specific date; similar to an implementation plan for a NERC Reliability Standard.
If it was the intention of the SDT to require a Responsible Entity to have a documented set of requirements to protect the sensitive BES
data transmitted between the Control Centers then the term “policy” would be more appropriate. A policy is interpreted to be more
dynamic and ongoing throughout the lifetime of the requirement. Additionally, as cyber security technology is constantly changing and
evolving, a policy would allow for a definite course of action for a Responsible Entity to protect sensitive BES data transmitted between
the Control Centers.
Likes

0

Dislikes

0

Response
Joe Tarantino - Joe Tarantino On Behalf of: Arthur Starkovich, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Beth Tincher,
Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Jamie Cutlip, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Kevin Smith,
Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Susan Oto, Sacramento
Municipal Utility District, 4, 1, 5, 6, 3; - Joe Tarantino
Answer

No

Document Name
Comment
It is an overwhelming task to differentiate what is or what isn’t confidential communication data over data links between Control
Centers. As such, it is recommended that ALL data transmitted between Control Center be protected. The standards should just address
all data communication between control centers. Technologies such as encryption are generally implemented by link, not
communication type.
Likes
Dislikes

0
0

Consideration of Comments | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | October 27, 2017

45

Response
Leonard Kula - Independent Electricity System Operator - 2
Answer

No

Document Name
Comment
The IESO agrees with the creation of a new standard, rather than expanding CIP-003, CIP-005 and/or CIP-006 requirements to provide
new controls over physical communication links. Specifically, the IESO commends the SDT for recognizing that not all utilities own or
control their own physical communications links.
The IESO offers the following comments and recommendations.
•

R1. For data used for Operational Planning Analysis, Real-time Assessments, and Real-time monitoring, as documented by a
Reliability Coordinator, Transmission Operator, or Balancing Authority, the Responsible Entity shall develop one or more
documented plan(s) to mitigate the risk of the unauthorized disclosure or modification of the data while it is being transmitted
between Control Centers. This excludes oral communications, regardless of transport means.

•

The note to R1 concerning the existence of a Control Center or specified data should be a dealt with in Section 4 – Applicability
part of the Standard. This would eliminate the need for this to be discussed as part of the RSAW.

•

Recommend that it be clarified whether this is a standalone Standard similar to CIP-014 or if it is intended to define the scope of
applicable systems to be protected under CIP-003 thru CIP-011.

•

In order to evaluate the extent and kind of obligation involved, the definition of between control centers needs to be clearer with
regard to the communication link. The Standard should address the proper demarcation points for obligation to show
implementation and compliance. To clearly define the obligation of Responsible Entities, the required plan should include
identification of the demarcation points. Information is also needed on the explicit agreements required on each end of the
physical communication link to arrange and identify such demarcation. Where there is disagreement on how protections are to be
applied between two or more Responsible Entities, what is the arbitration process to resolve these disagreements?

Consideration of Comments | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | October 27, 2017

46

•

How is the situation handled where a Responsible Entity (e.g., an RC) is receiving information from a third-party provider that is
aggregating and submitting data on behalf of one or more Responsible Entities (e.g., a TOP)? What is the identification of the
demarcation points? In reading the standard, it does not appear that the connection to the third-party provider is in scope since
they are not a Responsible Entity or even registered with NERC. The same situation may be present for entities that use an
outsourced data center provider. The question is also relevant for the data that is provided to regulatory agencies that are not
bound by CIP Standards.

Likes

2

Dislikes

Hydro One Networks, Inc., 1, Farahbakhsh Payam; Hydro One Networks, Inc., 3, Malozewski Paul
0

Response
Dermot Smyth - Con Ed - Consolidated Edison Co. of New York - 5, Group Name Con Edison
Answer

No

Document Name
Comment
The scope of the term “data” is unclear. Does “data” apply to all data or just machine to machine (e.g. automated) communications? If it
is all data would emails/ftp/etc. be in scope?
Likes

0

Dislikes

0

Response
Brandon McCormick - Brandon McCormick On Behalf of: Ginny Beigel, City of Vero Beach, 3; Lynne Mila, City of Clewiston, 4; Tom
Reedy, Florida Municipal Power Pool, 6; - Brandon McCormick, Group Name FMPA
Answer

No

Consideration of Comments | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | October 27, 2017

47

Document Name
Comment
FMPA does not agree with the revision of Requirement 1 (R1) because the obligation is not clear. The R1 note - “If the Responsible Entity
does not have a Control Center or it does not transmit the type of data specified in Requirement R1 of CIP-012-1 between two Control
Centers, the requirements in CIP-012-1 would not apply to that entity.”- should be in the Section 4 Applicability. This would eliminate the
need for this to be discussed as part of the RSAW.
In order to evaluate the extent and kind of obligation involved with R1, the phrase “transmitted between two control centers,” needs to
be clearer. FMPA believes that there should be more clarity or identification on the demarcation points of the link being protected.
Both TOP-003 and IRO-010 have a requirement that there be a mutually agreeable security protocol. It is not clear why a new standard
needs to be developed to address this same issue. The SDT should consider modifying TOP-003 and IRO-010 if these standards do not
provide adequate language to meet Order No. 822’s concerns.
Likes

0

Dislikes

0

Response
Frank Pace - Central Hudson Gas & Electric Corp. - 1
Answer

No

Document Name
Comment
There is a lack of language within the Requirement that specifies the demarcation point for compliance between applicable Control
Centers.
Likes

0

Consideration of Comments | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | October 27, 2017

48

Dislikes

0

Response
Donald Lock - Talen Generation, LLC - 5
Answer

No

Document Name
Comment
The applicability of the expression, “between Control Centers,” does not appear to be restricted to transmittals between Control Centers
owned by a single entity; exchanges between GO and TO/TOP Control Centers would be covered also, for example. This makes sense as
regards achieving a high degree of security, but could create confusion regarding who is responsible for inter-entity transmittals. CIP012-1 should state that GO/GOP obligations for inter-entity exchanges between Control Centers are fulfilled if they follow the data
specifications provided by the other party (ref. IRO-010-2 and TOP-003-3).
Likes

0

Dislikes

0

Response
David Rivera - New York Power Authority - 3
Answer

No

Document Name
Comment
The Note to R1 concerning the existence of a Control Center or specified data should be a dealt with in Section 4 – Applicability.
This would eliminate the need for this to be discussed as part of the RSAW.
2. In order to evaluate the extent and kind of obligation involved, the definition of between control centers needs to be more clear
with regard to the communication link. What are the demarcation points for obligation to show compliance?
1.

Consideration of Comments | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | October 27, 2017

49

3.

Request clarification does the 15 minute impact CIP-002 identification of BES Cyber Systems affect the applicability of CIP-012?

Likes

0

Dislikes

0

Response
Philip Huff - Arkansas Electric Cooperative Corporation - 3
Answer

No

Document Name
Comment
The Requirement should only permit the option to logically protect the data during transmission or at least remove the explicit options to
physically protect the data. We understand the Requirement is consistent with CIP-006 R1.10, but this Requirement addresses
communication lines within the same facility, and for which physical protection is possible. Cryptography is the only mechanism available
to protect data across geographically dispersed Control Centers. Stating other options is confusing and has a strong potential to guide the
industry toward ineffective solutions.
However, if the intent is to allow physical protection of communications of Control Centers in the same geographical location, then make
it clear in the Technical Guidelines the scenarios and alternative solutions the drafters had in mind.
Likes

0

Dislikes

0

Response
Jennifer Hohenshilt - Talen Energy Marketing, LLC - 6
Answer

No

Document Name
Consideration of Comments | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | October 27, 2017

50

Comment
The applicability of the expression, “between Control Centers,” does not appear to be restricted to transmittals between Control Centers
owned by a single entity; exchanges between GO and TO/TOP Control Centers would be covered also, for example. This makes sense as
regards achieving a high degree of security, but could create confusion regarding who is responsible for inter-entity transmittals. CIP012-1 should state that GO/GOP obligations for inter-entity exchanges between Control Centers are fulfilled if they follow the data
specifications provided by the other party (ref. IRO-010-2 and TOP-003-3).
Likes

0

Dislikes

0

Response
Dana Klem - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO NSRF
Answer

No

Document Name
Comment
As mentioned by the SDT, FERC directs that “…require responsible entities to implement controls to protect, at a minimum,
communication links and sensitive bulk electric system data communicated between bulk electric system Control Centers…”. First, having
a plan does not add to the reliability of protecting said data. This is an unwarranted layer of compliance that is not needed. Everything
does not need a plan in order to be protected. Recommend that R1 be written in parallel to the FERC directive, which does not require a
plan (per the SDTs Consideration of Issues and Directives).
If “Plan” is maintained in CIP-012-1 then, the SDT should explain what is meant by having a Plan? Per CIP-003-6 it states, The terms
program and plan are sometimes used in place of documented processes where it makes sense and is commonly understood. For
example, documented processes describing a response are typically referred to as plans (i.e., incident response plans and recovery plans).
Likewise, a security plan can describe an approach involving multiple procedures to address a broad subject matter. Is a plan the
template document which is used throughout our Standards or is it a set of controls that show that the data is being protected per
R1? The NSRF does not understand why a Plan is needed when the data is being protected by physical or electronic means. If a Plan is
Consideration of Comments | Project 2016-02 Modifications to CIP Standards
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51

required, then all the Plan is going to say is that the cabling that transfers data is in a protected conduit (or other means) between Control
Centers.
Secondly, The NSRF questions why the SDT is not in line with the FERC Order to “…protect …data…” but the proposed R1 states to
“…mitigate the risk of unauthorized disclosure or modification of data…”?
R1 should be rewritten to state: “The responsible entity shall have controls (or other understandable words) in place to protect against
the unauthorized disclosure or modification of BES data used for Operational Planning Analysis, Real-time Assessments, and Real-time
monitoring while being transmitted between BES Control Centers. This excludes oral communications”. Please note that the word “BES”
is needed within R1 regardless of it our proposed rewrite is accepted or not.
Likes

0

Dislikes

0

Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

No

Document Name
Comment
Texas RE appreciates the Standard Drafting Team’s (SDT) efforts to develop a workable approach to mitigate the risk of unauthorized
disclosure or modification of certain categories of Control Center communications. However, Texas RE is concerned that the proposed
CIP-012-1 R1 does not fully satisfy the directives established by the Federal Energy Regulatory Commission (FERC) in FERC Order No.
822. Texas RE is likewise concerned that the proposed CIP-012-1 may not adequately address third-party entities handling sensitive data
between Control Centers in the Texas RE region.
First, throughout its discussion concerning new requirements for protecting Control Center communications, FERC emphasized that
additional protections were required to protect both the “integrity and availability of sensitive bulk electric system data.” FERC Order No.
822, P. 54. FERC made clear that this involved, at a minimum, two discrete actions. First, FERC stressed that entities should implement

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52

controls to protect the physical communications links transmitting sensitive data between Control Centers. Second, FERC noted that the
sensitive data itself needed to be protected to ensure its accuracy and consistency. In issuing the directive underpinning this rulemaking,
FERC stated: “we adopt the NOPR proposal and direct that NERC . . . develop modifications to the CIP Reliability Standards to require
responsible entities to implement controls to protect, at a minimum, communications links and sensitive bulk electric system data
communicated between bulk electric system Control Centers . . . FERC Order No. 822, P. 53 (emphasis added).
FERC made it clear that protections should apply to both communication links and sensitive data. However, the proposed draft of CIP012-1 R1 potentially applies only to physical protections for communications links or to logical protections for data during its
transmission. That is, responsible entities could simply elect to plan and implement physical protections for communications links. This
would “mitigate” the risk of an unauthorized disclosure or modification of data using one of the delineated methods. As such, the
responsible entity would potentially be compliant with the Standard without proposing or implementing any logical protections for
sensitive data during its transmission. This appears counter to FERC’s intent to protect “both the integrity and availability of sensitive
bulk electric system data.” FERC Order No. 822, P. 54.
Second, Texas RE is concerned that the proposed CIP-012-1 standard may result in confusion, particularly among Generation Operators
with Control Centers subject to the standard regarding the scope of their compliance obligations or, alternatively, may inadvertently
result in a significant reliability gap given the structure of the ERCOT market. In ERCOT, generators do not communicate directly with the
regional Reliability Coordinator (ERCOT). Instead, generators are required to communicate through designated entities known as
Qualified Scheduling Entities (QSEs). In many instances, these QSEs are third-party entities. Within the NERC regulatory construct,
Generator Operators have delegated certain NERC compliance functions to these entities, including providing data used for Operational
Planning Analysis, Real-time Assessments, and Real-time monitoring. Critically, Generator Operators remain responsible for all
compliance obligations associated with QSE activities in the ERCOT region.
In light of this market and regulatory framework, Texas RE interprets the proposed draft of CIP-012-1 to likewise require Generator
Operators possessing Control Centers to take steps to mitigate the risk of unauthorized data disclosures at every step along the
communication chain between its Control Center and the ERCOT Control Center, including steps to protect this data at third-party
intermediary QSEs. Otherwise, the proposed draft of CIP-012-1 would result in a significant reliability gap as QSE communications links
and data passing from the QSE to ERCOT could be potentially unsecure. Given this fact, Generator Operators will likely need to take steps
to ensure that their third-party QSEs have accorded designated sensitive data appropriate protections, which could in turn require
incorporating such requirements into QSE agreements or other steps. Texas RE requests the SDT clarify that communications between
QSEs (or equivalent in other Regions) and the RC are subject to CIP-012-1 requirements and that Responsible Entities must take steps to

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address mitigate the risk of unauthorized data disclosures for these communications as well in order to ensure that Responsible Entities
have sufficient notice of these compliance obligations.
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Response
Alice Wright - Arkansas Electric Cooperative Corporation - 4
Answer

No

Document Name

2016-02_CIP-012-1_Comment_Form_07272017-AECC Comments.pdf

Comment
See attachment
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0

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0

Response
Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer

No

Document Name
Comment
See APPA Comments.
Likes

0

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Dislikes

0

Response
James Poston - Santee Cooper - 3, Group Name Santee Cooper
Answer

No

Document Name
Comment
Recommend removing “Operational Planning Analysis” from this requirement. Operational Planning Analysis is not Real-time data and
would not affect the BES within 15 minutes. The TOP-003-3 Standard currently requires a mutually agreeable security protocol for
sharing of data required for Operational Planning Analyses.
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0

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0

Response
Marty Hostler - Northern California Power Agency - 5
Answer

No

Document Name
Comment
NCPA does not feel CIP-012-1 is needed as both TOP-003 R5 and IRO-010 R3 require Registered Entities (REs) to use a mutually agreeable
security protocol. The SDT should consider modifying TOP-003 and IRO-010 if these standards do not provide adequate language to meet
Order No. 822’s concerns. Also please refer to other APPA, TAPs, and Utility Services comments.
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0

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Dislikes

0

Response
Dennis Sismaet - Northern California Power Agency - 6
Answer

No

Document Name
Comment
NCPA does not feel CIP-012-1 is needed as both TOP-003 R5 and IRO-010 R3 require Registered Entities (REs) to use a mutually agreeable
security protocol. The SDT should consider modifying TOP-003 and IRO-010 if these standards do not provide adequate language to meet
Order No. 822’s concerns. Also please refer to other APPA, TAPs, and Utility Services comments.
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0

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0

Response
David Gordon - Massachusetts Municipal Wholesale Electric Company - 5
Answer

No

Document Name
Comment
The applicability section of the Standard should specify that the requirements only apply to entities with Control Centers. This would
allow the elimination of the note to R1 and would simplify the ERO monitoring process.
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0

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Response
Heather Morgan - EDP Renewables North America LLC - 5
Answer

No

Document Name
Comment
What does, “Physically protecting the communication links transmitting the data,” mean? A Registered Entity is able to physically protect
its end point, but is not able to physically protect the communication link for the entire communication link. Please define “logical
protection” to provide clarification for entities for implementation and compliance oversight.
What does, “Using an equally effective method to mitigate the risk of unauthorized disclosure or modification of the data” mean?
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0

Response
Quintin Lee - Eversource Energy - 1, Group Name Eversource Group
Answer

No

Document Name
Comment
The Purpose section of CIP-012-1 adds the need to protect the confidentiality of data which is out of Scope of FERC order 822. Although it
is recognized that the SDT is not limited to just FERC orders, adding need to protect the confidentiality of data does not add reliability if
the data is being protected per CIP-012-1 R1.
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0

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Dislikes

0

Response
Aaron Austin - AEP - 3
Answer

No

Document Name
Comment
AEP suggests that a new requirement(s) be added to establish a hierarchy for REs that requires entities at the top with the most risk to
set the communications security protocols. And, modify the existing R1 to require REs to have plans that follow the protocols set by
the entities identified in the new requirement(s).
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0

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0

Response
Nicolas Turcotte - Hydro-Qu?bec TransEnergie - 1
Answer

No

Document Name
Comment
1.

The Note to R1 concerning the existence of a Control Center or specified data should be a dealt with in Section 4 – Applicability.
This would eliminate the need for this to be discussed as part of the RSAW.

2.

In order to evaluate the extent and kind of obligation involved, the definition of between control centers needs to be more clear
with regard to the communication link. What are the demarcation points for obligation to show compliance?

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3.

Request clarification does the 15 minute impact CIP-002 identification of BES Cyber Systems affect the applicability of CIP-012?

4.

Concerns exist with the relationships regarding implementation of CIP-012 with other NERC Standards such as IRO, TOP, CIP-006
R1 Part1.10

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Response
Lona Calderon - Salt River Project - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
SRP requests the SDT consider differentiating requirements for Control Center communications within an entity from those for Control
Center communications between entities. Because data being sent for TOP-003 and IRO-010 traverses over the ICCP network maintained
by a carrier, entities cannot provide physical protections for communication of this data from end to end. In this case, protecting the
confidentiality and integrity can only be done through encryption. However, since no one utility owns the hardware end to end on the
ICCP network, site to site encryption cannot be implemented. The only options available would be application layer encryption or
transport layer encryption utilizing IEC 62351-4 Secure ICCP.
For IRO-010 data, the RC in the Western Interconnect requires real-time data to be sent every 10 seconds. Likewise, For TOP-003 data,
SRP is required to send and receive real-time data every 10 seconds to and from various other entities on the ICCP network within the
Western Interconnect. It is unclear the amount of latency that may be added or amount of computing resources required to encrypt and
decrypt this data every 10 seconds. Additionally, the RC would be receiving this data from all applicable utilities in the Western
Interconnect. If all entities encrypt and send data every 10 seconds, it is unclear how much latency would be added and computing
resources would be required by the RC to decrypt the large amount data. It is also unclear how the added latency would affect the realtime operations of the Bulk Electric System. IRO and TOP data specification changes may be necessary to address delays in data due to
latency, or process/procedure changes to mitigate effects on real-time operations. SRP suggests performing a study or survey to
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determine how much data is being sent and received and what the effects would be from the added latency and the amount of extra
computing resources required.
SRP requests clarification on the exclusion of oral communications. Additionally, SRP suggests the exclusion for oral communications be
expanded to also exclude electronic mail.
SRP requests clarification for what would be accepted as physical security either in the measures or Technical Rationale and Justification.
SRP also requests clarification of what equally effective methods are in the measures or Technical Rationale and Justification.
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0

Response
Thomas Breene - WEC Energy Group, Inc. - 3
Answer

No

Document Name
Comment
As mentioned by the SDT, FERC directs that “…require responsible entities to implement controls to protect, at a minimum,
communication links and sensitive bulk electric system data communicated between bulk electric system Control Centers…”. First, having
a plan does not add to the reliability of protecting said data. This is an unwarranted layer of compliance that is not needed. Everything
does not need a plan in order to be protected. Recommend that R1 be written in parallel to the FERC directive, which does not require a
plan (per the SDTs Consideration of Issues and Directives).
If “Plan” is maintained in CIP-012-1 then, the SDT should explain what is meant by having a Plan? Per CIP-003-6 it states, The terms
program and plan are sometimes used in place of documented processes where it makes sense and is commonly understood. For
example, documented processes describing a response are typically referred to as plans (i.e., incident response plans and recovery plans).
Likewise, a security plan can describe an approach involving multiple procedures to address a broad subject matter. Is a plan the
template document which is used throughout our Standards or is it a set of controls that show that the data is being protected per

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R1? We do not understand why a Plan is needed when the data is being protected by physical or electronic means. If a Plan is required,
then all the Plan is going to say is that the cabling that transfers data is in a protected conduit (or other means) between Control Centers.
Secondly, we question why the SDT is not in line with the FERC Order to “…protect …data…” but the proposed R1 states to “…mitigate the
risk of unauthorized discloser or modification of data…”?
R1 should be rewritten to state: “The responsible entity shall have controls (or other understandable words) in place to protect against
the unauthorized disclosure or modification of BES data used for Operational Planning Analysis, Real-time Assessments, and Real-time
monitoring while being transmitted between BES Control Centers. This excludes oral communications”. Please note that the word “BES”
is needed within R1 regardless of it our proposed rewrite is accepted or not.
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0

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0

Response
Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer

No

Document Name
Comment
Xcel Energy agrees with and support the comments submitted by the MRO Standards Review Forum (NSRF) in regards to this question.
Likes

0

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0

Response
Russell Noble - Cowlitz County PUD - 3

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Answer

No

Document Name
Comment
Cowlitz PUD supports the comments submitted by APPA.
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0

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0

Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Con-Edison and Dominion
Answer

No

Document Name
Comment
·
The Note to R1 concerning the existence of a Control Center or specified data should be a dealt with in Section 4 – Applicability. This
would eliminate the need for this to be discussed as part of the RSAW.
·
In order to evaluate the extent and kind of obligation involved, the definition of between control centers needs to be clearer with
regard to the communication link. What are the demarcation points for obligation to show compliance?
·

Request clarification does the 15 minutes impact CIP-002 identification of BES Cyber Systems affect the applicability of CIP-012?

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0

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Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer

No

Document Name
Comment
ERCOT ISO signs on to the ITC SWG comments:
The ITC SWG agrees with the creation of a new standard, rather than expanding CIP-003, CIP-005 and/or CIP-006 requirements to provide
new controls over physical communication links. Specifically, the ITC SWG commends the SDT for recognizing that not all utilities own or
control their own physical communications links.
The ITC SWG offers the following comments and recommendations.
•

R1. For data used for Operational Planning Analysis, Real-time Assessments, and Real-time monitoring, as documented by a
Reliability Coordinator, Transmission Operator, or Balancing Authority, the Responsible Entity shall develop one or more
documented plan(s) to mitigate the risk of the unauthorized disclosure or modification of the data while it is being transmitted
between Control Centers. This excludes oral communications, regardless of transport means.

•

The note to R1 concerning the existence of a Control Center or specified data should be a dealt with in Section 4 – Applicability
part of the Standard. This would eliminate the need for this to be discussed as part of the RSAW.

•

Recommend that it be clarified whether this is a standalone Standard similar to CIP-014 or if it is intended to define the scope of
applicable systems to be protected under CIP-003 thru CIP-011.

•

In order to evaluate the extent and kind of obligation involved, the definition of between control centers needs to be clearer with
regard to the communication link. The Standard should address the proper demarcation points for obligation to show
implementation and compliance. To clearly define the obligation of Responsible Entities, the required plan should include
identification of the demarcation points. Information is also needed on the explicit agreements required on each end of the
physical communication link to arrange and identify such demarcation. Where there is disagreement on how protections are to be
applied between two or more Responsible Entities, what is the arbitration process to resolve these disagreements?

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•

How is the situation handled where a Responsible Entity (e.g., an RC) is receiving information from a third-party provider that is
aggregating and submitting data on behalf of one or more Responsible Entities (e.g., a TOP)? What is the identification of the
demarcation points? In reading the standard, it does not appear that the connection to the third-party provider is in scope since
they are not a Responsible Entity or even registered with NERC. The same situation may be present for entities that use an
outsourced data center provider. The question is also relevant for the data that is provided to regulatory agencies that are not
bound by CIP Standards.

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Response
Marc Donaldson - Tacoma Public Utilities (Tacoma, WA) - 3
Answer

No

Document Name
Comment
Tacoma Power suuports the commetns of APPA
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0

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0

Response
sean erickson - Western Area Power Administration - 1
Answer

No

Document Name

Project 2016-02_CIP-012-1_NSRF Final.docx

Comment
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WAPA agrees with the comments submitted by the NSRF (attached)
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0

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0

Response
Theresa Rakowsky - Puget Sound Energy, Inc. - 1
Answer

No

Document Name
Comment
See APPA Comments.
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0

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0

Response
Jack Cashin - American Public Power Association - 4
Answer

No

Document Name
Comment
APPA does not agree with the revision of Requirement 1 (R1) because the obligation is not clear. The R1 note - “If the Responsible Entity
does not have a Control Center or it does not transmit the type of data specified in Requirement R1 of CIP-012-1 between two Control

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Centers, the requirements in CIP-012-1 would not apply to that entity.”- should be in the Section 4 Applicability. This would eliminate the
need for this to be discussed as part of the RSAW.
Evaluation of the extent and kind of obligation involved with R1, requires a clearer phrase than, “transmitted between two control
centers.” Public power believes that there should be more clarity or identification on the demarcation points of the link being protected.
Both TOP-003 and IRO-010 have a requirement that there be a mutually agreeable security protocol. It is not clear why a new standard
needs to be developed to address this same issue. The SDT should consider modifying TOP-003 and IRO-010 if these standards do not
provide adequate language to meet Order No. 822’s concerns.
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0

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0

Response
Lan Nguyen - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
CenterPoint Energy Houston Electric, LLC (“CenterPoint Energy”) recommends adding more clarification on the scope of the term
“communication links.” Data used for Operational Planning Analysis (OPA), Real-time Assessments (RTA), and Real-time monitoring
(RTM) is collected based on an Entity-issued data specification, per TOP-003-3 and IRO-010-2. This data is collected through a medium
referred to as “data exchange capability,” as required by TOP-001-4 (Requirements R19 and R20) as well as IRO-002-5 (Requirements R1
and R2).
OPA data is typically not transmitted via a communication link, and OPA data presents lower risk to operations than real-time telemetry
data exchanged via ICCP communication links between Control Centers. The systems used to transmit the OPA data can be located
outside Control Centers and are not considered BES Cyber Systems since they do not impact the Bulk Electric System within 15
minutes. Thus, CenterPoint Energy believes OPA data should not be within the scope of Requirement R1.

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In addition to removing OPA from Requirement R1, CenterPoint Energy recommends revising Requirement R1 to include the term “inter
and intra Control Center communication links.” This revision aligns with the language in Federal Energy Regulatory Commission (“FERC”)
Order No. 822. The proposed revised language is below:
“The Responsible Entity shall develop one or more documented plan(s) to mitigate the risk of the unauthorized disclosure or modification
of data used for Real-time Assessments and Real-time monitoring while being transmitted between inter and intra Control Centers
communication links. This excludes oral communications.”
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0

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0

Response
Warren Cross - ACES Power Marketing - 1,3,4,5 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Standards Collaborators
Answer

No

Document Name
Comment
(1) We agree with the direction of the requirement, however, the wording of the “one of more of” phrase seems to be in conflict with
the intention of physical and logical protection. How can you protect the data without physical security, and how can you ensure data
integrity without logical protection? The “one or more of” reference should be stricken.
(2) We recommend the addition of wording that clearly excludes Low impact Entities from compliance with this requirement. Would a
low impact control room which communicates with a Control Center be out of scope?
(3) We propose moving the compliance applicability note that follows Requirement R1 to the applicability section of the standard,
particularly Section 4.2 Exemptions.
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0
0

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Response
Michael Puscas - ISO New England, Inc. - 2
Answer

No

Document Name
Comment
In order to evaluate the extent and kind of obligation involved, the definition of between control centers needs to be clearer with regard
to the communication link. What are the demarcation points for obligation to show compliance? Should there be explicit agreements
with each end of the communication link to arrange such demarcation? How should responsible entities deal with third parties involved
with trust relationships in communication links (i.e. telecommunications providers managing routers)?
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0

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0

Response
David Greyerbiehl - CMS Energy - Consumers Energy Company - 5
Answer

No

Document Name
Comment
The requirement as written does not provide clear definition on what type of data needs to be protected, and how exactly the
physical/logical protection approach should be accomplished.
Likes
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0
0

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Response
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
BPA appreciates the revisions that the SDT has made based on industry feedback on the SAR.
BPA reiterates its position as documented in our SAR comments that CIP-012-1 is not necessary.
Alternate proposal #1: The objectives can be met by coordinating with existing standards such as CIP-003 and CIP-005.
If CIP-012-1 moves forward, there are areas requiring clarification. FERC Order No. 822 requires implementation of controls to protect, at
a minimum, communication links AND sensitive BES data communicated between BES Control Centers. However, the SDT is providing
latitude to protect communication links, data or both. If it is an “AND” as stated in Order No. 822, it is not always technically feasible to
implement both controls to protect communication links and sensitive BES data communicated between BES Control Centers.
Points of discussion:
Implementation of controls to protect the data:
•

Encryption may not be feasible due to availability concerns. (e.g., failure of encryption keys or latency problems with encryption
for availability requirements.)

Implementation of controls on communication links:
•

The use of the term communication links may be broadly interpreted and difficult to audit.

•

It may not be technically feasible to implement physical controls, for example:

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o

on fiber optic cable on power lines

o

on a common carrier system where the links are unknown

o

for wireless communications - how does an entity physically protect the air between endpoints?

Additionally, entities and common carriers use a variety of media to carry traffic, and will undoubtedly use traffic shaping to maintain
service levels: routing becomes unpredictable; each packet could take a different route from point A to B.
If an entity owns the communication network from end to end, this is still a problem. Modern routing protocols will try to deliver packets
over a system with inoperable equipment, severed links, etc. The only remedy is to physically protect the entire communication system
in advance of system faults to satisfy CIP-012. If one packet traverses a link due to a system fault that is not protected – it would be a
violation.
If FERC agrees with the SDT’s proposal of allowing the entity the latitude to protect the data, communication links or both, BPA believes
the security objective will not be met. BPA recommends placing controls on the data AND end points where technically
feasible. However BPA recommends moving R1.1 to a Technical Guidance, considering there are multiple implementation methods for
controls on data and end points.
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0

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0

Response
James Anderson - CMS Energy - Consumers Energy Company - 1
Answer

No

Document Name
Comment

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The requirement as written does not provide clear definition on what type of data need to be protected, and how exactly the
physical/logical protection approach should be accomplished by an entity.
Likes

0

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0

Response
Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer

No

Document Name
Comment
Utility Services does not agree with the revision of Requirement 1 (R1) because the obligation is not clear. The R1 note - “If the
Responsible Entity does not have a Control Center or it does not transmit the type of data specified in Requirement R1 of CIP-012-1
between two Control Centers, the requirements in CIP-012-1 would not apply to that entity.”- should be in the Section 4 Applicability.
This would eliminate the need for this to be discussed as part of the RSAW.
In order to evaluate the extent and kind of obligation involved with R1, the phrase “transmitted between two control centers”, needs to
be clearer. Public power believes that there should be more clarity or identification on the demarcation points of the link being
protected.
Both TOP-003 and IRO-010 have a requirement that there be a mutually agreeable security protocol. It is not clear why a new standard
needs to be developed to address this same issue. The SDT should consider modifying TOP-003 and IRO-010 if these standards do not
provide adequate language to meet Order No. 822’s concerns.
Likes

0

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0

Response
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Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer

No

Document Name
Comment
Southern Company has concerns with the phrase “data used for Operational Planning Analysis, Real-time Assessments, and Real-time
monitoring” in CIP-012 R1. We understand this is a direct quote from TOP-003 R1 and IRO-010 R1 and the intent is for this phrase to
point to the data specification required by those standards. We understand there is a paragraph to this effect in the Technical Rationale
document which is not a binding document. Our concern is that the requirement says “data used for…” and without a stronger bind to
the IRO and TOP standards we believe this opens the scope of CIP-012 to yet another data definition exercise rather than a specific
requirement to protect an already defined data specification while that data is being transferred between Control Centers.
The draft RSAW for R1 puts this concern in writing. It does not instruct the auditor to use the specifications from TOP-003/IRO-010
Requirement 1 and verify that this previously defined data is protected while being transferred between Control Centers. Instead it
requires the auditor to verify
“The documented plan(s) collectively address all data used for Operational Planning Analysis, Real-time Assessments, and Real-time
monitoring transmitted between Control Centers”
It then includes glossary definitions for two of those terms. The auditor is instructed to look at two definitions, determine a definition of
the undefined “Real-time monitoring”, and then verify that all such data is protected. This effort alone dwarfs the true purpose of the
standard which is protecting those communications links over which BES Control Centers communicate system status with each other in
real time.
We suggest an alternative to resolve this issue. First, we suggest that a data centric approach is problematic for these and other reasons
and we strongly suggest a more technical approach that focuses CIP-012 on securing communication sessions and/or links based on their
destination. For example, data that is leaving the ESP or LEAP of a Control Center that has a destination address of an ESP or LEAP at
another Control Center should be encrypted. That is very distinct and concrete and much simpler to implement and demonstrate and
we believe is in line with FERC Order 822, paragraph 60 where the Commission outlines the reliability gap to be addressed.

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If this alternative is not acceptable, we suggest that R1 be modified to make the previously defined data specification the noun rather
than “data used for…”. Additionally, we suggest removing “Operational Planning Analysis” from the first paragraph of R1 as Operational
Planning Analysis data does not impact the BES within 15 minutes.
For example: “The Responsible Entity shall develop one or more documented plan(s) to mitigate the risk of the unauthorized disclosure or
modification of data used for Real-time Assessments and Real-time monitoring as specified by the Reliability Coordinator or
Transmission Operator while such data is being transmitted between Control Centers. This excludes oral communications.”
We also strongly suggest, based on questions in the draft RSAW, that the SDT consider moving any language relating to applicability to
the Applicability section of the standard rather than having a note in the requirement language. With the inclusion of the note in the
requirement, we notice the draft RSAW starts with questions for all the responsible entities that do not have Control Centers to prove the
negative, which should instead defer any auditor to the compliance auditing process of CIP-002-5.1.
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0

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0

Response
Ronald Donahey - TECO - Tampa Electric Co. - 3
Answer

No

Document Name
Comment
Tampa Electric Company suggests that the SDT provide additional instruction within the standard to address the requirements and
implications for BA’s that serve as the BA for other entities in the BA’s service area. It would be helpful to understand the BA’s
responsibility to mitigate the risk of unauthorized disclosure or modification of data used for the analysis, assessment and monitoring. In
addition, does this standard extend to communications between a Registered Entities and the Reliability Coordinators such as FRCC’s RC
in relation to communication between Control Centers?
Likes

0

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Dislikes

0

Response
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

No

Document Name
Comment
The SPP Standards Review Group has reviewed documentation and have developed some concerns in reference to Requirement R1. The
CIP Version 5 Transition Advisory Group (V5TAG) identified specific issues with the CIP Version 5 standard language that caused difficulty
in implementation of the requirements. This requirement or a supplemental to CIP-005 needs to clarify the 4.2.3.2 exemption phrase
“between discrete Electronic Security Perimeters.” When there is not an ESP at the location, consider clarity that the communication
equipment considered out of scope is the same communication equipment that would be considered out of scope if it were between two
ESPs or a single ESP. This should be address either in this standard, as an Exemption added or requirement added to CIP-005-6.
Here is proposed language for the Exemption:
4.2.3. Exemptions: The following are exempt from Standard CIP‐002‐5.1:
4.2.3.1. Cyber Assets at Facilities regulated by the Canadian Nuclear Safety
Commission.
4.2.3.2. Exemption of Communication Equipment that is owned and operated by a Third Party Communication Carrier or its equivalent is
exempted from the CIP standards that is communicating between system end points
Cyber Assets associated with communication networks and data (striking this information)
communication links between discrete Electronic Security Perimeters. (striking this information)
Or added to CIP-005-6 R1

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CIP-005-5 Table R1 – Electronic Security Perimeter
Part
1.6
Applicable
High Impact BES Cyber Systems and their associated:
•

PCA

Medium Impact BES Cyber Systems with External Routable Connectivity and their associated:
•

PCA

Requirements
For defined ESPs that use wide-area communications networks (e.g. ESPs that span multiple geographic locations), Cyber Assets
associated with communication networks and data communication links used to facilitate the ESP and owned by a third party are exempt
from the CIP Reliability Standards provided that the communications traversing across these Cyber Assets are encrypted. The Cyber Assets
that encrypt and decrypt the communications are EACMS.
Measures
An example of evidence may include, but is not limited to, network diagrams showing all communication networks, vendor owned
equipment, and encryption/decryption Cyber Assets.
There are two major reasons for addressing this issue listed above. 1) This was identified by the V5TAG group and can be easily fixed with
one of the two suggestions listed above. Reason 2) is because Registered Entities may expand their ESP’s to cover both control centers to
handle R1.1 in regards of:
•

Logically protecting the data during transmission; or (Provide example or measures)

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•

Using a measurements to mitigate the risk of unauthorized disclosure or modification of the data.

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Response
Wendy Center - U.S. Bureau of Reclamation - 5
Answer

No

Document Name
Comment
Reclamation recommends the SDT use the term “documented processes” consistently throughout the CIP standards. Pursuant to CIP003-6,
The terms program and plan are sometimes used in place of documented processes where it makes sense and is commonly understood.
For example, documented processes describing a response are typically referred to as plans (i.e., incident response plans and recovery
plans). Likewise, a security plan can describe an approach involving multiple procedures to address a broad subject matter.
Reclamation disagrees that having a plan adds to the reliability of protecting data used for Operational Planning Analysis, Real-time
Assessment, and Real-time monitoring. A plan is an unwarranted layer of compliance that is not needed. Reclamation recommends that
R1 be written in parallel with the FERC Order 822, which directed the development of controls to protect communication links and data.
Reclamation recommends R1 could be rewritten to state: “The responsible entity shall have documented processes in place to mitigate
the risk of the unauthorized disclosure or modification of BES data used for Operational Planning Analysis, Real-time Assessments, and
Real-time monitoring while being transmitted between BES Control Centers. This excludes oral communications.” Reclamation
recommends that the word “BES” be added to R1 regardless of whether the SDT accepts the rest of the above proposed language.
If the requirement for a plan is retained, Reclamation recommends the SDT clarify what is meant by having a plan and how a plan is
different from a documented process.

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Reclamation recommends using the following definitions of “plan” and “process:”
Plan: Written account of intended future course of action (scheme) aimed at achieving specific goal(s) or objective(s) within a specific
timeframe. It explains in detail what needs to be done, when, how, and by whom, and often includes best case, expected case, and worst
case scenarios. See also planning.
Process: Sequence of interdependent and linked procedures which, at every stage, consume one or more resources (employee time,
energy, machines, money) to convert inputs (data, material, parts, etc.) into outputs. These outputs then serve as inputs for the next stage
until a known goal or end result is reached.
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Scott Berry - Scott Berry On Behalf of: Jack Alvey, Indiana Municipal Power Agency, 1, 4; - Scott Berry
Answer

No

Document Name
Comment
We have attached our comments in the last question for the definition of Control Center. We are recommending changes to this
definition.
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0

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Lauren Price - American Transmission Company, LLC - 1

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Answer

No

Document Name
Comment
ATC believes the language should be in better alignment with the directives of the FERC order to establish a plan and implement controls
to address the risks posed to the BES. ATC also believes the requirement language should be less prescriptive as it relates to data types.
ATC believes the Requirement language must allow an appropriate level of flexibility for Registered Entities to identify and document the
risks posed to the BES and the corresponding data to assure implemented controls are (and remain) commensurate with risk. The
requirement should be focused on the achievement and ongoing sustainability of the security objective in order to permit adaption of
their plan(s) and the associated implemented controls such that they are designed to effectively address the current and emerging risks
posed to BES Control Center assets and information as the threat landscape changes. Some potential language for consideration is:
“R1. For sensitive Bulk Electric System (BES) data communicated between BES Control Centers, Responsible Entities shall establish and
implement one or more documented plans that collectively identifies and addresses:
R1.1. the communication links capable and purposed for the transport of BES data between BES Control Centers
R1.2. the risks posed to the BES from the transport of the BES data between BES Control Centers
R1.2. the BES data subject to the risk
R1.3. the protective measures and security practices designed and implemented to mitigate the identified risks.
R1.4. the process and cycle to review and update the plan(s) to maintain alignment with risks posed
BES data excludes oral communications.”
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James Gower - Entergy - NA - Not Applicable - SERC
Answer

No

Document Name
Comment
The standard as drafted explicitly excludes oral communications, but does not consider forms of written communication (email, chat, etc)
that could communicate the same type of information that an oral communication could. These written instructions are commonly
outside of SCADA systems and are on corporate systems, and this standard would require physical or logical controls on those systems for
communications that may traverse these systems. The standard should specify the protection of “operational data”, “BCS Data”, or some
other term to clarify protection of data outside of instructions, or provide data validation (i.e verify emails by phone) as an acceptable
control.
Additionally, Entergy has concerns over expanding the scope of protection from “real-time” as defined in other CIP standards and
through existing CIP definitions, to require the protection of Operational Planning Analysis data that is outside of the “real-time” horizon.
Requests additional clarity regarding whether the protection is required for data that is used to an input to Operational Planning Analysis,
or also includes Operational Planning Analysis data outputs. The Technical Justification and Rationale document seems to imply it is data
inputs as it calls out data believed to already be within BES Cyber Systems.
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0

Response
Guy Andrews - Georgia System Operations Corporation - 4
Answer

No

Document Name
Comment

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•

•
•
•

•

•

GSOC (Georgia Systems Operations Corporation) requests that the Standards Drafting team provide formal CIP-012 Guidance and
Technical Basis (GTB) or Implementation Guidance, either within the Standard or as separate documentation. This is crucial for an
entity’s understanding of how to meet the compliance objective of a new Standard.
GSOC requests clarification regarding:
he applicability of the Standard to TOs. This Standard should apply only TOs who own or operate Control Centers. An example of
modifying the applicability can be found in MOD-025-2.
the precise nature of Operator-to-Operator communications. “Oral Communications” are excluded. However, EOP-008
(Emergency Operating) Plans often specify using cell/text/email while in mid-failover to the backup site. Would these types of
communications also be excluded?
The Rationale talks about “CIP-012-1 Requirements R1 and R2 protections for applicable data during transmission between two
geographically separate Control Centers.” However, the requirements themselves don’t seem to make that same
distinction. Since the definition of a “Control Center” includes associated data centers, this could lead to the application of this
Standard, for example, to a facility that houses 2 control centers side-by-side (one with a data center downstairs). GSOC requests
that the Drafting Team provide more information about the Rationale, as it relates to geographical location and proximity of
Control Centers, and corresponding language of the Requirements.
CIP-012 includes protections for data while being transmitted between Control Centers. However, Control Centers are facilities
and do not transmit data. Does this include only data transmitted between BES Cyber Systems associated with a Control Center or
data transmitted by certified System Operators?

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0

Response
Laura McLeod - NB Power Corporation - 5
Answer

No

Document Name
Comment

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TOP-003/IRO-010 both require applicable entities have mutual agreement on security protocols. This mutual agreement requirement
text of TOP-003/IRO-010 may limit or prevent an entity from following its documented plans of CIP-012-1 R1 should, as an example,
either entity change its security protocols.
One approach is to also include the requirement for mutual agreement within CIP-12-1 and/or be more prescriptive in how an entity
complies with CIP-012-1 R1 including coordination between entities.
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Response
Annette Johnston - Berkshire Hathaway Energy - MidAmerican Energy Co. - 3
Answer

No

Document Name
Comment
We do not agree with two separate requirements, one for a plan and one to implement. We recommend following precedent in the other
CIP standards, for example, CIP-004-011. The obligation can be accomplished with one requirement, such as follows, with the caveat of
concerns expressed in question 1 about what data is covered.
The Responsible Entity shall implement one or more documented processes(s) to mitigate the risk of the unauthorized disclosure or
modification of data used for Operational Planning Analysis, Real-time Assessments, and Real-time monitoring while being transmitted
between Control Centers, except under CIP Exceptional Circumstances . This excludes oral communications. Risk mitigation shall be
accomplished by one or more of the following actions: (follow with the four bullets).
Delete R2.
With one requirement, the note could be simpler by not referencing "R1 of CIP-012-1" and "CIP-012-1." See following.

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Note: If the Responsible Entity does not have a Control Center or it does not transmit the type of data specified in this
Requirement between two Control Centers, this Requirement would not apply to that entity.
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Response
Terry Harbour - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1
Answer

No

Document Name
Comment
See MidAmerican Energy Company comments.
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0

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0

Response
Laurie Williams - PNM Resources - Public Service Company of New Mexico - 1
Answer

No

Document Name
Comment
The requirement is too general and would likely not yield consistent compliance among entities and would result in inconsistent auditing
of compliance.

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Likes

0

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0

Response
Lynn Goldstein - PNM Resources - Public Service Company of New Mexico - 3
Answer

No

Document Name
Comment
The requirement is too general and would likely not yield consistent compliance among entities and would result in inconsistent auditing
of compliance
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0

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0

Response
Haley Sousa - Public Utility District No. 1 of Chelan County - 5
Answer

No

Document Name
Comment
CHPD requests clarification be added to the Technical Rationale for acceptable means of physically protecting communications links and
identifying equally effective methods to mitigate risk.
CHPD requests that the exclusion for oral communications be extended to electronic mail.

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Likes

0

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0

Response
Janis Weddle - Public Utility District No. 1 of Chelan County - 6
Answer

No

Document Name
Comment
CHPD requests clarification be added to the Technical Rationale for acceptable means of physically protecting communications links and
identifying equally effective methods to mitigate risk.
CHPD requests that the exclusion for oral communications be extended to electronic mail.
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0

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0

Response
David Greene - SERC Reliability Corporation - 10, Group Name SERC CIPC
Answer

No

Document Name

3B-2016-02_CIP-012-1_Unofficial_Comment_Form_CIPC.docx

Comment
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0
0

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Response
Brian Millard - Tennessee Valley Authority - 1,3,5,6 - SERC, Group Name Tennessee Valley Authority
Answer

Yes

Document Name
Comment
TVA agrees, providing the proposed definition of Control Center is adopted.
TVA notes that in many cases some types of operational planning analysis data is housed in systems not classified as BES Cyber Systems
and may not reside within an ESP. A documented plan provides a mechanism to identify and document flows of BES sensitive data that
do not originate from within an ESP nor pass through an EAP.
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0

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0

Response
Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

Yes

Document Name
Comment
IPC does not agree with the need for mandatory requirements. IPC evaluates risks and develops strategies to mitigates those risks,
including those associated with communication infrastructure and data transmission. Risks can change, and the implementation of static
regulatory obligations that are not flexibly written can make it more difficult to adapt.
Likes

0

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Dislikes

0

Response
Anthony Jablonski - ReliabilityFirst - 10
Answer

Yes

Document Name
Comment
Even though ReliabilityFirst votes in the affirmative, ReliabilityFirst provides the following comments for consideration:
1.

Requirement R1 –

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i.

CIP-012-1 refers to data as outlined in NERC standards TOP-003-3 and IRO-010-2 that are required to be
protected. ReliabilityFirst understands these types of data can vary based on entity function and what data is needed.
From a compliance monitoring perspective, it may be difficult to verify what the entity is protecting versus what actually
should be protected. ReliabilityFirst requests the SDT to consider putting a list of typical data that should be protected per
the standard and include it in a guideline document or rationale section.

ii.

The standard, as written, states “Risk mitigation shall be accomplished by one or more of the following actions: Physically
protecting the communication links transmitting the data; Logically protecting the data during transmission; or Using an
equally effective method to mitigate the risk of unauthorized disclosure or modification of the data.” Since this is data in
transit (over the “air”) ReliabilityFirst inquires on how one provides physical protections? In addition to this, the selection
of encryption cyphers, and key lengths are not required. ReliabilityFirst suggests to place some language about encryption
in a “technical basis”, explaining that there are different cyphers, some better than others, and after weighing the pros and
cons of different cyphers and key lengths recommend the use of site-to-site IPV6 encapsulation with a specific cypher and
key length.

0
0

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Response
Chris Scanlon - Exelon - 1
Answer

Yes

Document Name
Comment
Exelon agrees with the approach of the latest revision, which provides latitude to protect the communication links, the data, or both, to
satisfy the security objective consistent with the capabilities of the Responsible Entity’s operational environment.
We do, however, question the placement of the “Note” portion within R1. The Note applies not just to R1, but to CIP-012-1 as a
whole. Is there a reason for not including this under Section 4 Applicability, as an exemption?
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0

Response
Vivian Vo - APS - Arizona Public Service Co. - 3
Answer

Yes

Document Name

2016-02 Modifications to CIP Standards CIP-012-1 - Answer to Question 1.docx

Comment
Please see the attached document for Arizona Public Service Co.'s answer to Question 1.
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0
0

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Response
Barry Lawson - National Rural Electric Cooperative Association - 4
Answer

Yes

Document Name
Comment
NRECA agrees with the construct of the standard and its requirements, but not the scope of sensitive BES data as detailed in the response
to question 2.
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0

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0

Response
Shelby Wade - PPL - Louisville Gas and Electric Co. - 3,5,6 - SERC, Group Name Louisville Gas and Electric Company and Kentucky Utilities
Company
Answer

Yes

Document Name
Comment
We support SERC's comments.
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0

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0

Response

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David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment
OPG has concerns with potential issues arising from communication links not owned by entity.
Potential issues can also occur when the communication is performed between the CC belonging to different entities; how is the
demarcation point determined.
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0

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0

Response
Mark Riley - Associated Electric Cooperative, Inc. - 1
Answer

Yes

Document Name
Comment
AECI agrees with the construct of the standard and its requirements, but not the scope of sensitive BES data as detailed in the response
to question 2.
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0

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0

Response

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RoLynda Shumpert - SCANA - South Carolina Electric and Gas Co. - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
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0

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0

Response
Nicholas Lauriat - Network and Security Technologies - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment

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Likes

0

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0

Response
Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Answer

Yes

Document Name
Comment
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0

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0

Response
Shannon Fair - Colorado Springs Utilities - 1,3,5,6, Group Name Colorado Springs Utilities
Answer

Yes

Document Name
Comment
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0

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0

Response
Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 3, Group Name FirstEnergy Corporation

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Answer

Yes

Document Name
Comment
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0

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0

Response
Jesus Sammy Alcaraz - Imperial Irrigation District - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
Sheranee Nedd - PSEG - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer

Yes

Document Name
Comment
Likes

1

PSEG - PSEG Fossil LLC, 5, Kucey Tim

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Dislikes

0

Response
Michael Shaw - Lower Colorado River Authority - 1, Group Name LCRA Compliance
Answer

Yes

Document Name
Comment
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0

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0

Response
Douglas Webb - Douglas Webb On Behalf of: Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., 3, 5, 1, 6; James
McBee, Great Plains Energy - Kansas City Power and Light Co., 3, 5, 1, 6; Jessica Tucker, Great Plains Energy - Kansas City Power and
Light Co., 3, 5, 1, 6; Jim Flucke, Great Plains Energy - Kansas City Power and Light Co., 3, 5, 1, 6; - Douglas Webb
Answer

Yes

Document Name
Comment
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0

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0

Response
Richard Vine - California ISO - 2
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Answer
Document Name
Comment
The California ISO supports the comments of the Security Working Group (SWG).
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2. Requirement R1: The SDT seeks comment on the need to scope sensitive BES data as it applies to Operational Planning Analysis,
Real-time Assessment, and Real-time monitoring. Do you agree with scoping CIP-012-1 Requirement R1 in this manner? Please provide
comment in support of your response.
Terry Harbour - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1
Answer

No

Document Name
Comment
See MidAmerican Energy Company comments.
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Response
Annette Johnston - Berkshire Hathaway Energy - MidAmerican Energy Co. - 3
Answer

No

Document Name
Comment
The FERC directive refers to "sensitive bulk electric system data" and directs NERC to "identify the scope of sensitive build electric system
data." The FERC directive also acknowledges that certain entities are already required to exchange necessary real-time and operational
planning data through secured networks using mutually agreeable security protocol.
Draft Requirement 1 refers to "data used for Operational Planning Analysis, Real-time Assessments, and Real-time monitoring." We agree
with other commenters that these references require revision. Further, we ask the SDT to consider scoping sensitive data explicitly to
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information exchanged between Control Centers' BES Cyber Systems. This corresponds to SDT's assertation that "this data resides within
BES Cyber Systems, and while at rest is protected by CIP-003 through CIP-011." It also corresponds to FERC's recognition of mutually
agreeable security protocol networks referenced above.
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0

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0

Response
Laura McLeod - NB Power Corporation - 5
Answer

No

Document Name
Comment
Since Operational Planning Analysis is not real-time data and since planning data/information is generally scrutinized when
performing analysis the risk of acting on corrupted data (entry error or unauthorized disclosure/modification) is low.
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0

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0

Response
Mark Riley - Associated Electric Cooperative, Inc. - 1
Answer

No

Document Name
Comment

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AECI contends that data used for Operational Planning Analysis (OPA) is not sensitive BES data and does not have a 15 minute impact on
the reliable operation of the BES. The CIP standards focus on span of control of BES Cyber Systems and their impact to the reliable
operation of the BES. Data used for Real-time Assessments and Real-time monitoring can immediately impact the reliable operation of
the BES, but data used for OPA has no such impact. AECI requests that the SDT remove OPA from R1 due to not impacting the reliable
operation of the BES.
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0

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0

Response
James Gower - Entergy - NA - Not Applicable - SERC
Answer

No

Document Name
Comment
Entergy has concerns over expanding the scope of protection from “real-time” as defined in other CIP standards and through existing CIP
definitions, to require the protection of Operational Planning Analysis data that is outside of the “real-time” horizon.
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0

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0

Response
Wendy Center - U.S. Bureau of Reclamation - 5
Answer

No

Document Name

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Comment
Reclamation recommends adding “BES” data to the language as stated above in question 1.
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0

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0

Response
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

No

Document Name
Comment
The SPP Standards Review Group has a concern that the scope doesn’t provide the appropriate coverage of the BES data. We would like
to propose some new language to address those potential concerns. First of all, a “plan” does not necessarily mean the data is protected.
According to the Rationale section FERC is looking for controls to protect these communication links. It should also be clarified that this is
“BES” data.
The SDT, in the Technical Rationale and Justification document acknowledges TOP-003-3 and IRO-010-2 “provides consistent scoping of
identified data” [R1 section: Alignment with IRO and TOP Standards”]. We believe that the data specifications under TOP-003-3 R1 and
IRO-010-2 R1 correctly scope the data to be protected; however the current R1 only leaves us with three defined terms for scoping. These
3 defined terms were already used to scope the data specifications under TOP-003-3 R1 and IRO-010-2 R1. CIP-012-1 R1 should reference
to TOP-003-1 R1 and IRO-010-2 R1. We realize that it is not the preferred method to reference another Standard; however since CIP-012
is classified as a CIP Standard, and not an Operations and Planning Standard which would be the correct classification, CIP auditors may
expand the data to be protected based solely on definitions. In order to properly scope CIP-012, it should reference the TOP-003 and IRO010 Standards.

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R1 should be re-written: “The Responsible Entity shall have controls in place to mitigate the risk of the unauthorized disclosure or
modification of BES data identified under entity developed data specifications in TOP-003-3 R1 for applicable entities and IRO-010-2 R1
for applicable entities; while such data is being transmitted between BES Control Centers. This excludes oral communications.”
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0

Response
Ronald Donahey - TECO - Tampa Electric Co. - 3
Answer

No

Document Name
Comment
Please provide additional clarification on the protection of load forecasting data as it may not consistently be included as a separate BES
Cyber System.
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0

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0

Response
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer

No

Document Name
Comment

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As per the concern noted in response to question 1, we agree that either further clarification on the scope of the data is needed so it is
clear the data in question has already been scoped and is in specifications that are required by IRO-010 and TOP-003, or the SDT should
consider setting aside a “data-centric” approach and focus protections on a more technical solution regardless of the data being
transmitted between Control Center ESPs and LEAPs.
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0

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0

Response
Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer

No

Document Name
Comment
Utility Services does not agree with the scope of the CIP-012-1 R1 as it applies to Operational Planning Analysis, Real-time Assessment,
and Real-time monitoring. Since Operational Planning Analysis data would not meet the 15-minute impact criteria used in the
identification of BES Cyber Systems, this data would only be required to be protected as it is being transmitted between Control Centers.
This inconsistency between the data systems identified by CIP-012-1 and those identified in other CIP standards may cause the
unintended expansion of scope of the CIP Standards.
Public power believes applying controls to the Operational Planning Analysis data may reduce the current ability of entities to share this
data which may cause a reduction in BES reliability. Not all of this data goes from Control Center to Control Center but may go to (or
from) a location outside of a Control Center and therefore would not be in scope of the drafted CIP-012 standard. USI suggests removing
the Operational Planning and Analysis data from the scope of this standard.
If the Operational Planning and Analysis data must be retained in the Standard, then USI believes that an exemption for the
communication of Operational Planning and Analysis data by email should be put in place. This would be similar to the exemption that
exists for voice communication.

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Likes

0

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0

Response
James Anderson - CMS Energy - Consumers Energy Company - 1
Answer

No

Document Name
Comment
The requirement suggested data are different from those protected in other CIP standards. This may cause confusion in the future by
calling it a CIP standard.
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David Greyerbiehl - CMS Energy - Consumers Energy Company - 5
Answer

No

Document Name
Comment
The requirement suggested data are different from those protected in other CIP standards. This may cause confusion in the future by
calling it a CIP standard.
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0

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Response
Warren Cross - ACES Power Marketing - 1,3,4,5 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Standards Collaborators
Answer

No

Document Name
Comment
We disagree with the inclusion of Operational Planning Analysis (OPA) based on its NERC definition, as these evaluations are assessed on
anticipated and potential conditions for next-day operations and outside the 15-minute impact on the reliable BES operations. The
inclusion of OPA is unnecessary and the technical basis does not support it being in scope because it is not impacting the BES in real time.
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Response
Lan Nguyen - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
CenterPoint Energy believes not all data included in OPA, RTA, and RTM is sensitive BES data. CenterPoint Energy recommends the SDT
narrow the scope further to only sensitive BES data. Some inputs into OPAs, RTAs, and RTMs (e.g. forecast type data, modeling data such
as Facility Ratings, phase angle limitations, etc.) should not be included in the scope of this project. On a situational basis, some
telemetry and outage information would also not be considered sensitive BES data.

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CenterPoint Energy further recommends that OPA data be completely removed from the scope of CIP-012-1. CenterPoint Energy does
not deem this data to be considered sensitive BES data, nor does this data carry the significance of actual Real-time data used for RTAs
and RTM.
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0

Response
Jack Cashin - American Public Power Association - 4
Answer

No

Document Name
Comment
APPA does not agree with the scope of the CIP-012-1 R1 as it applies to Operational Planning Analysis, Real-time Assessment, and Realtime monitoring. Since Operational Planning Analysis data would not meet the 15-minute impact criteria used in the identification of BES
Cyber Systems, this data would only be required to be protected as it is being transmitted between Control Centers. This inconsistency
between the data systems identified by CIP-012-1 and those identified in other CIP standards may cause the unintended expansion of
scope of the CIP Standards.
Public power believes applying controls to the Operational Planning Analysis data may reduce the current ability of entities to share this
data which may cause a reduction in BES reliability. Not all of this data goes from Control Center to Control Center but may go to (or
from) a location outside of a Control Center and therefore would not be in scope of the drafted CIP-012 standard. APPA suggests
removing the Operational Planning and Analysis data from the scope of this standard.
If the Operational Planning and Analysis data must be retained in the Standard, then APPA believes that an exemption for the
communication of Operational Planning and Analysis data by email should be put in place. This would be similar to the exemption that
exists for voice communication.

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An important consideration with respect to scope and data protection, is the impact encryption may have on the data being considered
within the scope of the standard. As SRP communicates in their comments: until the implications are understood about the amount of
data being considered for the standard and the impact of encryption on latency and computing resources, the scope may be overreaching. Therefore, APPA believes that the scoping for the standard does not sufficiently take these factors into account.
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Response
Theresa Rakowsky - Puget Sound Energy, Inc. - 1
Answer

No

Document Name
Comment
See APPA Comments.
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0

Response
Marc Donaldson - Tacoma Public Utilities (Tacoma, WA) - 3
Answer

No

Document Name
Comment

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Tacoma Power supports the comments of APPA
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Response
Jesus Sammy Alcaraz - Imperial Irrigation District - 1
Answer

No

Document Name
Comment
While we agree with the SDTs approach to align with TOP-003 and IRO-010, we feel that technologies such as encryption or physical
protection are generally implemented by link, not communication type.
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0

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Response
Russell Noble - Cowlitz County PUD - 3
Answer

No

Document Name
Comment
Cowlitz PUD supports the comments submitted by APPA.

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Likes

0

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Response
Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer

No

Document Name
Comment
Xcel Energy is concerned with the inclusion of BES data used for Operation Planning Analysis that does not have a 15 minute impact on
the Bulk Electric System. The inclusion of Operational Planning Assessment data would bring corporate communication links, such as
corporate email, into the scope of NERC Standards.
We are also concerned with the language in Requirement R1.1 which states that a method of risk mitigation could be done by "Physically
protecting the communication links transmitting data." Xcel Energy believes that the proposed standard does not define what physical
controls would be sufficient to mitigate the undefined risk of "unauthorized disclosure of modification of data." Many communication
devices owned by Xcel Energy reside in company facilities that have several layers of physical protection. However, once communication
links leave our enclosures and ownership purview, physical protection would be difficult at best, largely unknown, and impossible to
enforce. The implementation of physical controls only covers a small section of the medium for the data and does not actually protect
the data itself. As one of three options; if an organization elects to impement physical controls it would still leave a gap in data integrity
and add little benefit with excessive administrative burden.
Xcel Energy respectfully proposes the recommendation for physcial protection to be removed and require logical controls such as
encryption, firewalls, information protection release standards and password requirements. Logical controls would more sufficiently
protect the data itself end-to-end. We suggest the following edits to R1;
The Responsible Entity shall develop and implement controls [strikethrough: one or more documented plan(s)] to mitigate the risk of the
unauthorized disclosure of or modification to BES data used for Operational Planning Analysis, Real-time Assessments, and Real-time

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monitoring while being transmitted between Control Centers and which could have an adverse impact on the BES within 15 minutes.
This excludes verbal communications. [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]
1.1. Risk mitigation shall be accomplished by one or more of the following actions:
•

[strikethrough: Physically protecting the communication links transmitting the data;]

•

Logically protect[strikethrough:ing] the data during transmission; or

•

Use[strikethrough:ing] an equally effective method to mitigate the risk of unauthorized disclosure or modification of the data.

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0

Response
Thomas Breene - WEC Energy Group, Inc. - 3
Answer

No

Document Name
Comment
The SDT needs to add “BES” data into the language as recommended above in question 1. The “BES data” to be protected should be
identified as that “BES data” which can have an impact via high and medium BES Cyber Systems within 15 minutes. In other words, this
level of protection should be limited to High and Medium Control Centers and only that data which could put Real-time operations at risk.
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0

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0

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Lona Calderon - Salt River Project - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
SRP agrees this data should be protected. However, after further discussions within SRP and with other entities in the industry, it is clear
no one in the industry can state or has an understanding of the implications encryption would have on reliable operation of the BES and
the data within this scope. Until a survey or evaluation is performed to understand the amount of data this scope applies to and the
impact of encryption on latency and computing resources, the scope may be over-reaching. As such, the manner used for scoping does
not adequately take these factors into account.
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0

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0

Response
Barry Lawson - National Rural Electric Cooperative Association - 4
Answer

No

Document Name
Comment
NRECA contends that data used for Operational Planning Analysis (OPA) is not sensitive BES data and does not have a 15 minute impact
on the reliable operation of the BES. The CIP standards focus on span of control of BES Cyber Systems and their impact to the reliable
operation of the BES. Data used for Real-time Assessments and Real-time monitoring can immediately impact the reliable operation of
the BES, but data used for OPA has no such impact. We request that the SDT remove OPA from R1 due to not impacting the reliable
operation of the BES.
Likes

0

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Dislikes

0

Response
Aaron Austin - AEP - 3
Answer

No

Document Name
Comment
AEP suggests that “Operational Planning and Analysis” be removed from R1.
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0

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0

Response
Quintin Lee - Eversource Energy - 1, Group Name Eversource Group
Answer

No

Document Name
Comment
The Purpose section of CIP-012-1 adds the need to protect the confidentiality of data which is out of Scope of FERC order 822. Although it
is recognized that the SDT is not limited to just FERC orders, adding need to protect the confidentiality of data does not add reliability if
the data is being protected per CIP-012-1 R1.
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Vivian Vo - APS - Arizona Public Service Co. - 3
Answer

No

Document Name
Comment
AZPS respectfully submits that achieving a consensus regarding categorization of data as sensitive across all three interconnections will be
difficult – if not impossible – to achieve. The sensitivity of the same data can vary drastically between interconnections and entities
within each interconnections. For example, a piece of information that AZPS considers critical and sensitive to its real-time assessments
may be viewed as insignificant to another entity. Additionally, certain markets require publication of data that other markets would
consider sensitive. Hence, any attempted categorization may conflict with regulatory requirements in Open Access Transmission Tariffs,
Market Protocols, state and federal regulations, etc. that obligate entities to disclose and/or that require confidentiality and that are
already effective.
Furthermore, such a classification may not matter in practice. The reality is that data flows to Control Centers across a limited number of
communication channels. Consider a simplified control center that uses only ICCP for real-time monitoring and assessment, with only
half of the data transmitted across that channel being considered “sensitive.” It is unlikely that any entity would reasonably determine
that it should separate out the sensitive data for protection and leave the non-sensitive data unprotected. It is more likely that they
would, instead, protect the entire communication channel. Consequently, AZPS does not support the need or see any benefit to an effort
focused on scoping sensitive BES data. Instead, it recommends that responsible entities retain the authority to designate specific data or
communication links as “sensitive.”
Finally, in the event that the SDT determines a need to scope sensitive BES data, AZPS suggests striking the term “Operational Planning
Analysis” from the requirement and limiting the data considered as sensitive to that data which is subject to the NERC Operating
Reliability Data (ORD) Agreement. The NERC ORD Agreement is intended to ensure the confidentiality of sensitive data and the definition
of Operating Reliability Data and associated obligations included therein are clear, well-established, and well-understood by
industry. Importantly, the definition of ORD excludes “Operational Planning Analysis,” signaling that such data has not, historically, been
considered as “sensitive.” Moreover, the Operational Planning Analysis occurs in the next day horizon, providing entities with time to
receive and review data prior to use and, where data is suspect, request verification of data or, where data is not timely received, request
that such data be re-transmitted. For these reasons, the data utilized in Operational Planning Analyses has extremely limited impact on
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reliability, which is highly dependent on accurate, appropriate real-time data. Hence, protecting data used in real-time assessment and
monitoring as has been required by the NERC ORD Agreement for years is appropriate and the scope of such data has already been
evaluated for sensitivity and confidentiality. In summary, if the SDT is compelled to scope sensitive data, to ensure consistency, AZPS
recommends that the SDT interpret “sensitive BES data” as encompassing data used in Real-time Assessment and Real-time monitoring
only and utilize the NERC ORD Agreement as its primary reference.
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0

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0

Response
Dennis Sismaet - Northern California Power Agency - 6
Answer

No

Document Name
Comment
NCPA does not agree with the scope of the CIP-012-1 as it applies to Operational Planning Analysis, Real-time Assessment, and Real-time
monitoring. Since Operational Planning Analysis data would not meet the 15-minute impact criteria used in the identification of BES
Cyber Systems, this data would only be required to be protected as it is being transmitted between Control Centers. This inconsistency
between the data systems identified by CIP-012-1 and those identified in other CIP standards may cause the unintended expansion of
scope of the CIP Standards. Also see other APPA and Utility Services/TAPs comments.
Likes

0

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0

Response
Marty Hostler - Northern California Power Agency - 5
Answer

No

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Document Name
Comment
NCPA does not agree with the scope of the CIP-012-1 as it applies to Operational Planning Analysis, Real-time Assessment, and Real-time
monitoring. Since Operational Planning Analysis data would not meet the 15-minute impact criteria used in the identification of BES
Cyber Systems, this data would only be required to be protected as it is being transmitted between Control Centers. This inconsistency
between the data systems identified by CIP-012-1 and those identified in other CIP standards may cause the unintended expansion of
scope of the CIP Standards. Also see other APPA and Utility Services/TAPs comments.
Likes

0

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0

Response
James Poston - Santee Cooper - 3, Group Name Santee Cooper
Answer

No

Document Name
Comment
Recommend removing “Operational Planning Analysis” from this requirement. Operational Planning Analysis is not Real-time data and
would not affect the BES within 15 minutes. The TOP-003-3 Standard currently requires a mutually agreeable security protocol for
sharing of data required for Operational Planning Analyses.
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0

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0

Response
Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
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Answer

No

Document Name
Comment
See APPA Comments.
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0

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0

Response
Alice Wright - Arkansas Electric Cooperative Corporation - 4
Answer

No

Document Name
Comment
See attachment
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0

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0

Response
Dana Klem - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO NSRF
Answer

No

Document Name
Comment

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The SDT needs to add “BES” data into the language as recommended above in question 1.
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0

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0

Response
Jennifer Hohenshilt - Talen Energy Marketing, LLC - 6
Answer

No

Document Name
Comment
The question is unclear.
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0

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0

Response
Philip Huff - Arkansas Electric Cooperative Corporation - 3
Answer

No

Document Name
Comment
Please provide additional guidance on the scope of the information. The Standards from which the scope derives does not provide
guidance, and the expansion of scope in CIP-012-1 to all Control Centers necessitates the need for more specific guidance.

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Likes

0

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0

Response
Donald Lock - Talen Generation, LLC - 5
Answer

No

Document Name
Comment
The question is unclear.
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0

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0

Response
Brandon McCormick - Brandon McCormick On Behalf of: Ginny Beigel, City of Vero Beach, 3; Lynne Mila, City of Clewiston, 4; Tom
Reedy, Florida Municipal Power Pool, 6; - Brandon McCormick, Group Name FMPA
Answer

No

Document Name
Comment
APPA does not agree with the scope of the CIP-012-1 R1 as it applies to Operational Planning Analysis, Real-time Assessment, and Realtime monitoring. Since Operational Planning Analysis data would not meet the 15-minute impact criteria used in the identification of BES
Cyber Systems, this data would only be required to be protected as it is being transmitted between Control Centers. This inconsistency

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between the data systems identified by CIP-012-1 and those identified in other CIP standards may cause the unintended expansion of
scope of the CIP Standards.
FMPA believes applying controls to the Operational Planning Analysis data may reduce the current ability of entities to share this data
which may cause a reduction in BES reliability. Not all of this data goes from Control Center to Control Center but may go to (or from) a
location outside of a Control Center and therefore would not be in scope of the drafted CIP-012 standard. APPA suggests removing the
Operational Planning and Analysis data from the scope of this standard.
If the Operational Planning and Analysis data must be retained in the Standard, then APPA believes that an exemption for the
communication of Operational Planning and Analysis data by email should be put in place. This would be similar to the exemption that
exists for voice communication.
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0

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0

Response
Joe Tarantino - Joe Tarantino On Behalf of: Arthur Starkovich, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Beth Tincher,
Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Jamie Cutlip, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Kevin Smith,
Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Susan Oto, Sacramento
Municipal Utility District, 4, 1, 5, 6, 3; - Joe Tarantino
Answer

No

Document Name
Comment
We are concerned because unauthorized alteration of Operational Planning Analysis data does not pose a threat to the BES. This more
appropriately addressed by TOP 010-1 reliability standard regarding the quality of the data. We note that Operational Planning Data is
not real time data, as such we ask the STD to treat communicating Operational Planning Data Email exempt similar to the oral
communication.

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Likes

0

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0

Response
George Brown - Acciona Energy North America - 5
Answer

No

Document Name
Comment
The requirement as written does not meet the criteria as outlined in the document titled “Ten Benchmarks of an Excellent Reliability
Standard”, benchmark 8. Clear Language. As the SDT stated in the rationale, the data in scope is the data as specified in TOP-003-3 and
IRO-010-2. If this is in fact the case then the SDT should draw a clear and unambiguous line to these standards within the
requirement. The addition of such language will also prevent unintentional scope reach.
Suggested language should be something to the following effect:
R1.2 The Responsible Entity, as applicable to its registered function, shall consider the data used for Operational Planning Analysis, Realtime Assessments, and Real-time monitoring to be the data as specified in:
•

NERC Reliability Standard IRO-010-2, Requirement R1 and,

•

NERC Reliability Standard TOP-003-3 — Operational Reliability Data, Requirement R1 and Requirement R2.

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Response
Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion

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Answer

No

Document Name
Comment
Dominion asserts that data used for Operational Planning Analysis is often an ad-hoc report by exception (e.g., this line will be out or this
unit will be de-rated) and because this data is often collected by a stand-alone system it can often be entered by several people within an
organization and from several locations. Dominion is unclear on whether the entity expected to track which data is specifically entered
from within a Control Center as opposed to from an office external to the Control Center. Many stand-alone systems are web-based and
use https for all transactions. It is unclear what would qulaify as adequate evidence and that tracking locations and persons entering the
information is not necessary.
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0

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0

Response
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

No

Document Name
Comment
Duke Energy has concerns about the decision to add Operational Planning Analysis information to the scope of the data protected by this
standard. Currently, the scope of the CIP standards primarily focuses on real-time data, and bringing in Operational Planning Analysis
pushes the scope of CIP standards to include Day Ahead. Also, in some instances, Operational Planning Analyses can be performed by a
3rd party or require data transmitted between entities via 3rd party tools. How would these affect be impacted by the applicability of the
standard? Extending the CIP scope to apply to Day Ahead data is a departure, and could broaden the view of what tools (possibly
including web-based tools?) could fall under CIP scope.
Likes

0

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Dislikes

0

Response
RoLynda Shumpert - SCANA - South Carolina Electric and Gas Co. - 1,3,5,6 - SERC
Answer

No

Document Name
Comment
If there is the need to scope sensitive BES data as it applies to Operational Planning Analysis, Real-time Assessment, and Real-time
monitoring, it should all be scoped as data of the High Impact BES Cyber Systems.
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0

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0

Response
Lynn Goldstein - PNM Resources - Public Service Company of New Mexico - 3
Answer

No

Document Name
Comment
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0

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0

Response

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Lauren Price - American Transmission Company, LLC - 1
Answer

No

Document Name
Comment
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0

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0

Response
David Greene - SERC Reliability Corporation - 10, Group Name SERC CIPC
Answer

No

Document Name

3B-2016-02_CIP-012-1_Unofficial_Comment_Form_CIPC.docx

Comment
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0

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0

Response
sean erickson - Western Area Power Administration - 1
Answer

No

Document Name
Comment

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Likes

0

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0

Response
Guy Andrews - Georgia System Operations Corporation - 4
Answer

Yes

Document Name
Comment
We request clarification on the inclusion of data used for Operational Planning Analysis. This data does not have a 15 minute impact on
the Bulk Electric System. This data is also typically exchanged between operations engineering staff who would not be considered to be a
Control Center.
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0

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0

Response
Michael Shaw - Lower Colorado River Authority - 1, Group Name LCRA Compliance
Answer

Yes

Document Name
Comment
Please provide guidance on whether or not email is in scope as a communication medium.
Likes
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0
0

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Response
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
However, BPA questions the inclusion of Operational Planning Analysis.
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0

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0

Response
Sheranee Nedd - PSEG - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer

Yes

Document Name
Comment
RC, TOP and BA functional entities develop and disseminate specifications for the BES data they need to conduct Operational Planning
Analysis, Real-time Assessment, and Real-time monitoring, in NERC ‘693’ reliability standards TOP-003 and IRO-010. Relevant peer
RCs/TOPs/BAs and others (GOs; GOPs; TOs; LSEs; DPs) are required by these standards to meet these data specifications. The scope of
data subject to R1 is (or should be) thereby understood to be the data that entities both (i) specify in observance of these standards and
(ii) transmit between the entity’s and others’ Control Centers.
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1

PSEG - PSEG Fossil LLC, 5, Kucey Tim
0

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Response
Chris Scanlon - Exelon - 1
Answer

Yes

Document Name
Comment
Exelon agrees that aligning with TOP-003-3 and IRO-010-2 is helpful for scoping CIP-012-1, and promotes consistent application of the
NERC Standards.
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0

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0

Response
David Rivera - New York Power Authority - 3
Answer

Yes

Document Name
Comment
No Comment
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0

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0

Response

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Dermot Smyth - Con Ed - Consolidated Edison Co. of New York - 5, Group Name Con Edison
Answer

Yes

Document Name
Comment
Same comment as question #1 above.
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0

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0

Response
Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

Yes

Document Name
Comment
In the event mandatory standards are imposed, the scope should be limited to data that have well-defined terms.
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0

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0

Response
Brian Millard - Tennessee Valley Authority - 1,3,5,6 - SERC, Group Name Tennessee Valley Authority
Answer

Yes

Document Name

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Comment
TVA agrees that the entity needs to know what information is classified as BES sensitive data as it relates to operational planning analysis,
real-time assessment, and real-time monitoring. In many cases some types of operational planning analysis data is housed in systems not
classified as BES Cyber Systems and may not reside within an ESP.
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0

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0

Response
Janis Weddle - Public Utility District No. 1 of Chelan County - 6
Answer

Yes

Document Name
Comment
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0

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0

Response
Douglas Webb - Douglas Webb On Behalf of: Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., 3, 5, 1, 6; James
McBee, Great Plains Energy - Kansas City Power and Light Co., 3, 5, 1, 6; Jessica Tucker, Great Plains Energy - Kansas City Power and
Light Co., 3, 5, 1, 6; Jim Flucke, Great Plains Energy - Kansas City Power and Light Co., 3, 5, 1, 6; - Douglas Webb
Answer

Yes

Document Name
Comment

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Likes

0

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0

Response
Haley Sousa - Public Utility District No. 1 of Chelan County - 5
Answer

Yes

Document Name
Comment
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0

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0

Response
Laurie Williams - PNM Resources - Public Service Company of New Mexico - 1
Answer

Yes

Document Name
Comment
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0

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0

Response

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David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Michael Puscas - ISO New England, Inc. - 2
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment

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Likes

0

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0

Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Con-Edison and Dominion
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Nicolas Turcotte - Hydro-Qu?bec TransEnergie - 1
Answer

Yes

Document Name
Comment
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0

Dislikes

0

Response
Heather Morgan - EDP Renewables North America LLC - 5

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Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 3, Group Name FirstEnergy Corporation
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
David Gordon - Massachusetts Municipal Wholesale Electric Company - 5
Answer

Yes

Document Name
Comment
Likes

0

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Dislikes

0

Response
Shannon Fair - Colorado Springs Utilities - 1,3,5,6, Group Name Colorado Springs Utilities
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Frank Pace - Central Hudson Gas & Electric Corp. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

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Document Name
Comment
Likes

0

Dislikes

0

Response
Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Nicholas Lauriat - Network and Security Technologies - 1
Answer

Yes

Document Name
Comment
Likes
Dislikes

0
0

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Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE does not have comments on this question.
Likes

0

Dislikes

0

Response
Richard Vine - California ISO - 2
Answer
Document Name
Comment
The California ISO supports the comments of the Security Working Group (SWG).
Likes

0

Dislikes

0

Response

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3. Implementation Plan: The SDT revised the Implementation Plan such that the standard and NERC Glossary terms are effective the first
day of the first calendar quarter that is twelve (12) calendar months after the effective date of the applicable governmental authority’s
order approving the standard, or as otherwise provided for by the applicable governmental authority. Do you agree with this proposal? If
you agree with the proposed implementation time period, please note the actions you will take that require this amount of time to
complete. If you think an alternate implementation time period is needed – shorter or longer - please propose an alternate implementation
plan and provide a detailed explanation of actions and time needed to meet the implementation deadline.
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

No

Document Name
Comment
Duke Energy disagrees with the proposed 12 month Implementation Plan. Certain aspects of achieving compliance with this standard (for
example, implementing end to end encryption) would, in some instances, take a significant amount of time to put in place to due to the
significance of the impact of these changes on critical systems. Further, applying these protections between Control Centers owned by more
than one Responsible Entity will involve significant coordination, and additional time would be necessary to develop a shared understanding
of existing technical limitations, develop agreements, and implement those new approaches for compliance. Duke Energy suggests that a
phased implementation plan would be appropriate given the action necessary. We encourage the drafting team to consider an
Implementation Plan of 12 months for R1. This would give time for the Responsible Entity to assess the Control Centers that are in its scope,
decide on a method of protection, and involve any additional parties that may be necessary. We suggest a minimum of 24 months for the
implementation date for R2 (implementing the plan developed in R1).
Likes

0

Dislikes

0

Response
Brian Millard - Tennessee Valley Authority - 1,3,5,6 - SERC, Group Name Tennessee Valley Authority
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Answer

No

Document Name
Comment
TVA does not agree that twelve months is sufficient time to coordinate with other entities to agree on and implement protection
mechanisms. Implementation may require coordination of plans across a large and/or diverse group of entities employing a variety of
protective measures. TVA suggests 18-24 months would be a more realistic implementation period.
Likes

0

Dislikes

0

Response
Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

No

Document Name
Comment
Changes take time to evaluate and implement. The communication lines will have to be inventoried and evaluated. The data traveling across
these lines will have to be inventoried and evaluated to ensure entities can evidence that they are protecting the itemized list of data included
in the wording of R1 (Operational Planning Analysis, Real-time Assessment, and Real-time monitoring). Other activities that would need to
occur for successful implementation would include preparation and delivery of guidance by regulatory bodies, communication and
coordination with partner entities, configuration, and testing. At minimum, an 18-month implementation plan would be appropriate.
Likes

0

Dislikes

0

Response

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Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer

No

Document Name
Comment
Dominion asserts that budgets, resources, and other events between separate entities may require periods greater than 12
months. Dominion recommends that the implementation period be revised to 24 months.In addition, the time required to develop (R1), and
then successfully implement (R2) would take longer than 12 months from the start date. 24 months should allow sufficient time to
accomplish implementation of both requirements.
Likes

0

Dislikes

0

Response
George Brown - Acciona Energy North America - 5
Answer

No

Document Name
Comment
This standard will require a collaborative effort between Control Centers of the various applicable Functional Entities to achieve the securities
as required. As such, it may not feasible for some entities to implement these securities within 12 months. For example, a Reliability
Coordinator (RC) Control Center will have contact with the Control Centers of several Balancing Authorities (BA), Generator Operators (GOP),
Transmission Operators (TOP), Transmission Owners (TO) and other RCs. If a particular RC is unable to support the implementation of the
securities as required in NERC CIP-012-1 then there will be a cascading and unnecessary non-compliance effect among the other Functional
Entities that have Control Centers that transmit and receive this sensitive BES data with this particular RC’s Control Center. A phase-in
approach may be more appropriate for NERC CIP-012-1, based on schedules created using the Function Entity reliability hierarchy structure.

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Likes

0

Dislikes

0

Response
Joe Tarantino - Joe Tarantino On Behalf of: Arthur Starkovich, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Beth Tincher, Sacramento
Municipal Utility District, 4, 1, 5, 6, 3; Jamie Cutlip, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Kevin Smith, Balancing Authority of
Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Susan Oto, Sacramento Municipal Utility District,
4, 1, 5, 6, 3; - Joe Tarantino
Answer

No

Document Name
Comment
For complex entities the identification and agreement on communication protocols and architecture may require extensive testing and
learning. We recommend at least 18 months due to the quantity of details and logistics.
Likes

0

Dislikes

0

Response
Leonard Kula - Independent Electricity System Operator - 2
Answer

No

Document Name
Comment
The IESO also encourages the drafting team to make the requirement forward-looking in regards to contracts currently in place. Provisions
should be set for legacy contracts including grandfathering of existing agreements and equipment. Implementation of controls involving
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telecommunications providers will require coordination and scheduling to align to the providers’ resource availability and reduce adverse
impact on reliability. This should not require renewal and renegotiation of existing contracts until they reach the end of the existing contract
period.
It should be noted that it is difficult to determine suitability of the implementation timeline when there are open questions about the viability
of available solutions for adequate protections.
More time is necessary to allow for coordination with a large number of parties. This will require budgeting, planning, and scheduling with
external resources for implementation. It will also require significant testing and validation by parties on both ends of a connection.
The IESO recommends a phased implementation with defined milestones similar to CIP-014. Consider the following:
•

For creation of the plan, 12 months should be allowed to (1) conduct an impact assessments, (2) identify the approach to be included
in the plan, (3) implementation milestones, and (4) implementation schedule. This could identify the communication links that have
protections currently in place. The plan could also include identifying all links and protections requiring changes to address service
contracts and related relationships to adjust for new protections. The plan could then be approved by an appropriate entity.

•

For implementation of the plan, additional time should be allowed for budgeting, planning, and scheduling with external resources.
This includes planning with other Responsible Entities as well as telecommunications providers.

Likes

2

Dislikes

Hydro One Networks, Inc., 1, Farahbakhsh Payam; Hydro One Networks, Inc., 3, Malozewski Paul
0

Response
Brandon McCormick - Brandon McCormick On Behalf of: Ginny Beigel, City of Vero Beach, 3; Lynne Mila, City of Clewiston, 4; Tom Reedy,
Florida Municipal Power Pool, 6; - Brandon McCormick, Group Name FMPA
Answer

No

Document Name
Comment

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FMPA does not agree with the implementation proposal timeline. The time to implement R1 (develop a plan) should be 12 months from the
time of the order.
Due to technical complexity, agreements (outsourced and between registered entities), procurement, contracts and coordination between
registered entities (and provisioning of private networks), FMPA requests that the SDT consider the following options for R2 implementation:
•

additional 24 months allowed to undertake implementation,

•

using a phased implementation over a five or longer year period, or

•

in recognition that there is the potential for several existing contracts will have to be replaced (and associated equipment) that
affected contracts be grandfathered until new and or, replacements can be put in place.

Likes

0

Dislikes

0

Response
Frank Pace - Central Hudson Gas & Electric Corp. - 1
Answer

No

Document Name
Comment
It would appear that the proposed implementation period is too short; however, it is difficult to determine if a demarcation point for
compliance is not specified within the language of the Requirement.
Likes

0

Dislikes

0

Response

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Donald Lock - Talen Generation, LLC - 5
Answer

No

Document Name
Comment
The 12-month period provided in the implementation plan should be at least doubled. Developing a clear understanding of what is required
could take some time, and to then scope the project, obtain bids and budget approval, receive materials and implement in whatever portion
of the year remains may prove impractical.
Likes

0

Dislikes

0

Response
David Rivera - New York Power Authority - 3
Answer

No

Document Name
Comment
The time to implement R1 (develop plan) could be 12 months from time of order. For implementation of R2 there should be an
additional 24 months allowed to undertake implementation. This would include identifying all links and protections, with changes
needed to address communications service contracts and related relationships to adjust for new protections. This would also involve
inventory of data to comply with identification of all data transmitted between control centers.
2. Due to technical complexity, agreements (outsourced and between Entities), procurement, contracts and coordination between
Entities (and provisioning of private networks), request that the SDT also consider the following option for R2 implementation:
i. a phased implementation over a five or longer year period, or
ii. to avoid impacting reliability, existing contracts, equipment, etc be grandfathered until new / replacements are in place.
1.

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Likes

0

Dislikes

0

Response
Jennifer Hohenshilt - Talen Energy Marketing, LLC - 6
Answer

No

Document Name
Comment
The 12-month period provided in the implementation plan should be at least doubled. Developing a clear understanding of what is
required could take some time, and to then scope the project, obtain bids and budget approval, receive materials and implement in whatever
portion of the year remains may prove impractical.
Likes

0

Dislikes

0

Response
Dana Klem - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO NSRF
Answer

No

Document Name
Comment
The 12 month time period may only work for Entities who are vertically intergraded. The flow of applicable BES data within CIP-012-1 can be
viewed as a “spider web” of data transfer for large RC foot-prints. With this being said, there may be non-compliance issues when one side of
the data transference is protected and the other side is not. The SDT should propose a phased in approach to protecting data. A five (5) year
implementation plan will allow entities to fund these projects. This is especially important to small entities. Per the NERC Guidance
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concerning “Phase Implementation Plans with Completion Percentages
(http://www.nerc.com/pa/comp/guidance/CMEPPracticeGuidesDL/CMEP_Practice_Guide_Phased_Implementation_Completion_Percentage
s.pdf) please state that the CIP-012-1 does not fall under this guidance.
Likes

0

Dislikes

0

Response
Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer

No

Document Name
Comment
See APPA Comments.
Likes

0

Dislikes

0

Response
James Poston - Santee Cooper - 3, Group Name Santee Cooper
Answer

No

Document Name
Comment

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Recommend a 2 year Implementation Plan Period. For some entities, it may take a significant amount of time to agree on communication
protocols and architecture with neighboring systems. Time is also needed to troubleshoot and test each connection point.
Likes

0

Dislikes

0

Response
Marty Hostler - Northern California Power Agency - 5
Answer

No

Document Name
Comment
NCPA does not agree with the implementation proposal timeline. Due to technical complexity, agreements (outsourced and between REs),
procurement, contracts and coordination between REs (and provisioning of private networks), NCPA requests that the SDT consider the
following options for R2 implementation:
•

additional 24 months allowed to undertake implementation,

•

using a phased implementation over a five or longer year period, or

•

in recognition that there is the potential for several existing contracts will have to be replaced (and associated equipment) that
affected contracts be grandfathered until new and or, replacements can be put in place.

Likes

0

Dislikes

0

Response

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Dennis Sismaet - Northern California Power Agency - 6
Answer

No

Document Name
Comment
NCPA does not agree with the implementation proposal timeline. Due to technical complexity, agreements (outsourced and between REs),
procurement, contracts and coordination between REs (and provisioning of private networks), NCPA requests that the SDT consider the
following options for R2 implementation:
•

additional 24 months allowed to undertake implementation,

•

using a phased implementation over a five or longer year period, or

•

in recognition that there is the potential for several existing contracts will have to be replaced (and associated equipment) that
affected contracts be grandfathered until new and or, replacements can be put in place.

Likes

0

Dislikes

0

Response
Vivian Vo - APS - Arizona Public Service Co. - 3
Answer

No

Document Name
Comment
The proposed implementation plan does not consider complexities associated with implementing technical solutions reliant on inter-entity
coordination and agreement. The proposed implementation plan does not recognize the prerequisite of mutual agreement between entities
regarding a compatible technical solution or the time necessary to complete such prerequisite. Moreover, it does not appear to contemplate

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a potential need for dispute resolution when a transmitting entity and receiving entity cannot agree on a solution. Finally, any
implementation, testing, etc. can only occur once the mutually agreed-upon solution has been identified, budgeted, and procured. For these
reasons, AZPS proposes extending the implementation plan to at least twenty-four (24) calendar months. Two years would likely allot
adequate time to identify, agree upon, and procure appropriate technical solutions in coordination with other entities.
Likes

0

Dislikes

0

Response
David Gordon - Massachusetts Municipal Wholesale Electric Company - 5
Answer

No

Document Name
Comment
The Implementation Plan should be modified to allow 24 months for the implementation phase (R2) due to the potential impact resulting
from the necessity of redesigning communications architectures for secure communications between Control Centers.
Likes

0

Dislikes

0

Response
Heather Morgan - EDP Renewables North America LLC - 5
Answer

No

Document Name
Comment

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Generator Operator Control Centers are required to follow specifications pursuant to the requirements outlined by RCs, ISO,s RTOs, BAs, and
TOPs. To ensure GOP’s are able to properly carry out requirements for all of these parties and CIP-012-2, CIP-012-2’s Implementation Plan
should be phased in similar to IRO-010, and TOP-003. Otherwise, GOP Control Centers will not be able to properly plan for any requirements
delivered by the interconnecting authorities as a result of this Standard.
Likes

0

Dislikes

0

Response
Quintin Lee - Eversource Energy - 1, Group Name Eversource Group
Answer

No

Document Name
Comment
Request changing 12 months to 18 months in the implentation plan to allow time to make any required changes including design,
procurement, CIP assesment and deployment.
Likes

0

Dislikes

0

Response
Aaron Austin - AEP - 3
Answer

No

Document Name
Comment

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AEP suggests that the implementation time frame should be extended to at least 24 months to allow for activities such as coordination,
budgeting, procurement, implementation and testing.
Likes

0

Dislikes

0

Response
Barry Lawson - National Rural Electric Cooperative Association - 4
Answer

No

Document Name
Comment
NRECA asserts that smaller entities may need to procure equipment and implement technical controls that are not currently in place. The
implementation of the plan(s) detailed in requirement R1 could be impacted by budget cycles, procurement processes, and third party vendor
availability. NRECA recommends that the implementation plan be revised to allow 12 months for the development of the plan in requirement
R1 and 24 months for the implementation.
Likes

0

Dislikes

0

Response
Nicolas Turcotte - Hydro-Qu?bec TransEnergie - 1
Answer

No

Document Name
Comment

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Hydro Québec is in agreement with TFIST’s comments below in regards to taking into consideration technical complexities and coordination
between entities; however we suggest that the documented plan in R1 include an implementation plan with deadlines not exceeding 36
months, rather than a prescribed delay for implementing R2. Furthermore, clarifications are requested in regards to the question“please note
the actions you will take that require this amount of time to complete.
1.

The time to implement R1 (develop plan) could be 12 months from time of order. For implementation of R2 there should be an
additional 24 months allowed to undertake implementation. This would include identifying all links and protections, with changes
needed to address communications service contracts and related relationships to adjust for new protections. This would also involve
inventory of data to comply with identification of all data transmitted between control centers.

2.

Due to technical complexity, agreements (outsourced and between Entities), procurement, contracts and coordination between
Entities (and provisioning of private networks), request that the SDT consider:

a )a phased implementation over a five or longer year period, or b) to avoid impacting reliability, that existing contracts, equipment, etc
stay in place. New contracts / equipment will need to follow this new Standard.
Likes

0

Dislikes

0

Response
Lona Calderon - Salt River Project - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
SRP requests 24 calendar months due to the complex details and logistics associated with implementation. The Impact from encryption is
unknown. Because the data is being sent in real-time, it is difficult to test how encryption will affect reliability.

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More research and evaluation is required to understand the implications encryption will have as it may require architecture changes to
account for the extra computing resources required. Additionally, time is required to budget for funds in order to support any required
infrastructure improvements required.
Likes

0

Dislikes

0

Response
Thomas Breene - WEC Energy Group, Inc. - 3
Answer

No

Document Name
Comment
The 12 month time period may only work for Entities who are vertically intergraded. The flow of applicable BES data within CIP-012-1 can be
viewed as a “spider web” of data transfer for large RC foot-prints. With this being said, there may be non-compliance issues when one side of
the data transference is protected and the other side is not. The SDT should propose a phased in approach to protecting data. A five (5) year
implementation plan will allow entities to fund these projects. This is especially import to small entities. Per the NERC Guidance concerning
“Phase Implementation Plans with Completion Percentages
(http://www.nerc.com/pa/comp/guidance/CMEPPracticeGuidesDL/CMEP_Practice_Guide_Phased_Implementation_Completion_Percentage
s.pdf) please state that the CIP-012-1 does not fall under this guidance.
Likes

0

Dislikes

0

Response
Russell Noble - Cowlitz County PUD - 3
Answer

No

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Document Name
Comment
Cowlitz PUD supports the comments submitted by APPA.
Likes

0

Dislikes

0

Response
Jesus Sammy Alcaraz - Imperial Irrigation District - 1
Answer

No

Document Name
Comment
We recommend at least 18 months due to the quantity of details and logistics.
Likes

0

Dislikes

0

Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Con-Edison and Dominion
Answer

No

Document Name
Comment

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·
The time to implement R1 (develop plan) could be 12 months from time of order. For implementation of R2 there should be an
additional 24 months allowed to undertake implementation. This would include identifying all links and protections, with changes needed to
address communications service contracts and related relationships to adjust for new protections. This would also involve inventory of data
to comply with identification of all data transmitted between control centers.
·
Due to technical complexity, agreements (outsourced and between Entities), procurement, contracts and coordination between Entities
(and provisioning of private networks), request that the SDT also consider the following option for R2 implementation:
a.

a phased implementation over a five or longer year period, or

b.

to avoid impacting reliability, existing contracts, equipment, etc. be grandfathered until new / replacements are in place.

Likes

0

Dislikes

0

Response
Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer

No

Document Name
Comment
ERCOT ISO signs on to the ITC SWG comments:
The ITC SWG also encourages the drafting team to make the requirement forward-looking in regards to contracts currently in place.
Provisions should be set for legacy contracts including grandfathering of existing agreements and equipment. Implementation of controls
involving telecommunications providers will require coordination and scheduling to align to the providers’ resource availability and reduce
adverse impact on reliability. This should not require renewal and renegotiation of existing contracts until they reach the end of the existing
contract period.

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It should be noted that it is difficult to determine suitability of the implementation timeline when there are open questions about the viability
of available solutions for adequate protections.
More time is necessary to allow for coordination with a large number of parties. This will require budgeting, planning, and scheduling with
external resources for implementation. It will also require significant testing and validation by parties on both ends of a connection.
The ITC SWG recommends a phased implementation with defined milestones similar to CIP-014. Consider the following:
•

For creation of the plan, 12 months should be allowed to (1) conduct an impact assessments, (2) identify the approach to be included
in the plan, (3) implementation milestones, and (4) implementation schedule. This could identify the communication links that have
protections currently in place. The plan could also include identifying all links and protections requiring changes to address service
contracts and related relationships to adjust for new protections. The plan could then be approved by an appropriate entity.

•

For implementation of the plan, additional time should be allowed for budgeting, planning, and scheduling with external resources.
This includes planning with other Responsible Entities as well as telecommunications providers.

Likes

0

Dislikes

0

Response
Shelby Wade - PPL - Louisville Gas and Electric Co. - 3,5,6 - SERC, Group Name Louisville Gas and Electric Company and Kentucky Utilities
Company
Answer

No

Document Name
Comment
We support SERC's comments.
Likes

0

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Dislikes

0

Response
Marc Donaldson - Tacoma Public Utilities (Tacoma, WA) - 3
Answer

No

Document Name
Comment
Tacoma Power supports the comments of APPA
Likes

0

Dislikes

0

Response
Theresa Rakowsky - Puget Sound Energy, Inc. - 1
Answer

No

Document Name
Comment
PSE believes a 24 month implementation period and/or phased implementation approach is appropriate due to required coordination
between registered entities, potential need for renegotiation of contracts and/or agreements with other entities, and potential for significant
technical complexity for implementation.
Likes

0

Dislikes

0

Response
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Jack Cashin - American Public Power Association - 4
Answer

No

Document Name
Comment
APPA does not agree with the implementation proposal timeline. The time to implement R1 (develop a plan) should be 12 months from the
time of the order.
Due to technical complexity, agreements (outsourced and between registered entities), procurement, contracts and coordination between
registered entities (and provisioning of private networks), APPA requests that the SDT consider the following options for R2 implementation:
• additional 24 months allowed to undertake implementation,
• using a phased implementation over a five or longer year period
•

in recognition that there is the potential for several existing contracts will have to be replaced (and associated equipment) that
affected contracts be grandfathered until new and or, replacements can be put in place.

Likes

0

Dislikes

0

Response
Lan Nguyen - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment

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CenterPoint Energy recommends the effective date for CIP-012-1 to be 24 months after FERC approval. For instances where applicable data
is being transmitted between Control Centers owned by two or more separate Responsible Entities, additional time is needed to coordinate
plans and develop agreements to ensure adequate protection is applied.
Likes

0

Dislikes

0

Response
Warren Cross - ACES Power Marketing - 1,3,4,5 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Standards Collaborators
Answer

No

Document Name
Comment
New entities that are impacted by the new definition should be treated as “newly identified CIP facilities” and should be given the standard 18
month implementation period. Not the proposed 12 month implementation period. Budgetary cycles would need to be considered and an
additional reason for the 18 months.
Likes

0

Dislikes

0

Response
Sheranee Nedd - PSEG - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer

No

Document Name
Comment

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PSEG Supports the NPCC comments.
Likes

1

Dislikes

PSEG - PSEG Fossil LLC, 5, Kucey Tim
0

Response
Michael Puscas - ISO New England, Inc. - 2
Answer

No

Document Name
Comment
The time to implement the first requirement (develop plan) could be 12 months from time of order. For implementation of the plan, however
(R2) there should be an additional 12 months allowed to undertake implementation. This would include identifying all links and protections,
with changes needed to address communications service contracts and related relationships to adjust for new protections.
Likes

0

Dislikes

0

Response
David Greyerbiehl - CMS Energy - Consumers Energy Company - 5
Answer

No

Document Name
Comment
Twelve calendar months for implementation may not be sufficient, twenty-four calendar months should be recommended.

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Likes

0

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0

Response
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
BPA requests clarification about what “Physically protecting the communication links transmitting the data” in section 1.1 means. If it means
protecting the data at the source (at the Control Center), the implementation period is acceptable. BPA will be required to update customer
agreements during the implementation period.
If it means the data must be protected throughout the transmission, it would seem that could only be accomplished with encryption. For
cases where the existing equipment is not capable of encryption, BPA cannot propose an implementation timeline or solution other than
technically feasible exception.
Likes

0

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0

Response
James Anderson - CMS Energy - Consumers Energy Company - 1
Answer

No

Document Name
Comment

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Twelve calendar months for implementation may not be sufficient, twenty-four calendar months should be recommended.
Likes

0

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0

Response
Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer

No

Document Name
Comment
Utility Services does not agree with the implementation proposal timeline. The time to implement R1 (develop a plan) should be 12 months
from the time of the order.
Due to technical complexity, agreements (outsourced and between registered entities), procurement, contracts and coordination between
registered entities (and provisioning of private networks), UTILITY SERVICES requests that the SDT consider the following options for R2
implementation:
·

additional 24 months allowed to undertake implementation,

·

using a phased implementation over a five or longer year period, or

·
in recognition that there is the potential for several existing contracts will have to be replaced (and associated equipment) that affected
contracts be grandfathered until new and or, replacements can be put in place.
Likes

0

Dislikes

0

Response

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Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer

No

Document Name
Comment
Southern Company feels that 12 months is not enough time to implement the Standard as currently written. Implementation of the proposed
methods of compliance could embark entities on budget and procurement processes to acquire new, upgraded, or revamped hardware,
software, or other physical components at existing sites, and this can be a lengthy process. Southern recommends at least a 24 month or
greater implementation timeframe. Southern agrees with comments provided by other commenters that the complexity of the technology
solutions to be implemented, the number of interconnecting lines to secure, connection point testing, and coordination requirements with
external stakeholders are additional factors supporting a 2 year implementation period.
Likes

0

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0

Response
Ronald Donahey - TECO - Tampa Electric Co. - 3
Answer

No

Document Name
Comment
If additional contracts/agreements are required to address a plan for other entities, Registered Entities may need a longer time to implement
the plan (Requirement R2). Tampa Electric Company recommends an 18 month timeframe for Requirement 2.
Likes
Dislikes

0
0

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Response
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

No

Document Name
Comment
The Standard Review Group has a concern that all Implementation needs may not be met in a timely fashion at the twelve (12) calendar
month time frame. We would recommend that the drafting team extends the deadline to eighteen (18) calendar months. Due to
technological changes needed to secure the data and collaboration between sending and receiving party, we feel more time is needed to
implement the standard.
Likes

0

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0

Response
Wendy Center - U.S. Bureau of Reclamation - 5
Answer

No

Document Name
Comment
Eighteen calendar months after the approval of the control center definition and the CIP-012-1 standard to allow entities time to evaluate the
impact of the changes effected by the new standard and implement an appropriate response.
Likes
Dislikes

0
0

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Response
James Gower - Entergy - NA - Not Applicable - SERC
Answer

No

Document Name
Comment
Cannot support at this time until additional clarity is given to requirements for written communications outside of operational data and for
Operational Planning Analysis data. If corporate systems require protection that could greatly affect implementation timelines. Additionally,
the twelve month window may fall outside of yearly budget planning, compressing project planning timelines.
Likes

0

Dislikes

0

Response
Mark Riley - Associated Electric Cooperative, Inc. - 1
Answer

No

Document Name
Comment
AECI asserts that smaller entities may need to procure equipment and implement technical controls that are not currently in place. The
implementation of the plan(s) detailed in requirement R1 could be impacted by budget cycles, procurement processes, and third party vendor
availability. AECI recommends that the implementation plan be revised to allow 12 months for the development of the plan in requirement
R1 and 24 months for the implementation
Likes

0

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Dislikes

0

Response
Guy Andrews - Georgia System Operations Corporation - 4
Answer

No

Document Name
Comment
•

Additional time would be required to plan, budget, and implement this Standard. Further, only allowing 12 months for
implementation may limit the technology solutions that may be implemented to only those that can be accomplished with minimal
planning and testing. GSOC requests twenty-four months.

Likes

0

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0

Response
Annette Johnston - Berkshire Hathaway Energy - MidAmerican Energy Co. - 3
Answer

No

Document Name
Comment
At least three years is needed in order to coordinate with other entities, including specification, design, budgeting, implementation and
testing.
Likes
Dislikes

0
0

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Response
Terry Harbour - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1
Answer

No

Document Name
Comment
See MidAmerican Energy Company comments.
Likes

0

Dislikes

0

Response
Haley Sousa - Public Utility District No. 1 of Chelan County - 5
Answer

No

Document Name
Comment
The coordination time required to perform a migration to secure communications protocols is expected to take longer than the schedule
presented by the SDT. CHPD recommends at least twenty-four (24) calendar months to implement communication updates and implement
other available protection measures.
Likes

0

Dislikes

0

Response

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Janis Weddle - Public Utility District No. 1 of Chelan County - 6
Answer

No

Document Name
Comment
The coordination time required to perform a migration to secure communications protocols is expected to take longer than the schedule
presented by the SDT. CHPD recommends at least twenty-four (24) calendar months to implement communication updates and implement
other available protection measures.
Likes

0

Dislikes

0

Response
sean erickson - Western Area Power Administration - 1
Answer

No

Document Name
Comment
Likes

0

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0

Response
David Greene - SERC Reliability Corporation - 10, Group Name SERC CIPC
Answer

No

Document Name

3B-2016-02_CIP-012-1_Unofficial_Comment_Form_CIPC.docx

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Comment
Likes

0

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0

Response
Lauren Price - American Transmission Company, LLC - 1
Answer

No

Document Name
Comment
Likes

0

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0

Response
Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Answer

Yes

Document Name
Comment
A region-wide agreement may be difficult to develop and execute in a year. Tri-State believes 18 months would be more appropriate.
Likes
Dislikes

0
0

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Response
Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer

Yes

Document Name
Comment
Xcel Energy believes that the Implementation Plan would allow sufficient time for our operating companies to implement required controls
specified in the language of CIP-012-1. However, Xcel Energy would require coordination from up to 25 other Responsible Entities is
communicates BES data with and cannot speak to their abilities. Any agreements in coordination between entities would need to go through
a legal review process, which could take more than 12 months to formalize and implement. A 24 month implementation period may be more
feasible given the legal review challenges that would inevitably occur.
Likes

0

Dislikes

0

Response
David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment
OPG has some concerns and recommends a graded approach implementation over a longer period of time. The communications links
requiring protections will require inventory; this will be a complex task for the RC.

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The recommended 12 months may be sufficient for the inventory, however we also need to determine the applicable solution and agree on
the solution with another entities.
Likes

0

Dislikes

0

Response
Laura McLeod - NB Power Corporation - 5
Answer

Yes

Document Name
Comment
See 1 above. Note that additional time may be required to reach consensus between entities when establishing security protocols.
Likes

0

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0

Response
Douglas Webb - Douglas Webb On Behalf of: Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., 3, 5, 1, 6; James McBee,
Great Plains Energy - Kansas City Power and Light Co., 3, 5, 1, 6; Jessica Tucker, Great Plains Energy - Kansas City Power and Light Co., 3, 5,
1, 6; Jim Flucke, Great Plains Energy - Kansas City Power and Light Co., 3, 5, 1, 6; - Douglas Webb
Answer

Yes

Document Name
Comment

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The company will review current systems and protections to identify if further action is required to protect the communications links between
control centers as set forth in the approved Standard.
Likes

0

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0

Response
RoLynda Shumpert - SCANA - South Carolina Electric and Gas Co. - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Nicholas Lauriat - Network and Security Technologies - 1
Answer

Yes

Document Name
Comment
Likes
Dislikes

0
0

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Response
Dermot Smyth - Con Ed - Consolidated Edison Co. of New York - 5, Group Name Con Edison
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Philip Huff - Arkansas Electric Cooperative Corporation - 3
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Shannon Fair - Colorado Springs Utilities - 1,3,5,6, Group Name Colorado Springs Utilities
Answer

Yes

Document Name

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Comment
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0

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0

Response
Alice Wright - Arkansas Electric Cooperative Corporation - 4
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Chris Scanlon - Exelon - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response

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Michael Shaw - Lower Colorado River Authority - 1, Group Name LCRA Compliance
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Laurie Williams - PNM Resources - Public Service Company of New Mexico - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Lynn Goldstein - PNM Resources - Public Service Company of New Mexico - 3
Answer

Yes

Document Name
Comment

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Likes

0

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0

Response
Richard Vine - California ISO - 2
Answer
Document Name
Comment
The California ISO supports the comments of the Security Working Group (SWG).
Likes

0

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0

Response
Kristine Ward - Seminole Electric Cooperative, Inc. - 1,2,4,5,6 - FRCC
Answer
Document Name
Comment
SECI would like examples of evidence so we know how to proceed
Likes
Dislikes

0
0

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Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
This question implies there are NERC Glossary terms in the Implementation Plan. There are no NERC Glossary terms in the CIP-012-1
Implementation Plan.
Texas RE does not oppose the enforcement timelines set forth in the proposed Implementation Plan. However, Texas RE respectfully
requests that the SDT provide a specific justification for any proposed implementation timeframes, as well as any revisions to the timeframes
as currently proposed. The goal is to ensure there are no issues with the implementation plan such as not having an initial performance date
where one is needed or not including information for new facilities such as the instance that led to an errata change in the PRC-023-4
implementation plan. These issues cause confusion and ambiguity for both registered entities and Regional Entities upon enforcement of the
standard.
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0

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0

Response
Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 3, Group Name FirstEnergy Corporation
Answer
Document Name
Comment

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FirstEnergy recommends adjusting the Implementation Plan time period to become effective the first day of the first calendar quarter that
is eighteen (18) calendar months after the effective date of the applicable governmental authority’s order approving the standard. The
additional time will be needed to ensure that the implementation of any new technology (e.g. encryption) does not impact reliability of
the BES.
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0

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0

Response

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4. The SDT believes proposed CIP-012-1 provides entities with flexibility to meet the reliability objectives in a cost effective manner. Do
you agree? If you do not agree, or if you agree but have suggestions for improvement to enable more cost effective approaches, please
provide your recommendation and, if appropriate, technical justification.
Janis Weddle - Public Utility District No. 1 of Chelan County - 6
Answer

No

Document Name
Comment
CHPD cannot determine if the objectives may be accomplished in a cost-effective manner until further clarification is provided for
physical or other equally effective protection measures and the request for electronic mail exclusion is added. CHPD also has concerns
with vendor availability, with respect to the system software implementation that will be required for all entities industry-wide. The
comments provided by other entities to develop an industry-wide encryption specification is appealing and CHPD believes that would
provide a better method for achieving the desired intra-entity security.
Likes

0

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0

Response
Haley Sousa - Public Utility District No. 1 of Chelan County - 5
Answer

No

Document Name
Comment
CHPD cannot determine if the objectives may be accomplished in a cost-effective manner until further clarification is provided for
physical or other equally effective protection measures and the request for electronic mail exclusion is added. CHPD also has concerns
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with vendor availability, with respect to the system software implementation that will be required for all entities industry-wide. The
comments provided by other entities to develop an industry-wide encryption specification is appealing and CHPD believes that would
provide a better method for achieving the desired intra-entity security.
Likes

0

Dislikes

0

Response
Laura McLeod - NB Power Corporation - 5
Answer

No

Document Name
Comment
See 2 above.
Likes

0

Dislikes

0

Response
James Gower - Entergy - NA - Not Applicable - SERC
Answer

No

Document Name
Comment

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Cannot agree with the flexibility and cost effectiveness until additional clarity is given to requirements for written communications
outside of operational data and Operational Planning Analysis. If corporate systems require protection that could greatly affect potential
cost.
Likes

0

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0

Response
Ronald Donahey - TECO - Tampa Electric Co. - 3
Answer

No

Document Name
Comment
Until industry is able to determine the extent of information to be protected extends beyond the real-time 15 minute time frame, we are
not able to agree with the statement regarding cost-effective manner.
Likes

0

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0

Response
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer

No

Document Name
Comment

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The cost of implementing the intended protections, as they are understood by Southern, will be prohibitive. See the response to
Question 1 as the primary driver for our disagreement with this question, as well as other supporting information provided in response to
Question 3.
Likes

0

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0

Response
James Anderson - CMS Energy - Consumers Energy Company - 1
Answer

No

Document Name
Comment
More flexibility and less guidance could lead to inconsistency on requirement implementation among different entities.
Likes

0

Dislikes

0

Response
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

No

Document Name
Comment

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If it means the data must be protected throughout the transmission, it would seem that could only be accomplished with encryption. For
cases where the existing equipment is not capable of encryption, replacement will be costly and implementation lengthy.
Likes

0

Dislikes

0

Response
David Greyerbiehl - CMS Energy - Consumers Energy Company - 5
Answer

No

Document Name
Comment
More flexibiity and less guidance could lead to inconsistency on requirement implentation among different entities.
Likes

0

Dislikes

0

Response
Michael Puscas - ISO New England, Inc. - 2
Answer

No

Document Name
Comment
To fully assess the logistics and costs associated with compliance, some guidance or specification of boundaries of communications links
involved would be required for entities to complete assessment of impacts to their operations.

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Likes

0

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0

Response
Warren Cross - ACES Power Marketing - 1,3,4,5 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Standards Collaborators
Answer

No

Document Name
Comment
(1) The standard doesn’t directly address the Inter-Control Center Communications Protocol (ICCP) for exchanging data between control
centers or utilities. Will those ICCP servers and supportive infrastructure need to be upgraded or replaced with data encryption
capabilities to support compliance with this standard?
(2) The standard doesn’t provide any direction as to what is the level of physical and logical protection that is mandatory. We ask the
SDT to develop guidance to clarify this ambiguity and identify how all entities can achieve a minimum level of compliance.
Likes

0

Dislikes

0

Response
Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer

No

Document Name
Comment
ERCOT ISO signs on to the ITC SWG comments:

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In addition to the comments provided in response to question 3, the SWG offers these comments regarding cost effectiveness. Open
Source options to satisfy the requirement to protect communication links and sensitive bulk electric system data communicated between
bulk electric systems Control Centers are limited. Few options generally translated to high vendor leverage, which could lead to high
implementation costs. It is unclear how or whether costs could be shared among participants in the network. Architectural changes to
support these requirements should be spread out over several years. Plus there will be business impacts.
Likes

0

Dislikes

0

Response
Lona Calderon - Salt River Project - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
SRP needs more detail on what would be acceptable as physical security to determine if the standard provides adequate flexibility. Also,
as stated in response to question 3, significant capital may need to be budgeted in order to implement architecture improvements to
address the required computing resources for encrypting and decrypting of data. Additionally, SRP agrees with LPPC’s comment that an
industry-wide initiative for an encryption specification may be a more cost-effective approach than a new standard.
Likes

0

Dislikes

0

Response
Aaron Austin - AEP - 3
Answer

No

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Document Name
Comment
AEP believes that most entities are at the mercy of what Balancing Authorities and Reliability Coordinators will require. This coupled
with the fact that data for Operational Planning and Analysis is included, flexibility may lead to variability and as such makes it only a
presumption that solutions will be cost effective.
Likes

0

Dislikes

0

Response
Dennis Sismaet - Northern California Power Agency - 6
Answer

No

Document Name
Comment
NCPA does not agree that the standard provides entities with the flexibility to implement the standard cost-effectively and offers these
further suggestions. To fully assess the logistics and costs associated with compliance, some guidance or specification of boundaries of
communications links involved would be required for entities to complete assessment of impacts to their operations. In addition,
architectural changes should be spread out over several budget cycles (years).
Likes

0

Dislikes

0

Response
Marty Hostler - Northern California Power Agency - 5

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Answer

No

Document Name
Comment
NCPA does not agree that the standard provides entities with the flexibility to implement the standard cost-effectively and offers these
further suggestions. To fully assess the logistics and costs associated with compliance, some guidance or specification of boundaries of
communications links involved would be required for entities to complete assessment of impacts to their operations. In addition,
architectural changes should be spread out over several budget cycles (years).
Likes

0

Dislikes

0

Response
Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer

No

Document Name
Comment
See APPA Comments.
Likes

0

Dislikes

0

Response
Alice Wright - Arkansas Electric Cooperative Corporation - 4
Answer

No

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Document Name
Comment
See attachment
Likes

0

Dislikes

0

Response
Philip Huff - Arkansas Electric Cooperative Corporation - 3
Answer

No

Document Name
Comment
Please see our comments to Question 1. The additional flexibility in this context has the potential to cause more confusion when selecting
a mechanisms to secure the data.
Likes

0

Dislikes

0

Response
David Rivera - New York Power Authority - 3
Answer

No

Document Name
Comment

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To fully assess the logistics and costs associated with compliance, some guidance or specification of boundaries of
communications links involved would be required for entities to complete assessment of impacts to their operations.
2. Architectural changes should be spread out over several budget cycles (years). Plus there will be business impacts. See comments
to Q3
1.

Likes

0

Dislikes

0

Response
Leonard Kula - Independent Electricity System Operator - 2
Answer

No

Document Name
Comment
In addition to the comments provided in response to question 3, the IESO offers these comments regarding cost effectiveness. Open
Source options to satisfy the requirement to protect communication links and sensitive bulk electric system data communicated between
bulk electric systems Control Centers are limited. Few options generally translated to high vendor leverage, which could lead to high
implementation costs. It is unclear how or whether costs could be shared among participants in the network. Architectural changes to
support these requirements should be spread out over several years. Plus there will be business impacts.
Likes

2

Dislikes

Hydro One Networks, Inc., 1, Farahbakhsh Payam; Hydro One Networks, Inc., 3, Malozewski Paul
0

Response
Joe Tarantino - Joe Tarantino On Behalf of: Arthur Starkovich, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Beth Tincher,
Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Jamie Cutlip, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Kevin Smith,

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Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Susan Oto, Sacramento
Municipal Utility District, 4, 1, 5, 6, 3; - Joe Tarantino
Answer

No

Document Name
Comment
It may be more cost effective if an industry wide initiative is conducted with encryption specifications.
Likes

0

Dislikes

0

Response
Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

No

Document Name
Comment
There will likely be additional costs associated with administrative overhead, hardware, and software, as well as costs associated with
monitoring the performance of the implemented solutions.
Likes

0

Dislikes

0

Response
Brian Millard - Tennessee Valley Authority - 1,3,5,6 - SERC, Group Name Tennessee Valley Authority
Answer

No

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Document Name
Comment
TVA suggests additional guidance is needed to identify examples of acceptable standard security mechanisms for exchanging data
between entities. Without clearer guidance some entities may out of an abundance of caution spend beyond what is necessary to
mitigate this risk, or expend unnecessary effort determining a mutual security mechanism.
Likes

0

Dislikes

0

Response
Lauren Price - American Transmission Company, LLC - 1
Answer

No

Document Name
Comment
Likes

0

Dislikes

0

Response
Terry Harbour - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1
Answer

Yes

Document Name
Comment

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See MidAmerican Energy Company comments.
Likes

0

Dislikes

0

Response
Annette Johnston - Berkshire Hathaway Energy - MidAmerican Energy Co. - 3
Answer

Yes

Document Name
Comment
The three bullets are constructive.
Likes

0

Dislikes

0

Response
Guy Andrews - Georgia System Operations Corporation - 4
Answer

Yes

Document Name
Comment
no comments
Likes

0

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Dislikes

0

Response
David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment
OPG recommends further collaboration to further enhance the cost effectiveness. Solution implementation will require collaboration
when the communication link is between CC belonging to different entities. There is also the issue of agreed solution; for example the
stronger the protection implemented the higher the budgetary costs. If this may not be an issue for the RC it can be an issue for a small
entity required to report to the RC via these communication links.
Likes

0

Dislikes

0

Response
Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment
Utility Services agrees that the standard provides entities with the flexibility to implement the standard cost-effectively and offers these
further suggestions. To fully assess the logistics and costs associated with compliance, some guidance or specification of boundaries of
communications links involved would be required for entities to complete assessment of impacts to their operations. In addition,
architectural changes should be spread out over several budget cycles (years).

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Likes

0

Dislikes

0

Response
Sheranee Nedd - PSEG - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer

Yes

Document Name
Comment
PSEG supports the NPCC comments.
Likes

1

Dislikes

PSEG - PSEG Fossil LLC, 5, Kucey Tim
0

Response
Marc Donaldson - Tacoma Public Utilities (Tacoma, WA) - 3
Answer

Yes

Document Name
Comment
Tacoma Power supports the comments of APPA
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0

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0

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Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Con-Edison and Dominion
Answer

Yes

Document Name
Comment
·
To fully assess the logistics and costs associated with compliance, some guidance or specification of boundaries of communications
links involved would be required for entities to complete assessment of impacts to their operations.
·
Q3

Architectural changes should be spread out over several budget cycles (years), and there will be business impacts. See comments to

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0

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0

Response
Russell Noble - Cowlitz County PUD - 3
Answer

Yes

Document Name
Comment
Cowlitz PUD supports the comments submitted by APPA.
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0

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0

Response

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Thomas Breene - WEC Energy Group, Inc. - 3
Answer

Yes

Document Name
Comment
Thank you for adding the third bullet of R1.
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0

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0

Response
Nicolas Turcotte - Hydro-Qu?bec TransEnergie - 1
Answer

Yes

Document Name
Comment
1.

To fully assess the logistics and costs associated with compliance, some guidance or specification of boundaries of
communications links involved would be required for entities to complete assessment of impacts to their operations.

2.

Architectural changes should be spread out over several budget cycles (years). Plus there will be business impacts. See comments
to Q3.

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0

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0

Response

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Heather Morgan - EDP Renewables North America LLC - 5
Answer

Yes

Document Name
Comment
None at this time
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0

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0

Response
Vivian Vo - APS - Arizona Public Service Co. - 3
Answer

Yes

Document Name
Comment
While the Standard is sufficiently flexible for an individual responsible entity, it leaves a potential chasm between different entities’
interpretation of cost-effective approaches. A top-tier utility’s impression of a cost effective approach may not match a smaller
neighbor’s idea of a cost effective approach. Such a disparity could encumber both large and small entities with disparate concerns that
complicate negotiation and agreement on appropriate solutions.
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0

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0

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Chris Scanlon - Exelon - 1
Answer

Yes

Document Name
Comment
Exelon agrees with the approach used in CIP-012-1, which allows each Registered Entity to analyze risk and use discretion in determining
the best risk mitigation implementation for protecting transmission of applicable data.
Likes

0

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0

Response
Dana Klem - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO NSRF
Answer

Yes

Document Name
Comment
Thank you for adding the third bullet of R1
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0

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0

Response
Dermot Smyth - Con Ed - Consolidated Edison Co. of New York - 5, Group Name Con Edison
Answer

Yes

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Document Name
Comment
To fully assess the logistics and costs associated with compliance, some guidance or specification of boundaries of communications links
involved should be provided so that entities can perform an assessment of impacts to their operations.
Likes

0

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0

Response
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment
Duke Energy agrees that the language provided in R1 appears to provide a Responsible Entity flexibility in how it may implement the
standard, but concern exists in the amount of protection options given. Additional documentation such as Implementation Guidance
including additional suggestions for implementation may give entities more options to consider, while still keeping the flexibility of
determining what is the most suitable method of protection for said entity.
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0

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0

Response
Douglas Webb - Douglas Webb On Behalf of: Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., 3, 5, 1, 6; James
McBee, Great Plains Energy - Kansas City Power and Light Co., 3, 5, 1, 6; Jessica Tucker, Great Plains Energy - Kansas City Power and
Light Co., 3, 5, 1, 6; Jim Flucke, Great Plains Energy - Kansas City Power and Light Co., 3, 5, 1, 6; - Douglas Webb
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Answer

Yes

Document Name
Comment
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0

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0

Response
Laurie Williams - PNM Resources - Public Service Company of New Mexico - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
Wendy Center - U.S. Bureau of Reclamation - 5
Answer

Yes

Document Name
Comment
Likes

0

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Dislikes

0

Response
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Michael Shaw - Lower Colorado River Authority - 1, Group Name LCRA Compliance
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
David Greene - SERC Reliability Corporation - 10, Group Name SERC CIPC
Answer

Yes

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Document Name
Comment
Likes

0

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0

Response
Lan Nguyen - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

Yes

Document Name
Comment
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0

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0

Response
Theresa Rakowsky - Puget Sound Energy, Inc. - 1
Answer

Yes

Document Name
Comment
Likes
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0
0

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Response
sean erickson - Western Area Power Administration - 1
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Shelby Wade - PPL - Louisville Gas and Electric Co. - 3,5,6 - SERC, Group Name Louisville Gas and Electric Company and Kentucky Utilities
Company
Answer

Yes

Document Name
Comment
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0

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0

Response
Jesus Sammy Alcaraz - Imperial Irrigation District - 1
Answer

Yes

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Document Name
Comment
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0

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0

Response
Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer

Yes

Document Name
Comment
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0

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0

Response
Quintin Lee - Eversource Energy - 1, Group Name Eversource Group
Answer

Yes

Document Name
Comment
Likes
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0
0

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Response
Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 3, Group Name FirstEnergy Corporation
Answer

Yes

Document Name
Comment
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0

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0

Response
David Gordon - Massachusetts Municipal Wholesale Electric Company - 5
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
James Poston - Santee Cooper - 3, Group Name Santee Cooper
Answer

Yes

Document Name

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Comment
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0

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0

Response
Shannon Fair - Colorado Springs Utilities - 1,3,5,6, Group Name Colorado Springs Utilities
Answer

Yes

Document Name
Comment
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0

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0

Response
Jennifer Hohenshilt - Talen Energy Marketing, LLC - 6
Answer

Yes

Document Name
Comment
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0

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0

Response

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Donald Lock - Talen Generation, LLC - 5
Answer

Yes

Document Name
Comment
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0

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0

Response
Frank Pace - Central Hudson Gas & Electric Corp. - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
George Brown - Acciona Energy North America - 5
Answer

Yes

Document Name
Comment

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Likes

0

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0

Response
Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer

Yes

Document Name
Comment
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0

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0

Response

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Nicholas Lauriat - Network and Security Technologies - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
RoLynda Shumpert - SCANA - South Carolina Electric and Gas Co. - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Jack Cashin - American Public Power Association - 4
Answer
Document Name
Comment

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APPA agrees that the standard provides entities with the flexibility to implement the standard cost-effectively and offers these further
suggestions. To fully assess the logistics and costs associated with compliance, some guidance or specification of boundaries of
communications links involved would be required for entities to complete assessment of impacts to their operations. In addition,
architectural changes should be spread out over several budget cycles (years).
Likes

0

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0

Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE does not have comments on this questions.
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0

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0

Response
Richard Vine - California ISO - 2
Answer
Document Name
Comment

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The California ISO supports the comments of the Security Working Group (SWG).
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0

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5. If you have additional comments on the proposed CIP-012-1 – Cyber Security -- Communication Networks drafted in response to the
FERC directive that you have not provided in response to the questions above, please provide them here.
Richard Vine - California ISO - 2
Answer
Document Name
Comment
The California ISO supports the comments of the Security Working Group (SWG).
Likes

0

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0

Response
Brian Millard - Tennessee Valley Authority - 1,3,5,6 - SERC, Group Name Tennessee Valley Authority
Answer
Document Name
Comment
TVA notes that the requirement language focuses on the risk of unauthorized disclosure or modification of data. In an operational
environment the integrity and availability legs of the CIA triad are more critical than the confidentiality. TVA suggests consider revising to
focus on ensuring the integrity and availability of the data.
Likes
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0
0

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Response
Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer
Document Name
Comment
Applicability:
Based on the first 2 questions in the proposed RSAW requiring entities to prove that the standard does not apply to them, could the
Applicability section of the standard be modified to indicate that the standard only applies to those specific registered entities (e.g., GOPs
and TOs) that maintain Control Centers AND transmit data between Control Centers?
Additionally, the proposed standard does not provide a sufficient level of detail on how entities should work together to handle security
concerns across a communication network. The standard should clearly identify where the obligations for protecting data in a
communication network start and end per entity.
Technical Rationale:
Does the TO field asset box on page # 5 of Technical Rationale and Justification for CIP-012-1 document include TO Control Centers? If
no, where are TO Control Centers represented ?
Implementation Guidance:
CIP-012 R2 requires the Responsible Entity to implement on or more documented plan(s) to mitigate the risk of the unauthorized
disclosure or modification of applicable data whish being transmitted between Control Centers. Without implementation guidance
describing how to accomplish this risk mitigation either physically protecting the communication links transmitting the data or logically
protecting the data during transmission; or some other equally effective means it is difficult to predict the amount of time that would be
required to implement this requirement part and therefore we cannot assume the 12 months prescribed in the proposed implementation
plan is adequate.

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Likes

0

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0

Response
Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Answer
Document Name
Comment
If the region is responsible for the system, what does the entity have to do for compliance? All entities would have to coordinate with the
region on a solution. The solution may require additional equipment to be installed. A region-wide formal agreement may be difficult to
develop and execute in a year.
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0

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0

Response
Anthony Jablonski - ReliabilityFirst - 10
Answer
Document Name
Comment
Even though ReliabilityFirst votes in the affirmative, ReliabilityFirst provides the following comments for consideration:
1.

Requirement R2

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i.

Requirement R2 of the Standard does not identify a “reasonable” timeline for implementing the plan identified in R1. This
lack of time determinant could lead to prolonged and needless delay in implementing the required protections.

ii.

Requirement R2 uses the phrase “CIP Exceptional Circumstances”. The intent is “to protect confidentiality and integrity of
data transmitted between Control Centers required for reliable operation of the Bulk Electric System (BES).”

ReliabilityFirst questions if using the phrase “CIP Exceptional Circumstances” is appropriate here. The definition of CIP
Exceptional Circumstance is defined as “A situation that involves or threatens to involve one or more of the following, or
similar, conditions that impact safety or BES reliability: a risk of injury or death; a natural disaster; civil unrest; an imminent
or existing hardware, software, or equipment failure; a Cyber Security Incident requiring emergency assistance; a response
by emergency services; the enactment of a mutual assistance agreement; or an impediment of large scale workforce
availability.” ReliabilityFirst believes CIP Exceptional Circumstances criteria are not relative to data transmission.
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George Brown - Acciona Energy North America - 5
Answer
Document Name
Comment
1- Generator Operators within the ERCOT footprint who are not also a Qualified Scheduling Entity (QSE) will not be able to comply with
the standard as written if their Control Center transmits and receives the data as specified in Requirement R1.
Within the ERCOT footprint the sensitive BES data transmitted between the Control Centers of the Balancing Authority (BA), Transmission
Operator (TOP), Reliability Coordinator (RC) and Generator Operator (GOP) is submitted through the QSE (Assume that ERCOT is acting as
the RC, BA and/or TOP for particular GOP and that GOP is not also a QSE). The QSE is not a recognized NERC Functional Entity and as
such would not be subject to adhering to NERC Reliability Standards. Therefore it would not be possible for a GOP to protect the

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sensitive BES data that is transmitted to and from the Control Center of the QSE and ERCOT that ultimately is either being sent or
received by the GOP Control Center. NERC CIP-012-1, as written, does not account for this ERCOT nuance.
2 - Pursuant to NERC CIP-012-1, §4 Applicability, this standard is applicable to the Generator Owner. However, the proposed definition of
Control Center, exempts the Generator Owner as it only speaks to the Generator Operator’s Control Center. NERC CIP-012-1 should not
be applicable to the Generator Owner.
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0

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0

Response
Joe Tarantino - Joe Tarantino On Behalf of: Arthur Starkovich, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Beth Tincher,
Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Jamie Cutlip, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Kevin Smith,
Balancing Authority of Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Susan Oto, Sacramento
Municipal Utility District, 4, 1, 5, 6, 3; - Joe Tarantino
Answer
Document Name
Comment
We seek clarification in the standard verbiage that the intent of this standard applies to inter control center communication. In addition,
it would be beneficial to have guidance on key management and inter utility agreements particularly as it pertains to coordination for
encryption of data between 3rd parties and compliance impacts on reliability.
Likes

0

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0

Response

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Leonard Kula - Independent Electricity System Operator - 2
Answer
Document Name
Comment
The IESO asserts that the proposed standard does not make clear how entities should work together when addressing security concerns
across a communication network link. If both entities work with CIP Standard assumptions on both ends of a communication network,
some support for joint handling of issues could be made clear. However, if only one entity is CIP-compliant for a given link, the current
standard draft does not make clear the extent of protection expected for the data. The Standard should provide more information on the
ownership of obligations for protecting the entire link
It is unclear whether the addition of CIP-012 affects the exemptions of communication networks in any of the applicability sections of
other standards (CIP-002 through CIP-011). The IESO requests clarification that CIP-012 fills in some of the gap created the CIP-002 – CIP011 third party telecommunications exemption (4.2.3.2. Cyber Assets associated with communication networks and data communication
links between discrete Electronic Security Perimeters.)
It has been ten years since the SANDIA report (“Secure ICCP Considerations and Recommendations”), the only detailed report on this
subject which could be considered close having entered mainstream awareness in the industry. Today, as ten years ago, Secure ICCP is
not a viable choice for utilities, if only due to limited community experience and vendor support, not to mention the complexities of key
management. The transition strategies that SANDIA discusses – Layer 3 protection using IPsec and Layer 2 protection with hardware
encryption – remain today’s target solutions.
IPsec is a viable alternative. Over MPLS, IPsec could secure GRE tunnels between CE routers. Challenges with this approach include the
possibility of having to hire a third party to manage certificates and IPsec links, especially for ISOs that do not manage their own MPLS
networks.
The IESO position on security architecture is that business transactions (such as ICCP) should not be tightly coupled with encryption
technologies. Solutions should prefer network overlays versus security extensions to a protocol (such as Secure ICCP or DNP3 SA).
The security architecture should prefer least-latent encryption solutions at the Ethernet or IP layers of the network stack. MACsec
(802.1AE) models the spirit of an optimal solution within a metro area – could it scale wider?

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The IESO’s overall position on Secure ICCP is that it represents too much reliability risk. The IESO is concerned about the lack of open
standards and protocols available to meet the confidentiality and integrity security objectives of CIP-012. Assuming that a solution
involves encryption, the only two open standards and protocols that can meet the CIP-012 security objectives are IPsec and TLS. The
potential for vendor leverage in such a small open solution space is large. Vendor-managed MPLS networks, typical among utilities,
already entrench high annual telecommunication costs in utility budgets. Security vendors continue to benefit from the expense of
establishing layered cyber defenses. Open Source solutions provide a cost and agility refuge from this lopsided value chain without
compromising defense layers. The trend toward managed services makes the cost problem worse for utilities, especially in the context of
insufficiently evaluated risk. Vendor leverage only grows given the practical consideration that all the communicating parties in a WAN of
connected real-time Control Centers would need to adopt a common solution in order to minimize complexity and cost.
Likes

2

Dislikes

Hydro One Networks, Inc., 1, Farahbakhsh Payam; Hydro One Networks, Inc., 3, Malozewski Paul
0

Response
Dermot Smyth - Con Ed - Consolidated Edison Co. of New York - 5, Group Name Con Edison
Answer
Document Name
Comment
CIP-012-1 should be aligned with TOP-003-3. Data security is already required in TOP-003-3 R5. Only data that is stipulated in the TOP003-3 R1 data specification for Operational Planning Analysis, Real-time Assessment, and Real-time monitoring should be in scope for CIP012.
The proposed standard does not make clear how entities should work together when addressing security concerns across a
communication network link. Some guidance regarding joint handling of communication links would be helpful. Where does the
obligation for protecting a link per entity start and end?
Likes

0

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Dislikes

0

Response
Brandon McCormick - Brandon McCormick On Behalf of: Ginny Beigel, City of Vero Beach, 3; Lynne Mila, City of Clewiston, 4; Tom
Reedy, Florida Municipal Power Pool, 6; - Brandon McCormick, Group Name FMPA
Answer
Document Name
Comment
FMPA believes that the proposed standard does not make clear how entities should work together when addressing security concerns
across a communication network link. Some support for joint handling of issues should be made clear.
FMPA believes that an Implementation Guidance document should be developed and include guidance on possible determination of the
security method used being developed at the regional or RC level. This may facilitate a more cost-effective approach. Moreover, the
Implementation Guidance could also address the entities evidence needed when they are following what was determined by the Region,
RC or ISO.
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0

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0

Response
David Rivera - New York Power Authority - 3
Answer
Document Name
Comment

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The proposed standard does not make clear how entities should work together when addressing security concerns across a
communication network link. Some support for joint handling of issues could be made clear. Where does the obligation for protecting a
link per entity start and end?
Note: These comments are equivalent to those submitted by the NPCC/TFIST group, except for changes in the Yes/No answers.
Likes

0

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0

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Dana Klem - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO NSRF
Answer
Document Name
Comment
1. The NSRF questions the use of “Real-time monitoring” as an applicable object within R1. “Real-time” is defined as “present time as
opposed to future time”. Which our industry understands and without the word “monitoring” being defined, may lead to
misinterpretation by responsible entities and CEAs, alike. The word “monitoring” may mean ALL monitoring of an entity’s entire SCADA
system. It should be the “monitoring” of BES data, only, that is required for Operational Planning Analysis and Real-time Assessments.
2. The Applicability section states, “For requirements in this standard where a specific functional entity or subset of functional entities
are the applicable entity or entities, the functional entity or entities are specified explicitly”. This proposed Standard does not specify
any specific entities and we recommend that this is removed.
3. The NSRF has concerns with the proposed definition of Control Center. The largest issue is the last paragraph concerning a Generating
Operator. The use of the word “capability” is ambiguous and will confuse Registered Entities and CEAs, a like. The SDT should consider
the approved Applicability within PER-005-2 part 4.1.5.1, which reads:

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Dispatch personnel at a centrally located dispatch center who receive direction from the Generator Operator’s Reliability Coordinator,
Balancing Authority, Transmission Operator, or Transmission Owner, and may develop specific dispatch instructions for plant operators
under their control. This personnel does not include plant operators located at a generator plant site or personnel at a centrally located
dispatch center who relay dispatch instructions without making any modifications.
This aligns with current and understood wording of PER-005-2.
4. Are the noted “Real-time reliability related- tasks” within the proposed definition, the same “Real-time Reliability-related task
prescribed in PER-005-2? If so, please state this in your consideration of comments document and within your guidance document.
5. The NSRF believes that data associated with Operational Planning Analyses (OPA), Real-time monitoring (RTm), and Real-time
Assessments (RTA) are predicated on other Standards and protection of data is required but all three areas (OPA, RTm, and RTA) are not
subject equally to the Applicable Entities noted in CIP-012-1. Per IRO-010-2, R1, the RC is to document its specifications necessary for
OPA, RTm, and RTA. Per TOP-003-3, R1 the TOP is to document its specifications necessary for OPA, RTm, and RTA. Per TOP-003-3, R2,
the BA is to document its specifications necessary for analysis functions and RTm, only. The SDT, in the Technical Rationale and
Justification document, acknowledges TOP-003 and IRO-010 “provides consistent scoping of identified data” [R1 section: Alignment with
IRO and TOP Standards”]. The SDT should quantify that the data to be protected is the data associated with the Applicable entities with
IRO-010-2 and TOP-003-3. With doing this, the SDT will articulate what the entity is to perform what analysis and what “data” is to be
protected, based on already approved NERC Reliability Standards. By clearly identifying (and linking) the data to be protected from the
data specifications developed under Standards TOP-003 and IRO-010, there is no room for interpretation of what “data” is to be
protected.
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0

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0

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Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name

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Comment
Although the FERC order specifies data between Control Centers, Texas RE notes that there is OPA, RTA, Real-time monitoring data that is
not between control centers. For example, Distribution Providers provide BES sensitive data but would not be subject the standard. Also
there are numerous GOPs that do not have a control center per the definition that provide BES sensitive data which also would not
subject to CIP-012-1. Texas RE is concerned this creates a reliability gap since these scenarios would not be covered under the proposed
draft of CIP-012-1.
Although Texas RE does not oppose a CIP Exceptional Circumstances exception from the implementation requirements set forth in CIP012-1 R2, Texas RE requests that the SDT provide a rationale for why such an exception is appropriate. In particular, it is unclear why
certain CIP exception conditions, such as an imminent hardware failure, should necessarily trigger a relaxation of physical security
protections for communications links transmitted sensitive data in all circumstances.
Likes

0

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0

Response
Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer
Document Name
Comment
See APPA Comments.
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0

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0

Response

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Chris Scanlon - Exelon - 1
Answer
Document Name
Comment
N/A
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0

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0

Response
Marty Hostler - Northern California Power Agency - 5
Answer
Document Name
Comment
Refer to APPA, TAPs, and Utility Services comments.
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0

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0

Response
Dennis Sismaet - Northern California Power Agency - 6
Answer
Document Name

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Comment
Refer to APPA, TAPs, and Utility Services comments.
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0

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Vivian Vo - APS - Arizona Public Service Co. - 3
Answer
Document Name
Comment
AZPS reiterates its comments provided in response to Requirement R1 regarding clear delineation of responsibilities between receiving
and transmitting entities. Because the potential impacts of a receiving entity not appropriately implementing the technology needed for
decryption or use of protected data sent by a transmitting entity lie outside of the proposed Requirement R1 in real-time data and
assessment obligations, placement of the obligations for Requirement R1 on the transmitting is appropriate and reduces the potential for
double jeopardy and/or “waterfall” non-compliance events. Hence, AZPS suggests that it is appropriate to place the obligation for
Requirement R1 on the transmitting entity.
Finally, AZPS reiterates the NERC ORD as a reference guide and resource regarding the scope of this standard and sensitive data
generally. The NERC ORD Agreement has long maintained an accepted, well-established definition for sensitive reliability data. That
definition does not include data utilized in the Operational Planning Horizon and, for the reasons discussed above, AZPS asserts that the
inclusion of Operational Planning Analysis in Requirement R1 extends the scope of BES sensitive data without attendant benefit to
reliability. AZPS recommends the deletion of Operational Planning Analysis from Requirement R1 to allow the Requirement to remain
consistent with well-established, well understood precedent as set forth in the NERC ORD Agreement.
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Quintin Lee - Eversource Energy - 1, Group Name Eversource Group
Answer
Document Name
Comment
Clarification needed – Does 'data used for Operational Planning Analysis, Real-time Assessments, and Real-time monitoring ' include
Generator Unit Commitment Data and/or transmission and generator outages which are posted publicly?
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Aaron Austin - AEP - 3
Answer
Document Name

CIP-012-1 – Cyber Security -Communication Networks Diagram.doc

Comment
AEP suggests these should be added to the diagram as clearly in scope.
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Barry Lawson - National Rural Electric Cooperative Association - 4
Answer
Document Name
Comment
NRECA appreciates the continuing efforts of the SDT.
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Nicolas Turcotte - Hydro-Qu?bec TransEnergie - 1
Answer
Document Name
Comment
The proposed standard does not make clear how entities should work together when addressing security concerns across a
communication network link. Some support for joint handling of issues could be made clear. Where does the obligation for protecting a
link per entity start and end?
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Lona Calderon - Salt River Project - 1,3,5,6 - WECC
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Answer
Document Name
Comment
One challenge associated with CIP-012-1 is industry-wide coordination would be necessary to successfully implement encryption.
In addition to adding latency, encryption adds burden for ongoing maintenance and management for an encryption program. SRP agrees
with LPPC that guidance is needed on key management and inter utility agreements pertaining to coordination for encryption of data and
impacts on real-time operation of the Bulk Electric System.
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Thomas Breene - WEC Energy Group, Inc. - 3
Answer
Document Name
Comment
1. We question the use of “Real-time monitoring” as an applicable object within R1. “Real-time” is defined as “present time as opposed
to future time”. Which our industry understands and without the word “monitoring” being defined, may lead to misinterpretation by
responsible entities and CEAs, alike. The word “monitoring” may mean ALL monitoring of an entity’s entire SCADA system. It should be
the “monitoring” of BES data, only, that is required for Operational Planning Analysis and Real-time Assessments.
2. The Applicability section states, “For requirements in this standard where a specific functional entity or subset of functional entities
are the applicable entity or entities, the functional entity or entities are specified explicitly”. This proposed Standard does not specify
any specific entities and recommend that this be removed.

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3. We have concerns with the proposed definition of Control Center. The largest issue is the last paragraph concerning a Generating
Operator. The use of the word “capability” is ambiguous and will confuse Registered Entities and CEAs, a like. The SDT should consider
the approved Applicability within PER-005-2 part 4.1.5.1, which reads:
Dispatch personnel at a centrally located dispatch center who receive direction from the Generator Operator’s Reliability Coordinator,
Balancing Authority, Transmission Operator, or Transmission Owner, and may develop specific dispatch instructions for plant operators
under their control. These personnel do not include plant operators located at a generator plant site or personnel at a centrally located
dispatch center who relay dispatch instructions without making any modifications.
This aligns with current and understood wording of PER-005-2.
4. Are the noted “Real-time reliability related- tasks” within the proposed definition, the same “Real-time Reliability-related task
prescribed in PER-005-2? If so, please state this in your consideration of comments document and within your guidance document.
5. We believe that data associated with Operational Planning Analyses (OPA), Real-time monitoring (RTm), and Real-time Assessments
(RTA) are predicated on other Standards and protection of data is required but all three areas (OPA, RTm, and RTA) are not subject
equally to the Applicable Entities noted in CIP-012-1. Per IRO-010-2, R1, the RC is to document its specifications necessary for OPA, RTm,
and RTA. Per TOP-003-3, R1 the TOP is to document its specifications necessary for OPA, RTm, and RTA. Per TOP-003-3, R2, the BA is to
document its specifications necessary for analysis functions and RTm, only. The SDT, in the Technical Rationale and Justification
document acknowledges TOP-003 and IRO-010 “provides consistent scoping of identified data” [R1 section: Alignment with IRO and TOP
Standards”]. The SDT should quantify that the data to be protected is the data associated with the Applicable entities with IRO-010-2 and
TOP-003-3. With doing this, the SDT will articulate what the entity is to preform what analysis and what “data” is to be protected, based
on already approved NERC Reliability Standards. By clearly identifying (and linking) the data to be protected from the data specifications
developed under Standards TOP-003 and IRO-010, there is no room for interpretation of what “data” is to be protected.
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Russell Noble - Cowlitz County PUD - 3

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Answer
Document Name
Comment
Although Cowlitz PUD agrees with the intent of the proposed standard, we are concerned the protective measures developed by entities
could have unintended consequences. In particular, there is concern encryption could unacceptably slow data transmission.
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Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Con-Edison and Dominion
Answer
Document Name
Comment
·
The proposed standard does not make clear how entities should work together when addressing security concerns across a
communication network link. Some support for joint handling of issues could be made clear. Where does the obligation for protecting a
link per entity start and end?
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Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer
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Document Name
Comment
ERCOT ISO signs on to the ITC SWG comments:
The ITC SWG asserts that the proposed standard does not make clear how entities should work together when addressing security
concerns across a communication network link. If both entities work with CIP Standard assumptions on both ends of a communication
network, some support for joint handling of issues could be made clear. However, if only one entity is CIP-compliant for a given link, the
current standard draft does not make clear the extent of protection expected for the data. The Standard should provide more
information on the ownership of obligations for protecting the entire link.
It is unclear whether the addition of CIP-012 affects the exemptions of communication networks in any of the applicability sections of
other standards (CIP-002 through CIP-011). The SWG requests clarification that CIP-012 fills in some of the gap created the CIP-002 – CIP011 third party telecommunications exemption (4.2.3.2. Cyber Assets associated with communication networks and data communication
links between discrete Electronic Security Perimeters.)
It has been ten years since the SANDIA report (“Secure ICCP Considerations and Recommendations”), the only detailed report on this
subject which could be considered close having entered mainstream awareness in the industry. Today, as ten years ago, Secure ICCP is
not a viable choice for utilities, if only due to limited community experience and vendor support, not to mention the complexities of key
management. The transition strategies that SANDIA discusses – Layer 3 protection using IPsec and Layer 2 protection with hardware
encryption – remain today’s target solutions.
WECC, and specifically the WECC DEMSWG (Data Exchange and EMS Working Group) has been working with Pacific Northwest National
Laboratory (PNNL) for some time on a new evaluation of Secure ICCP. PNNL recently completed their work and presented the results to
DEMSWG in 2016. The PNNL study functionally succeeded but with enough limitations that PNNL was prompted to conclude that it
would be difficult to make a business case for implementing Secure ICCP when other solutions are available.
IPsec is a viable alternative. Over MPLS, IPsec could secure GRE tunnels between CE routers. Challenges with this approach include the
possibility of having to hire a third party to manage certificates and IPsec links, especially for ISOs that do not manage their own MPLS
networks.

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The ITC SWG position on security architecture is that business transactions (such as ICCP) should not be tightly coupled with encryption
technologies. Solutions should prefer network overlays versus security extensions to a protocol (such as Secure ICCP or DNP3 SA).
The security architecture should prefer least-latent encryption solutions at the Ethernet or IP layers of the network stack. MACsec
(802.1AE) models the spirit of an optimal solution within a metro area – could it scale wider?
The ITC SWG’s overall position on Secure ICCP is that it represents too much reliability risk. The ITC SWG is concerned about the lack of
open standards and protocols available to meet the confidentiality and integrity security objectives of CIP-012. Assuming that a solution
involves encryption, the only two open standards and protocols that can meet the CIP-012 security objectives are IPsec and TLS. The
potential for vendor leverage in such a small open solution space is large. Vendor-managed MPLS networks, typical among utilities,
already entrench high annual telecommunication costs in utility budgets. Security vendors continue to benefit from the expense of
establishing layered cyber defenses. Open Source solutions provide a cost and agility refuge from this lopsided value chain without
compromising defense layers. The trend toward managed services makes the cost problem worse for utilities, especially in the context of
insufficiently evaluated risk. Vendor leverage only grows given the practical consideration that all the communicating parties in a WAN of
connected real-time Control Centers would need to adopt a common solution in order to minimize complexity and cost.
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Marc Donaldson - Tacoma Public Utilities (Tacoma, WA) - 3
Answer
Document Name
Comment
Tacoma Power supports the comments of APPA
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Response
Theresa Rakowsky - Puget Sound Energy, Inc. - 1
Answer
Document Name
Comment
n/a
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Jack Cashin - American Public Power Association - 4
Answer
Document Name
Comment
APPA believes that the proposed standard does not make clear how entities should work together when addressing security concerns
across a communication network link. Some support for joint handling of issues should be made clear.
Public power believes that an Implementation Guidance document should be developed and include guidance on possible determination
of the security method used being developed at the regional or RC level. This may facilitate a more cost-effective approach. Moreover,
the Implementation Guidance could also address the entities evidence needed when they are following what was determined by the
Region, RC or ISO.
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Lan Nguyen - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer
Document Name
Comment
The STD should consider changing the title of the CIP-012-1 requirement to “CIP-012-1-Cyber Security – Control Center Communication
Links” to align with the language in FERC Order No. 822 and the language in Requirement R1. The current use of the term “Networks”
may be misleading because it implies a broader scope of communication.
Additionally, the violation severity levels (VSL) for this requirement is limited to “Severe”. CenterPoint Energy recommends that
Requirement R1 VSL be “Moderate” to “High” due to the fact that Requirement R1 is a documentation requirement.
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David Greene - SERC Reliability Corporation - 10, Group Name SERC CIPC
Answer
Document Name
Comment
NA
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Warren Cross - ACES Power Marketing - 1,3,4,5 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Standards Collaborators
Answer
Document Name
Comment
We thank you for this opportunity to provide these comments.
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Sheranee Nedd - PSEG - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer
Document Name
Comment
PSEG supports the NPCC comments.
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1

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PSEG - PSEG Fossil LLC, 5, Kucey Tim
0

Response

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Michael Puscas - ISO New England, Inc. - 2
Answer
Document Name
Comment
Comments:
•

The proposed standard does not make clear how entities should work together when addressing security concerns across a
communication network link. If both entities work with CIP Standard assumptions on both ends of a communication network,
some support for joint handling of issues could be made clear. However, if only one entity is CIP-compliant for a given link, the
current standard draft does not make clear the extent of protection expected for the data. Where does the obligation for
protecting a link per entity start and end?

•

Does the addition of CIP-012 affect the exemptions of communication networks in any of the applicability sections of other
standards (CIP-002 through CIP-011)?

•

While the CIP standards should emphasize outcomes and allow entities to achieve specific security objectives in many ways,
protections applied to communications should be evaluated with due consideration of the context in which people, processes and
technology are applied to establish a given security protection. Demonstration of risk mitigation should include assessment of not
just technology and process to provide protection, but also the diversity and severity of threats present in a given context (e.g. the
difference between dedicated communication links as opposed to broadly shared communications infrastructure). Particular
technology and process applied in a context with fewer or lower likelihood threats should be preferred over the same technology
and process in a context with more or greater likelihood threats (i.e. greater overall risk). Simply specifying that some (how
much?) risk mitigation should be applied by means that include physical, logical and possibly other means leads to insufficient
conditions for establishing compliance both for the responsible entity and anyone reviewing compliance for that entity. Entities
should consider not only that risk mitigation should take place, but also the thresholds for residual risk that should be considered
acceptable for such communication.

•

It should be noted that in a recent report from the National Infrastructure Advisory Council (NIAC) to the DHS and President of the
United States, the NIAC recommended that separate communication networks be used for critical communications (reference

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https://www.dhs.gov/publication/niac-securing-cyber-assets-addressing-urgent-cyber-threats-critical-infrastructure-final, report
page 3, first recommendation).
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Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name
Comment
BPA suggests adding the verbiage “where technically feasible” to the requirements, in order to implement controls where appropriate,
based on the technology (as discussed in Q1) and risk.
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Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer
Document Name
Comment

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Utility Services believes that the proposed standard does not make clear how entities should work together when addressing security
concerns across a communication network link. Some support for joint handling of issues should be made clear.
Utility Services believes that an Implementation Guidance document should be developed and include guidance on possible
determination of the security method used being developed at the regional or RC level. This may facilitate a more cost-effective
approach. Moreover, the Implementation Guidance could also address the entities evidence needed when they are following what was
determined by the Region, RC or ISO.
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Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Document Name
Comment
If the SDT retains a data-centric approach, we believe the time element is very important and is correctly captured in the requirement
with the phrase “while being transmitted between Control Centers.” We encourage the SDT to retain this language. We note the RSAW
drops the time element and just says “transmitted between”. The time element is very important, as data transmitted between Control
Centers a year ago is not the focus of this standard. This will, ideally, be reflected in the Standard itself, as well as the Technical Rationale
and the RSAW, for clarity.
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David Ramkalawan - Ontario Power Generation Inc. - 5
Answer
Document Name
Comment
OPG understands the focus is on protection of data communication between control centers but would like to clarify that it is not being
required to verify integrity of data from it’s origination points to the point where it’s first aggregated at a control center, as this would be
a substantially more difficult and costly requirement to achieve.
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Ronald Donahey - TECO - Tampa Electric Co. - 3
Answer
Document Name
Comment
Tampa Electric appreciates the efforts of the Standards Drafting Team in developing protections for Communication Networks. We have
concerns that the scope of the standard regarding data protection (based on IRO-010 and TOP-003) extends the requirement to
data/information that is not currently required to be protected at the level of a High Impact BES Cyber System. This approach does not
match the intent and protections of all other NERC CIP standards.
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Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer
Document Name
Comment
The SPP Standards Review Group recommends the drafting team verifies and confirms that the NERC defined terms ‘Operational Planning
Analyses’, ‘Real-time Assessments’, and ‘Real-time’ (mentioned in the Rationale Section in reference to Requirement R1) are defined
and properly aligned with the Rules of Procedure (RoP) documentation. We have a concern that if the terms aren’t properly defined and
aligned in both documents that this could lead to potential interpretation issues for future projects. During the verification process,
should the drafting team discover that there is supporting evidence to SPP’s concerns, we would recommend the drafting team
developing a Standard Authorization Request (SAR) to help ensures that both documents have consistency in the definition of the terms
mentioned.
The SPP Standard Review Group would ask the drafting team to provide clarity on why the RoP is not mentioned in the Implementation
Plan like the NERC Glossary of Terms. From our perspective, the RoP and the definitions, it contains have the same significance that the
Glossary of Terms have in reference to the industry defined terms.
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Wendy Center - U.S. Bureau of Reclamation - 5
Answer
Document Name
Comment

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Reclamation recommends the SDT define the term “Real-time monitoring” in the NERC Glossary of Terms.
The Applicability section states, “For requirements in this standard where a specific functional entity or subset of functional entities are
the applicable entity or entities, the functional entity or entities are specified explicitly.” No Requirements in this proposed Standard
explicitly specify a functional entity or entities; therefore, Reclamation also recommends that this sentence be removed.
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Scott Berry - Scott Berry On Behalf of: Jack Alvey, Indiana Municipal Power Agency, 1, 4; - Scott Berry
Answer
Document Name

2016-02_Unofficial_Comment_Form_Control_Center_Definition_08142017.docx

Comment
IMPA is attaching its comments for Control Center. The feedback/survey sheet is not linked to this vote. Our Control Center survey
response is attached.
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Lauren Price - American Transmission Company, LLC - 1
Answer
Document Name
Comment
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Not Applicable
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Laura McLeod - NB Power Corporation - 5
Answer
Document Name
Comment
No additional comments.
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Haley Sousa - Public Utility District No. 1 of Chelan County - 5
Answer
Document Name
Comment
Implementing industry-wide secure communication is a significant coordination challenge for entities and their associated vendors. The
increase in security also brings increased complexity, maintenance, and failure potential that may negatively impact the reliable

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operation of the BES. As a result, coordination for encryption key management will become an essential activity and CHPD would, similar
to other entity comments, appreciate guidance for these activities.
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Douglas Webb - Douglas Webb On Behalf of: Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., 3, 5, 1, 6; James
McBee, Great Plains Energy - Kansas City Power and Light Co., 3, 5, 1, 6; Jessica Tucker, Great Plains Energy - Kansas City Power and
Light Co., 3, 5, 1, 6; Jim Flucke, Great Plains Energy - Kansas City Power and Light Co., 3, 5, 1, 6; - Douglas Webb
Answer
Document Name
Comment
None.
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Janis Weddle - Public Utility District No. 1 of Chelan County - 6
Answer
Document Name
Comment

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Implementing industry-wide secure communication is a significant coordination challenge for entities and their associated vendors. The
increase in security also brings increased complexity, maintenance, and failure potential that may negatively impact the reliable
operation of the BES. As a result, coordination for encryption key management will become an essential activity and CHPD would, similar
to other entity comments, appreciate guidance for these activities.
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Comments from David Greene, SERC
Questions

1. Requirement R1: The SDT drafted CIP-012-1 Requirement R1 to meet the mandatory requirement for the Responsible Entity to
develop one or more documented plan(s) to mitigate the risk of the unauthorized disclosure or modification of data used for
Operational Planning Analysis, Real-time Assessment, and Real-time monitoring data while being transmitted between Control
Centers. Do you agree with this revision? If not, please provide the basis for your disagreement and an alternate proposal.
Yes
No
Comments:
•

Revise R1. First paragraph, remove “Operational Planning Analysis”

Rationale: Operational Planning Analysis data does not impact the BES within 15 minutes. The systems handling Operational
Planning Analysis data are typically separate from the systems performing real-time BES analysis/control.

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The data involved with Operational Planning is “theoretical”, e.g., requests to take a line out of service or de-rate a generation
unit. If an event occurs in real-time to trip a line or de-rate a unit, information is immediately conveyed via a mechanism other than
Operational Planning data.
Because the Operational Planning data is requesting permission to do something, the request will be validated by other measures –
e.g., permission to take the line out of service/de-rate the unit, followed (later) by switching orders to take the line out of service or
revised bid into the generation market indicating the unit will only provide the de-rated output.
Thus, because it does not directly impact the reliable operation of the BES and cross-checks are already built into the data process,
stringent controls for data transfer is not required.
2. Requirement R1: The SDT seeks comment on the need to scope sensitive BES data as it applies to Operational Planning Analysis,
Real-time Assessment, and Real-time monitoring. Do you agree with scoping CIP-012-1 Requirement R1 in this manner? Please
provide comment in support of your response.
Yes
No
Comments:
•

Revise R1. First paragraph, remove “Operational Planning Analysis”

Rationale: Operational Planning Analysis data does not impact the BES within 15 minutes. The systems handling Operational
Planning Analysis data are typically separate from the systems performing real-time BES analysis/control.
The data involved with Operational Planning is “theoretical”, e.g., requests to take a line out of service or de-rate a generation
unit. If an event occurs in real-time to trip a line or de-rate a unit, information is immediately conveyed via a mechanism other than
Operational Planning data.
Because the Operational Planning data is requesting permission to do something, the request will be validated by other measures –
e.g., permission to take the line out of service/de-rate the unit, followed (later) by switching orders to take the line out of service or
revised bid into the generation market indicating the unit will only provide the de-rated output.
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Thus, because it does not directly impact the reliable operation of the BES and cross-checks are already built into the data process,
stringent controls for data transfer is not required.
3. Implementation Plan: The SDT revised the Implementation Plan such that the standard and NERC Glossary terms are effective the
first day of the first calendar quarter that is twelve (12) calendar months after the effective date of the applicable governmental
authority’s order approving the standard, or as otherwise provided for by the applicable governmental authority. Do you agree with
this proposal? If you agree with the proposed implementation time period, please note the actions you will take that require this
amount of time to complete. If you think an alternate implementation time period is needed – shorter or longer - please propose an
alternate implementation plan and provide a detailed explanation of actions and time needed to meet the implementation deadline.
Yes
No
Comments:
•

Alternate Implementation Period: 2 Year Implementation Plan Period

Rationale: There are a number of factors to consider, and all affect the time required to implement, to include the following:
o Complexity of the technology solutions to be implemented,
o Number of interconnecting lines to secure,
o Troubleshooting/testing at each connection point, and
o Coordination requirements with external stakeholders
4. The SDT believes proposed CIP-012-1 provides entities with flexibility to meet the reliability objectives in a cost effective manner. Do
you agree? If you do not agree, or if you agree but have suggestions for improvement to enable more cost effective approaches,
please provide your recommendation and, if appropriate, technical justification.
Yes
No
Comments:
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5. If you have additional comments on the proposed CIP-012-1 – Cyber Security -- Communication Networks drafted in response to the
FERC directive that you have not provided in response to the questions above, please provide them here.
Comments: NA
Comments from Vivian Vo, APS
Questions

1. Requirement R1: The SDT drafted CIP-012-1 Requirement R1 to meet the mandatory requirement for the Responsible Entity to
develop one or more documented plan(s) to mitigate the risk of the unauthorized disclosure or modification of data used for
Operational Planning Analysis, Real-time Assessment, and Real-time monitoring data while being transmitted between Control
Centers. Do you agree with this revision? If not, please provide the basis for your disagreement and an alternate proposal.
Yes
No
Comments:
AZPS respectfully submits that, as written, the allocation of responsibilities between transmitting and receiving entities is unclear.
Delineation of these responsibilities is essential because a receiving entity has no control over the behavior, implementation, and/or
lack of implementation of third-party entities and cannot prevent third-party entities from transmitting unprotected data. As
written, Requirement R1 could be construed as holding both the transmitting and receiving entity responsible where the
transmitting entity fails to implement its plan. The receiving entity would only be aware/in receipt of the protected or unprotected
data once it is transmitted by the transmitting entity. At which point, the potential for non-compliance has already occurred.
Accordingly, because the data emanates from the transmitting entity, the data protection obligation should emanate from the
transmitting entity.
For this reason, Requirement R1 should not hold receiving entities responsible for receiving data from another entity that failed to
implement its plan. Responsibility for CIP-012-1 R1 should be placed clearly upon the transmitting entity and AZPS requests that the
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SDT modify Requirement R1 to ensure that there is a clear allocation of responsibilities between the transmitting and receiving
entities. AZPS submits for consideration by the SDT a revised Requirement R1 below with language clarifying the allocation of
responsibilities
R1. The Responsible Entity shall develop one or more documented plan(s) to mitigate the risk of the unauthorized disclosure or
modification of data used for Operational Planning Analysis, Real-time Assessments, and Real-time monitoring while being
transmitted when transmitting data from one Control Center to another Control Center between Control Centers. This excludes
oral communications. [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]
The above proposed revisions clarify allocation of responsibilities without compromising on the level of required protection and
while maintaining recognition that meaningful, logically protected communication that can be decrypted for use by the receiving
entity requires bilateral agreement between the transmitting entity and receiving entity.
Comments from Scott Berry, Indiana Municipal Power Agency
Proposed Definition of “Control Center”
Revised Definition:
One or more facilities, including their associated data centers, that monitor and control the Bulk Electric System (BES) and host
operating personnel who perform Real-time reliability-related tasks of: 1) a Reliability Coordinator, 2) a Balancing Authority, 3) a
Transmission Operator for Transmission Facilities at two or more locations, or 4) a Generator Operator for generation Facilities at two or
more locations.
For Reliability Coordinators, Balancing Authorities, and Transmission Operators, the operating personnel above are System Operators.
For Transmission Owners performing the Real-time reliability-related tasks of a Transmission Operator, the operating personnel above
consist of personnel, excluding field switching personnel, who can act independently to operate or direct the operation of the
Transmission Owner’s Bulk Electric System Transmission Facilities in Real-time.

Consideration of Comments | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | October 27, 2017

242

For Generator Operators, the operating personnel above consist of dispatch personnel at a centrally located dispatch center who
receive direction from the Generator Operator’s Reliability Coordinator, Balancing Authority, Transmission Operator, or Transmission
Owner, and have the capability to develop specific dispatch instructions for plant operators under their control. These personnel do not
include plant operators located at a generator plant site or personnel at a centrally located dispatch center who relay dispatch
instructions without making any modifications.
Redline Definition:
One or more facilities, including their associated data centers, that monitor and control the Bulk Electric System (BES) and host hosting
operating personnel that monitor and control the Bulk Electric System (BES) in real-time to who perform the Real-time reliability-related
tasks, including their associated data centers, of: 1) a Reliability Coordinator, 2) a Balancing Authority, 3) a Transmission Operator for
Transmission Facilities at two or more locations, or 4) a Generator Operator for generation Facilities at two or more locations.
For Reliability Coordinators, Balancing Authorities, and Transmission Operators, the operating personnel above are System Operators.
For Transmission Owners performing the Real-time reliability-related tasks of a Transmission Operator, the operating personnel above
consist of personnel, excluding field switching personnel, who can act independently to operate or direct the operation of the
Transmission Owner’s Bulk Electric System Transmission Facilities in Real-time.
For Generator Operators, the operating personnel above consist of dispatch personnel at a centrally located dispatch center who
receive direction from the Generator Operator’s Reliability Coordinator, Balancing Authority, Transmission Operator, or Transmission
Owner, and have the capability to develop specific dispatch instructions for plant operators under their control. These personnel do not
include plant operators located at a generator plant site or personnel at a centrally located dispatch center who relay dispatch
instructions without making any modifications.
Currently Approved Definition:
One or more facilities hosting operating personnel that monitor and control the Bulk Electric System (BES) in real-time to perform the
reliability tasks, including their associated data centers, of: 1) a Reliability Coordinator, 2) a Balancing Authority, 3) a Transmission
Operator for transmission Facilities at two or more locations, or 4) a Generator Operator for generation Facilities at two or more
locations.
End of Report
Consideration of Comments | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | October 27, 2017

243

Standards Announcement

Project 2016-01 Modifications to CIP Standards
CIP-012-1
Draft Reliability Standard Audit Worksheet (RSAW) Posted for Industry
Comment through September 11, 2017
Now Available
The draft RSAW for CIP-012-1 − Cyber Security – Control Center Communication Networks is
posted on the project page for industry comment through 8 p.m. Eastern, Monday, September 11,
2017. Submit feedback regarding the draft RSAW to [email protected].
For more information or assistance, contact Standards Developers, Katherine Street at (404) 446-9702 or
Mat Bunch at (404) 446-9785.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Proposed Definition of:
“Control Center”
Term: “Control Center”
Revised Definition:
One or more facilities, including their associated data centers, that monitor and control the Bulk Electric
System (BES) and host operating personnel who perform Real-time reliability-related tasks of: 1) a
Reliability Coordinator, 2) a Balancing Authority, 3) a Transmission Operator for Transmission Facilities at
two or more locations, or 4) a Generator Operator for generation Facilities at two or more locations.
For Reliability Coordinators, Balancing Authorities, and Transmission Operators, the operating personnel
above are System Operators.
For Transmission Owners performing the Real-time reliability-related tasks of a Transmission Operator,
the operating personnel above consist of personnel, excluding field switching personnel, who can act
independently to operate or direct the operation of the Transmission Owner’s Bulk Electric System
Transmission Facilities in Real-time.
For Generator Operators, the operating personnel above consist of dispatch personnel at a centrally
located dispatch center who receive direction from the Generator Operator’s Reliability Coordinator,
Balancing Authority, Transmission Operator, or Transmission Owner, and have the capability to develop
specific dispatch instructions for plant operators under their control. These personnel do not include plant
operators located at a generator plant site or personnel at a centrally located dispatch center who relay
dispatch instructions without making any modifications.

Redline Definition:
One or more facilities, including their associated data centers, that monitor and control the Bulk Electric
System (BES) and hosthosting operating personnel that monitor and control the Bulk Electric System (BES)
in real-time to who perform the Real-time reliability related- tasks, including their associated data centers,
of: 1) a Reliability Coordinator, 2) a Balancing Authority, 3) a Transmission Operator for
transmissionTransmission Facilities at two or more locations, or 4) a Generator Operator for generation
Facilities at two or more locations.
For Reliability Coordinators, Balancing Authorities, and Transmission Operators, the operating personnel
above are System Operators.
For Transmission Owners performing the Real-time reliability- related tasks of a Transmission Operator,
the operating personnel above consist of personnel, excluding field switching personnel, who can act
independently to operate or direct the operation of the Transmission Owner’s Bulk Electric System
transmissionTransmission Facilities in Real-time.

For Generator Operators, the operating personnel above consist of dispatch personnel at a centrally
located dispatch center who receive direction from the Generator Operator’s Reliability Coordinator,
Balancing Authority, Transmission Operator, or Transmission Owner, and have the capability to develop
specific dispatch instructions for plant operators under their control. These personnel do not include plant
operators located at a generator plant site or personnel at a centrally located dispatch center who relay
dispatch instructions without making any modifications.

Currently Approved Definition:
One or more facilities hosting operating personnel that monitor and control the Bulk Electric System (BES)
in real-time to perform the reliability tasks, including their associated data centers, of: 1) a Reliability
Coordinator, 2) a Balancing Authority, 3) a Transmission Operator for transmission Facilities at two or
more locations, or 4) a Generator Operator for generation Facilities at two or more locations.

Definition of Control Center

2

DRAFT
Cyber Security
Control Center
Communication Plans
Technical Rationale and Justification for
Reliability Standard CIP-012-1
August 11, 2017

NERC | Technical Rationale and Justification for Reliability Standard CIP-012-1| August 2017
I

Table of Contents
Introduction ............................................................................................................................................................... iii
Requirement R1..........................................................................................................................................................4
General Considerations for Requirement R1 ......................................................................................................4
Overview of confidentiality and integrity ...........................................................................................................4
Alignment with IRO and TOP standards ..............................................................................................................4
Control Center Ownership ..................................................................................................................................5
Requirement R2..........................................................................................................................................................6
General Considerations for R2 ............................................................................................................................6
References ..................................................................................................................................................................7

NERC | Technical Rationale and Justification for Reliability Standard CIP-012-1 | Draft: August 2017
ii

Introduction
On January 21, 2016, the Federal Energy Regulatory Commission (FERC or Commission) issued Order No. 822,
approving seven Critical Infrastructure Protection (CIP) Reliability Standards and new or modified terms in the
Glossary of Terms Used in NERC Reliability Standards, and directing modifications to the CIP Reliability Standards.
Among others, the Commission directed the North American Electric Reliability Corporation (NERC) to “develop
modifications to the CIP Reliability Standards to require Responsible Entities1 to implement controls to protect, at
a minimum, communication links and sensitive bulk electric system data communicated between bulk electric
system Control Centers in a manner that is appropriately tailored to address the risks posed to the bulk electric
system by the assets being protected (i.e., high, medium, or low impact).” (Order 822, Paragraph 53)
In response to the directive in Order No. 822, the Project 2016-02 standard drafting team (SDT) drafted Reliability
Standard CIP-012-1 to require Responsible Entities to implement controls to protect sensitive Bulk Electric System
(BES) data and communications links between BES Control Centers. Due to the sensitivity of the data being
communicated between Control Centers, as defined in the Glossary of Terms Used in NERC Reliability Standards,
the standard applies to all impact levels (i.e., high, medium, or low impact).
The SDT drafted requirements to provide Responsible Entities the latitude to protect the communication links,
the data, or both, to satisfy the security objective consistent with the capabilities of the Responsible Entity’s
operational environment. Requirement R1 requires Responsible Entities to document one or more plans that
protect Operational Planning Analysis, Real-time Assessment, and Real-time monitoring data while being
transmitted between Control Centers. The plan(s) must address how the Responsible Entity will mitigate the risk
of unauthorized disclosure or modification of the applicable data. Requirement R2 covers implementation of the
plan developed according to Requirement R1.
This technical rationale and justification document explains the technical rationale for the proposed Reliability
Standard to provide stakeholders and the ERO Enterprise an understanding of the technology and technical
requirements in the Reliability Standard. It also contains information on the SDT’s intent in crafting the
requirements.

1

As used in the CIP Standards, a Responsible Entity refers to the registered entities subject to the CIP Standards.
NERC | Technical Rationale and Justification for Reliability Standard CIP-012-1 | Draft: August 2017
iii

Requirement R1
R1.

The Responsible Entity shall develop one or more documented plan(s) to mitigate the risk of the
unauthorized disclosure or modification of data used for Operational Planning Analysis, Real-time
Assessments, and Real-time monitoring while being transmitted between Control Centers. This
excludes oral communications. [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]
1.1

Risk mitigation shall be accomplished by one or more of the following actions:


Physically protecting the communication links transmitting the data;



Logically protecting the data during transmission; or



Using an equally effective method to mitigate the risk of unauthorized
disclosure or modification of the data.

Note: If the Responsible Entity does not have a Control Center or it does not transmit the type of data
specified in Requirement R1 of CIP-012-1 between two Control Centers, the requirements in CIP-012-1
would not apply to that entity.
General Considerations for Requirement R1
The focus of Requirement R1 is on developing a plan to protect information that is critical to the real-time
operations of the Bulk Electric System while in transit between applicable Control Centers.
Overview of confidentiality and integrity
The SDT drafted CIP-012-1 to address confidentiality and integrity of data used for Operational Planning
Analysis, Real-time Assessment, and Real-time monitoring. This is accomplished by drafting the
requirement to mitigate the risk from unauthorized disclosure (confidentiality) or modification (integrity).
For this Standard, the SDT relied on the definitions of confidentiality and integrity as defined by National
Institute of Standards and Technology (NIST).
 Confidentiality is defined as, “Preserving authorized restrictions on information access and
disclosure, including means for protecting personal privacy and proprietary information.”2
 Integrity is defined as, “Guarding against improper information modification or destruction, and
includes ensuring information non-repudiation and authenticity.”3
The SDT asserts that the availability of this data is already required by the performance obligation of the
Operating and Planning Reliability Standards. The SDT drafted CIP-012 to address the data while being
transmitted. The SDT maintains that this data resides within BES Cyber Systems, and while at rest is
protected by CIP-003 through CIP-011.
Alignment with IRO and TOP standards
The SDT noted the FERC reference to additional Reliability Standards and the responsibilities to protect
the data in accordance with those standards (TOP-003 and IRO-010). The SDT used these references to
drive the identification of sensitive BES data and chose to base the CIP-012 requirements on the data
specifications in these standards. This approach provides consistent scoping of identified data, and does
not require each entity to devise its own list or inventory of this data. Many entities are required to provide
this data under agreements executed with their RC, BA or TOP, often without benefit of knowing how
those entities use that data.

2
3

NIST Special Publication 800-53A, Revision 4, page B-3
NIST Special Publication 800-53A, Revision 4, page B-6
NERC | Technical Rationale and Justification for Reliability Standard CIP-012-1 | Draft: August 2017
4

Requirement R1

Control Center Ownership
The requirements are very clear about implementing protection for data being used for Operational
Planning Analysis, Real-time Assessment, and Real-time monitoring while being transmitted between
Control Centers owned by a single Responsible Entity. They also cover the applicable data transmitted
between Control Centers owned by two or more separate Responsible Entities. Applying protection
among a Responsible Entity’s owned Control Centers is solely at its discretion. Applying protection
between Control Centers owned by more than one Responsible Entity requires additional diligence. The
requirements do not explicitly require formal agreements between Responsible Entities partnering for
transmission of applicable data. It is strongly recommended, however, that these partnering entities
develop agreements, or use existing ones, to define responsibilities to ensure adequate protection is
applied. For example as noted in FERC Order No. 822 Paragraph 59, “if several registered entities have
joint responsibility for a cryptographic key management system used between their respective Control
Centers, they should have the prerogative to come to a consensus on which organization administers that
particular key management system." It is important to note that each Responsible Entity may be held
individually accountable for the protection applied to the communications methods of data used for
Operational Planning Analysis, Real-time Assessment, and Real-time that is transmitted between Control
Centers.
As an example, the reference model below depicts some of the data transmissions between Control
Centers that a Responsible Entity should consider to be in-scope. The example does not include all possible
scenarios. The green solid lines are in-scope communications. The red dashed lines are out-of-scope
communications.

NERC | Technical Rationale and Justification for Reliability Standard CIP-012-1 | Draft: August 2017
5

Requirement R2

Requirement R2
R2.

The Responsible Entity shall implement the plan(s) specified in Requirement R1, except under CIP
Exceptional Circumstances.

General Considerations for R2
The security objective of Requirement R1 can be achieved through a variety of methods or combinations of
methods, such as site to site encryption, application layer encryption, physical protection, etc. The protection
must prevent unauthorized disclosure or modification of applicable data on the applicable communication
methods between Control Centers identified in 1.1. The Responsible Entity has the discretion to choose and apply
protection that meets the security objective.

NERC | Technical Rationale and Justification for Reliability Standard CIP-012-1 | Draft: August 2017
6

References

References
Here are several references to assist entities in developing plan(s) for protection of communication links:
 NIST Special Publication 800-53A, Revision 4: Security and Privacy Controls for Federal Information
Systems and Organizations
 NIST Special Publication 800-82: Guide to Industrial Control Systems (ICS) Security
 NIST Special Publication 800-175B: Guideline for Using Cryptographic Standards in the Federal
Government: Cryptographic Mechanisms
 NIST Special Publication 800-47: Security Guide for Interconnecting Information Technology Systems

NERC | Technical Rationale and Justification for Reliability Standard CIP-012-1 | Draft: August 2017
7

Unofficial Comment Form

Project 2016-02 Modifications to CIP Standards
Glossary of Terms Used in NERC Reliability Standards – Control Center
Do not use this form for submitting comments. Use the electronic form to submit comments on Project
2016-02 Modifications to NERC Glossary of Terms Used in Reliability Standards – Control Center. The
electronic form must be submitted by 8 p.m. Tuesday, September 12, 2017.
m. Eastern, Thursday, August 20, 2015
Additional information is available on the project page. If you have questions, contact Standards
Developers, Katherine Street (404-446-69702) or Mat Bunch (404-446-9785).
Background Information

The Standard Authorization Request (SAR) of the Project 2016-02 Modifications to CIP Standards Standard
Drafting Team (Project 2016-02 SDT) contains multiple issue areas that impact Control Centers. These
areas include clarifying applicability for Transmission Owners performing
the functional obligations of Transmission Operators, and protecting communication links and sensitive
Bulk Electric System (BES) data communicated between BES Control Centers. In the course of its research
of these issues, the SDT has identified potential improvements to the Control Center definition.
In the development of the current Control Center definition, the Project 2008-06 Cyber Security Order 706
Version 5 CIP Standards Standard Drafting Team (Project 2008-06 SDT) received comments 1 stating that
the scope of the Control Center definition did not adequately identify control centers. The comment
noted that the defined term Control Center could inaccurately apply to some generator plant control
rooms. In response, the Project 2008-06 SDT created criteria in CIP-002 that would categorize BES Cyber
Systems associated with these facilities as low impact. Since there were no low impact requirements
specific to Control Centers, this temporarily mitigated the issue. The Project 2016-02 SDT is now
proposing the development of new requirements that apply to low impact Control Centers in its draft CIP012 standard. The 2016-02 SDT is seeking feedback on whether modifications to the Control Center
definition are also necessary.
The SDT is seeking comments on potential modifications to the Control Center definition to provide
further clarification of the term “operating personnel.” The proposed Control Center definition identifies
facilities that have two characteristics. The first characteristic is that the facility hosts operating personnel
that perform Real-time reliability-related tasks to operate the Bulk Electric System. The second
characteristic is that the facility contains BES Cyber Systems that are used by operating personnel to
See Consideration of Comments Cyber Security Order 706 Version 5 CIP Standards Comment Form D Definitions and Implementation Plans, Page 21, available
at: http://www.nerc.com/pa/Stand/Project20086CyberSecurityOrder706Version5CIPStanda/Consideration_of_Comments_D_2008-06_091012.pdf. “One
commenter suggested that Control Center as it applies to the function of a Generation Operator has a threshold of generation located at two or more
locations, and that this single qualifier could unintentionally sweep in the control centers for multi-location generation of very small capacity. The commenter
suggested that a capacity qualifier be added to this definition. The SDT does not think that the threshold should be in the definition, but has amended the
criterion for generation Control Centers in the Medium Impact category that addresses this comment.”
1

monitor and control the BES. The SDT asserts that operating personnel in this definition should align with
personnel already identified in Reliability Standard PER-005-2. The purpose of Reliability Standard PER005-2 is, “[t]o ensure that personnel performing or supporting Real-time operations on the Bulk Electric
System are trained using a systematic approach.” The proposed revisions to the Control Center definition
clarify that operating personnel perform Real-time reliability-related tasks and lists functional entities that
perform those tasks as identified in the applicability section of PER-005-2.

Unofficial Comment Form | Control Center Definition
Project 2016-02 Modifications to CIP Standards | August-September 2017

2

Proposed Definition of “Control Center”
Revised Definition:
One or more facilities, including their associated data centers, that monitor and control the Bulk Electric
System (BES) and host operating personnel who perform Real-time reliability-related tasks of: 1) a
Reliability Coordinator, 2) a Balancing Authority, 3) a Transmission Operator for Transmission Facilities at
two or more locations, or 4) a Generator Operator for generation Facilities at two or more locations.
For Reliability Coordinators, Balancing Authorities, and Transmission Operators, the operating personnel
above are System Operators.
For Transmission Owners performing the Real-time reliability-related tasks of a Transmission Operator,
the operating personnel above consist of personnel, excluding field switching personnel, who can act
independently to operate or direct the operation of the Transmission Owner’s Bulk Electric System
Transmission Facilities in Real-time.
For Generator Operators, the operating personnel above consist of dispatch personnel at a centrally
located dispatch center who receive direction from the Generator Operator’s Reliability Coordinator,
Balancing Authority, Transmission Operator, or Transmission Owner, and have the capability to develop
specific dispatch instructions for plant operators under their control. These personnel do not include plant
operators located at a generator plant site or personnel at a centrally located dispatch center who relay
dispatch instructions without making any modifications.
Redline Definition:
One or more facilities, including their associated data centers, that monitor and control the Bulk Electric
System (BES) and host hosting operating personnel that monitor and control the Bulk Electric System
(BES) in real-time to who perform the Real-time reliability-related tasks, including their associated data
centers, of: 1) a Reliability Coordinator, 2) a Balancing Authority, 3) a Transmission Operator for
Transmission Facilities at two or more locations, or 4) a Generator Operator for generation Facilities at
two or more locations.
For Reliability Coordinators, Balancing Authorities, and Transmission Operators, the operating personnel
above are System Operators.
For Transmission Owners performing the Real-time reliability-related tasks of a Transmission Operator,
the operating personnel above consist of personnel, excluding field switching personnel, who can act
independently to operate or direct the operation of the Transmission Owner’s Bulk Electric System
Transmission Facilities in Real-time.
For Generator Operators, the operating personnel above consist of dispatch personnel at a centrally
located dispatch center who receive direction from the Generator Operator’s Reliability Coordinator,
Balancing Authority, Transmission Operator, or Transmission Owner, and have the capability to develop
specific dispatch instructions for plant operators under their control. These personnel do not include plant

Unofficial Comment Form | Control Center Definition
Project 2016-02 Modifications to CIP Standards | August-September 2017

3

operators located at a generator plant site or personnel at a centrally located dispatch center who relay
dispatch instructions without making any modifications.
Currently Approved Definition:
One or more facilities hosting operating personnel that monitor and control the Bulk Electric System (BES)
in real-time to perform the reliability tasks, including their associated data centers, of: 1) a Reliability
Coordinator, 2) a Balancing Authority, 3) a Transmission Operator for transmission Facilities at two or
more locations, or 4) a Generator Operator for generation Facilities at two or more locations.

Unofficial Comment Form | Control Center Definition
Project 2016-02 Modifications to CIP Standards | August-September 2017

4

Questions

The SDT seeks comment on the potential modifications to the definition of Control Center to clarify the
scope of included facilities by identifying the operating personnel at Control Centers performing various
registered functions.
1. Control Center definition: The SDT seeks comment on potential modifications to the definition of
Control Center to clarify the scope of included facilities by identifying the operating personnel at
Control Centers under various functional registrations based on the applicability language in PER005-2. Do you agree with the alignment to PER-005-2? If not, please provide rationale or propose
an alternative definition.
Yes
No
Comments:
2. Control Center definition: Do the potential modifications to the Control Center definition change
the scope or intent of any current or pending Reliability Standard(s) (examples include Reliability
Standards: COM-001-3; TOP-001-4; and IRO-002-5)? If yes, provide details of the affected
Reliability Standard(s), requirements, and any anticipated impact.
Yes
No
Comments:
3. Control Center definition: The SDT contends that there will be no change in BES Cyber System
categorization by clarifying the definition of Control Center. This assertion is based on SDT review
of the CIP-002-5.1a criteria and its understanding of BES Cyber System categorization through
experience implementing CIP-002-5.1a. Do you agree with this assertion? If not, please provide
rationale and practical examples of where a change in categorization will occur as a result of this
modification.
Yes
No
Comments:

Unofficial Comment Form | Control Center Definition
Project 2016-02 Modifications to CIP Standards | August-September 2017

5

4. Control Center definition: Do you agree with the potential definition of Control Center? If not,
please provide rationale or propose an alternative definition.
Yes
No
Comments:
5. Implementation Plan: The SDT proposes to make the new Control Center definition effective upon
applicable governmental authority’s order approving the definition, or as otherwise provided for
by the applicable governmental authority. Do you agree with this proposal not to provide
additional implementation time following approval? If you agree with the potential
implementation time period, please note the actions you will take that require this amount of time
to complete. If you think an alternate implementation time period is needed, please propose an
alternate implementation period and provide a detailed explanation of actions and time needed to
meet your proposed implementation deadline.
Yes
No
Comments:
6. If you have additional comments on the proposed definition of Control Center that you have not

provided in response to the questions above, please provide them here.
Comments:

Unofficial Comment Form | Control Center Definition
Project 2016-02 Modifications to CIP Standards | August-September 2017

6

Unofficial Comment Form

Project 2016-02 Modifications to CIP Standards
Cyber Security – Control Center Communication Networks
Technical Rationale and Justification for CIP-012-1
Do not use this form for submitting comments. Use the electronic form to submit comments on Project
2016-02 Modifications to CIP Standards CIP-012-1 – Cyber Security – Control Center Communication
Networks. The electronic form must be submitted by 8 p.m. Eastern, Tuesday, September 12, 2017.
m. Eastern, Thursday, August 20, 2015
Additional information is available on the project page. If you have questions, contact Standards
Developers, Katherine Street (404-446-69702) or Mat Bunch (404-446-9785).
Background Information

On January 21, 2016, the Commission issued Order No. 822, approving seven CIP Reliability Standards and
new or modified definitions, and directing modifications to the CIP Reliability Standards. Among others,
the Commission directed NERC to “develop modifications to the CIP Reliability Standards to require
responsible entities to implement controls to protect, at a minimum, communication links and sensitive
bulk electric system data communicated between bulk electric system Control Centers in a manner that is
appropriately tailored to address the risks posed to the bulk electric system by the assets being protected
(i.e., high, medium, or low impact).” (Order 822, Paragraph 53)
The Project 2016-02 Standard Drafting Team (SDT) drafted Reliability Standard CIP-012-1 to require
Responsible Entities to implement controls to protect sensitive Bulk Electric System (BES) data and
communications links between BES Control Centers. Due to the sensitivity of the data being
communicated between the Control Centers, as defined in the NERC Glossary of Terms Used in Reliability
Standards, the standard applies to all impact levels (i.e., high, medium, or low impact).
To complement the requirements drafted in CIP-012-1, the SDT drafted and seeks comment on the
Technical Rationale and Justification for CIP-012-1.

Questions

1. The SDT developed draft Technical Rationale and Justification for CIP-012-1 to provide
stakeholders and the ERO Enterprise an understanding of the technology and technical
requirements in the Reliability Standard. Do you agree that the draft Technical Rationale and
Justification for CIP-012-1 clearly explains the technical reasoning for the proposed standard? If
you do not agree, or if you agree but have comments or suggestions for the draft document,
please provide your recommendation and explanation.
Yes
No
Comments:

Unofficial Comment Form | Technical Rationale and Justification
Project 2016-02 Modifications to CIP Standards | August - September 2017

2

Standards Announcement

Project 2016-02 Modifications to CIP Standards
Informal Comment Period Open through September 12, 2017
Now Available

Two simultaneous 30-day informal comment periods on the proposed definition of “Control Center”
and the Technical Rationale and Justification for CIP-012-1 – Cyber Security – Control Center
Communication Networks are open through 8 p.m. Eastern, Tuesday, September 12, 2017.
Commenting

Use the electronic forms to submit comments. If you experience any difficulties using the electronic
forms, contact Wendy Muller. Unofficial Word versions of the comment forms are posted on the project
page.
If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential error
messages, or system lock-out, contact NERC IT support directly at https://support.nerc.net/ (Monday –
Friday, 8 a.m. - 5 p.m. Eastern).
•

Passwords expire every 6 months and must be reset.

•

The SBS is not supported for use on mobile devices.

•

Please be mindful of ballot and comment period closing dates. We ask to allow at least 48 hours for
NERC support staff to assist with inquiries. Therefore, it is recommended that users try logging into
their SBS accounts prior to the last day of a comment/ballot period.

Next Steps

The drafting team will review all responses received during the informal comment periods and
determine the next steps of the project.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, Katherine Street (via email) or at (404) 446-9702 or Mat Bunch (via
email) or at (404) 446-9785.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Comment Report
Project Name:

2016-02 Modifications to CIP Standards | Proposed Definition of Control Center

Comment Period Start Date:

8/14/2017

Comment Period End Date:

9/12/2017

Associated Ballots:

There were 51 sets of responses, including comments from approximately 181 different people from approximately 119 companies
representing 10 of the Industry Segments as shown in the table on the following pages.

Questions
1. Control Center definition: The SDT seeks comment on potential modifications to the definition of Control Center to clarify the scope of
included facilities by identifying the operating personnel at Control Centers under various functional registrations based on the applicability
language in PER-005-2. Do you agree with the alignment to PER-005-2? If not, please provide rationale or propose an alternative definition.

2. Control Center definition: Do the potential modifications to the Control Center definition change the scope or intent of any current or
pending Reliability Standard(s) (examples include Reliability Standards: COM-001-3; TOP-001-4; and IRO-002-5)? If yes, provide details of the
affected Reliability Standard(s), requirements, and any anticipated impact.

3. Control Center definition: The SDT contends that there will be no change in BES Cyber System categorization by clarifying the definition
of Control Center. This assertion is based on SDT review of the CIP-002-5.1a criteria and its understanding of BES Cyber System
categorization through experience implementing CIP-002-5.1a. Do you agree with this assertion? If not, please provide rationale and practical
examples of where a change in categorization will occur as a result of this modification.

4. Control Center definition: Do you agree with the potential definition of Control Center? If not, please provide rationale or propose an
alternative definition.

5. Implementation Plan: The SDT proposes to make the new Control Center definition effective upon applicable governmental authority’s
order approving the definition, or as otherwise provided for by the applicable governmental authority. Do you agree with this proposal not to
provide additional implementation time following approval? If you agree with the potential implementation time period, please note the
actions you will take that require this amount of time to complete. If you think an alternate implementation time period is needed, please
propose an alternate implementation period and provide a detailed explanation of actions and time needed to meet your proposed
implementation deadline.

6. If you have additional comments on the proposed definition of Control Center that you have not provided in response to the questions
above, please provide them here.

Organization
Name

Name

Southern
Brandon
Company Cain
Southern
Company
Services, Inc.

Florida
Municipal
Power
Agency

Segment(s)

1,3,5,6

Brandon
3,4,5
McCormick

Region

FRCC,MRO,NPCC,SERC,SPP
RE,Texas RE,WECC

FRCC

Group Name

Southern
Company

FMPA

Group Member
Name

Group Member
Organization

Group
Group
Member
Member
Segment(s) Region

Katherine Prewitt

Southern
Company Southern
Company
Services, Inc.

1

SERC

R. Scott Moore

Southern
3
Company Alabama Power
Company

SERC

William D. Shultz

Southern
Company Southern
Company
Generation

5

SERC

Jennifer Sykes

Southern
6
Company Southern
Company
Generation and
Energy
Marketing

SERC

Tim Beyrle

City of New
4
Smyrna Beach
Utilities
Commission

FRCC

Jim Howard

Lakeland
Electric

5

FRCC

Lynne Mila

City of
Clewiston

4

FRCC

Javier Cisneros

Fort Pierce
Utilities
Authority

3

FRCC

Randy Hahn

Ocala Utility
Services

3

FRCC

Don Cuevas

Beaches
Energy
Services

1

FRCC

Jeffrey Partington

Keys Energy
Services

4

FRCC

Tom Reedy

Florida
Municipal
Power Pool

6

FRCC

Tennessee
Valley
Authority

Brian
Millard

Duke Energy Colby
Bellville

MRO

1,3,5,6

1,3,5,6

Dana Klem 1,2,3,4,5,6

SERC

FRCC,RF,SERC

MRO

Tennessee
Valley
Authority

Duke Energy

MRO NSRF

Steven Lancaster

Beaches
Energy
Services

3

FRCC

Mike Blough

Kissimmee
5
Utility Authority

FRCC

Chris Adkins

City of
Leesburg

3

FRCC

Ginny Beigel

City of Vero
Beach

3

FRCC

Scott, Howell D.

Tennessee
1
Valley Authority

SERC

Grant, Ian S.

Tennessee
3
Valley Authority

SERC

Thomas, M. Lee

Tennessee
5
Valley Authority

SERC

Parsons, Marjorie S.

Tennessee
6
Valley Authority

SERC

Doug Hils

Duke Energy

1

RF

Lee Schuster

Duke Energy

3

FRCC

Dale Goodwine

Duke Energy

5

SERC

Greg Cecil

Duke Energy

6

RF

Joseph DePoorter

Madison Gas & 3,4,5,6
Electric

MRO

Larry Heckert

Alliant Energy

4

MRO

Amy Casucelli

Xcel Energy

1,3,5,6

MRO

Michael Brytowski

Great River
Energy

1,3,5,6

MRO

Jodi Jensen

Western Area
Power
Administration

1,6

MRO

Kayleigh Wilkerson

Lincoln Electric 1,3,5,6
System

MRO

Mahmood Safi

Omaha Public
Power District

1,3,5,6

MRO

Brad Parret

Minnesota
Powert

1,5

MRO

Terry Harbour

MidAmerican
Energy
Company

1,3

MRO

Tom Breene

Wisconsin
Public Service
Corporation

3,5,6

MRO

Midcontinent David
ISO, Inc.
Francis

SERC
Reliability
Corporation
Seattle City
Light

David
Greene

Ginette
Lacasse

2,3

10

1,3,4,5,6

FRCC,MRO,NPCC,RF,SERC,SPP SRC + SWG
RE,Texas RE,WECC

SERC

WECC

SERC CIPC

Seattle City
Light Ballot
Body

Jeremy Voll

Basin Electric
Power
Cooperative

1

MRO

Kevin Lyons

Central Iowa
Power
Cooperative

1

MRO

Mike Morrow

Midcontinent
ISO

2

MRO

Gregory Campoli

New York
Independent
System
Operator

2

NPCC

Mark Holman

PJM
2
Interconnection,
L.L.C.

RF

Charles Yeung

Southwest
Power Pool,
Inc. (RTO)

2

SPP RE

Terry BIlke

Midcontinent
ISO, Inc.

2

RF

Elizabeth Axson

Electric
Reliability
Council of
Texas, Inc.

2,3

Texas RE

Ben Li

IESO

1

MRO

Drew Bonser

SWG

NA - Not
Applicable

NA - Not
Applicable

Darrem Lamb

CAISO

2

WECC

Matt Goldberg

ISONE

2

NPCC

Bill Peterson

SERC RRO

10

SERC

Mike Hagee

SERC RRO

10

SERC

SERC CIPC

Various

1,2,5,9

SERC

Pawel Krupa

Seattle City
Light

1

WECC

Hao Li

Seattle City
Light

4

WECC

Bud (Charles)
Freeman

Seattle City
Light

6

WECC

Mike Haynes

Seattle City
Light

5

WECC

Michael Watkins

Seattle City
Light

1,4

WECC

Santee
Cooper

Entergy

James
Poston

Julie Hall

1,3,5,6

6

Santee
Cooper

Faz Kasraie

Seattle City
Light

5

WECC

John Clark

Seattle City
Light

6

WECC

Tuan Tran

Seattle City
Light

3

WECC

Laurrie Hammack

Seattle City
Light

3

WECC

Rene' Free

Santee Cooper 1

SERC

Rodger Blakely

Santee Cooper 1

SERC

Chris Jimenez

Santee Cooper 1

SERC

Troy Lee

Santee Cooper 1

SERC

Tom Abrams

Santee Cooper 1

SERC

Jennifer Richards

Santee Cooper 1

SERC

Stony Martin

Santee Cooper 1

SERC

Glenn Stephens

Santee Cooper 1

SERC

Tom Perry

Santee Cooper 1

SERC

Entergy Entergy
Services, Inc.

1

SERC

Entergy Entergy
Services, Inc.

5

SERC

Associated
Electric
Cooperative,
Inc.

1

SERC

Brian Ackermann

Associated
Electric
Cooperative,
Inc.

6

SERC

Brad Haralson

Associated
Electric
Cooperative,
Inc.

5

SERC

Todd Bennett

Associated
Electric
Cooperative,
Inc.

3

SERC

Michael Bax

Central Electric 1
Power

SERC

Entergy/NERC Oliver Burke
Compliance
Jaclyn Massey

Associated
Mark Riley 1,3,5,6
Electric
Cooperative,
Inc.

AECI &
Mark Riley
Member G&Ts

Cooperative
(Missouri)

BC Hydro
and Power
Authority

Patricia
1,3,5
Robertson

BC Hydro

Adam Weber

Central Electric 3
Power
Cooperative
(Missouri)

SERC

Ted Hilmes

KAMO Electric
Cooperative

3

SERC

Walter Kenyon

KAMO Electric
Cooperative

1

SERC

Stephen Pogue

M and A
Electric Power
Cooperative

3

SERC

William Price

M and A
Electric Power
Cooperative

1

SERC

Mark Ramsey

N.W. Electric
Power
Cooperative,
Inc.

1

SERC

Kevin White

Northeast
Missouri
Electric Power
Cooperative

1

SERC

Skyler Wiegmann

Northeast
Missouri
Electric Power
Cooperative

3

SERC

John Stickley

NW Electric
Power
Cooperative,
Inc.

3

SERC

Jeff Neas

Sho-Me Power 3
Electric
Cooperative

SERC

Peter Dawson

Sho-Me Power 1
Electric
Cooperative

SERC

Patricia Robertson

BC Hydro and 1
Power Authority

WECC

Venkataramakrishnan BC Hydro and 2
Vinnakota
Power Authority

WECC

Pat G. Harrington

BC Hydro and 3
Power Authority

WECC

Clement Ma

BC Hydro and 5
Power Authority

WECC

Northeast
Ruida Shu 1,2,3,4,5,6,7,8,9,10 NPCC
Power
Coordinating
Council

RSC no ConEdison and
Dominion

Guy V. Zito

Northeast
Power
Coordinating
Council

10

NPCC

Randy MacDonald

New Brunswick 2
Power

NPCC

Wayne Sipperly

New York
4
Power Authority

NPCC

Glen Smith

Entergy
Services

4

NPCC

Brian Robinson

Utility Services 5

NPCC

Bruce Metruck

New York
6
Power Authority

NPCC

Alan Adamson

New York State 7
Reliability
Council

NPCC

Edward Bedder

Orange &
Rockland
Utilities

1

NPCC

David Burke

Orange &
Rockland
Utilities

3

NPCC

Michele Tondalo

UI

1

NPCC

Laura Mcleod

NB Power

1

NPCC

Michael Schiavone

National Grid

1

NPCC

Michael Jones

National Grid

3

NPCC

David Ramkalawan

Ontario Power 5
Generation Inc.

NPCC

Quintin Lee

Eversource
Energy

1

NPCC

Kathleen Goodman

ISO-NE

2

NPCC

Greg Campoli

NYISO

2

NPCC

Silvia Mitchell

NextEra Energy 6
- Florida Power
and Light Co.

NPCC

Paul Malozewski

Hydro One
Networks, Inc.

3

NPCC

Sylvain Clermont

Hydro Quebec

1

NPCC

Helen Lainis

IESO

2

NPCC

Chantal Mazza

Hydro Quebec

2

NPCC

Dominion Dominion
Resources,
Inc.

Southwest
Power Pool,
Inc. (RTO)

PPL Louisville
Gas and
Electric Co.

PSEG

Sean
Bodkin

Shannon
Mickens

Shelby
Wade

Sheranee
Nedd

3,5,6

2

3,5,6

1,3,5,6

Dominion

SPP RE

RF,SERC

NPCC,RF

Connie Lowe

Dominion 3
Dominion
Resources, Inc.

NA - Not
Applicable

Lou Oberski

Dominion 5
Dominion
Resources, Inc.

NA - Not
Applicable

Larry Nash

Dominion Dominion
Virginia Power

NA - Not
Applicable

1

SPP
Shannon Mickens
Southwest
2
Standards
Power Pool Inc.
Review Group Deborah McEndaffer Midwest
NA - Not
Energy, Inc.
Applicable

SPP RE

Don Schmit

Nebraska
Public Power
District

5

SPP RE

Louis Guidry

Cleco
Corporation

1,3,5,6

SPP RE

Robert Hirchak

Cleco
Corporation

6

SPP RE

Marty Paulk

Cleco
Corporation

1,3,5,6

SPP RE

Michelle Corley

Cleco
Corporation

3

SPP RE

Robert Gray

Board of Public NA - Not
Utilities
Applicable

SPP RE

Ron Spicer

EDP
Renewables

NA - Not
Applicable

SPP RE

Steven Keller

Southwest
Power Pool

2

SPP RE

Laura Cox

Westar Energy 5

SPP RE

PPL - Louisville 3
Gas and
Electric Co.

SERC

PPL - Louisville 5
Gas and
Electric Co.

SERC

Linn Oelker

PPL - Louisville 6
Gas and
Electric Co.

SERC

Tim Kucey

PSEG - PSEG
Fossil LLC

5

RF

Karla Jara

PSEG Energy 6
Resources and
Trade LLC

RF

Louisville Gas Charles Freibert
and Electric
Company and
Kentucky
Dan Wilson
Utilities
Company

PSEG REs

SPP RE

Jeffrey Mueller

PSEG - Public 3
Service Electric
and Gas Co

RF

Joseph Smith

PSEG - Public 1
Service Electric
and Gas Co

RF

1. Control Center definition: The SDT seeks comment on potential modifications to the definition of Control Center to clarify the scope of
included facilities by identifying the operating personnel at Control Centers under various functional registrations based on the applicability
language in PER-005-2. Do you agree with the alignment to PER-005-2? If not, please provide rationale or propose an alternative definition.
Matthew Beilfuss - WEC Energy Group, Inc. - 3,4,5,6 - MRO,RF
Answer

No

Document Name
Comment
PER-005-2 does not use Real-time reliability related tasks when referring to a GOP. The proposed definition implies these tasks exist. A
GOP does not perform a Real-time reliability related task. Therefore, no GOP would have a Control Center that meets the definition.
Likes

0

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0

Response

George Brown - Acciona Energy North America - 5
Answer

No

Document Name
Comment
The Control Center definition should only define a physical location where Real-time Bulk Electrical System (BES) reliability related operating tasks are
performed. It also can include, but cautiously, information on personnel that a Control Center houses, however it should not attempt to define these
personnel, either System Operators or operating personnel.
If it is the intention of the SDT to define operating personnel of a Transmission Owner (TO) performing the Real-time reliability-related operating tasks of
a Transmission Operator and Generator Operator (GOP) operating personnel, then a separate term needs to be defined to identify these individuals.
Data centers usually do not host personnel and the proposed Control Center definition needs to be modified to account for this.
In the context of the proposed definition of Control Center, in the Generator Operator section, the term “direction” is used, “Operating Instruction” is
already a defined term and should be used instead of “direction”. Also, the term “capability” is used and is inaccurate, many individuals have the
capability to modify a generator, i.e. IT/OT personnel, however, few have the authority; “capability should be modified to “authority”.
The following is suggested:
Control Center: One or more facilities that monitor and control the Bulk Electric System and host System Operators and Operating Personnel who
perform the Real-time operating reliability related-tasks, and includes the associated data centers, of:
1) a Reliability Coordinator,
2) a Balancing Authority,

3) a Transmission Operator for Transmission Facilities at two or more locations,
4) a Transmission Owner performing the delegated Real-time reliability-related operating tasks of a Transmission Operator at two or more locations or
5) a Generator Operator for generation Facilities at two or more locations.
Operating Personnel: An individual at a Control Center of a Transmission Owner or Generator Operator who perform the Real-time operating reliability
related-tasks as follows:
1. For a Transmission Owner these individuals would be personnel who can act independently and have the authority to operate or direct the
operation of the Transmission Owner’s Bulk Electric System Transmission Facilities in Real-time.
2. For a Generator Operator these individuals would be personnel who receive Operating Instructions from the Generator Operator’s Reliability
Coordinator, Balancing Authority, Transmission Operator, or Transmission Owner, and have the authority to develop and direct specific dispatch
instructions for plant operators under their control. These personnel do not include plant operators located at a generator plant site or personnel
at a centrally located dispatch center who relay Operating Instructions and dispatch instructions without making any modifications.
Likes

0

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0

Response

Dana Klem - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO NSRF
Answer

No

Document Name
Comment
The NSRF has great concerns with the wording of “...having the capability…” This wording is ambiguous since everyone has the “capability” to do
develop dispatch instructions even if they are not authorized to do so. Recommend that “having the capability” be changed to “have the authority”. This
clearly states that the GOP can make said adjustments.
For Generator Operators, the operating personnel above consist of dispatch personnel at a centrally located dispatch center who receive direction from
the Generator Operator’s Reliability Coordinator, Balancing Authority, Transmission Operator, or Transmission Owner, and have the capability to
develop specific dispatch instructions for plant operators under their control. This personnel does not include plant operators located at a generator
plant site or personnel at a centrally located dispatch center who relay dispatch instructions without making any modifications.
Likes

0

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0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment

No

Texas RE appreciates the Standard Drafting Team’s (SDT) effort to clarify the Control Center definition within the overall project scope set forth in the
governing Standards Authorization Request (SAR). While Texas RE does not necessarily object to these clarifications and understands that the SDT’s
intent is not to substantively alter the Control Center definition as it is currently applied to registered entities, Texas RE is concerned that the overall
project may increase confusion around the application of the Control Center definition across the industry.

As an initial matter, Texas RE notes that there are a number of areas in which there is a clear need for further clarity regarding the use of the term
“Control Center.” Texas RE has identified several standards using descriptors such as primary and backup, several standards where the term control
center is not capitalized, and standards with confusion regarding the TO acting as TOP. Texas RE respectfully requests that the SDT consider these
additional applications and scenarios as part of a more comprehensive review of the “Control Center” definition.

For example, EOP-008 refers to functionality at an entity’s “primary control center” and “backup control center.” In either case, the term “control center”
is not capitalized and therefore does not appear to refer to the defined term. In contrast, IRO-002-5 R2 and R3, in parallel with TOP-001-4 R23 and 24
reference “primary Control Centers.” Here, the reference is to the defined “Control Center” term, but there is no defined understanding in the standards
of what constitutes a primary Control Center. It seems that the new definition removes the need for descriptors such as “primary” and “back up”.

The following standards use the term control center, which is not capitalized: BAL-005-0.2b, BAL-006-2, CIP-014-2, COM-001-3, EOP-008-1, EOP-0082, and FAC-003-4.

Texas RE is supportive of a more narrowly focused effort to correct the obvious NERC Registration issues with the “TO acting as a TOP” issue. Most
importantly, TOP is a certified function and the fact that TOs are acting as a TOP without the requisite certification is a potential reliability gap that
should be taken more seriously by the ERO. The following Standards/Requirements do not adequately cover TOs acting as a TOP:
•
•

•

COM-001-3 R12: Field personnel are called out for having communication capability but are excluded in the definition of Control Center. This
will create confusion and inconsistent implementation of applicability.
IRO-002-5 R2: TOs acting as TOPs may be considered only if the RC “deems necessary”. It is apparent that the establishment of compliance
obligations that are contingent on non-definitive terms such as “deems necessary” with no specificity or criteria do not occur in a consistent
manner. This leads to poor communication and reliability gaps due to compliance concerns (or compliance postures where a company, in this
example an RC, does not want to place a compliance burden on a company due to the political nature of such an act).
CIP-014-2 in its entirety missed a “TO acting as a TOP” partially because that condition is not fully recognized and the term “Control Center” is
lower cased. Does the SDT believe there is a difference between the proposed definition and the lower-case term? If so, what is it?

Beyond these scoping issues, Texas RE is concerned that the proposed clarifications may inadvertently introduce more ambiguity into the Standard in
two areas. First, the “Control Center” definition continues to hinge on the concept of a facility that “hosts” operating personnel. Texas RE has
consistently interpreted this language to describe the intended functionality of a facility and not to imply any current staffing levels or operations. That is
to say, the fact that a Control Center operating as an entity’s backup facility is not currently hosting operating personnel does not mean that facility is not
a “Control Center” under the definition. Although the proposed revisions do not appear intended to alter this common sense interpretation, the
introduction of the conjunctive “and” could possibly lead entities to conclude that until a Control Center is actually hosting operating personnel, the mere
fact that it can monitor and control the Bulk Electric System does not render that facility a “Control Center” as defined. Texas RE requests that the SDT
clarify that facilities that have the purpose of hosting operating personnel are subject to the Control Center definition, regardless of whether they have
done so or not.

Second, Texas RE notes that the proposed “Control Center” definition could be interpreted to limit Generator Operator “Control Centers” subject to the
definition. In particular, the SDT has elected to fold training requirements for Generator Operator personnel into the Control Center definition,
presumably to provide clarity around the scope of facilities that “host operating personnel.” Texas RE noticed the proposed description of GOP
operating personnel utilizes the description of dispatch personnel in PER-005-2. Texas RE requests the SDT evaluate the tasks for each dispatch
personnel and operating personnel to determine whether or not this is appropriate. Folding this training requirement directly into the Control Center
definition may result in further confusion. In Texas RE’s experience, numerous GOPs have the capability to develop dispatch instructions and may take
various actions in response to requests from their Reliability Coordinators or Transmission Operators, including altering their voltage profile or Real
power output. It is not clear in what circumstances these constitute “developing dispatch instructions.” A better approach may be to clarify that
operating personnel include persons that “are capable of developing dispatch instructions” to reduce ambiguity about the scope of the Control Center
definition as it pertains to the internal operating procedures of specific Generator Operators.
Likes

0

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0

Response

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer

No

Document Name
Comment
SCL supports the APPA submitted comments.
Likes

0

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0

Response

Sean Bodkin - Dominion - Dominion Resources, Inc. - 3,5,6, Group Name Dominion
Answer

No

Document Name
Comment
Dominion generally agrees with the alignment to PER-005-2. Dominion has concerns that one of the requirements of PER-005-2 is to “create a list of
BES company-specific Real-time reliability-related tasks based on a defined and documented methodology”. This clause results in the proposed
definition being dependent on the execution of PER-005-2, and can vary from one Entity to another. Also, the phrase “Real-time reliability-related tasks”
is not specifically used in reference to Generator Operators in PER-005-2.
Dominion suggests the following changes to the proposed defintion to resolve this issue:
One or more facilities, including their associated data centers, of an RC, BA, TOP, TO, GOP that monitor and control the Bulk Electric System (BES)
and host operating personnel who perform Real-time reliability-related tasks of: 1) a Reliability Coordinator, 2) a Balancing Authority, 3) a Transmission
Operator for Transmission Facilities at two or more locations, or 4) a Generator Operator for generation Facilities at two or more locations.have the

capability to operate or direct in Real-time the operation of Bulk Electric System Transmission Facilities at two or more locations or have the capability to
direct specific dispatch instructions to plant operators or plant control systems for generation Facilities at two or more locations.
Likes

0

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0

Response

Thomas Breene - WEC Energy Group, Inc. - 3,4,5,6
Answer

No

Document Name
Comment
We have great concerns with the wording of “...having the capability…”. This wording is ambiguous since everyone has the “capability” to do develop
dispatch instructions even if they are not authorized to do so. Recommend that “having the capability” be changed to “have the authority”. This clearly
states that the GOP can make said adjustments.
For Generator Operators, the operating personnel above consist of dispatch personnel at a centrally located dispatch center who receive direction from
the Generator Operator’s Reliability Coordinator, Balancing Authority, Transmission Operator, or Transmission Owner, and have the capability to
develop specific dispatch instructions for plant operators under their control. These personnel do not include plant operators located at a generator plant
site or personnel at a centrally located dispatch center who relay dispatch instructions without making any modifications.
While including personnel roles executed helps to clarify what is and what isn’t a Control Center, the definitions of those roles should be standalone in
the NERC Glossary of Terms. I.E. “Operating Personnel” should have its own definition and be used as a defined term in the Control Center definition.
Likes

0

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0

Response

sean erickson - Western Area Power Administration - 1,6
Answer

No

Document Name
Comment
Per the NSRF: the proposed definition of Control Center. The largest issue is the last paragraph concerning a Generating Operator. The use of the
word “capability” is ambiguous and will confuse Registered Entities and CEAs, a like. The SDT should consider the approved Applicability within PER005-2 part 4.1.5.1, which reads:

Dispatch personnel at a centrally located dispatch center who receive direction from the Generator Operator’s Reliability Coordinator, Balancing
Authority, Transmission Operator, or Transmission Owner, and may develop specific dispatch instructions for plant operators under their control. These

personnel do not include plant operators located at a generator plant site or personnel at a centrally located dispatch center who relay dispatch
instructions without making any modifications.

This aligns with current and understood wording of PER-005-2.
Are the noted “Real-time reliability related- tasks” within the proposed definition, the same “Real-time Reliability-related task prescribed in PER-0052? If so, please state this in your consideration of comments document and within your guidance document.

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0

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0

Response

David Francis - Midcontinent ISO, Inc. - 2,3 - FRCC,MRO,WECC,Texas RE,NPCC,SERC,SPP RE,RF, Group Name SRC + SWG
Answer

No

Document Name
Comment
The SRC & ITC SWG agrees with the creation of a new standard, rather than expanding CIP-003, CIP-005 and/or CIP-006 requirements to provide new
controls over physical communication links. Specifically, the SRC & ITC SWG commends the SDT for recognizing that not all utilities own or control
their own physical communications links.

The SRC & ITC SWG offers the following comments and recommendations.
R1. For data used for Operational Planning Analysis, Real-time Assessments, and Real-time monitoring, as documented by a Reliability Coordinator,
Transmission Operator, or Balancing Authority, the Responsible Entity shall develop one or more documented plan(s) to mitigate the risk of the
unauthorized disclosure or modification of the data while it is being transmitted between Control Centers. This excludes oral communications,
regardless of transport means.
The note to R1 concerning the existence of a Control Center or specified data should be a dealt with in Section 4 – Applicability part of the
Standard. This would eliminate the need for this to be discussed as part of the RSAW.
Recommend that it be clarified whether this is a standalone Standard similar to CIP-014 or if it is intended to define the scope of applicable systems to
be protected under CIP-003 thru CIP-011.
In order to evaluate the extent and kind of obligation involved, the definition of between control centers needs to be clearer with regard to the
communication link. The Standard should address the proper demarcation points for obligation to show implementation and compliance. To clearly
define the obligation of Responsible Entities, the required plan should include identification of the demarcation points. Information is also needed on the
explicit agreements required on each end of the physical communication link to arrange and identify such demarcation. Where there is disagreement on
how protections are to be applied between two or more Responsible Entities, what is the arbitration process to resolve these disagreements?

How is the situation handled where a Responsible Entity (e.g., an RC) is receiving information from a third-party provider that is aggregating and
submitting data on behalf of one or more Responsible Entities (e.g., a TOP)? What is the identification of the demarcation points? In reading the
standard, it does not appear that the connection to the third-party provider is in scope since they are not a Responsible Entity or even registered with
NERC. The same situation may be present for entities that use an outsourced data center provider. The question is also relevant for the data that is
provided to regulatory agencies that are not bound by CIP Standards.
Likes

0

Dislikes

0

Response

Sheranee Nedd - PSEG - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer

No

Document Name
Comment
The definition is not consistent with PER-005-2 part 4.1.5.1. It uses the statement “have the capability to develop specific dispatch instructions… “,
where PER-005-2 part 4.1.5.1. states “may develop specific dispatch instructions…”. There is significant difference between having the capability to do
something, versus doing it. The language (i.e.”may” versus “having the capability to”) concerning Generation and Control Centers (a “centrally located
dispatch center” in PER-005-2 part 4.1.5.1) has already been settled by industry, through development and approval of PER-005-2. The proposed
definition should stay consistent with PER-005-2 part 4.1.5.1.

Likes

3

Dislikes

PSEG - PSEG Fossil LLC, 5, Kucey Tim; PSEG - Public Service Electric and Gas Co., 1, Smith Joseph;
PSEG - Public Service Electric and Gas Co., 3, Mueller Jeffrey
0

Response

Jamie Monette - Allete - Minnesota Power, Inc. - 1
Answer

No

Document Name
Comment
MP agrees with the NATF's concerns with the wording of “...having the capability…”. This wording is ambiguous since everyone has the “capability” to
do develop dispatch instructions even if they are not authorized to do so. Recommend that “having the capability” be changed to “have the
authority”. This clearly states that the GOP can make said adjustments.

For Generator Operators, the operating personnel above consist of dispatch personnel at a centrally located dispatch center who receive direction from
the Generator Operator’s Reliability Coordinator, Balancing Authority, Transmission Operator, or Transmission Owner, and have the capability to

develop specific dispatch instructions for plant operators under their control. These personnel do not include plant operators located at a generator plant
site or personnel at a centrally located dispatch center who relay dispatch instructions without making any modifications.
Likes

0

Dislikes

0

Response

Barry Lawson - National Rural Electric Cooperative Association - 3,4
Answer

No

Document Name
Comment
NRECA requests additional clarity to be added to the draft revised Control Center definition. Specifically, in the third paragraph, second and third line,
of the definition, replace “who can act independently to operate …..” with “who have independent authority to operate ……” This better and more clearly
addresses the capability and independent authority issues.
Likes

0

Dislikes

0

Response

David Jendras - Ameren - Ameren Services - 1,3,6
Answer

No

Document Name
Comment
While the inclusion of the language to link the duties to PER-005 make sense, PER-005 also includes Transmission Owner employees who operate
local control centers. If the logic holds that PER-005 attributes are linked to these requirements, we believe the omission of Transmission Owners is
inappropriate. Even though Transmission Owners are discussed in the third paragraph, they should be listed as number 5) to ensure TO personnel
hosted at such a facility would qualify that facility.

Likes

0

Dislikes

0

Response

Brandon Cain - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - FRCC,MRO,WECC,Texas RE,NPCC,SERC,SPP RE, Group
Name Southern Company

Answer

No

Document Name
Comment
Southern respectfully disagrees with the approach used by the SDT to re-define the term Control Center based solely on the functions of a facility’s
operating personnel (as defined in PER-005-2) rather than based on the reliability impact of the equipment and data associated with the facility. We
believe the proposed definition may result in the unintended consequence of omitting dispatch centers with control over significant amounts of
generation because operating personnel in the facility do not modify dispatch instructions they receive from their RC, BA or TOP.
Likes

0

Dislikes

0

Response

Annette Johnston - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1,3
Answer

No

Document Name
Comment
We agree with the concept of aligning with PER-005-2 with two exceptions. First, the existing language for PER-005-2 has become somewhat outdated
because it does not comprehend renewable energy such as wind and solar. A wind farm is not a plant site, but personnel for a wind farm should be
excluded too. Second, the language for generator operator was changed from “may develop” to “have the capability to develop.” Consider, “and
develops”.

Likes

0

Dislikes

0

Response

Brandon McCormick - Florida Municipal Power Agency - 3,4,5 - FRCC, Group Name FMPA
Answer

Yes

Document Name
Comment
Agree with the alignment but not the specific wording
Request clarification of the Transmission Owner’s “field switching personnel,” for this definition. This term was not explained well in PER-005.

Request clarification of the Generation Operator – “have the capability to develop specific dispatch instructions.” Should this be the capability to issue
instead of capability to develop? The word “capability” is too generic. Suggest that the phrase be changed to “authority to develop or modify the
specific dispatch instructions” since authority is related to the generator operating personnel and not the control systems.
Suggest that the phrase “These personnel do not include plant operators located at a generator plant site or personnel at a centrally located dispatch
center who relay dispatch instructions without making any modifications.” Be modified to “These personnel do not include plant operators located at a
generator plant site or personnel at a centrally located dispatch center who relay verbal dispatch instructions without making any modifications.” This
would clarify that this is related to the generator operating personnel and not the
Likes

0

Dislikes

0

Response

Marty Hostler - Northern California Power Agency - 5,6
Answer

Yes

Document Name
Comment
1. NCPA agrees with the SDT decision to align the operating personnel in the Project 2016-02 Standard with personnel identified in Reliability
Standard PER-005-2. While the alignment is appropriate, NCPA believes that some wording needs to be clarified.

2. The term, “field switching personnel,” used in the draft control center definition, is not well explained in PER-005-2. Therefore, this term needs to
be clarified for use in the CIP Standards.

3. NCPA requests clarification regarding the language associated with Generation Operator (GOP) – that the GOP, “have the capability to develop
specific dispatch instructions.” Specifically, is “capability” referring to the capability to issue instructions, or is it the capability to develop
instructions? The use of the word “capability” here is too generic and NCPA suggests changing it to, “authority to develop or modify the specific
dispatch instructions,” since authority is related to the generator operating personnel and not the control systems.

4. NCPA requests that the phrase, “These personnel do not include plant operators located at a generator plant site, or personnel at a centrally
located dispatch center who relay dispatch instructions without making any modifications,” be changed to “These personnel do not include plant
operators located at a generator plant site, or personnel at a centrally located dispatch center who relay verbal dispatch instructions without
making any modifications.” This would clarify that this is related to the generator operating personnel and not the control systems.
Likes

0

Dislikes

0

Response

Vivian Vo - APS - Arizona Public Service Co. - 1,3,5,6

Answer

Yes

Document Name
Comment
To better ensure alignment with PER-005-2, AZPS suggests clarifying the term Real-time reliability-related tasks as utilized in the definition. An
amendment to the first sentence of the definition similar to the following is recommended:
One or more facilities, including their associated data centers, that monitor and control the Bulk Electric System (BES) and host operating personnel
who perform Real-time reliability-related tasks identified by the Responsible Entity as part of its systematic approach to training under the
Operations Personnel Training standard, of: 1) a Reliability Coordinator, 2) a Balancing Authority, 3) a Transmission Operator for Transmission
Facilities at two or more locations, or 4) a Generator Operator for generation Facilities at two or more locations.
An additional possible revision could be:
One or more facilities, including their associated data centers, that monitor and control the Bulk Electric System (BES) and host operating personnel
who perform Real-time reliability-related tasks of: 1) a Reliability Coordinator, 2) a Balancing Authority, 3) a Transmission Operator for Transmission
Facilities at two or more locations, or 4) a Generator Operator for generation Facilities at two or more locations. Real-time reliability-related tasks are
those tasks identified by the Responsible Entity as part of its systematic approach to training under the Operations Personnel Training standard.
Alternatively, AZPS suggests that the SDT define “Real-time reliability-related tasks” in the glossary of terms.
Likes

0

Dislikes

0

Response

Aaron Austin - AEP - 3,5
Answer

Yes

Document Name
Comment
AEP suggests the SDT should consider making the argument that the Real-time Reliability Tasks that the personnel and Cyber Assets can
perform comprise the rationale for making the change.

Likes

0

Dislikes

0

Response

Russell Noble - Cowlitz County PUD - 3,5
Answer
Document Name

Yes

Comment
Public Utility District No. 1 of Cowlitz County (District) supports APPA comments.
In addition, the District believes the intent is to exclude personnel having no system wide awareness and who manually operate BES Facilities on
location, while including personnel who perform autonomous (“independent”) centralized reliability monitoring and remote control (via “Real-time”
SCADA) for two or more discrete Transmission Facilities located at unique addresses on behalf of a registered TOP. While the District agrees with
basing operating personnel qualification on the applicability language in PER-005-2 in part, it is not clear if a Control Center is inclusive of a room
containing dispatch personnel who can only perform local reliability operations which do not impact or concern the covering Transmission Operator’s
greater system. The District seeks greater clarification. In particular, it is not clear if autonomous directives related to public safety or quality of service,
such as clearing transmission segments compromised by weather or traffic accidents, are inclusive within the undefined term “reliability.”
Further, it is not clear what operational aspect of a Transmission Owner’s central control room raises it to the status of a Control Center; note that PER005-2 avoids associating a TO with a Control Center and performing “tasks of a Transmission Operator.” In the case of the “TO Control Center,” it
appears the intent is to limit inclusion to those control rooms containing personnel tasked by the registered TOP to autonomously address events
meeting a list of PER-005-2 “BES company-specific Real-time reliability-related” tasks that align with the covering TOP’s Reliable Operation obligation.
This will depend on how the TO defines a “BES company-specific Real-time reliability-related task,” and assuming Enforcement agrees. If Enforcement
finds the entity in violation of PER-005-2 Requirement R2, this may create double jeopardy with the CIP standards. However, the intent could
conversely imply the inclusion of control rooms that have the ability (sans authority) to independently impact the covering TOP’s obligation to Reliably
Operate the BES. The District requests the SDT clarify the intent, and submits a possible solution in question 4.
Likes

0

Dislikes

0

Response

Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment
ERCOT ISO supports the comments of the ITC SWG.
Likes

0

Dislikes

0

Response

Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer
Document Name
Comment

Yes

Request clarification of the Transmission Owner’s “field switching personnel,” for this definition. This term was not explained well in PER-005.

Request clarification of the Generation Operator – “have the capability to develop specific dispatch instructions.” Should this be the capability to issue
instead of capability to develop? The word “capability” is too generic. Suggest that the phrase be changed to “authority to develop or modify the
specific dispatch instructions” since authority is related to the generator operating personnel and not the control systems.

Suggest that the phrase “These personnel do not include plant operators located at a generator plant site or personnel at a centrally located dispatch
center who relay dispatch instructions without making any modifications.” Be modified to “These personnel do not include plant operators located at a
generator plant site or personnel at a centrally located dispatch center who relay verbal dispatch instructions without making any modifications.” This
would clarify that this is related to the generator operating personnel and not the control systems
Likes

0

Dislikes

0

Response

Wendy Center - U.S. Bureau of Reclamation - 1,5
Answer

Yes

Document Name
Comment
Reclamation supports having the Control Center definition only in the Glossary, rather than contained within other standards.
Likes

0

Dislikes

0

Response

David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment
OPG recommend to change the “capability to develop specific dispatch instructions” to “capability to originate or modify and issue specific dispatch
instructions”.
Likes
Dislikes

0
0

Response

Normande Bouffard - Hydro-Qu?bec Production - 1,5
Answer

Yes

Document Name
Comment
Alternative proposition for GOP:
For Generator Operators, the operating personnel above consist of dispatch personnel at a centrally located dispatch center who receive direction from
the Generator Operator’s Reliability Coordinator, Balancing Authority, Transmission Operator, or Transmission Owner. These operating personnel only
include personnel who can act independently to operate or direct the operation of the Generator Owner’s Bulk Electric System Facilities in Real-time.

Likes

0

Dislikes

0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Con-Edison and Dominion
Answer

Yes

Document Name
Comment
Agree with the alignment but not the specific wording

This definition of uses the NERC defined term “System Operator”. In the NERC Glossary, the “System Operator” definition uses the term “Control
Center.” Request this dependency be addressed.

Request clarification of the Transmission Owner’s “field switching personnel,” for this definition. This term was not explained well in PER-005.

Request clarification of “who can act independently to operate or direct the operation.” Is this addressing capability or authority?

Request clarification of the Generation Operator – “have the capability to develop specific dispatch instructions.” Should this be the capability to issue
instead of capability to develop?

Likes

0

Dislikes

0

Response

Lona Calderon - Salt River Project - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
SRP agrees with the alignment of the Control Center definition with PER-005-2, such as the incorporation of the phrase “Real-time reliability related
tasks."
Likes

0

Dislikes

0

Response

Jack Cashin - American Public Power Association - 4
Answer

Yes

Document Name
Comment
APPA agrees with the SDT decision to align the operating personnel in the Project 2016-02 Standard with the personnel identified in Reliability
Standard PER-005-2. While the alignment is appropriate, public power believes that some of the wording needs clarification.
The term, “field switching personnel,” used in the draft control center definition, is not well explained in PER-005-2. Therefore, this term will need to be
clarified for use in the CIP Standards. Specifically, regarding Transmission Owners’ field switching personnel, the term needs clarification to be used
effectively in the CIP standards.
Public power agrees with the comments of the Public Utility District No. 1 of Cowlitz County that, while alignment with PER-005-2 is appropriate for
Project 2016-02, further clarity is needed regarding personnel roles. Specifically, it should be made clear that the CIP standard’s intent is to exclude
personnel having no system-wide awareness and who manually operate BES facilities on location, while including personnel who perform autonomous
reliability monitoring and remote control for a registered Transmission Operator (TOP). Further clarity is needed because, under PER-005-2, it is not
clear if Control Center personnel include dispatch personnel who only perform local reliability functions rather than impacting the TOP’s greater
system. Therefore, while the alignment with PER-005-2 is appropriate, further clarity is needed to work within the CIP standards and
prevent significantly changing BES Cyber System categorization (see question 3).

Additionally, public power requests clarification regarding the language associated with Generation Operator (GOP) – that the GOP, “have the capability
to develop specific dispatch instructions.” Specifically, is “capability” referring to the capability to issue instructions, or is it the capability to develop
instructions? The use of the word “capability” here is too generic and public power suggests changing it to, “authority to develop or modify the specific
dispatch instructions,” since authority is related to the generator operating personnel and not the control systems.

APPA also suggests that the phrase, “These personnel do not include plant operators located at a generator plant site, or personnel at a centrally
located dispatch center who relay dispatch instructions without making any modifications,” be changed to “These personnel do not include plant
operators located at a generator plant site, or personnel at a centrally located dispatch center who relay verbal dispatch instructions without making any
modifications.” This would clarify that this is related to the generator operating personnel and not the control systems.
Likes

0

Dislikes

0

Response

Mark Riley - Associated Electric Cooperative, Inc. - 1,3,5,6, Group Name AECI & Member G&Ts
Answer

Yes

Document Name
Comment
AECI supports the SDT's approach to align the Control Center definition with PER-005-2. However, AECI requests additional clarity to be added to the
draft Control Center definition. Specifically, in the third paragraph, second and third line, of the definition, replace “who can act independently to operate
…..” with “who have independent authority to operate ……”
Likes

0

Dislikes

0

Response

Marc Donaldson - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6
Answer

Yes

Document Name
Comment
Tacoma Power supports the comments of APPA.
Likes

0

Dislikes

0

Response

Nicholas Lauriat - Network and Security Technologies - 1
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Brian Millard - Tennessee Valley Authority - 1,3,5,6 - SERC, Group Name Tennessee Valley Authority
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Chris Scanlon - Exelon - 1,3,5,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

James Poston - Santee Cooper - 1,3,5,6, Group Name Santee Cooper
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Amy Folz - Southern Indiana Gas and Electric Co. - 1,3,5,6 - RF
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Shelby Wade - PPL - Louisville Gas and Electric Co. - 3,5,6 - SERC, Group Name Louisville Gas and Electric Company and Kentucky Utilities
Company
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

Theresa Rakowsky - Puget Sound Energy, Inc. - 1,3,5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

David Greene - SERC Reliability Corporation - 10, Group Name SERC CIPC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Lan Nguyen - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Harold Sherrill - Sempra - San Diego Gas and Electric - 7 - WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Julie Hall - Entergy - 6, Group Name Entergy/NERC Compliance
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Robert Blackney - Edison International - Southern California Edison Company - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer
Document Name
Comment

Yes

Likes

1

Dislikes

Stephanie Burns, N/A, Burns Stephanie
0

Response

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 1,3,4
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Patricia Robertson - BC Hydro and Power Authority - 1,3,5, Group Name BC Hydro
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Douglas Webb - Great Plains Energy - Kansas City Power and Light Co. - 1,3,5,6 - SPP RE

Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Richard Vine - California ISO - 2
Answer
Document Name
Comment
The California ISO supports the comments of the Security Working Group (SWG)
Likes

0

Dislikes
Response

0

2. Control Center definition: Do the potential modifications to the Control Center definition change the scope or intent of any current or
pending Reliability Standard(s) (examples include Reliability Standards: COM-001-3; TOP-001-4; and IRO-002-5)? If yes, provide details of the
affected Reliability Standard(s), requirements, and any anticipated impact.
Brandon Cain - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - FRCC,MRO,WECC,Texas RE,NPCC,SERC,SPP RE, Group
Name Southern Company
Answer

No

Document Name
Comment
Considering the definition’s proposed alignment with PER-005, Southern does not see a change in the GOP function based on this definition.
Likes

0

Dislikes

0

Response

Lona Calderon - Salt River Project - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
Neither the definition of Control Center proposed by the SDT, nor the definition proposed by SRP in comment #4 affect the scope or intent of any O&P
requirements.
SRP agrees with APPA and LPPC that this commenting should not be included along with comments to CIP standards. By doing so, the personnel
working exclusively with 693 standards are being excluded and may cause unintentional consequences.

Likes

0

Dislikes

0

Response

Wendy Center - U.S. Bureau of Reclamation - 1,5
Answer
Document Name
Comment

No

Reclamation supports having the Control Center definition only in the Glossary, rather than contained within different standards.
Likes

0

Dislikes

0

Response

Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer

No

Document Name
Comment
ERCOT ISO supports the comments of the ITC SWG.
Likes

0

Dislikes

0

Response

Russell Noble - Cowlitz County PUD - 3,5
Answer

No

Document Name
Comment
The District finds the proposed definition as it relates to the registered functions of the RC, BA, TOP, and GOP does not change the original intent and
scope. Further, the proposed definition clarifies “operating personnel” for the RC, BA, and TOP registered functions as System Operators, who are
presumably NERC certified (please see question 4). The District strongly agrees with subjecting registered entities with monitoring and enforcement
action as officially registered, and seeks full retirement of the phrase “performing the functional obligations of.” Rather, the new definition seeks to
define TO activities that closely aligns with certain standard requirements placed on the TOP. The District believes the registered TOP may delegate
certain tasks to the TO, but not transfer responsibility. In this case, where the TO is performing Real-time reliability-related tasks – regardless if
autonomous or directed – as defined by “Reliable Operation of the BES” on behalf of its TOP, the term Control Center definitely applies. Although the
District advances improvements in the definition of Control Center, the District fully supports SDT’s definition modification efforts.
Likes

0

Dislikes

0

Response

Marty Hostler - Northern California Power Agency - 5,6
Answer

No

Document Name
Comment
CIP standards typically garner comments from information technology personnel rather than from system operations personnel. This could result in the
unintended consequence of potential operational impacts not being appropriately identified during the standard balloting and commenting process.
Likes

0

Dislikes

0

Response

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer

No

Document Name
Comment
SCL supports the APPA submitted comments.
Likes

0

Dislikes

0

Response

Matthew Beilfuss - WEC Energy Group, Inc. - 3,4,5,6 - MRO,RF
Answer

No

Document Name
Comment
Though the proposed modifciation (adding transmission owner) has the potential to impact how other standards (EOP-004, EOP-008) consider using
the NERC defined term in the future.
Likes

0

Dislikes

0

Response

Mark Riley - Associated Electric Cooperative, Inc. - 1,3,5,6, Group Name AECI & Member G&Ts
Answer
Document Name

No

Comment

Likes

0

Dislikes

0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Jack Cashin - American Public Power Association - 4
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Douglas Webb - Great Plains Energy - Kansas City Power and Light Co. - 1,3,5,6 - SPP RE
Answer

No

Document Name
Comment

Likes

0

Dislikes
Response

0

Patricia Robertson - BC Hydro and Power Authority - 1,3,5, Group Name BC Hydro
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Normande Bouffard - Hydro-Qu?bec Production - 1,5
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

David Ramkalawan - Ontario Power Generation Inc. - 5
Answer
Document Name
Comment

No

Likes

0

Dislikes

0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

No

Document Name
Comment

Likes

1

Dislikes

Stephanie Burns, N/A, Burns Stephanie
0

Response

Robert Blackney - Edison International - Southern California Edison Company - 1,3,5,6 - WECC
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Julie Hall - Entergy - 6, Group Name Entergy/NERC Compliance
Answer

No

Document Name
Comment

Likes

0

Dislikes
Response

0

Harold Sherrill - Sempra - San Diego Gas and Electric - 7 - WECC
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Lan Nguyen - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

David Greene - SERC Reliability Corporation - 10, Group Name SERC CIPC
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Theresa Rakowsky - Puget Sound Energy, Inc. - 1,3,5
Answer
Document Name
Comment

No

Likes

0

Dislikes

0

Response

sean erickson - Western Area Power Administration - 1,6
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Shelby Wade - PPL - Louisville Gas and Electric Co. - 3,5,6 - SERC, Group Name Louisville Gas and Electric Company and Kentucky Utilities
Company
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Aaron Austin - AEP - 3,5
Answer

No

Document Name
Comment

Likes

0

Dislikes
Response

0

Amy Folz - Southern Indiana Gas and Electric Co. - 1,3,5,6 - RF
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Sean Bodkin - Dominion - Dominion Resources, Inc. - 3,5,6, Group Name Dominion
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Vivian Vo - APS - Arizona Public Service Co. - 1,3,5,6
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Chris Scanlon - Exelon - 1,3,5,6
Answer
Document Name
Comment

No

Likes

0

Dislikes

0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Nicholas Lauriat - Network and Security Technologies - 1
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Annette Johnston - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1,3
Answer

Yes

Document Name
Comment
The change in the definition could impact CIP-012 scope.
Likes

0

Dislikes
Response

0

David Jendras - Ameren - Ameren Services - 1,3,6
Answer

Yes

Document Name
Comment
In our opinion, the changes are fraught with problems. First of all, in the NERC definition of System Operator, facilities DO NOT monitor or control the
BES, people do. The language as written says otherwise. Second, the inclusion of “and” means a control center must have facilities and people. As
automation becomes more prevalent, the definition as written would allow a “control center” that governed thousands (or tens of thousands) of MW of
load and/or generation to escape classification as a NERC Control Center if it was completely automated, i.e. hosted no people. (Or even today, the
“control center” could be personnel free but operators remotely accessed it.) We feel that when considering cyber security, this hardly seems like a
change that supports BES reliability. Finally, if the control center definition is going to be amended, it should be modified to fix the ambiguity regarding
Transmission facilities. “Two or more locations” while meaningful and clear when describing substations we believe this makes little to no sense on its
face when thinking about lines. If the intent is two or more circuits, then the language should plainly say so.
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0

Response

Jamie Monette - Allete - Minnesota Power, Inc. - 1
Answer

Yes

Document Name
Comment
See question 1
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0

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0

Response

Thomas Breene - WEC Energy Group, Inc. - 3,4,5,6
Answer

Yes

Document Name
Comment
See question 1.
Likes
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0
0

Response

Dana Klem - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO NSRF
Answer

Yes

Document Name
Comment
See question 1.
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0

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0

Response

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 1,3,4
Answer

Yes

Document Name
Comment

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0

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0

Response

David Francis - Midcontinent ISO, Inc. - 2,3 - FRCC,MRO,WECC,Texas RE,NPCC,SERC,SPP RE,RF, Group Name SRC + SWG
Answer

Yes

Document Name
Comment

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0

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0

Response

James Poston - Santee Cooper - 1,3,5,6, Group Name Santee Cooper
Answer

Yes

Document Name
Comment

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0

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0

Response

Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Marc Donaldson - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6
Answer
Document Name
Comment
Tacoma Power supports the comments of APPA.
Likes

0

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0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Please see Texas RE’s comments for #1.

Likes

0

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0

Response

Brandon McCormick - Florida Municipal Power Agency - 3,4,5 - FRCC, Group Name FMPA
Answer
Document Name
Comment
As a CIP standard, most of the commenting will be done by non-operations personnel. It is a concern that the operational impact will not be identified
during the balloting and commenting process. This may cause unintentional consequences if the definition is approved.
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0

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0

Response

Brian Millard - Tennessee Valley Authority - 1,3,5,6 - SERC, Group Name Tennessee Valley Authority
Answer
Document Name
Comment
No comment.
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0

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0

Response

George Brown - Acciona Energy North America - 5
Answer
Document Name
Comment
From a Generator Operator perspective the proposed definition of Control Center does not. The Control Center definition should only define a physical
location where Real-time Bulk Electrical System (BES) reliability related operating tasks are performed. It also can include, but cautiously, information
on personnel that a Control Center houses, however it should not attempt to define these personnel, either System Operators or operating personnel.

Likes

0

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0

Response

Richard Vine - California ISO - 2
Answer
Document Name
Comment
The California ISO supports the comments of the Security Working Group (SWG)
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0

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Response

0

3. Control Center definition: The SDT contends that there will be no change in BES Cyber System categorization by clarifying the definition
of Control Center. This assertion is based on SDT review of the CIP-002-5.1a criteria and its understanding of BES Cyber System
categorization through experience implementing CIP-002-5.1a. Do you agree with this assertion? If not, please provide rationale and practical
examples of where a change in categorization will occur as a result of this modification.
Brandon McCormick - Florida Municipal Power Agency - 3,4,5 - FRCC, Group Name FMPA
Answer

No

Document Name
Comment
This new definition may bring in new assets or change the impact level of existing assets which would change the list of BES Cyber Systems and
impact levels
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0

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0

Response

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer

No

Document Name
Comment
SCL supports the APPA submitted comments.
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0

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0

Response

Marty Hostler - Northern California Power Agency - 5,6
Answer

No

Document Name
Comment
NCPA does not agree with the SDT assertion that there will be no change in BES Cyber System categorization due to the Control Center definition. This
new definition may bring in new assets or change the impact level of existing assets which would change the list of BES Cyber Systems and impact
levels.
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0

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0

Response

Russell Noble - Cowlitz County PUD - 3,5
Answer

No

Document Name
Comment
The District supports APPA comment. The current definition draft may pull the District’s low impact dispatch center in as a Control Center if further
clarifications are not provided. This is due to possible RE identification of the District’s ability to independently control for public safety as a “Real-time
reliability-related TOP task.” Of note, the District’s covering Transmission Operator’s intent is to remove all TOP Reliable Operation obligation from the
District; this assures improved Reliable Operation of the BES by removing a “bucket line” approach to BES critical operations.
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0

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0

Response

David Francis - Midcontinent ISO, Inc. - 2,3 - FRCC,MRO,WECC,Texas RE,NPCC,SERC,SPP RE,RF, Group Name SRC + SWG
Answer

No

Document Name
Comment
The SRC & ITC SWG also encourages the drafting team to make the requirement forward-looking in regards to contracts currently in place. Provisions
should be set for legacy contracts including grandfathering of existing agreements and equipment. Implementation of controls involving
telecommunications providers will require coordination and scheduling to align to the providers’ resource availability and reduce adverse impact on
reliability. This should not require renewal and renegotiation of existing contracts until they reach the end of the existing contract period.

It should be noted that it is difficult to determine suitability of the implementation timeline when there are open questions about the viability of available
solutions for adequate protections.

More time is necessary to allow for coordination with a large number of parties. This will require budgeting, planning, and scheduling with external
resources for implementation. It will also require significant testing and validation by parties on both ends of a connection.

The SRC & ITC SWG recommends a phased implementation with defined milestones similar to CIP-014. Consider the following:
For creation of the plan, 12 months should be allowed to (1) conduct an impact assessments, (2) identify the approach to be included in the plan, (3)
implementation milestones, and (4) implementation schedule. This could identify the communication links that have protections currently in place. The

plan could also include identifying all links and protections requiring changes to address service contracts and related relationships to adjust for new
protections. The plan could then be approved by an appropriate entity.
For implementation of the plan, additional time should be allowed for budgeting, planning, and scheduling with external resources. This includes
planning with other Responsible Entities as well as telecommunications providers.
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0

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0

Response

Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer

No

Document Name
Comment
This new definition may bring in new assets or change the impact level of existing assets which would change the list of BES Cyber Systems and
impact levels

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0

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0

Response

David Jendras - Ameren - Ameren Services - 1,3,6
Answer

No

Document Name
Comment
As noted above, and summarized here, the current enforcement is wide ranging and would incorporate for instance a TOP “control center” that had a
meaningful potential impact on the BES without regard to the presence or absence of personnel. While the current Standard may not directly mention
this, the wide ranging practical enforcement has included a review of any such facilities. However, we believe that the new definition will absolutely
provide an opportunity to avoid compliance obligations by ensuring that no personnel are present at the facility relying instead on automation or remote
access.
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0

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0

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Con-Edison and Dominion
Answer

No

Document Name
Comment
This new definition may bring in new assets or change the impact level of existing assets which would change the list of BES Cyber Systems and
impact levels.
Likes

0

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0

Response

Lona Calderon - Salt River Project - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
This new definition may bring in new assets or change the impact level of existing assets which would change the list of BES Cyber Systems and
impact levels
Likes

0

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0

Response

Brandon Cain - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - FRCC,MRO,WECC,Texas RE,NPCC,SERC,SPP RE, Group
Name Southern Company
Answer

No

Document Name
Comment
Southern disagrees with the above assertion. Given the assumption that the term “operating personnel” in the current definition is a point of ambiguity
and the focus of these Control Center definition changes, Southern has evaluated potential scenarios where a Facility under the current definition would
be considered a Control Center, but under the proposed definition, due to ambiguity and interpretation, might not be considered a Control Center, which
could ultimately impact your CIP-002-5.1 impact identification and categorization of BES Cyber Systems. The strategy of attempting to remove from
scope those lower impact Facilities as Control Centers appears to have the potential to scope out larger impact Facilities as well. We applaud the SDTs
efforts in this regard, but recognize that additional discussion and consideration is needed to come up with a better approach to modifying the Control
Center definition.
Likes

0

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0

Response

Jack Cashin - American Public Power Association - 4
Answer

No

Document Name
Comment
APPA does not agree with the SDT assertion that there will be no change in BES Cyber System categorization due to the Control Center definition. This
new definition may bring in new assets or change the impact level of existing assets which would change the list of BES Cyber Systems and impact
levels.
If the clarifications APPA (and others) request in question 1 are sufficient, then potentially little or no change in BES Cyber System categorization will
occur. However, without adequate clarification, public power believes that there will be significant change in BES Cyber System categorization, should
local control rooms become considered as Control Centers.

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0

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0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
Some entities, registered as Transmission Owners, contract out their Transmission Operator responsibilities but have dispatch centers that are capable
of performing tasks on their BES system for safety or maintenance reasons. The current Control Center definition would not automatically classify these
dispatch centers as Control Centers. The proposed definition, without clarification, would allow interpretations that may identify these dispatch centers
as a Control Center.
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0

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0

Response

Mark Riley - Associated Electric Cooperative, Inc. - 1,3,5,6, Group Name AECI & Member G&Ts
Answer
Document Name

No

Comment
The revised Control Center definition may bring in new assets that would be identified by the revised definition. Furthermore, assets such as local
control centers/dispatch centers that were not previously considered Control Centers could now be identified as medium impact BES Cyber Systems
due to the "functional obligations" language that is present in CIP-002-5.1a Attachment 1, Criterion 2.12.
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0

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0

Response

Marc Donaldson - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6
Answer

No

Document Name
Comment
Tacoma Power supports the comments of APPA.
Likes

0

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0

Response

Annette Johnston - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1,3
Answer

No

Document Name
Comment
One of the fundamental purposes for changing the Control Center definition was so Transmission Owners under certain circumstances could have the
responsibilities of a Control Therefore, Responsible Entities who previously did not have a Transmission Control Center could have one with this change
in definition. There could be other scenarios too, including generation.
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0

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0

Response

George Brown - Acciona Energy North America - 5
Answer
Document Name

Yes

Comment
From a Generator Operator perspective the proposed definition of Control Center does not.
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0

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0

Response

Brian Millard - Tennessee Valley Authority - 1,3,5,6 - SERC, Group Name Tennessee Valley Authority
Answer

Yes

Document Name
Comment
TVA believes adoption of the proposed definition provides useful clarification regarding identification of Low Control Centers.
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0

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0

Response

Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment
ERCOT ISO supports the comments of the ITC SWG.
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0

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0

Response

Nicholas Lauriat - Network and Security Technologies - 1
Answer
Document Name
Comment

Yes

Likes

0

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0

Response

Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment

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0

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0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment

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0

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0

Response

Dana Klem - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO NSRF
Answer

Yes

Document Name
Comment

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0

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0

Response

Chris Scanlon - Exelon - 1,3,5,6

Answer

Yes

Document Name
Comment

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0

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0

Response

James Poston - Santee Cooper - 1,3,5,6, Group Name Santee Cooper
Answer

Yes

Document Name
Comment

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0

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0

Response

Vivian Vo - APS - Arizona Public Service Co. - 1,3,5,6
Answer

Yes

Document Name
Comment

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0

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0

Response

Sean Bodkin - Dominion - Dominion Resources, Inc. - 3,5,6, Group Name Dominion
Answer

Yes

Document Name
Comment

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0

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0

Response

Amy Folz - Southern Indiana Gas and Electric Co. - 1,3,5,6 - RF
Answer

Yes

Document Name
Comment

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0

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0

Response

Aaron Austin - AEP - 3,5
Answer

Yes

Document Name
Comment

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0

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0

Response

Thomas Breene - WEC Energy Group, Inc. - 3,4,5,6
Answer

Yes

Document Name
Comment

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0

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0

Response

Shelby Wade - PPL - Louisville Gas and Electric Co. - 3,5,6 - SERC, Group Name Louisville Gas and Electric Company and Kentucky Utilities
Company

Answer

Yes

Document Name
Comment

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0

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0

Response

sean erickson - Western Area Power Administration - 1,6
Answer

Yes

Document Name
Comment

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0

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0

Response

Theresa Rakowsky - Puget Sound Energy, Inc. - 1,3,5
Answer

Yes

Document Name
Comment

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0

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0

Response

David Greene - SERC Reliability Corporation - 10, Group Name SERC CIPC
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Lan Nguyen - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Sheranee Nedd - PSEG - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer

Yes

Document Name
Comment

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3

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PSEG - PSEG Fossil LLC, 5, Kucey Tim; PSEG - Public Service Electric and Gas Co., 1, Smith Joseph;
PSEG - Public Service Electric and Gas Co., 3, Mueller Jeffrey
0

Response

Harold Sherrill - Sempra - San Diego Gas and Electric - 7 - WECC
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Julie Hall - Entergy - 6, Group Name Entergy/NERC Compliance

Answer

Yes

Document Name
Comment

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0

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0

Response

Robert Blackney - Edison International - Southern California Edison Company - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment

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0

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0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

Yes

Document Name
Comment

Likes

1

Dislikes

Stephanie Burns, N/A, Burns Stephanie
0

Response

Wendy Center - U.S. Bureau of Reclamation - 1,5
Answer

Yes

Document Name
Comment

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0

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0

Response

Jamie Monette - Allete - Minnesota Power, Inc. - 1
Answer

Yes

Document Name
Comment

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0

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0

Response

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 1,3,4
Answer

Yes

Document Name
Comment

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0

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0

Response

David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment

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0

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0

Response

Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

Yes

Document Name
Comment

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0

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0

Response

Normande Bouffard - Hydro-Qu?bec Production - 1,5
Answer

Yes

Document Name
Comment

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0

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0

Response

Patricia Robertson - BC Hydro and Power Authority - 1,3,5, Group Name BC Hydro
Answer

Yes

Document Name
Comment

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0

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0

Response

Douglas Webb - Great Plains Energy - Kansas City Power and Light Co. - 1,3,5,6 - SPP RE
Answer

Yes

Document Name
Comment

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0
0

Response

Richard Vine - California ISO - 2
Answer
Document Name
Comment
The California ISO supports the comments of the Security Working Group (SWG)
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0

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0

Response

Matthew Beilfuss - WEC Energy Group, Inc. - 3,4,5,6 - MRO,RF
Answer
Document Name
Comment
No comment
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0

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0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE does not have comments on this question.
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0

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0

4. Control Center definition: Do you agree with the potential definition of Control Center? If not, please provide rationale or propose an
alternative definition.
Annette Johnston - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1,3
Answer

No

Document Name
Comment
As expressed in the comments on question 1, the revised Control Center definition doesn’t adequately address renewable energy sites. Also, the
change in wording to add “capability” potentially broadens the scope.
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0

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0

Response

Marc Donaldson - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6
Answer

No

Document Name
Comment
Tacoma Power supports the comments of APPA.
Likes

0

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0

Response

Mark Riley - Associated Electric Cooperative, Inc. - 1,3,5,6, Group Name AECI & Member G&Ts
Answer

No

Document Name
Comment
AECI supports NRECA's comments.
Additionally, the phrase “reliability-related tasks” is not defined and may be misinterpereted by Responsible Entities or compliance enforcement
staff. AECI suggests that the SDT clarify the the meaning of this phrase or propose a definition for inclusion in the Glossary of Terms Used in NERC
Reliability Standards.
Likes

0

Dislikes

0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
Additional clarity is needed with the phrase “operating personnel who perform Real-time reliability-related tasks of…”. If the operating personnel have
the capability of performing the real-time reliability-related tasks of a TOP but do not have the authority, it is unclear if their facility would be a Control
Center. It is also unclear if the SDT’s goal is to make these facilities Control Centers or not.
BPA believes that updating the Control Center definition for CIP standard purposes can potentially cause issues with O&P compliance. BPA
recommends broadening scope of the control center definition to include more active engagement from O&P SME’s. More analysis will need to be
done once the definition is clarified.
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0

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0

Response

Jack Cashin - American Public Power Association - 4
Answer

No

Document Name
Comment
APPA does not agree with the proposed definition of Control Center based on the need for language clarity in several places. The response to question
1 above provides several examples of where the draft language needs to be changed.
Public power believes there are additional language changes that need to be made to the draft definition. The proposed definition uses the NERC
defined term “System Operator.” In the NERC Glossary, the “System Operator” definition uses the term “Control Center.” APPA believes this
circular dependency of terms needs to be addressed.
APPA also requests the SDT clarify the term, “who can act independently to operate or direct the operation.” It is not clear if the operation or direction of
this person is specifically addressing that person’s capability or authority to direct or operate. Public power believes this should be clarified.
The phrase “Real-time reliability-related tasks” used in the draft definition is not a NERC defined term. APPA believes that the term could be
confusing to some NERC compliance personnel who may think it has some relation to the NERC Functional Model. Consequently, public power
believes this phrase needs clarification.
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0
0

Response

Brandon Cain - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - FRCC,MRO,WECC,Texas RE,NPCC,SERC,SPP RE, Group
Name Southern Company
Answer

No

Document Name
Comment
As noted in #1, above, Southern respectfully disagrees with the approach chosen by the SDT to redefine the term Control Center. The reliability impact
of the facility(ies) controlled by the center are an important element of this definition and this aspect did not receive due consideration in the proposed
version of the definition.
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0

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0

Response

Lona Calderon - Salt River Project - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
SRP does not agree with the inclusion of “Transmission Owner” in the following statement, “For Generator Operators, the operating personnel above
consist of dispatch personnel at a centrally located dispatch center who receive direction from the Generator Operator’s Reliability Coordinator,
Balancing Authority, Transmission Operator, or Transmission Owner, and have the capability to develop specific dispatch instructions for plant
operators under their control." By definition, Transmission Owners have no responsibility for operation.
SRP believes the majority of the proposed language in paragraphs 2 through 4 is already expressed within the first paragraph and is redundant. SRP
proposes the following language: “One or more facilities, including their associated data centers, that monitor and control the Bulk Electric System
(BES) and host operating personnel who perform Real-time reliability-related tasks of any of the following, regardless of NERC registration: 1) a
Reliability Coordinator, 2) a Balancing Authority, 3) a Transmission Operator for Transmission Facilities at two or more locations, or 4) a Generator
Operator for generation Facilities at two or more locations. These personnel do not include individuals who only execute or relay dispatch instructions
without making any modifications.”
The language within the proposed definition of “Control Center” seeks to further identify and define a “System Operator.” This term is already a defined
term within the NERC Glossary of terms. Seeking to create a second definition of the term creates confusion and redundancy.
Additionally, SRP agrees with APPA’s comment and requests clarification of what is meant by “Real-time reliability-related tasks.”
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0

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0

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Con-Edison and Dominion
Answer

No

Document Name
Comment
Need clarification(s) – see Q1.
Likes

0

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0

Response

Normande Bouffard - Hydro-Qu?bec Production - 1,5
Answer

No

Document Name
Comment
Alternative proposition for GOP:
For Generator Operators, the operating personnel above consist of dispatch personnel at a centrally located dispatch center who receive direction from
the Generator Operator’s Reliability Coordinator, Balancing Authority, Transmission Operator, or Transmission Owner. These operating personnel only
include personnel who can act independently to operate or direct the operation of the Generator Owner’s Bulk Electric System Facilities in Real-time.
Likes

0

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0

Response

David Jendras - Ameren - Ameren Services - 1,3,6
Answer

No

Document Name
Comment
It provides a new gap in enforcement and does not improve the current one where needed.
Likes

0

Dislikes
Response

0

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 1,3,4
Answer

No

Document Name
Comment
FirstEnergy recognizes that the proposed Control Center language describing Transmission Owner operating personnel is to a large degree
already used in NERC Reliability Standard PER-005-2 — Operations Personnel Training. However, from a cyber system point of view, it might
be beneficial to clarify that these personnel are not inclusive of operating personnel who “can act”, which could be interpreted as “who are
capable of”. There may be personnel who are capable within a location based on cyber system privileges, but who are not authorized,
trained, etc. to independently take actions using a cyber system (e.g. IT System Administrators). FirstEnergy recommends the following
change to the definition:
For Transmission Owners performing the Real-time reliability-related tasks of a Transmission Operator, the operating personnel above
consist of personnel, excluding field switching personnel, who independently operate or direct the operation of the Transmission Owner’s
Bulk Electric System Transmission Facilities in Real-time
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0

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0

Response

Barry Lawson - National Rural Electric Cooperative Association - 3,4
Answer

No

Document Name
Comment
See NRECA’s answer to Question 1.
Likes

0

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0

Response

Wendy Center - U.S. Bureau of Reclamation - 1,5
Answer

No

Document Name
Comment
Reclamation recommends the first paragraph of the proposed definition revise to state:

One or more agency-designated (i.e., primary or backup) Facilities that host System Operators

Reclamation also recommends that the Control Center definition be restricted to Facilities with the capability to control two or more Facilities that, when
combined, are considered high or medium impact rated Facilities.

Reclamation also recommends the SDT consider the implications of whether the Facility has the capability to perform “Real-time reliability-related tasks”
with or without hosting System Operators or dispatch personnel.
Likes

0

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0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

No

Document Name
Comment
The SPP Standards Review Group has a concern that the term Real-time in the proposed definition does not properly align with the term mention or
defined in other Reliability Standards.
Likes

1

Dislikes

Stephanie Burns, N/A, Burns Stephanie
0

Response

Robert Blackney - Edison International - Southern California Edison Company - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
The proposed definition of Control Center, as written, does not specify whether manned or unmanned data centers are considered facilities associated
with a Control Center. NERC should modify the proposed definition to clarify that both manned and unmanned data centers are facilities associated with
a Control Center. Specific modifications to the proposed Control Center definition are provided below (modifications are in bold):
“One or more facilities, including their associated manned or unmanned data centers, that monitor and control the Bulk Electric System (BES)…”
Likes
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0
0

Response

Julie Hall - Entergy - 6, Group Name Entergy/NERC Compliance
Answer

No

Document Name
Comment
Note that while Transmission Owners are mentioned in the third paragraph, they are not mentioned in the 4 applicable functions. For completeness,
Transmission Owners should be listed as a 5th applicable function. Recommend adding a fifth identification for Transmission Owner for Transmission
Facilities who can act independently to operate or direct the operation of the Transmission Owner’s Bulk Electric System Transmission Facilities in
Real-time to the 1st paragraph definition.
Likes

0

Dislikes

0

Response

Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer

No

Document Name
Comment
See comments to question 1.

This definition of uses the NERC defined term “System Operator”. In the NERC Glossary, the “System Operator” definition uses the term “Control
Center.” Request this dependency be addressed.

Request clarification of “who can act independently to operate or direct the operation.” Is this addressing capability or authority?

The phrase “Real-time reliability-related tasks” is not defined and may be determined by some entities or auditors to be associated with the Functional
Model. Suggest clarification on the meaning of this phrase
Likes

0

Dislikes
Response

0

Sheranee Nedd - PSEG - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer

No

Document Name
Comment
The definition is not consistent with PER-005-2 part 4.1.5.1. It uses the statement “have the capability to develop specific dispatch instructions… “,
where PER-005-2 part 4.1.5.1. states “may develop specific dispatch instructions…”. There is significant difference between having the capability to do
something, versus doing it. The language (i.e.”may” versus “having the capability to”) concerning Generation and Control Centers (a “centrally located
dispatch center” in PER-005-2 part 4.1.5.1) has already been settled by industry, through development and approval of PER-005-2. The proposed
definition should stay consistent with PER-005-2 part 4.1.5.1.
Likes

3

Dislikes

PSEG - PSEG Fossil LLC, 5, Kucey Tim; PSEG - Public Service Electric and Gas Co., 1, Smith Joseph;
PSEG - Public Service Electric and Gas Co., 3, Mueller Jeffrey
0

Response

David Greene - SERC Reliability Corporation - 10, Group Name SERC CIPC
Answer

No

Document Name
Comment
•

Revised Definition: Second paragraph, change to read “…the operating personnel above includes System Operators.”

Rationale: Not all operating personnel are technically System Operators
•

Revised Definition: Third paragraph, change to read “…who has the ability to act independently to operate or direct the operation of the
Transmission Owner’s Bulk Electric System Transmission Facilities in Real-time.”

Rationale: To provide clarity that the intent is to include operators that have the ability to act independently even though they might not have the
authorization to do so.
Likes

0

Dislikes

0

Response

David Francis - Midcontinent ISO, Inc. - 2,3 - FRCC,MRO,WECC,Texas RE,NPCC,SERC,SPP RE,RF, Group Name SRC + SWG
Answer
Document Name
Comment

No

In addition to the comments provided in response to question 3, the SRC & SWG offers these comments regarding cost effectiveness. Open Source
options to satisfy the requirement to protect communication links and sensitive bulk electric system data communicated between bulk electric systems
Control Centers are limited. Few options generally translated to high vendor leverage, which could lead to high implementation costs. It is unclear how
or whether costs could be shared among participants in the network. Architectural changes to support these requirements should be spread out over
several years. Plus there will be business impacts.
Likes

0

Dislikes

0

Response

Shelby Wade - PPL - Louisville Gas and Electric Co. - 3,5,6 - SERC, Group Name Louisville Gas and Electric Company and Kentucky Utilities
Company
Answer

No

Document Name
Comment
We support SERC's comments.
Likes

0

Dislikes

0

Response

Thomas Breene - WEC Energy Group, Inc. - 3,4,5,6
Answer

No

Document Name
Comment
See question 1.
Likes

0

Dislikes

0

Response

Russell Noble - Cowlitz County PUD - 3,5
Answer
Document Name

No

Comment
The District supports APPA comment.
The District proposes the SDT to consider control rooms restricted to TOP authorized planned maintenance and/or public safety emergency operations
as outside the scope of the Control Center definition. If the TO control room is necessary for BES Reliable Operation, then it must be treated as a
Control Center. Further, if the covering TOP is able to perform its registered functional obligation without utilizing the TO’s control room capabilities, it is
counterproductive to add secondary process, i.e., directing the TO personnel, in executing actions to maintain BES within Reliable Operation
parameters.
The District suggests the following to clarify the intent of identifying a TO control room as a Control Center:
One or more facilities, including their associated data centers, that monitor and control the Bulk Electric System (BES) and host operating personnel
who perform Real-time reliability-related tasks of: 1) a Reliability Coordinator, 2) a Balancing Authority, 3) a Transmission Operator, or Transmission
Owner performing BES Reliable Operation tasks on behalf of the Transmission Operator, for Transmission Facilities at two or more locations, or 4) a
Generator Operator for generation Facilities at two or more locations.
For Reliability Coordinators, Balancing Authorities, and Transmission Operators, the operating personnel above appropriately maintain NERC System
Operator Certification credentials.
For Transmission Owners performing tasks necessary for Bulk Electric System Reliable Operation on behalf of the Transmission Operator, the
operating personnel above consist of personnel, excluding field switching personnel lacking Real-time monitoring capability, who can monitor and
control the Transmission Owner’s Bulk Electric System Transmission Facilities in Real-time as directed by the Transmission Operator’s certified
operating personnel. Transmission Owner operations related to Transmission Operator authorized planned facility maintenance, and autonomous
emergency operations to protect public safety are excluded from this definition.
Likes

0

Dislikes

0

Response

Amy Folz - Southern Indiana Gas and Electric Co. - 1,3,5,6 - RF
Answer

No

Document Name
Comment
While Vectren understands the need to clarify the Control Center definition and the use of NERC Standard PER-005-2 language to provide clarity, we
believe that the language “have the capability to develop” is ambiguous. At Vectren, the operating personnel at the centrally located dispatch center
may have the capability to perform, but do not actually perform Real-time Reliability related tasks. PER-005-2 language doesn’t mention capability, but
rather states that “dispatch personnel at a centrally located dispatch center… may develop dispatch instructions…” We propose that the SDT modify the
definition to better align with PER-005-2 language by removing the words “have the capability”.
Likes

0

Dislikes
Response

0

Sean Bodkin - Dominion - Dominion Resources, Inc. - 3,5,6, Group Name Dominion
Answer

No

Document Name
Comment
Please refer the comments in Q1,
Likes

0

Dislikes

0

Response

Vivian Vo - APS - Arizona Public Service Co. - 1,3,5,6
Answer

No

Document Name
Comment
AZPS is concerned that, although the SDT intends to align the definition with PER-005-2, the language in the definition leaves ambiguity regarding the
genesis of reliability-related tasks. To better ensure this alignment, alleviate the potential for confusion, and enhance clarity, AZPS reiterates its
comments provided in response to Question 1 above.
Likes

0

Dislikes

0

Response

Marty Hostler - Northern California Power Agency - 5,6
Answer

No

Document Name
Comment
1. NCPA does not agree with the proposed definition of Control Center based on the need for language clarity in several places. The response to
question 1 above provides several examples of where the draft language needs to be changed.

2. NCPA believes there are other language changes that need to be made to the draft definition. The proposed definition uses the NERC defined
term “System Operator.” In the NERC Glossary, the “System Operator” definition uses the term “Control Center.” APPA believes this circular
dependency of terms needs to be addressed.

3. NCPA requests the SDT clarify the term, “who can act independently to operate or direct the operation.” It is not clear if the operation or
direction of this person is specifically addressing that person’s capability or authority to direct or operate.
Likes

0

Dislikes

0

Response

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer

No

Document Name
Comment
SCL supports the APPA submitted comments.
Likes

0

Dislikes

0

Response

Brandon McCormick - Florida Municipal Power Agency - 3,4,5 - FRCC, Group Name FMPA
Answer

No

Document Name
Comment
This definition of uses the NERC defined term “System Operator”. In the NERC Glossary, the “System Operator” definition uses the term “Control
Center.” Request this dependency be addressed.
Request clarification of “who can act independently to operate or direct the operation.” Is this addressing capability or authority?
The phrase “Real-time reliability-related tasks” is not defined and may be determined by some entities or auditors to be associated with the Functional
Model. Suggest clarification on the meaning of this phrase
Likes

0

Dislikes

0

Response

George Brown - Acciona Energy North America - 5
Answer
Document Name

No

Comment
The Control Center definition should only define a physical location where Real-time Bulk Electrical System (BES) reliability related operating tasks are
performed. It also can include, but cautiously, information on personnel that a Control Center houses, however it should not attempt to define these
personnel, either System Operators or operating personnel.
If it is the intention of the SDT to define operating personnel of a Transmission Owner (TO) performing the Real-time reliability-related operating tasks of
a Transmission Operator and Generator Operator (GOP) operating personnel, then a separate term needs to be defined to identify these individuals.
Data centers usually do not host personnel and the Control Center definition needs to be modified to account for this.
In the context of the proposed definition of Control Center, in the Generator Operator section, the term “direction” is used, “Operating Instruction” is
already a defined term and should be used instead of “direction”. Also, the term “capability” is used and is inaccurate, many individuals have the
capability to modify a generator, i.e. IT/OT personnel, however, few have the authority; “capability should be modified to “authority”.
The following is suggested:
Control Center: One or more facilities that monitor and control the Bulk Electric System and host System Operators and Operating Personnel who
perform the Real-time operating reliability related-tasks, and includes the associated data centers, of:
1) a Reliability Coordinator,
2) a Balancing Authority,
3) a Transmission Operator for Transmission Facilities at two or more locations,
4) a Transmission Owner performing the delegated Real-time reliability-related operating tasks of a Transmission Operator at two or more locations or
5) a Generator Operator for generation Facilities at two or more locations.
Operating Personnel: An individual at a Control Center of a Transmission Owner or Generator Operator who perform the Real-time operating reliability
related-tasks as follows:
1. For a Transmission Owner these individuals would be personnel who can act independently and have the authority to operate or direct the
operation of the Transmission Owner’s Bulk Electric System Transmission Facilities in Real-time.
2. For a Generator Operator these individuals would be personnel who receive Operating Instructions from the Generator Operator’s Reliability
Coordinator, Balancing Authority, Transmission Operator, or Transmission Owner, and have the authority to develop and direct specific dispatch
instructions for plant operators under their control. These personnel do not include plant operators located at a generator plant site or personnel
at a centrally located dispatch center who relay Operating Instructions and dispatch instructions without making any modifications.
Likes

0

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0

Response

Matthew Beilfuss - WEC Energy Group, Inc. - 3,4,5,6 - MRO,RF
Answer
Document Name
Comment

No

Adjusting the NERC defined term for Control Center to facilitate the expansion of CIP-002 scope to additional cyber assets is not appropriate. In
particular, the inclusion of Transmission Owner and lengthy definition of operating personnel does not belong in the NERC Glossary of Terms. If a CIP
project team identifies a class of cyber assets that can impact the BES (a gap in the existing standards), approaches that expand the definition of a
Control Center beyond what is understood by industry potentially limits use of the term in other standards.
Below is a proposed revision, please note we have included the operating personnel of a TO for illustrative purposes, we do not believe it belongs in the
Control Center definition.
One or more facilities, including their associated data centers that monitor and control the Bulk Electric System (BES) and host System
Operators, or any of the following;
•

operating personnel of a Generator Operator that have the ability to develop specific dispatch instructions for plant operators under
their control at two or more locations

•

operating personnel of a Transmission Owner who can act independently to operate or direct the operation of the Transmission
Owner’s Bulk Electric System Transmission Facilities in Real-time.

Likes

0

Dislikes

0

Response

Jamie Monette - Allete - Minnesota Power, Inc. - 1
Answer

Yes

Document Name
Comment
With modification in question 1.
Likes

0

Dislikes

0

Response

Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment
ERCOT ISO supports the comments of the ITC SWG.

Likes

0

Dislikes

0

Response

Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment
Duke Energy agrees with the proposed changes to the definition of Control Center, but would like to recommend the drafting team consider the
following revision to the first sentence in the first paragraph of the definition:
One or more facilities, including their associated data centers, that host operating personnel who monitor and control the Bulk Electric system (BES) by
performing Real-time reliability-related tasks of: 1) a Reliability Coordinator, 2) a Balancing Authority, 3) a Transmission Operator for Transmission
Facilities at two or more locations, or 4) a Generator Operator for generation Facilities at two or more locations.
For Reliability Coordinators, Balancing Authorities, and Transmission Operators, the operating personnel above are System Operators.
For Transmission Owners performing the Real-time reliability-related tasks of a Transmission Operator, the operating personnel above consist of
personnel, excluding field switching personnel, who can act independently to operate or direct the operation of the Transmission Owner’s Bulk Electric
System Transmission Facilities in Real-time.
For Generator Operators, the operating personnel above consist of dispatch personnel at a centrally located dispatch center who receive direction from
the Generator Operator’s Reliability Coordinator, Balancing Authority, Transmission Operator, or Transmission Owner, and have the capability to
develop specific dispatch instructions for plant operators under their control. These personnel do not include plant operators located at a generator plant
site or personnel at a centrally located dispatch center who relay dispatch instructions without making any modifications.
As currently written, the first sentence of the first paragraph of the proposed definition, it seems to imply that it is the Facilities that monitor and control
the BES, however, it should actually read that the operating personnel are responsible for monitoring and controlling of the BES. We feel that the above
is a more accurate statement, and better reflects the current state of operations.

Likes

0

Dislikes

0

Response

Douglas Webb - Great Plains Energy - Kansas City Power and Light Co. - 1,3,5,6 - SPP RE
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

Patricia Robertson - BC Hydro and Power Authority - 1,3,5, Group Name BC Hydro
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Harold Sherrill - Sempra - San Diego Gas and Electric - 7 - WECC

Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Lan Nguyen - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Theresa Rakowsky - Puget Sound Energy, Inc. - 1,3,5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Aaron Austin - AEP - 3,5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

James Poston - Santee Cooper - 1,3,5,6, Group Name Santee Cooper
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Chris Scanlon - Exelon - 1,3,5,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Brian Millard - Tennessee Valley Authority - 1,3,5,6 - SERC, Group Name Tennessee Valley Authority
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Nicholas Lauriat - Network and Security Technologies - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Please see Texas RE’s comments to #1.
Likes

0

Dislikes

0

Response

Richard Vine - California ISO - 2
Answer
Document Name
Comment
The California ISO supports the comments of the Security Working Group (SWG)

Likes

0

Dislikes
Response

0

5. Implementation Plan: The SDT proposes to make the new Control Center definition effective upon applicable governmental authority’s
order approving the definition, or as otherwise provided for by the applicable governmental authority. Do you agree with this proposal not to
provide additional implementation time following approval? If you agree with the potential implementation time period, please note the
actions you will take that require this amount of time to complete. If you think an alternate implementation time period is needed, please
propose an alternate implementation period and provide a detailed explanation of actions and time needed to meet your proposed
implementation deadline.
George Brown - Acciona Energy North America - 5
Answer

No

Document Name
Comment
From a Generator Operator perspective the proposed definition of Control Center should not affect current operations. However, the proposed
definition of Control Center applies to a new Functional Entity, the Transmission Owner, and as such an implementation plan/period will be
required. Transmission Owner’s should suggest an appropriate plan/period.
Likes

0

Dislikes

0

Response

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer

No

Document Name
Comment
SCL supports the APPA submitted comments.
Likes

0

Dislikes

0

Response

Amy Folz - Southern Indiana Gas and Electric Co. - 1,3,5,6 - RF
Answer
Document Name
Comment

No

Vectren respectfully requests the SDT consider that Responsible Entities which are impacted by these changes should have at least 12 months to
implement the new definition, similar to other NERC operational and CIP standards.
Likes

0

Dislikes

0

Response

Shelby Wade - PPL - Louisville Gas and Electric Co. - 3,5,6 - SERC, Group Name Louisville Gas and Electric Company and Kentucky Utilities
Company
Answer

No

Document Name
Comment
We support SERC's comments.
Likes

0

Dislikes

0

Response

David Greene - SERC Reliability Corporation - 10, Group Name SERC CIPC
Answer

No

Document Name
Comment
•

Alternate Implementation Period: 2 Year Implementation Plan Period

Rationale: There are a number of factors to consider, and all affect the time required to implement, to include the following:
•

Likes
Dislikes

0
0

o

Complexity of the technology solutions to be implemented,

o

Number of interconnecting lines to secure,

o

Troubleshooting/testing at each connection point, and

o

Coordination requirements with external stakeholders

Response

Julie Hall - Entergy - 6, Group Name Entergy/NERC Compliance
Answer

No

Document Name
Comment
Would recommend at least a 30 day implementation period upon applicable governmental authority approval to allow entities appropriate time to make
any necessary changes to policies, procedures and other necessary administrative documentation and make notification and training as necessary.
Likes

0

Dislikes

0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

No

Document Name
Comment
The SPP Standards Review Group has developed an interpretation based on discussions from the CIP SDT, it’s believed that this is just a definition
change and no additional implementation time. If this does involve an additional implementation time, we believe 18 months is better than 12 months.
Due to technological changes needed to secure the data and collaboration between sending and receiving party, we feel more time is needed to
implement the standard.
Likes

1

Dislikes

Stephanie Burns, N/A, Burns Stephanie
0

Response

Wendy Center - U.S. Bureau of Reclamation - 1,5
Answer

No

Document Name
Comment
Eighteen calendar months after the approval of the control center definition and the CIP-012-1 standard to allow entities time to evaluate the impact of
the changes effected by the new standard and implement an appropriate response.
Likes

0

Dislikes

0

Response

Barry Lawson - National Rural Electric Cooperative Association - 3,4
Answer

No

Document Name
Comment
NRECA requests that the Implementation Plan (IP) be revised to provide a 24 month period of time for registered entities that do not meet the current
Control Center definition, but under a revised Control Center definition they do have a Control Center. This 24 month time period is necessary to
provide registered entities enough time to deal with procurement and budget cycles, and the implementation of the required technical and procedural
controls for a “low, medium or high” category Control Center.
Likes

0

Dislikes

0

Response

Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

No

Document Name
Comment
Idaho Power proposes that additional implementation time be provided to evaluate the effect of the new definition and to ensure applicable
protections/controls are in place. Idaho Power believes 6 to 12 months would be appropriate.
Likes

0

Dislikes

0

Response

Normande Bouffard - Hydro-Qu?bec Production - 1,5
Answer

No

Document Name
Comment
12 to 18 months needed for new control center
Likes

0

Dislikes

0

Response

Lona Calderon - Salt River Project - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
SRP agrees with APPA and LPPC that this commenting should not be included along with comments to CIP standards. By doing so, the personnel
working exclusively with 693 standards are being excluded and may cause unintentional consequences.
Likes

0

Dislikes

0

Response

Mark Riley - Associated Electric Cooperative, Inc. - 1,3,5,6, Group Name AECI & Member G&Ts
Answer

No

Document Name
Comment
AECI supports NRECA's response to Question 5.
Likes

0

Dislikes

0

Response

Annette Johnston - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1,3
Answer

No

Document Name
Comment
The Implementation Plan for other standards provide that unplanned changes could result in a low impact categorization where previously the asset
containing BES Cyber Systems had no categorization. Categorization changes due to this definition should be treated that same... Under these
circumstances for CIP version 5, Responsible Entities were to comply with all Requirements applicable to low impact BES Cyber Systems within 12
months following the identification and categorization of the affected BES Cyber System.
Likes

0

Dislikes

0

Response

Aaron Austin - AEP - 3,5
Answer

Yes

Document Name
Comment
AEP suggests that the SDT include explicit reference to the section of Implementation Plan for Version 5 CIP Cyber Security Standards for
unplanned changes.

Likes

0

Dislikes

0

Response

Russell Noble - Cowlitz County PUD - 3,5
Answer

Yes

Document Name
Comment
The District believes the proposed timing for the implementation plan is appropriate. The Implementation Plans for in the existing CIP Standards will
cover newly identified Control Centers.
Likes

0

Dislikes

0

Response

Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment
ERCOT ISO supports the comments of the ITC SWG.
Likes

0

Dislikes

0

Response

Jamie Monette - Allete - Minnesota Power, Inc. - 1
Answer

Yes

Document Name
Comment
With regards to CIP, this wouldn’t be a problem. I cannot speak for others that would be impacted.

Likes

0

Dislikes

0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Con-Edison and Dominion
Answer

Yes

Document Name
Comment
Yes, because the Implementation Plan in the CIP Standards will cover newly identified assets.
Likes

0

Dislikes

0

Response

Douglas Webb - Great Plains Energy - Kansas City Power and Light Co. - 1,3,5,6 - SPP RE
Answer

Yes

Document Name
Comment
The company will review current systems and protections against the approved Control Center glossary term and as part of CIP-012-1 implementation.
Likes
Dislikes

0
0

Response

Jack Cashin - American Public Power Association - 4
Answer

Yes

Document Name
Comment
APPA believes the proposed timing for the implementation plan is appropriate. The Implementation Plans for in the existing CIP Standards will cover
newly identified Control Centers.
Likes

0

Dislikes

0

Response

Nicholas Lauriat - Network and Security Technologies - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Leonard Kula - Independent Electricity System Operator - 2

Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Brian Millard - Tennessee Valley Authority - 1,3,5,6 - SERC, Group Name Tennessee Valley Authority
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Chris Scanlon - Exelon - 1,3,5,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

James Poston - Santee Cooper - 1,3,5,6, Group Name Santee Cooper
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Marty Hostler - Northern California Power Agency - 5,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Vivian Vo - APS - Arizona Public Service Co. - 1,3,5,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Sean Bodkin - Dominion - Dominion Resources, Inc. - 3,5,6, Group Name Dominion
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

sean erickson - Western Area Power Administration - 1,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Theresa Rakowsky - Puget Sound Energy, Inc. - 1,3,5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Lan Nguyen - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Sheranee Nedd - PSEG - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer

Yes

Document Name
Comment

Likes

3

PSEG - PSEG Fossil LLC, 5, Kucey Tim; PSEG - Public Service Electric and Gas Co., 1, Smith Joseph;
PSEG - Public Service Electric and Gas Co., 3, Mueller Jeffrey

Dislikes

0

Response

Harold Sherrill - Sempra - San Diego Gas and Electric - 7 - WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Robert Blackney - Edison International - Southern California Edison Company - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 1,3,4
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

David Jendras - Ameren - Ameren Services - 1,3,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Patricia Robertson - BC Hydro and Power Authority - 1,3,5, Group Name BC Hydro
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Brandon Cain - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - FRCC,MRO,WECC,Texas RE,NPCC,SERC,SPP RE, Group
Name Southern Company
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Richard Vine - California ISO - 2
Answer
Document Name
Comment
The California ISO supports the comments of the Security Working Group (SWG)
Likes

0

Dislikes

0

Response

Matthew Beilfuss - WEC Energy Group, Inc. - 3,4,5,6 - MRO,RF
Answer
Document Name
Comment
No comment
Likes

0

Dislikes

0

Response

Brandon McCormick - Florida Municipal Power Agency - 3,4,5 - FRCC, Group Name FMPA
Answer
Document Name
Comment
This seems appropriate for CIP because the Implementation Plans in the other CIP Standards will cover newly identified Control Centers. It is unclear
of the impact on Operations so it also unclear on the implementation of any changes to operations
Likes

0

Dislikes
Response

0

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Absent a specific implementation plan, Texas RE understands the definition would be effective upon FERC approval.
Likes

0

Dislikes

0

Response

Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer
Document Name
Comment
This seems appropriate for CIP because the Implementation Plans in the other CIP Standards will cover newly identified Control Centers. It is unclear
of the impact on Operations so it also unclear on the implementation of any changes to operations.

Likes

0

Dislikes

0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name
Comment
BPA believes that the implementation period is dependent on the clarification of what will or what should become a control center.
Likes

0

Dislikes
Response

0

Marc Donaldson - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6
Answer
Document Name
Comment
Tacoma Power supports the comments of APPA.
Likes

0

Dislikes
Response

0

6. If you have additional comments on the proposed definition of Control Center that you have not provided in response to the questions
above, please provide them here.
Marc Donaldson - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6
Answer
Document Name
Comment
Tacoma Power supports the comments of APPA.
Likes

0

Dislikes

0

Response

Jack Cashin - American Public Power Association - 4
Answer
Document Name
Comment
APPA thanks the SDT for the opportunity to comment.
Likes

0

Dislikes

0

Response

Douglas Webb - Great Plains Energy - Kansas City Power and Light Co. - 1,3,5,6 - SPP RE
Answer
Document Name
Comment
None.
Likes

0

Dislikes
Response

0

Lona Calderon - Salt River Project - 1,3,5,6 - WECC
Answer
Document Name
Comment
SRP is concerned the SDT presented this proposed definition under CIP only. This could result in missing comments from a broader 693 audience who
will be affected by this definition change.
Likes

0

Dislikes

0

Response

Barry Lawson - National Rural Electric Cooperative Association - 3,4
Answer
Document Name
Comment
NRECA appreciates the continued efforts of the CIP SDT.
Likes

0

Dislikes

0

Response

Wendy Center - U.S. Bureau of Reclamation - 1,5
Answer
Document Name
Comment
None.
Likes

0

Dislikes

0

Response

Harold Sherrill - Sempra - San Diego Gas and Electric - 7 - WECC
Answer

Document Name
Comment
·
SDG&E desires clarification on the definition of “associated data centers”. Is it the data centers that house the Industrial Controls Systems (ICS) or
is it all data centers that support the “control center”?

·
The language in the proposed definition excludes oral communication, but could email be considered “data used for Operational Planning Analysis,
Real-time Assessments, and Real-time monitoring”?

·
The proposed definition states: “One or more facilities, including their associated data center, that monitor and control the BES……” SDG&E
recommends the following change: “One or more facilities, including their associated data center, used to monitor and control the BES……”
-In sections where “Transmission Operator” is mentioned the term BES should be inserted before “Transmission Facilities…”
- In sections where “Generator Operator” is mentioned the term BES should be inserted before Generator Operator for “Generation Facilities….”

·
SDG&E believes clarity could be given to the words: “have the capability to develop specific dispatch instructions for plant operators under their
control.”
•

SDG&E seeks clarification on the phrase: “centrally located dispatch center who relay dispatch instructions without making any modifications.”

Likes

0

Dislikes

0

Response

Sheranee Nedd - PSEG - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer
Document Name
Comment
It is unclear if/how RC “backup control center” facilities or TOP/BA “backup functionality” required for RC and TOPs/BAs, respectively, by NERC
reliability standard EOP-008, are addressed by the proposed definition.
Likes

3

Dislikes

PSEG - PSEG Fossil LLC, 5, Kucey Tim; PSEG - Public Service Electric and Gas Co., 1, Smith Joseph;
PSEG - Public Service Electric and Gas Co., 3, Mueller Jeffrey
0

Response

Lan Nguyen - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE

Answer
Document Name
Comment
CenterPoint Energy Houston Electric, LLC believes the revisions to the Control Center definition more accurately identify Control Centers.
Likes

0

Dislikes

0

Response

David Francis - Midcontinent ISO, Inc. - 2,3 - FRCC,MRO,WECC,Texas RE,NPCC,SERC,SPP RE,RF, Group Name SRC + SWG
Answer
Document Name
Comment
The SRC & ITC SWG asserts that the proposed standard does not make clear how entities should work together when addressing security concerns
across a communication network link. If both entities work with CIP Standard assumptions on both ends of a communication network, some support for
joint handling of issues could be made clear. However, if only one entity is CIP-compliant for a given link, the current standard draft does not make
clear the extent of protection expected for the data. The Standard should provide more information on the ownership of obligations for protecting the
entire link

It is unclear whether the addition of CIP-012 affects the exemptions of communication networks in any of the applicability sections of other standards
(CIP-002 through CIP-011). The SWG requests clarification that CIP-012 fills in some of the gap created the CIP-002 – CIP-011 third party
telecommunications exemption (4.2.3.2. Cyber Assets associated with communication networks and data communication links between discrete
Electronic Security Perimeters.)

It has been ten years since the SANDIA report (“Secure ICCP Considerations and Recommendations”), the only detailed report on this subject which
could be considered close having entered mainstream awareness in the industry. Today, as ten years ago, Secure ICCP is not a viable choice for
utilities, if only due to limited community experience and vendor support, not to mention the complexities of key management. The transition strategies
that SANDIA discusses – Layer 3 protection using IPsec and Layer 2 protection with hardware encryption – remain today’s target solutions.
IPsec is a viable alternative. Over MPLS, IPsec could secure GRE tunnels between CE routers. Challenges with this approach include the possibility of
having to hire a third party to manage certificates and IPsec links, especially for ISOs that do not manage their own MPLS networks.

The SRC & ITC SWG position on security architecture is that business transactions (such as ICCP) should not be tightly coupled with encryption
technologies. Solutions should prefer network overlays versus security extensions to a protocol (such as Secure ICCP or DNP3 SA).

The security architecture should prefer least-latent encryption solutions at the Ethernet or IP layers of the network stack. MACsec (802.1AE) models
the spirit of an optimal solution within a metro area – could it scale wider?

The SRC & ITC SWG’s overall position on Secure ICCP is that it represents too much reliability risk. The ITC SWG is concerned about the lack of
open standards and protocols available to meet the confidentiality and integrity security objectives of CIP-012. Assuming that a solution involves
encryption, the only two open standards and protocols that can meet the CIP-012 security objectives are IPsec and TLS. The potential for vendor
leverage in such a small open solution space is large. Vendor-managed MPLS networks, typical among utilities, already entrench high annual
telecommunication costs in utility budgets. Security vendors continue to benefit from the expense of establishing layered cyber defenses. Open Source
solutions provide a cost and agility refuge from this lopsided value chain without compromising defense layers. The trend toward managed services
makes the cost problem worse for utilities, especially in the context of insufficiently evaluated risk. Vendor leverage only grows given the practical
consideration that all the communicating parties in a WAN of connected real-time Control Centers would need to adopt a common solution in order to
minimize complexity and cost.
Likes

0

Dislikes

0

Response

Theresa Rakowsky - Puget Sound Energy, Inc. - 1,3,5
Answer
Document Name
Comment
n/a
Likes

0

Dislikes

0

Response

Thomas Breene - WEC Energy Group, Inc. - 3,4,5,6
Answer
Document Name
Comment
N/A
Likes

0

Dislikes
Response

0

Russell Noble - Cowlitz County PUD - 3,5
Answer
Document Name
Comment
Thank you for the opportunity to comment.
Likes

0

Dislikes

0

Response

Aaron Austin - AEP - 3,5
Answer
Document Name
Comment
None
Likes

0

Dislikes

0

Response

Amy Folz - Southern Indiana Gas and Electric Co. - 1,3,5,6 - RF
Answer
Document Name
Comment
Vectren is committed to the safety and reliability of the BES and committed to compliance excellence. We appreciate the efforts of the Standard
Drafting Team and will be glad to provide any additional detail upon request. Thank you for allowing Vectren the opportunity to provide comments on
this draft definition.
Likes

0

Dislikes
Response

0

Marty Hostler - Northern California Power Agency - 5,6
Answer
Document Name
Comment
No additional comments.
Likes

0

Dislikes

0

Response

Chris Scanlon - Exelon - 1,3,5,6
Answer
Document Name
Comment
No comments
Likes

0

Dislikes

0

Response

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer
Document Name
Comment
SCL supports the APPA submitted comments. Our primary concern here is that it is not appropriate to ballot in CIP only for a far-reaching change that
can impact both O&P and CIP standards.
Likes

0

Dislikes

0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

Document Name
Comment
Texas RE does not have additional comments.
Likes

0

Dislikes

0

Response

Brian Millard - Tennessee Valley Authority - 1,3,5,6 - SERC, Group Name Tennessee Valley Authority
Answer
Document Name
Comment
TVA agrees with the proposed definition of Control Center.
Likes

0

Dislikes

0

Response

George Brown - Acciona Energy North America - 5
Answer
Document Name
Comment
No further comments.
Likes

0

Dislikes

0

Response

Matthew Beilfuss - WEC Energy Group, Inc. - 3,4,5,6 - MRO,RF
Answer
Document Name
Comment

No ocmment
Likes

0

Dislikes

0

Response

Richard Vine - California ISO - 2
Answer
Document Name
Comment
The California ISO supports the comments of the Security Working Group (SWG)
Likes

0

Dislikes
Response

0

Comment Report
Project Name:

2016-02 Modifications to CIP Standards | Technical Rationale and Justification for CIP-012-1

Comment Period Start Date:

8/14/2017

Comment Period End Date:

9/12/2017

Associated Ballots:

There were 42 sets of responses, including comments from approximately 137 different people from approximately 92 companies
representing 10 of the Industry Segments as shown in the table on the following pages.

Questions
1. The SDT developed draft Technical Rationale and Justification for CIP-012-1 to provide stakeholders and the ERO Enterprise an
understanding of the technology and technical requirements in the Reliability Standard. Do you agree that the draft Technical Rationale and
Justification for CIP-012-1 clearly explains the technical reasoning for the proposed standard? If you do not agree, or if you agree but have
comments or suggestions for the draft document, please provide your recommendation and explanation.

Organization
Name

Name

Segment(s)

FirstEnergy - Aaron
1,3,4
FirstEnergy Ghodooshim
Corporation

Southern
Brandon
Company Cain
Southern
Company
Services, Inc.

Florida
Municipal
Power
Agency

Brandon
McCormick

1,3,5,6

3,4,5

Region

RF

FRCC,MRO,NPCC,SERC,SPP
RE,Texas RE,WECC

FRCC

Group
Name

Group Member
Name

Group Member
Organization

Group
Group
Member
Member
Segment(s) Region

FirstEnergy FirstEnergy
Corporation

4

RF

Aubrey Short

FirstEnergy FirstEnergy
Corporation

1

RF

Theresa Ciancio

FirstEnergy FirstEnergy
Corporation

3

RF

Robert Loy

FirstEnergy FirstEnergy
Solutions

5

RF

Ann Ivanc

FirstEnergy FirstEnergy
Solutions

6

RF

Katherine Prewitt

Southern
Company Southern
Company
Services, Inc.

1

SERC

R. Scott Moore

Southern
3
Company Alabama Power
Company

SERC

William D. Shultz

Southern
Company Southern
Company
Generation

5

SERC

Jennifer Sykes

Southern
6
Company Southern
Company
Generation and
Energy
Marketing

SERC

Tim Beyrle

City of New
4
Smyrna Beach
Utilities
Commission

FRCC

Jim Howard

Lakeland
Electric

FRCC

FirstEnergy Aaron Ghdooshim
Corporation

Southern
Company

FMPA

5

Midcontinent David
ISO, Inc.
Francis

2,3

FRCC,MRO,NPCC,RF,SERC,SPP SRC +
RE,Texas RE,WECC
SWG

Lynne Mila

City of
Clewiston

4

FRCC

Javier Cisneros

Fort Pierce
Utilities
Authority

3

FRCC

Randy Hahn

Ocala Utility
Services

3

FRCC

Don Cuevas

Beaches
Energy
Services

1

FRCC

Jeffrey Partington

Keys Energy
Services

4

FRCC

Tom Reedy

Florida
Municipal
Power Pool

6

FRCC

Steven Lancaster

Beaches
Energy
Services

3

FRCC

Mike Blough

Kissimmee
5
Utility Authority

FRCC

Chris Adkins

City of
Leesburg

3

FRCC

Ginny Beigel

City of Vero
Beach

3

FRCC

Gregory Campoli

New York
Independent
System
Operator

2

NPCC

Mark Holman

PJM
2
Interconnection,
L.L.C.

RF

Charles Yeung

Southwest
Power Pool,
Inc. (RTO)

2

SPP RE

Terry BIlke

Midcontinent
ISO, Inc.

2

RF

Elizabeth Axson

Electric
Reliability
Council of
Texas, Inc.

2,3

Texas RE

Ben Li

IESO

1

MRO

Drew Bonser

SWG

NA - Not
Applicable

NA - Not
Applicable

Darrem Lamb

CAISO

2

WECC

SERC
Reliability
Corporation

David
Greene

10

Con Ed Dermot
Consolidated Smyth
Edison Co. of
New York

1,3,5,6

Seattle City
Light

1,3,4,5,6

Santee
Cooper

Ginette
Lacasse

James
Poston

Patricia
Robertson

SERC

NPCC

SERC
CIPC

Matt Goldberg

ISONE

2

NPCC

Bill Peterson

SERC RRO

10

SERC

Mike Hagee

SERC RRO

10

SERC

SERC CIPC

Various

1,2,5,9

SERC

Con Edison
Company of
New York

1,3,5,6

NPCC

Con Edison Dermot Smyth

Edward Bedder

1,3,5,6

1,3,5

WECC

Seattle City Pawel Krupa
Light Ballot
Body
Hao Li

Santee
Cooper

BC Hydro

Orange &
Rockland

NPCC

Seattle City
Light

1

WECC

Seattle City
Light

4

WECC

Bud (Charles)
Freeman

Seattle City
Light

6

WECC

Mike Haynes

Seattle City
Light

5

WECC

Michael Watkins

Seattle City
Light

1,4

WECC

Faz Kasraie

Seattle City
Light

5

WECC

John Clark

Seattle City
Light

6

WECC

Tuan Tran

Seattle City
Light

3

WECC

Laurrie Hammack

Seattle City
Light

3

WECC

Rene' Free

Santee Cooper 1

SERC

Rodger Blakely

Santee Cooper 1

SERC

Chris Jimenez

Santee Cooper 1

SERC

Troy Lee

Santee Cooper 1

SERC

Tom Abrams

Santee Cooper 1

SERC

Jennifer Richards

Santee Cooper 1

SERC

Stony Martin

Santee Cooper 1

SERC

Glenn Stephens

Santee Cooper 1

SERC

Tom Perry

Santee Cooper 1

SERC

Patricia Robertson

BC Hydro and 1
Power Authority

WECC

BC Hydro
and Power
Authority

Northeast
Ruida Shu
Power
Coordinating
Council

1,2,3,4,5,6,7,8,9,10 NPCC

Venkataramakrishnan BC Hydro and 2
Vinnakota
Power Authority

WECC

Pat G. Harrington

BC Hydro and 3
Power Authority

WECC

Clement Ma

BC Hydro and 5
Power Authority

WECC

Northeast
Power
Coordinating
Council

NPCC

RSC no
Guy V. Zito
Con-Edison
and
Dominion

10

Randy MacDonald

New Brunswick 2
Power

NPCC

Wayne Sipperly

New York
4
Power Authority

NPCC

Glen Smith

Entergy
Services

4

NPCC

Brian Robinson

Utility Services 5

NPCC

Bruce Metruck

New York
6
Power Authority

NPCC

Alan Adamson

New York State 7
Reliability
Council

NPCC

Edward Bedder

Orange &
Rockland
Utilities

1

NPCC

David Burke

Orange &
Rockland
Utilities

3

NPCC

Michele Tondalo

UI

1

NPCC

Laura Mcleod

NB Power

1

NPCC

Michael Schiavone

National Grid

1

NPCC

Michael Jones

National Grid

3

NPCC

David Ramkalawan

Ontario Power 5
Generation Inc.

NPCC

Quintin Lee

Eversource
Energy

1

NPCC

Kathleen Goodman

ISO-NE

2

NPCC

Greg Campoli

NYISO

2

NPCC

Silvia Mitchell

NextEra Energy 6
- Florida Power
and Light Co.

NPCC

Southwest
Power Pool,
Inc. (RTO)

PPL Louisville
Gas and
Electric Co.

PSEG

Shannon
Mickens

Shelby
Wade

Sheranee
Nedd

2

3,5,6

1,3,5,6

SPP RE

RF,SERC

NPCC,RF

SPP
Standards
Review
Group

Louisville
Gas and
Electric
Company
and
Kentucky
Utilities
Company

Paul Malozewski

Hydro One
Networks, Inc.

3

NPCC

Sylvain Clermont

Hydro Quebec

1

NPCC

Helen Lainis

IESO

2

NPCC

Chantal Mazza

Hydro Quebec

2

NPCC

Shannon Mickens

Southwest
2
Power Pool Inc.

SPP RE

Deborah McEndaffer Midwest
Energy, Inc.

NA - Not
Applicable

SPP RE

Don Schmit

Nebraska
Public Power
District

5

SPP RE

Louis Guidry

Cleco
Corporation

1,3,5,6

SPP RE

Robert Hirchak

Cleco
Corporation

6

SPP RE

Marty Paulk

Cleco
Corporation

1,3,5,6

SPP RE

Michelle Corley

Cleco
Corporation

3

SPP RE

Robert Gray

Board of Public NA - Not
Utilities
Applicable

SPP RE

Ron Spicer

EDP
Renewables

NA - Not
Applicable

SPP RE

Steven Keller

Southwest
Power Pool

2

SPP RE

Laura Cox

Westar Energy 5

SPP RE

Charles Freibert

PPL - Louisville 3
Gas and
Electric Co.

SERC

Dan Wilson

PPL - Louisville 5
Gas and
Electric Co.

SERC

Linn Oelker

PPL - Louisville 6
Gas and
Electric Co.

SERC

PSEG - PSEG
Fossil LLC

5

RF

PSEG Energy 6
Resources and
Trade LLC

RF

PSEG REs Tim Kucey
Karla Jara

Jeffrey Mueller

PSEG - Public 3
Service Electric
and Gas Co

RF

Joseph Smith

PSEG - Public 1
Service Electric
and Gas Co

RF

1. The SDT developed draft Technical Rationale and Justification for CIP-012-1 to provide stakeholders and the ERO Enterprise an
understanding of the technology and technical requirements in the Reliability Standard. Do you agree that the draft Technical Rationale and
Justification for CIP-012-1 clearly explains the technical reasoning for the proposed standard? If you do not agree, or if you agree but have
comments or suggestions for the draft document, please provide your recommendation and explanation.
Leonard Kula - Independent Electricity System Operator - 2
Answer

No

Document Name
Comment
The IESO offers the following comments:
•

On page 5, under the Control Center Ownership section, the following statement is confusing, “Applying protection among a Responsible
Entity’s owned Control Centers is solely at its discretion.” Our understanding is that choosing to apply protections is not at our discretion, it is
required. We recommend the following, “The method of applying protection to Control Center’s exclusively owned by a Responsible Entity is
solely at its discretion. However, when multiple Responsible Entities own a Control Center at either end of the communication link, applying
protection requires additional coordination and diligence.”

•

Recommend that the rationale state that the standard does not increase the scope of BES Cyber Systems that require protections under CIP002 thru CIP-011. The requirements apply only to the protection of the data that is transmitted across infrastructure not owned by a Responsible
Entity.

•

Implementation guidance is needed on the use of armored cable as a physical security protection method when using leased or subscribed
fiber with multiple telecom carriers in the path. The guidance needs to address router hops and fiber patch panels that exist within a telecom
provider’s central office.

Likes

0

Dislikes

0

Response

Dermot Smyth - Con Ed - Consolidated Edison Co. of New York - 1,3,5,6, Group Name Con Edison
Answer

No

Document Name
Comment
Please disregard answer above. This was an error. I am unable to change it. We have no comments on this item. Dermot Smyth.
Likes

0

Dislikes
Response

0

David Rivera - New York Power Authority - 1,3,5,6
Answer

No

Document Name
Comment
While the CIP standards should emphasize outcomes and allow entities to achieve specific security objectives in many ways, protections applied to
communications should be evaluated with due consideration of the context in which people, processes and technology are applied to establish a given
security protection. Demonstration of risk mitigation should include assessment of not just technology and process to provide protection, but also the
diversity and severity of threats present in a given context (e.g. the difference between dedicated communication links as opposed to broadly shared
communications infrastructure). Particular technology and process applied in a context with fewer or lower likelihood threats should be preferred over
the same technology and process in a context with more or greater likelihood threats (i.e. greater overall risk). Simply specifying that some (how
much?) risk mitigation should be applied by means that include physical, logical and possibly other means leads to insufficient conditions for
establishing compliance both for the responsible entity and anyone reviewing compliance for that entity. Entities should consider not only that risk
mitigation should take place, but also the thresholds for residual risk that should be considered acceptable for such communication.
Likes

0

Dislikes

0

Response

Brandon McCormick - Florida Municipal Power Agency - 3,4,5 - FRCC, Group Name FMPA
Answer

No

Document Name
Comment
FMPA does not agree that the Technical Rationale and Justification for CIP-012-1 fully explains the technical reasoning for the standard.
The Rationale document does not provide justification for the Operational Planning and Analysis data that is included in the scope of this standard.
While the document does provide an example of communication paths (page 5), the example would be improved by adding a communication path
between the TOP Control Center and the GOP Control Center.
Likes

0

Dislikes

0

Response

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer
Document Name

No

Comment
SCL supports APPA comments
Likes

0

Dislikes

0

Response

Marty Hostler - Northern California Power Agency - 5,6
Answer

No

Document Name
Comment
This document does not provide justification for the inclusion of the Operational Planning and Analysis data. NCPA suggests it be removed from the
standards scope.
Likes

0

Dislikes

0

Response

Vivian Vo - APS - Arizona Public Service Co. - 1,3,5,6
Answer

No

Document Name
Comment
AZPS provides the following comments for the SDT’s consideration:
1. The statement provided in “General Considerations for Requirement R1” clearly limits the applicability of Requirement R1 to the real-time
horizon and does not indicate Requirement R1 being applicable to the Operational Planning Horizon. Specifically, the technical justification
states that the focus is on “developing a plan to protect information that is critical to the real-time operations of the Bulk Electric System.” This is
in direct conflict with the draft standard, which scopes the plan to “to mitigate the risk of the unauthorized disclosure or modification of data used
for Operational Planning Analysis, Real-time Assessment, and Real-time monitoring data.” AZPS reiterates its comments in response to the
draft CIP-012-1 that the inclusion of data used for Operational Planning Analysis does not have a meaningful impact on reliability or real-time
operations for the BES such that extending protection to Operational Planning Analysis results in overall benefits to reliability.
2. AZPS is concerned that the rationale provided in “Alignment with IRO and TOP standards” may misalign with the IRO Standards. The IRO and
TOP Standards explicitly allow each responsible entity to develop individual data specifications because responsible entity processes can differ
based upon operational characteristics, coordinated functional registrations, delegation agreements, operating agreements, etc. Statements
within that section that these requirements force consistency in data and data specifications appear to directly conflict with the intent and
flexibility of the IRO and TOP data specification requirements.
3. AZPS also suggests revising the third sentence in the section entitled “Control Center Ownership” because that sentence, read alone, absolves
a responsible entity from protecting communications between its own control centers. The sentence in question reads “Applying protection

among a Responsible Entity’s owned Control Centers is solely at its discretion.” This sentence also seems to conflict with the first sentence in
the same section.
Likes

0

Dislikes

0

Response

Aaron Austin - AEP - 3,5
Answer

No

Document Name
Comment
The document makes a good case for the security needed for Real-time data. It does not treat the Planning and Analysis data as well. Please
see the AEP comments in the Unofficial Comment Form for CIP-012-1.
Likes

0

Dislikes

0

Response

sean erickson - Western Area Power Administration - 1,6
Answer

No

Document Name

Project 2016-02_CIP-012-1_NSRF Final.docx

Comment
WAPA feels there is additional need for clarity and proposed language as identified in the NSRF comments.
Likes

0

Dislikes

0

Response

Russell Noble - Cowlitz County PUD - 3,5
Answer

No

Document Name
Comment
Cowlitz PUD supports comment submitted by APPA.

Likes

0

Dislikes

0

Response

David Francis - Midcontinent ISO, Inc. - 2,3 - FRCC,MRO,WECC,Texas RE,NPCC,SERC,SPP RE,RF, Group Name SRC + SWG
Answer

No

Document Name
Comment
The SRC & ITC SWG offers the following comments:
On page 5, under the Control Center Ownership section, the following statement is confusing, “Applying protection among a Responsible Entity’s owned
Control Centers is solely at its discretion.” Our understanding is that choosing to apply protections is not at our discretion, it is required. We recommend
the following, “The method of applying protection to Control Center’s exclusively owned by a Responsible Entity is solely at its discretion. However,
when multiple Responsible Entities own a Control Center at either end of the communication link, applying protection requires additional coordination
and diligence.”

Recommend that the rationale state that the standard does not increase the scope of BES Cyber Systems that require protections under CIP-002 thru
CIP-011. The requirements apply only to the protection of the data that is transmitted across infrastructure not owned by a Responsible Entity.

Implementation guidance is needed on the use of armored cable as a physical security protection method when using leased or subscribed fiber with
multiple telecom carriers in the path. The guidance needs to address router hops and fiber patch panels that exist within a telecom provider’s central
office.
Likes

0

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0

Response

Michael Puscas - ISO New England, Inc. - 2
Answer

No

Document Name
Comment
In order to evaluate the extent and kind of obligation involved, the definition of between control centers needs to be clearer with regard to the
communication link. What are the demarcation points for obligation to show compliance? Should there be explicit agreements with each end of the
communication link to arrange such demarcation? How should responsible entities deal with third parties involved with trust relationships in
communication links (i.e. telecommunications providers managing routers)?

Likes

0

Dislikes

0

Response

Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer

No

Document Name
Comment

A) It is understood that the reference model shown on page 5 is an example of communication paths. Suggest adding the communication path
between the TOP Control Center and the GOP Control Center to provide further clarity.

B) This document does not provide justification for the inclusion of the Operational Planning and Analysis data is included in the scope of this
standard. Suggest that this be added to the Technical Rationale and Justification document or this data be removed from the scope of the standard.
Likes

0

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0

Response

Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer

No

Document Name
Comment
ERCOT ISO supports the comments of the ITC SWG.
The ITC SWG offers the following comments:
•

On page 5, under the Control Center Ownership section, the following statement is confusing, “Applying protection among a Responsible
Entity’s owned Control Centers is solely at its discretion.” Our understanding is that choosing to apply protections is not at our discretion, it is
required. We recommend the following, “The method of applying protection to Control Center’s exclusively owned by a Responsible Entity is
solely at its discretion. However, when multiple Responsible Entities own a Control Center at either end of the communication link, applying
protection requires additional coordination and diligence.”

•

Recommend that the rationale state that the standard does not increase the scope of BES Cyber Systems that require protections under CIP002 thru CIP-011. The requirements apply only to the protection of the data that is transmitted across infrastructure not owned by a Responsible
Entity.

•

Implementation guidance is needed on the use of armored cable as a physical security protection method when using leased or subscribed
fiber with multiple telecom carriers in the path. The guidance needs to address router hops and fiber patch panels that exist within a telecom
provider’s central office.

Likes

0

Dislikes

0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

No

Document Name
Comment
The SPP Standards Review Group recommends that the drafting team includes other Standards that are identified in question #2 comment form
(Glossary of Terms Used in NERC Reliability Standards-Control Center). From our perspective, the technical documents only mention the applicable
TOP and IRO Standards. If other standards are identified that are potentially impacted by this definition change, they need to be included in that the
documentation to help support justification as well as showing consistency.
Likes

1

Dislikes

Stephanie Burns, N/A, Burns Stephanie
0

Response

James Gower - Entergy - NA - Not Applicable - SERC
Answer

No

Document Name
Comment
The standard as drafted explicitly excludes oral communications, but does not consider forms of written communication (email, chat, etc) that could
communicate the same type of information that an oral communication could. These written instructions are commonly outside of SCADA systems and
are on corporate systems, and this standard would require physical or logical controls on those systems for communications that may traverse these
systems. The standard should specify the protection of “operational data”, “BCS Data”, or some other term to clarify protection of data outside of
instructions, or provide data validation (i.e verify emails by phone) as an acceptable control.

Additionally, Entergy has concerns over expanding the scope of protection from “real-time” as defined in other CIP standards and through existing CIP
definitions, to require the protection of Operational Planning Analysis data that is outside of the “real-time” horizon.
Likes
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0
0

Response

Wendy Center - U.S. Bureau of Reclamation - 1,5
Answer

No

Document Name
Comment
Reclamation recommends the NIST definitions of “confidentiality” and “integrity” be added to the NERC Glossary of Terms Used in Reliability
Standards, rather than referring to NIST Special Publication 800-53A, Revision 4.

Reclamation also recommends the Drafting Team state clearly that examples provided in Technical Rationale and Justification documents are neither
mandatory, nor enforceable, nor the only method of achieving compliance.
Likes

0

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0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Con-Edison and Dominion
Answer

No

Document Name
Comment
While the CIP standards should emphasize outcomes, and allow entities to achieve specific security objectives in many ways, protections applied to
communications should be evaluated with due consideration of the context in which people, processes and technology are applied to establish a given
security protection. Demonstration of risk mitigation should include assessment of not just technology and process to provide protection, but also the
diversity and severity of threats present in a given context (e.g. the difference between dedicated communication links as opposed to broadly shared
communications infrastructure). Particular technology and process applied in a context with fewer or lower likelihood threats should be preferred over
the same technology and process in a context with more or greater likelihood threats (i.e. greater overall risk). Simply specifying that some (how
much?) risk mitigation should be applied by means that include physical, logical and possibly other means leads to insufficient conditions for
establishing compliance both for the responsible entity and anyone reviewing compliance for that entity. Entities should consider not only that risk
mitigation should take place, but also the thresholds for residual risk that should be considered acceptable for such communication.
Likes

0

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0

Response

Lona Calderon - Salt River Project - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
This document does not address what equally effective methods are or what appropriate physical controls may be. It also does not discuss where
physical controls may or may not be appropriate over logical controls such as encryption. SRP also does not believe the document addresses latency or
computer resource concerns. SRP requests additional guidance on what would be acceptable for these items.
SRP also agrees with APPA’s recommendation to provide justification for the inclusion of the Operational Planning and Analysis data in the scope of
this standard.

Likes

0

Dislikes

0

Response

Brandon Cain - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - FRCC,MRO,WECC,Texas RE,NPCC,SERC,SPP RE, Group
Name Southern Company
Answer

No

Document Name
Comment
Southern disagrees with the Technical Rationale and Justification for CIP-012 for several reasons. We feel that the “data centric approach” being
pursued opens the door for misinterpretation and the unintentional scoping-in of data that does not require protection. We are concerned that under the
proposed Standard, the efforts required in redefining the data to be protected will obscure the true intent of the standard which is to protect the
communications links over which the data travels. We feel that clarification of the scope of the data to be protected is essential for ensuring that the
correct communications links are secured and the standard can be properly implemented via an appropriate technical solution. As currently written,
Southern feels that the scope is too broad and the protections required would be cost prohibitive.
Likes

0

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0

Response

Jack Cashin - American Public Power Association - 4
Answer
Document Name
Comment

No

APPA does not agree that the Technical Rationale and Justification for CIP-012-1 fully explains the technical reasoning for the standard. The document
does not address what equally effective methods are, or what appropriate physical controls may be. Nor does it discuss where physical controls may or
may not be appropriate over logical controls such as encryption. In addition, latency and computer resource concerns are not addressed.
The Rationale document does not provide justification for the Operational Planning and Analysis data that is included in the scope of this standard.

While the document does provide an example of communication paths (page 5), the example would be improved by adding a communication path
between the TOP Control Center and the GOP Control Center.
Likes

0

Dislikes

0

Response

Annette Johnston - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1,3
Answer

No

Document Name
Comment
MidAmerican Energy Company comments on the CIP-012 focused on two major areas which impact the Technical Rationale and Justification
document.
One,we do not agree with two separate requirements, one for a plan and one to implement. We recommend following precedent in the other CIP
standards, for example, CIP-004 through CIP-011. The obligation can be accomplished with one requirement,
Two, the scoping for sensitive data should be explicitly to information exchanged between Control Centers' BES Cyber Systems. This corresponds to
SDT's assertation that "this data resides within BES Cyber Systems, and while at rest is protected by CIP-003 through CIP-011." It also corresponds to
FERC's recognition in their order that certain entities are already required to exchange necessary real-time and operational planning data through
secured networks using mutually agreeable security protocol.
Additionally, the Technical Rationale and Justification document creates a higher bar than the obligation in the requirement and should be changed.
Specifically, expectation levels are different between the requirement “to mitigate the risk of the unauthorized disclosure or modification of data” and
Technical Rationale and Justification's second sentence in the General Consideration for R2 section on page six, which states, “The protection must
prevent unauthorized disclosure or modification of applicable data”. “Must prevent” is a higher bar than “mitigate the risk of.” The sentence on page 6
should be changed to match the sentence in the requirement.
MidAmerican Energy Company's comments on the proposed Control Center definition reflect concerns that renewable generation resources such as
wind and solar are insufficiently addressed. While the concept of alignment with PER-005-2 has merit, PER-005-2 is antiquated in the reference to
"plant operators located at a generator plant site." Renewable resources do not fit the traditional "plant site" or "plant operators" model of historical
traditional generating plants. (The diagram on page five represents these as "control rooms." We agree with excluding the plant operators at the plant
site for traditional generation. It must also be clear that the operating personnel at wind and solar farms are also excluded.
Corresponding to the comment above, the diagram on page 5 of the Technical Rationale and Justification should include a box to demonstrate with a
red dashed line that renewables operating personnel are also out-of-scope for Control Center communications.

Also in the diagram, we are trying to understand the two BA Control Center boxes. Why does one have no field assets depicted?
Also in the diagram, there is a box for "GOP control room." Shouldn't this be labeled as a GO control room?

Likes

0

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0

Response

Marc Donaldson - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6
Answer

No

Document Name
Comment
Tacoma Power supports the comments of APPA.
Likes

0

Dislikes

0

Response

Joe Tarantino - Sacramento Municipal Utility District - 1,3,4,5,6 - WECC
Answer

Yes

Document Name
Comment

However we are concerned because unauthorized alteration Operational Planning Analysis data does not pose a threat to the BES. This should be
addressed by TOP 010-1 regarding the quality of the data. Accordingly, we are not clear on the utility of the standard since TOP 010-1 will mitigate the
risk. Operational Planning Data is not real time data.

The SDT should consider exempting Email as they did with oral communication because of its use for communicating Operational Planning Data. We
suggest that the SDT communicate the risk related to operational planning analysis data.

We would also like more guidance on key management and inter utility agreements on key management. Whatever measures implemented to meet
compliance, it would increase operational burden and decrease reliability.

It may be more cost effective if an industry wide initiative is conducted with encryption specifications. There may be issues with entities using divergent
technologies and measures to prevent an uncoordinated mismatched implementation that should be addressed. This initiative requires an industry
wide standard, entities cannot decide individually to implement encryption schemes without coordination.

Likes

0

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0

Response

David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment
OPG understands the focus is on protection of data communication between control centers but would like to clarify that it is not being required to verify
integrity of data from it’s origination points to the point where it’s first aggregated at a control center, as this would be a substantially more difficult and
costly requirement to achieve.
Likes

0

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0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
While BPA agrees that the draft Technical Rationale and Justification for CIP-012-1 clearly explains the technical reasoning for the proposed standard,
BPA does not agree that the intent of FERC Order No. 822 has been met. Order No. 822 requires implementation of controls to protect, at a minimum,

communication links AND sensitive BES data communicated between BES Control Centers. However, the SDT is providing latitude to protect
communication links, data or both. BPA recommends placing controls on the data (encryption where availability requirements are not negatively
impacted) AND end points (physical controls) where technically feasible.
Additionally, BPA has concerns about the SDT’s assumption that “availability” is adequately addressed by other NERC standards (TOP-001-4 and IRO002-5), as discussed in the “Overview of confidentiality and integrity” section of the Technical Rationale and Justification.
1. The proposed language includes protection of “confidentiality and integrity of data” but excludes “availability” from the language of the
requirement. However, in the Confidentiality/Integrity/Availability (CIA) triad for information security, each leg must be balanced against the
other two legs. By segregating Availability to TOP-001-4 and IRO-002-5, while leaving Confidentiality/Integrity in the proposed CIP-012
standard, it becomes impossible to properly balance all three legs of the triad to achieve optimum Reliability of the BES. The cyber security
triad represents design tradeoffs; entities can’t properly design communications networks – or worse: existing infrastructure may need to be
rebuilt – if one of the options (Availability) is removed from consideration.
2. While TOP-001-4 and IRO-002-5 (redundancy and diverse routing of data) can be used to increase Availability, Availability can also be
achieved through other equally effective methods. Therefore, “Availability” is not adequately addressed by TOP-001-4 and IRO-002-5 and
limits entities’ options to address availability by other methods more appropriate to their systems.
Therefore, BPA proposes that “availability” be included in the Technical Rationale and Justification to meet the security objectives of Order 822, i.e.,
“…to protect AVAILABILITY, confidentiality and integrity of data required for reliable operation....”
BPA also encourages the SDT to use the Guidelines and Technical Basis section to recognize the distinction between the engineering/design term
“availability” (in which availability is quantitative – e.g., a system is designed to be available 99.99% of the time) and the cyber security
application in which availability is a qualitative element of security that is constantly balanced against two other (often competing) elements
(confidentiality and integrity).
Likes

0

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0

Response

Nicholas Lauriat - Network and Security Technologies - 1
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Chris Scanlon - Exelon - 1,3,5,6
Answer
Document Name

Yes

Comment

Likes

0

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0

Response

James Poston - Santee Cooper - 1,3,5,6, Group Name Santee Cooper
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Shelby Wade - PPL - Louisville Gas and Electric Co. - 3,5,6 - SERC, Group Name Louisville Gas and Electric Company and Kentucky Utilities
Company
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Theresa Rakowsky - Puget Sound Energy, Inc. - 1,3,5
Answer

Yes

Document Name
Comment

Likes
Dislikes

0
0

Response

David Greene - SERC Reliability Corporation - 10, Group Name SERC CIPC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Sheranee Nedd - PSEG - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer

Yes

Document Name
Comment

Likes

3

Dislikes

PSEG - PSEG Fossil LLC, 5, Kucey Tim; PSEG - Public Service Electric and Gas Co., 1, Smith Joseph;
PSEG - Public Service Electric and Gas Co., 3, Mueller Jeffrey
0

Response

Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Jamie Monette - Allete - Minnesota Power, Inc. - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 1,3,4, Group Name FirstEnergy Corporation
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Patricia Robertson - BC Hydro and Power Authority - 1,3,5, Group Name BC Hydro
Answer

Yes

Document Name
Comment

Likes
Dislikes

0
0

Response

Douglas Webb - Great Plains Energy - Kansas City Power and Light Co. - 1,3,5,6 - SPP RE
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Richard Vine - California ISO - 2
Answer
Document Name
Comment
The California ISO supports the comments of the Security Working Group (SWG).
Likes

0

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0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE understands that the intent of a Technical Rationale document, as presented to the NERC Members Representative Committee on August 9,
2017, is to provide stakeholders and the ERO Enterprise an understanding of the technology and technical requirements of the Reliability
Standard. However, the majority of this Technical Rationale Document for proposed Reliability Standard CIP-012-1 appear to be Implementation
Guidance. Texas RE recommends following the process for submitting Implementation Guidance for the content of this document.

Texas RE addressed its concerns with CIP-012-1 in its comments on the requirement language. Please refer to Texas RE’s comments on the
proposed draft of CIP-012-1. If, in the future, a draft Implementation Guidance is posted for review, Texas RE will evaluate it at that point.

Likes

0

Dislikes

0

Response

Normande Bouffard - Hydro-Qu?bec Production - 1,5
Answer
Document Name
Comment
N/A,
Likes

0

Dislikes

0

Response

Comments from Sean Erickson, WAPA
Questions

1. Requirement R1: The SDT drafted CIP-012-1 Requirement R1 to meet the mandatory requirement for the Responsible Entity to develop one or
more documented plan(s) to mitigate the risk of the unauthorized disclosure or modification of data used for Operational Planning Analysis,
Real-time Assessment, and Real-time monitoring data while being transmitted between Control Centers. Do you agree with this revision? If
not, please provide the basis for your disagreement and an alternate proposal.
Yes
No
Comments: As mentioned by the SDT, FERC directs that “…require responsible entities to implement controls to protect, at a minimum,
communication links and sensitive bulk electric system data communicated between bulk electric system Control Centers…”. First, having a plan
does not add to the reliability of protecting said data. This is an unwarranted layer of compliance that is not needed. Everything does not
need a plan in order to be protected. Recommend that R1 be written in parallel to the FERC directive, which does not require a plan (per the
SDTs Consideration of Issues and Directives).
If “Plan” is maintained in CIP-012-1 then, the SDT should explain what is meant by having a Plan? Per CIP-003-6 it states, The terms program
and plan are sometimes used in place of documented processes where it makes sense and is commonly understood. For example, documented
processes describing a response are typically referred to as plans (i.e., incident response plans and recovery plans). Likewise, a security plan

can describe an approach involving multiple procedures to address a broad subject matter. Is a plan the template document which is used
throughout our Standards or is it a set of controls that show that the data is being protected per R1? The NSRF does not understand why a
Plan is needed when the data is being protected by physical or electronic means. If a Plan is required, then all the Plan is going to say is that
the cabling that transfers data is in a protected conduit (or other means) between Control Centers.
Secondly, The NSRF questions why the SDT is not in line with the FERC Order to “…protect …data…” but the proposed R1 states to “…mitigate
the risk of unauthorized discloser or modification of data…”?
R1 should be rewritten to state: “The responsible entity shall have controls (or other understandable words) in place to protect against the
unauthorized disclosure or modification of BES data used for Operational Planning Analysis, Real-time Assessments, and Real-time monitoring
while being transmitted between BES Control Centers. This excludes oral communications”. Please note that the word “BES” is needed within
R1 regardless of it our proposed rewrite is accepted or not.
2. Requirement R1: The SDT seeks comment on the need to scope sensitive BES data as it applies to Operational Planning Analysis, Real-time
Assessment, and Real-time monitoring. Do you agree with scoping CIP-012-1 Requirement R1 in this manner? Please provide comment in
support of your response.
Yes
No
Comments: The SDT needs to add “BES” data into the language as recommended above in question 1.
3. Implementation Plan: The SDT revised the Implementation Plan such that the standard and NERC Glossary terms are effective the first day of
the first calendar quarter that is twelve (12) calendar months after the effective date of the applicable governmental authority’s order
approving the standard, or as otherwise provided for by the applicable governmental authority. Do you agree with this proposal? If you agree
with the proposed implementation time period, please note the actions you will take that require this amount of time to complete. If you think
an alternate implementation time period is needed – shorter or longer - please propose an alternate implementation plan and provide a
detailed explanation of actions and time needed to meet the implementation deadline.
Yes
No
Comments: The 12 month time period may only work for Entities who are vertically intergraded. The flow of applicable BES data within CIP012-1 can be viewed as a “spider web” of data transfer for large RC foot-prints. With this being said, there may be non-compliance issues
when one side of the data transference is protected and the other side is not. The SDT should propose a phased in approach to protecting
data. A five (5) year implementation plan will allow entities to fund these projects. This is especially import to small entities. Per the NERC
Guidance concerning “Phase Implementation Plans with Completion Percentages
(http://www.nerc.com/pa/comp/guidance/CMEPPracticeGuidesDL/CMEP_Practice_Guide_Phased_Implementation_Completion_Percentages.
pdf) please state that the CIP-012-1 does not fall under this guidance.

4. The SDT believes proposed CIP-012-1 provides entities with flexibility to meet the reliability objectives in a cost effective manner. Do you
agree? If you do not agree, or if you agree but have suggestions for improvement to enable more cost effective approaches, please provide
your recommendation and, if appropriate, technical justification.
Yes
No
Comments: Thank you for adding the third bullet of R1.
5. If you have additional comments on the proposed CIP-012-1 – Cyber Security -- Communication Networks drafted in response to the FERC
directive that you have not provided in response to the questions above, please provide them here.
Comments:
1. The NSRF questions the use of “Real-time monitoring” as an applicable object within R1. “Real-time” is defined as “present time as
opposed to future time”. Which our industry understands and without the word “monitoring” being defined, may lead to misinterpretation by
responsible entities and CEAs, alike. The word “monitoring” may mean ALL monitoring of an entity’s entire SCADA system. It should be the
“monitoring” of BES data, only, that is required for Operational Planning Analysis and Real-time Assessments.
2. The Applicability section states, “For requirements in this standard where a specific functional entity or subset of functional entities are the
applicable entity or entities, the functional entity or entities are specified explicitly”. This proposed Standard does not specify any specific
entities and recommend that this be removed.
3. The NSRF has concerns with the proposed definition of Control Center. The largest issue is the last paragraph concerning a Generating
Operator. The use of the word “capability” is ambiguous and will confuse Registered Entities and CEAs, a like. The SDT should consider the
approved Applicability within PER-005-2 part 4.1.5.1, which reads:
Dispatch personnel at a centrally located dispatch center who receive direction from the Generator Operator’s Reliability Coordinator,
Balancing Authority, Transmission Operator, or Transmission Owner, and may develop specific dispatch instructions for plant operators under
their control. These personnel do not include plant operators located at a generator plant site or personnel at a centrally located dispatch
center who relay dispatch instructions without making any modifications.
This aligns with current and understood wording of PER-005-2.
4. Are the noted “Real-time reliability related- tasks” within the proposed definition, the same “Real-time Reliability-related task prescribed in
PER-005-2? If so, please state this in your consideration of comments document and within your guidance document.
5. The NSRF believes that data associated with Operational Planning Analyses (OPA), Real-time monitoring (RTm), and Real-time Assessments
(RTA) are predicated on other Standards and protection of data is required but all three areas (OPA, RTm, and RTA) are not subject equally to
the Applicable Entities noted in CIP-012-1. Per IRO-010-2, R1, the RC is to document its specifications necessary for OPA, RTm, and RTA. Per
TOP-003-3, R1 the TOP is to document its specifications necessary for OPA, RTm, and RTA. Per TOP-003-3, R2, the BA is to document its

specifications necessary for analysis functions and RTm, only. The SDT, in the Technical Rationale and Justification document acknowledges
TOP-003 and IRO-010 “provides consistent scoping of identified data” [R1 section: Alignment with IRO and TOP Standards”]. The SDT should
quantify that the data to be protected is the data associated with the Applicable entities with IRO-010-2 and TOP-003-3. With doing this, the
SDT will articulate what the entity is to preform what analysis and what “data” is to be protected, based on already approved NERC Reliability
Standards. By clearly identifying (and linking) the data to be protected from the data specifications developed under Standards TOP-003 and
IRO-010, there is no room for interpretation of what “data” is to be protected.

CIP-012-1 – Cyber Security – Communications between Control Centers

Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).

Description of Current Draft
This is the second draft of the proposed standard.
Completed Actions

Date

Standards Committee approved Standard Authorization Request
(SAR) for posting

March 9, 2016

SAR posted for comment

March 23 - April 21,
2016

SAR posted for comment

June 1 – June 30,
2016

Informal comment period

February 10- March
13, 2017

45-day formal comment period with additional ballot

July 27 – September
11, 2017

45-day formal comment period with additional ballot

October 27 –
December 11, 2017

Anticipated Actions

Date

10-day final ballot

TBD

Board

TBD

Draft 2 of CIP-012-1
October 2017

Page 1 of 7

CIP-012-1 – Cyber Security – Communications between Control Centers

A. Introduction
1.

Title: Cyber Security – Communications between Control Centers

2.

Number: CIP-012-1

3.

Purpose: To protect the confidentiality and integrity of Real-time Assessment and
Real-time monitoring and control data transmitted between Control Centers.

4.

Applicability:
4.1. Functional Entities: The requirements in this standard apply to the following
functional entities, referred to as “Responsible Entities,” that own or operate a
Control Center.
4.1.1. Balancing Authority
4.1.2. Generator Operator
4.1.3. Generator Owner
4.1.4. Reliability Coordinator
4.1.5. Transmission Operator
4.1.6. Transmission Owner
4.2. Exemptions: The following are exempt from Reliability Standard CIP-012-1:
4.2.1. Cyber Assets at Facilities regulated by the Canadian Nuclear Safety
Commission.
4.2.2. The systems, structures, and components that are regulated by the
Nuclear Regulatory Commission under a cyber security plan pursuant to
10 C.F.R. Section 73.54.

5.

Effective Date: See Implementation Plan for CIP-012-1.

B. Requirements and Measures
R1.

The Responsible Entity shall develop one or more documented plan(s) to mitigate the
risk of unauthorized disclosure or modification of Real-time Assessment and Real-time
monitoring and control data while being transmitted between any Control Centers.
This requirement excludes oral communications. The plan shall include: [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning]
1.1. Identification of security protection used to mitigate the risk of unauthorized
disclosure or modification of Real-time Assessment and Real-time monitoring
and control data while being transmitted between Control Centers;
1.2. Identification of demarcation point(s) where security protection is applied for
transmitting Real-time Assessment and Real-time monitoring and control data
between Control Centers; and

Draft 2 of CIP-012-1
October 2017

Page 2 of 7

CIP-012-1 – Cyber Security – Communications between Control Centers

1.3. Identification of roles and responsibilities of each Responsible Entity for applying

security protection to the transmission of Real-time Assessment and Real-time
monitoring and control data between Control Centers, when the Control Centers are
owned or operated by different Responsible Entities.

M1. Evidence may include, but is not limited to, documented plan(s) that meet the
security objective of Requirement R1.
R2.

The Responsible Entity shall implement the plan(s) specified in Requirement R1,
except under CIP Exceptional Circumstances.

M2. Evidence may include, but is not limited to, documentation demonstrating
implementation of the plans developed pursuant to Requirement R1.

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority”
means NERC, the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below
is shorter than the time since the last audit, the Compliance Enforcement
Authority may ask an entity to provide other evidence to show that it was
compliant for the full-time period since the last audit.
The Responsible Entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation.
•

The Responsible Entities shall keep data or evidence of each Requirement in
this Reliability Standard for three calendar years.

•

If a Responsible Entity is found non-compliant, it shall keep information
related to the non-compliance until mitigation is complete and approved or for
the time specified above, whichever is longer.

•

The Compliance Enforcement Authority (CEA) shall keep the last audit records
and all requested and submitted subsequent audit records.

1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers
to the identification of the processes that will be used to evaluate data or

Draft 2 of CIP-012-1
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CIP-012-1 – Cyber Security – Communications between Control Centers

information for the purpose of assessing performance or outcomes with the
associated Reliability Standard.

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CIP-012-1 – Cyber Security – Communications between Control Centers

Violation Severity Levels
Violation Severity Levels

R#

R1.

R2.

Lower VSL

Moderate VSL

High VSL

Severe VSL

N/A

The Responsible Entity
documented its plan(s) but
failed to include one of the
applicable parts of the plan
as specified in Requirement
R1.

The Responsible Entity
documented its plan(s) but
failed to include two of the
applicable parts of the plan
as specified in Requirement
R1.

The Responsible Entity failed
to document plan(s) for
Requirement R1.

N/A

N/A

N/A

The Responsible Entity failed
to implement its plan(s) as
specified in Requirement R1,
except under CIP Exceptional
Circumstances.

D. Regional Variances
None.

E. Associated Documents
Implementation Plan.

Draft 2 of CIP-012-1
October 2017

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CIP-012-1 – Cyber Security – Communications between Control Centers

Version History
Version

Date

1

TBD

Draft 2 of CIP-012-1
October 2017

Action

Respond to FERC Order No. 822

Change
Tracking

N/A

Page 6 of 7

CIP-012-1 Supplemental Material

Standard Attachments
None.

Draft 2 of CIP-012-1
October 2017

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CIP-012-1 – Cyber Security – Communications between Control Center Communication
NetworksCenters

Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).

Description of Current Draft
This is the firstsecond draft of the proposed standard.
Completed Actions

Date

Standards Committee approved Standard Authorization Request
(SAR) for posting

March 9, 2016

SAR posted for comment

March 23 - April 21,
2016

SAR posted for comment

June 1 – June 30,
2016

Informal comment period

February 10- March
13, 2017

45-day formal comment period with additional ballot

July 27 – September
11, 2017

45-day formal comment period with additional ballot

October 27 –
December 11, 2017

Anticipated Actions

Date

45-day formal comment period with additional ballot

TBD

10-day final ballot

TBD

Board

TBD

Upon Board adoption, the rationale boxes will be moved to the Supplemental Material Section.

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CIP-012-1 – Cyber Security – Communications between Control Center Communication
NetworksCenters

A. Introduction
1.

Title: Cyber Security – Communications between Control Center Communication
Networks Centers

2.

Number: CIP-012-1

3.

Purpose: To protect the confidentiality and integrity of Real-time Assessment and
Real-time monitoring and control data transmitted between Control Centers required
for reliable operation of the Bulk Electric System (BES)..

4.

Applicability:
4.1. Functional Entities: For the purpose of theThe requirements contained
herein,in this standard apply to the following list of functional entities will be
collectively, referred to as “Responsible Entities.” For requirements in this
standard where a specific functional entity,” that own or subset of functional
entities are the applicable entity or entities, the functional entity or entities
are specified explicitly.operate a Control Center.
4.1.1. Balancing Authority
4.1.2. Generator Operator
4.1.3. Generator Owner
4.1.4. Reliability Coordinator
4.1.5. Transmission Operator
4.1.6. Transmission Owner
4.2. Exemptions: The following are exempt from Reliability Standard CIP-012-1:
4.2.1. Cyber Assets at Facilities regulated by the Canadian Nuclear Safety
Commission.
4.2.2. The systems, structures, and components that are regulated by the
Nuclear Regulatory Commission under a cyber security plan pursuant to
10 C.F.R. Section 73.54.

5.

Effective Date: See Implementation Plan for CIP-012-1.

B. Requirements and Measures
Rationale for Requirements R1 and R2: FERC Order No. 822 directed NERC to develop
modifications to the CIP Reliability Standards to require Responsible Entities to implement
controls to protect communication links and sensitive Bulk Electric System (BES) data
communicated between BES Control Centers. Reliability Standard CIP-012-1 responds to that
directive, requiring Responsible Entities to develop a plan to protect the confidentiality and
integrity of sensitive data while being transmitted between Control Centers. Responsible
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CIP-012-1 – Cyber Security – Communications between Control Center Communication
NetworksCenters

Entities use various means to communicate information between Control Centers. The plan
for protecting these communications is required for all impact levels due to the interdependency of multiple impact levels.
The type of data in scope of CIP-012-1 is data used for Operational Planning Analyses, Realtime Assessments, and Real-time monitoring. The terms Operational Planning Analyses, Realtime Assessments, and Real-time used are defined in the Glossary of Terms Used in NERC
Reliability Standards and used in TOP-003 and IRO-010, among other Reliability Standards.
There are differences between the plan(s) required to be developed and implemented for
CIP-012-1 and the protection required in CIP-006-6 Requirement R1 Part 1.10. CIP-012-1
Requirements R1 and R2 protect the applicable data during transmission between two
geographically separate Control Centers. CIP-006 Requirement R1 Part 1.10 protects
nonprogrammable communication components within an Electronic Security Perimeter (ESP)
but outside of a Physical Security Perimeter (PSP). The transmission of applicable data
between Control Centers takes place outside of an ESP. Therefore, the protection contained
in CIP-006-6 Requirement R1 Part 1.10 does not apply.
R1.

The Responsible Entity shall develop one or more documented plan(s) to mitigate the
risk of the unauthorized disclosure or modification of data used for Operational
Planning Analysis, Real-time Assessments,Assessment and Real-time monitoring and
control data while being transmitted between any Control Centers. This requirement
excludes oral communications. The plan shall include: [Violation Risk Factor: Medium]
[Time Horizon: Operations Planning]
1.1. Risk mitigation shall be accomplished by one or more of the following actions:
•

Physically protecting the communication links transmitting the data;

•

Logically protecting the data during transmission; or

1.2.1.1.
Using an equally effective methodIdentification of security protection
used to mitigate the risk of unauthorized
disclosure or modification of the data. Real-time Assessment and Real-time
monitoring and control data while being transmitted between Control Centers;
Note: If the Responsible Entity does not have a Control Center or it does not transmit
the type of data specified in Requirement R1 of CIP-012-1 between two Control
Centers, the requirements in CIP-012-1 would not apply to that entity.
1.2. Identification of demarcation point(s) where security protection is applied for
transmitting Real-time Assessment and Real-time monitoring and control data
between Control Centers; and
1.3. Identification of roles and responsibilities of each Responsible Entity for applying

security protection to the transmission of Real-time Assessment and Real-time
monitoring and control data between Control Centers, when the Control Centers are
owned or operated by different Responsible Entities.

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CIP-012-1 – Cyber Security – Communications between Control Center Communication
NetworksCenters

M1. Evidence may include, but is not limited to, documented plan(s) that meet the
security objective of Requirement R1.
R2.

The Responsible Entity shall implement the plan(s) specified in Requirement R1,
except under CIP Exceptional Circumstances.

M2. Evidence may include, but is not limited to, documentation to
demonstratedemonstrating implementation of methods to mitigate the risk of the
unauthorized disclosure or modification of data inplans developed pursuant to
Requirement R1.

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority”
means NERC or, the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below
is shorter than the time since the last audit, the Compliance Enforcement
Authority may ask an entity to provide other evidence to show that it was
compliant for the full-time period since the last audit.
The applicable entityResponsible Entity shall keep data or evidence to show
compliance as identified below unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation.
•

The Responsible Entities shall keep data or evidence of each Requirement in
this Reliability Standard for three calendar years.

•

If a Responsible Entity is found non-compliant, it shall keep information
related to the non-compliance until mitigation is complete and approved or for
the time specified above, whichever is longer.

•

The Compliance Enforcement Authority (CEA) shall keep the last audit records
and all requested and submitted subsequent audit records.

1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers
to the identification of the processes that will be used to evaluate data or
information for the purpose of assessing performance or outcomes with the
associated Reliability Standard.
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Violation Severity Levels
Violation Severity Levels

R#

R1.

Lower VSL
N/A

Moderate VSL
N/A

The Responsible Entity
documented its plan(s) but
failed to include one of the
applicable parts of the plan
as specified in Requirement
R1.

R2.

N/A

Draft 12 of CIP-012-1
JuneOctober 2017

N/A

High VSL

Severe VSL

N/AThe Responsible Entity
documented its plan(s) but
failed to include two of the
applicable parts of the plan
as specified in Requirement
R1.

The Responsible Entity failed
to document one or more
plan(s) that achieve the
security objective to mitigate
the risk of unauthorized
disclosure or modification of
data used for Operational
Planning Analysis, Real-time
Assessments, and Real-time
monitoring while being
transmitted, excluding oral
communication, between
Control Centers as specified
in Requirement R1.

N/A

The Responsible Entity failed
to implement its plan(s) to
mitigate the risk of
unauthorized disclosure or
modification of data used for
Operational Planning
Analysis, Real-time
Assessments, and Real-time

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CIP-012-1 – Cyber Security – Communications between Control Center Communication NetworksCenters

monitoring while being
transmitted, excluding oral
communication, between
Control Centers as specified
in Requirement R1, except
under CIP Exceptional
Circumstances.

D. Regional Variances
None.

E. Associated Documents
Implementation Plan.

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NetworksCenters

Version History
Version

Date

1

TBD

Draft 12 of CIP-012-1
JuneOctober 2017

Action

Respond to FERC Order No. 822

Change
Tracking

N/A

Page 7 of 8

CIP-012-1 Supplemental Material

Standard Attachments
None.

Draft 12 of CIP-012-1
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Implementation Plan

Project 2016-02 Modifications to CIP Standards
Reliability Standard CIP-012-1
Applicable Standard
•

Reliability Standard CIP-012-1 - Cyber Security – Communications between Control Centers

Requested Retirements
•

None

Prerequisite Standard
These standard(s) or definitions must be approved before the Applicable Standard becomes
effective:
•

None

Applicable Entities
•
•
•
•
•
•

Balancing Authority
Generator Operator
Generator Owner
Reliability Coordinator
Transmission Operator
Transmission Owner

Effective Date
Reliability Standard CIP-012-1 - Cyber Security – Communications between Control Centers
Where approval by an applicable governmental authority is required, Reliability Standard CIP-012-1
shall become effective on the first day of the first calendar quarter that is twenty-four (24) calendar
months after the effective date of the applicable governmental authority’s order approving the
standard, or as otherwise provided for by the applicable governmental authority.
Where approval by an applicable governmental authority is not required, Reliability Standard CIP012-1 shall become effective on the first day of the first calendar quarter that is twenty-four (24)
calendar months after the date the standard is adopted by the NERC Board of Trustees, or as
otherwise provided for in that jurisdiction.

Implementation Plan

Project 2016-02 Modifications to CIP Standards
Reliability Standard CIP-012-1
Applicable Standard
•

Reliability Standard CIP-012-1 - Cyber Security – Communications between Control Center
Communication NetworksCenters

Requested Retirements
•

None

Prerequisite Standard

These standard(s) or definitions must be approved before the Applicable Standard becomes
effective:
•

None

Applicable Entities
•
•
•
•
•
•

Balancing Authority
Generator Operator
Generator Owner
Reliability Coordinator
Transmission Operator
Transmission Owner

Effective Date
Reliability Standard CIP-012-1 - Cyber Security – Communications between Control Center
Communication NetworksCenters
Where approval by an applicable governmental authority is required, Reliability Standard CIP-012-1
shall become effective on the first day of the first calendar quarter that is twelve (12twenty-four
(24) calendar months after the effective date of the applicable governmental authority’s order
approving the standard, or as otherwise provided for by the applicable governmental authority.
Where approval by an applicable governmental authority is not required, Reliability Standard CIP012-1 shall become effective on the first day of the first calendar quarter that is twelve (12twentyfour (24) calendar months after the date the standard is adopted by the NERC Board of Trustees, or
as otherwise provided for in that jurisdiction.

Unofficial Comment Form

Project 2016-02 Modifications to CIP Standards
CIP-012-1
Do not use this form for submitting comments. Use the Standards Balloting and Commenting System
(SBS) to submit comments on CIP-012-1 – Cyber Security – Communications between Control Centers.
Comments must be submitted by 8 p.m. Eastern, Monday, December 11, 2017.
m. Eastern, Thursday, August 20, 2015
Additional information is available on the project page. If you have questions, contact Katherine Street at
(404) 446-9702 or Mat Bunch at (404) 446-9785.
Background Information

On January 21, 2016, the Commission issued Order No. 822, approving seven CIP Reliability Standards and
new or modified definitions, and directing modifications to the CIP Reliability Standards. Among others,
the Commission directed NERC to “develop modifications to the CIP Reliability Standards to require
responsible entities to implement controls to protect, at a minimum, communication links and sensitive
bulk electric system data communicated between bulk electric system Control Centers in a manner that is
appropriately tailored to address the risks posed to the bulk electric system by the assets being protected
(i.e., high, medium, or low impact).” (Order 822, Paragraph 53)
The Project 2016-02 Standard Drafting Team (SDT) drafted Reliability Standard CIP-012-1 to require
Responsible Entities to implement controls to protect sensitive Bulk Electric System (BES) data while being
transmitted over communications links between BES Control Centers. Due to the sensitivity of the data
being communicated between the Control Centers the standard applies to all impact levels (i.e., high,
medium, or low impact).
The SDT drafted requirements allowing Responsible Entities to apply protection to the links, the data, or
both, to satisfy the security objective consistent with the capabilities of the Responsible Entity’s
operational environment. Requirement R1 requires Responsible Entities to document one or more plans
that protect Real-time Assessment and Real-time monitoring and control data while being transmitted
between Control Centers. The plan(s) must address how the Responsible Entity will mitigate the risk of
unauthorized disclosure or modification of the applicable data. Requirement R2 covers implementation
of the plan developed according to Requirement R1.

Questions

1. Requirement R1: The SDT drafted CIP-012-1 Requirement R1 for the Responsible Entity to develop
one or more documented plan(s) to mitigate the risk of the unauthorized disclosure or
modification of Real-time Assessment and Real-time monitoring and control data while being
transmitted between any Control Centers. Do you agree with this revision? If not, please provide
the basis for your disagreement and an alternate proposal.
Yes
No
Comments:
2. Requirement R1: The SDT seeks comment on scoping sensitive BES data as it applies to Real-time
Assessment and Real-time monitoring and control data. Do you agree with scoping CIP-012-1
Requirement R1 in this manner? Please provide comment in support of your response.
Yes
No
Comments:
3. Requirement R2: The SDT drafted CIP-012-1 Requirement R2 for the Responsible Entity to
implement the plan(s) specified in Requirement R1, except under CIP Exceptional Circumstances.
Do you agree with this revision? If not, please provide the basis for your disagreement and an
alternate proposal.
Yes
No
Comments:
4. Implementation Plan: The SDT revised the Implementation Plan to make the standard effective the
first day of the first calendar quarter that is twenty-four (24) calendar months after the effective
date of the applicable governmental authority’s order approving the standard, or as otherwise
provided for by the applicable governmental authority. Do you agree with this proposal? If you
think an alternate implementation time period is needed, please provide a detailed explanation of
actions and time needed to meet the implementation deadline.
Yes
No
Comments:

Unofficial Comment Form | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | October-December, 2017

2

5. The SDT believes proposed CIP-012-1 provides entities with flexibility to meet the reliability
objectives in a cost effective manner. Do you agree? If you do not agree, or if you agree but have
suggestions for improvement to enable more cost effective approaches, please provide your
recommendation and, if appropriate, technical justification.
Yes
No
Comments:
6. If you have additional comments on the proposed CIP-012-1 – Cyber Security – Communications

between Control Centers drafted in response to the FERC directive that you have not provided in
response to the questions above, please provide them here.
Comments:

Unofficial Comment Form | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | October-December, 2017

3

Project 2016-02 Consideration of Issues and Directives
Federal Energy Regulatory Commission Order No. 822
October 27, 2017

Directives from FERC Order No. 822
Paragraph
53

Directive Language
53. As discussed in detail below, however, the
Commission concludes that modifications to CIP-006-6
to provide controls to protect, at a minimum,
communication links and data communicated
between bulk electric system Control Centers are
necessary in light of the critical role Control Center
communications play in maintaining bulk electric
system reliability. Therefore, we adopt the NOPR
proposal and direct that NERC, pursuant to section
215(d)(5) of the FPA, develop modifications to the CIP
Reliability Standards to require responsible entities to
implement controls to protect, at a minimum,
communication links and sensitive bulk electric system
data communicated between bulk electric system
Control Centers in a manner that is appropriately
tailored to address the risks posed to the bulk electric
system by the assets being protected (i.e., high,
medium, or low impact).

Consideration of Issue or Directive
The Project 2016-02 Standard Drafting Team (SDT) drafted
Reliability Standard CIP-012-1 Requirement R1 to require
responsible entities to document one or more plan(s) to
mitigate the risk of unauthorized disclosure or modification of
Real-time Assessment and Real-time monitoring and control
data while being transmitted between Bulk Electric System
(BES) Control Centers. Requirement R2 requires
implementation of the documented plan(s). Due to the
sensitivity of the data being transmitted between the Control
Centers, the SDT created the standard to apply to all impact
levels of BES Cyber Systems (i.e., high, medium, or low
impact).
Based on operational risk, the SDT determined that Real-time
Assessments and Real-time monitoring and control data was
the appropriate scope of the requirement. This critical
information is necessary for immediate situational awareness
and real-time operation of the BES.

Directives from FERC Order No. 822
Paragraph

54

Directive Language

54. NERC and other commenters recognize that interControl Center communications play a critical role in
maintaining bulk electric system reliability by, among
other things, helping to maintain situational awareness
and reliable bulk electric system operations through
timely and accurate communication between Control
Centers.59 We agree with this assessment. In order for
certain responsible entities such as reliability
coordinators, balancing authorities, and transmission
operators to adequately perform their reliability

Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

Consideration of Issue or Directive
The SDT has drafted requirements allowing Responsible
Entities the flexibility to apply protection to the
communication links, the data, or both, consistent with their
operational environments to satisfy the security objective of
the Commission’s directive
FERC Order No. 822 specifically references CIP-006-6, which
pertains to physical security controls. CIP-006-6, Requirement
R1, Part 1.10 focuses on protecting the nonprogrammable
communication components between Cyber Assets within the
same ESP for medium and high impact BES Cyber Systems. The
SDT asserts that most of the communications contemplated by
FERC Order No. 822 are not within the same ESP, and, as such,
CIP-006-6, Requirement R1, Part 1.10 would not be the
appropriate location for this requirement.
The SDT agrees that inter-Control Center communications play
a critical role in Bulk Electric System reliability. Responsible
Entities should therefore apply security measures to mitigate
the risk of unauthorized disclosure or modification of Realtime Assessment and Real-time monitoring and control data.
Since the current CIP Reliability Standards do not address this,
the SDT has designed requirements to protect the data while it
is being transmitted between inter-entity and intra-entity
Control Centers.

2

Directives from FERC Order No. 822
Paragraph

Directive Language
functions, their associated control centers must be
capable of receiving and storing a variety of sensitive
bulk electric system data from interconnected entities.
Accordingly, we find that additional measures to protect
both the integrity and availability of sensitive bulk
electric system data are warranted.60 We also
understand that the attributes of the data managed by
responsible entities could require different information
protection controls. 61 For instance, certain types of
reliability data will be sensitive to data manipulation
type attacks, while other types of reliability data will be
sensitive to eavesdropping type attacks aimed at
collecting operational information (such as line and
equipment ratings and impedances). NERC should
consider the differing attributes of bulk electric system
data as it assesses the development of appropriate
controls.

Consideration of Issue or Directive
The SDT has drafted requirements that allow responsible
entities to apply protection to the communication links, the
data, or both to satisfy the security objective consistent with
the capabilities of the responsible entity’s operational
environment.

Footnotes:
59 NERC Comments at 20.
60 Protecting the integrity of bulk electric system data
involves maintaining and ensuring the accuracy and
consistency of inter-Control Center communications.
Protecting the availability of bulk electric system data

Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

3

Directives from FERC Order No. 822
Paragraph

55

Directive Language
involves ensuring that required data is available when
needed for bulk electric system operations.
61 Moreover, in order for certain responsible entities to
adequately perform their Reliability Functions, the
associated control centers must be capable of receiving
and storing a variety of sensitive data as specified by the
IRO and TOP Standards. For instance, pursuant to
Reliability Standard TOP-003-3, Requirements R1, R3
and R5, a transmission operator must maintain a
documented specification for data and distribute its
data specification to entities that have data required by
the transmission operator’s Operational Planning
Analyses, Real-time Monitoring and Real-time
Assessments. Entities receiving a data specification must
satisfy the obligation of the documented specification.
55. With regard to NERC’s development of modifications
responsive to our directive, we agree with NERC and
other commenters that NERC should have flexibility in
the manner in which it addresses the Commission’s
directive. Likewise, we find reasonable the principles
outlined by NERC that protections for communication
links and sensitive bulk electric system data
communicated between bulk electric system Control
Centers: (1) should not have an adverse effect on
reliability, including the recognition of instances where

Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

Consideration of Issue or Directive

The SDT drafted Reliability Standard CIP-012-1 requirements to
mitigate the risk of unauthorized disclosure or modification of
Real-time Assessments and Real-time monitoring and control
data while being transmitted between Control Centers. The SDT
rather
than
prescriptive
developed
objective-based
requirements. This approach will allow Responsible Entities
flexibility in protecting these communications networks and
sensitive BES data in a manner suited to each of their respective
operational environments. It will also allow Responsible Entities
to implement protection that considers the risks noted by the
4

Directives from FERC Order No. 822
Paragraph

56

Directive Language
the introduction of latency could have negative results;
(2) should account for the risk levels of assets and
information being protected, and require protections
that are commensurate with the risks presented; and (3)
should be results-based in order to provide flexibility to
account for the range of technologies and entities
involved in bulk electric system communications.62
Footnote:
62 See NERC Comments at 20-21.
56. We disagree with the assertion of NIPSCO and
G&T Cooperatives that the risk posed by bulk electric
system communication networks does not justify the
costs of implementing controls. Communications
between Control Centers over such networks are
fundamental to the operations of the bulk electric
system, and the record here does not persuade us
that controls for such networks are not available at a
reasonable cost (through encryption or otherwise).
Nonetheless, we recognize that not all communication
network components and data pose the same risk to
bulk electric system reliability and may not require the
same level of protection. We expect NERC to develop
controls that reflect the risk posed by the asset or
data being protected, and that can be implemented in

Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

Consideration of Issue or Directive
Commission. The SDT identified a need to mitigate the risk of
unauthorized disclosure or modification of Real-time Assessment
and Real-time monitoring and control data regardless of asset
risk level. The proposal requires protection for all Real-time
Assessment and Real-time monitoring and control data while
being transmitted between Control Centers.

The SDT noted the FERC reference to additional Reliability
Standards (TOP-003-3 and IRO-010-2) and the responsibilities to
protect the data in accordance with those standards. The SDT
interpreted these references as examples of potentially
sensitive BES data and chose to base the CIP-012 requirements
on the data specifications in TOP-003-3 and IRO-010-2.. This
consolidates scoping and helps ensure that Responsible Entities
mitigate the risk of the unauthorized disclosure or modification
of Real-time Assessment and Real-time monitoring and control
data, rather than leaving the scoping of sensitive bulk electric
system data to individual Responsible Entities.
The SDT drafted CIP-012-1 to address confidentiality and
integrity of Real-time Assessment and Real-time monitoring and
control data. This was accomplished by drafting the
5

Directives from FERC Order No. 822
Paragraph

58

Directive Language
a reasonable manner. It is important to recognize that
certain entities are already required to exchange
necessary real-time and operational planning data
through secured networks using a “mutually
agreeable security protocol,” regardless of the entity’s
size or impact level.63 NERC’s response to the
directives in this Final Rule should identify the scope
of sensitive bulk electric system data that must be
protected and specify how the confidentiality,
integrity, and availability of each type of bulk electric
system data should be protected while it is being
transmitted or at rest.
Footnote:
63 See Reliability Standards TOP-003-3, Requirement
R5 and IRO-010-2, Requirement R3.
58. Several commenters sought clarification whether
Control Centers owned by multiple registered entities
would be included under the Commission’s proposal.
We clarify that the scope of the directed modifications
apply to Control Center communications from
facilities at all impact levels, regardless of ownership.
The directed modification should encompass
communication links and data for intra-Control Center
and inter-Control Center communications.

Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

Consideration of Issue or Directive
requirement to mitigate the risk from unauthorized disclosure
or modification. The SDT asserts that the availability of this data
is already required by the performance obligation of the TOP
and IRO Reliability Standards.
The SDT drafted CIP-012-1 to address the data while being
transmitted. The SDT contends that this data is maintained
within BES Cyber Systems, and is afforded the protections of
CIP-003 through CIP-011 while at rest.

The SDT drafted CIP-012-1 to apply to all impact levels of BES
Cyber Systems (i.e., high, medium, or low impact), regardless of
ownership. The SDT designed requirements to mitigate the risk
of unauthorized disclosure or modification of Real-time
Assessment and Real-time monitoring and control data while
being transmitted between inter-entity and intra-entity BES
Control Centers.

6

Directives from FERC Order No. 822
Paragraph
62

Directive Language
62. Several commenters addressed encryption and
latency. Based on the record in this proceeding, it is
reasonable to conclude that any lag in communication
speed resulting from implementation of protections
should only be measureable on the order of
milliseconds and, therefore, will not adversely impact
Control Center communications. Several commenters
raise possible technical implementation difficulties
with integrating encryption technologies into their
current communications networks. Such technical
issues should be considered by the standard drafting
team when developing modifications in response to
this directive, and may be resolved, e.g., by making
certain aspects of the revised CIP Standards eligible
for Technical Feasibility Exceptions.

Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

Consideration of Issue or Directive
The SDT developed objective-based rather than prescriptive
requirements. This approach will allow Responsible Entities
flexibility in mitigating the risk of unauthorized disclosure or
modification of Real-time Assessments and Real-time
monitoring data in a manner suited to each of their respective
operational environments. It will also allow Responsible Entities
to implement protection that considers the risks noted by the
Commission.

7

Project 2016-02 Consideration of Issues and Directives
Federal Energy Regulatory Commission Order No. 822
June 21October 27, 2017

Directives from FERC Order No. 822
Paragraph
53

Directive Language

Consideration of Issue or Directive

53. As discussed in detail below, however, the
Commission concludes that modifications to CIP-006-6
to provide controls to protect, at a minimum,
communication links and data communicated
between bulk electric system Control Centers are
necessary in light of the critical role Control Center
communications play in maintaining bulk electric
system reliability. Therefore, we adopt the NOPR
proposal and direct that NERC, pursuant to section
215(d)(5) of the FPA, develop modifications to the CIP
Reliability Standards to require responsible entities to
implement controls to protect, at a minimum,
communication links and sensitive bulk electric system
data communicated between bulk electric system
Control Centers in a manner that is appropriately
tailored to address the risks posed to the bulk electric
system by the assets being protected (i.e., high,
medium, or low impact).

The Project 2016-02 Standard Drafting Team (SDT) drafted
Reliability Standard CIP-012-1 Requirement R1 to require
responsible entities to document one or more plan(s) to
mitigate the risk of the unauthorized disclosure or
modification of data used for Operational Planning Analysis,
Real-time Assessments,Assessment and Real-time monitoring
and control data while being transmitted between Bulk Electric
System (BES) Control Centers. Requirement R2 requires
implementation of the documented plan(s). Due to the
sensitivity of the data being transmitted between the Control
Centers, as defined in the NERC Glossary of Terms Used in
Reliability Standards, the SDT created the standard and
determined that it appliesto apply to all impact levels of BES
Cyber Systems (i.e., high, medium, or low impact).
Based on operational risk, the SDT determined that Real-time
Assessments and Real-time monitoring and control data was
the appropriate scope of the requirement. This critical

Directives from FERC Order No. 822
Paragraph

Directive Language

Consideration of Issue or Directive
information is necessary for immediate situational awareness
and real-time operation of the BES.
The SDT has drafted requirements allowing Responsible
Entities the flexibility to apply protection to the
communication links, the data, or both, consistent with their
operational environments to satisfy the security objective of
the Commission’s directive, consistent with the capabilities of
the Responsible Entity’s operational environment. The
directive language

54

54. NERC and other commenters recognize that interControl Center communications play a critical role in
maintaining bulk electric system reliability by, among
other things, helping to maintain situational awareness
and reliable bulk electric system operations through

Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

FERC Order No. 822 specifically references CIP-006-6, which
pertains to physical security controls. CIP-006-6, Requirement
R1, Part 1.10 focuses on protecting the nonprogrammable
communication components between Cyber Assets within the
same ESP for medium and high impact BES Cyber Systems. The
SDT asserts that most of the communications contemplated by
theFERC Order No. 822 are not within the same ESP, and that,
as such, CIP-006-6, Requirement R1, Part 1.10 would not be
the appropriate location for this requirement.
The SDT agrees that inter-Control Center communications play
a critical role in Bulk Electric System reliability. Responsible
Entities should therefore apply security measures to mitigate
the risk of the unauthorized disclosure or modification of data
used for Operational Planning Analysis, Real-time
2

Directives from FERC Order No. 822
Paragraph

Directive Language
timely and accurate communication between Control
Centers.59 We agree with this assessment. In order for
certain responsible entities such as reliability
coordinators, balancing authorities, and transmission
operators to adequately perform their reliability
functions, their associated control centers must be
capable of receiving and storing a variety of sensitive
bulk electric system data from interconnected entities.
Accordingly, we find that additional measures to protect
both the integrity and availability of sensitive bulk
electric system data are warranted.60 We also
understand that the attributes of the data managed by
responsible entities could require different information
protection controls. 61 For instance, certain types of
reliability data will be sensitive to data manipulation
type attacks, while other types of reliability data will be
sensitive to eavesdropping type attacks aimed at
collecting operational information (such as line and
equipment ratings and impedances). NERC should
consider the differing attributes of bulk electric system
data as it assesses the development of appropriate
controls.

Consideration of Issue or Directive
Assessments,Assessment and Real-time monitoring, which and
control data. Since the current CIP Reliability Standards do not
address. As such this, the SDT has defineddesigned
requirements that are designed to protect the data while it is
being transmitted between inter-entity and intra-entity
Control Centers.
The SDT has drafted requirements allowingthat allow
responsible entities to apply protection to the communication
links, the data, or both to satisfy the security objective
consistent with the capabilities of the responsible entity’s
operational environment.

Footnotes:
59 NERC Comments at 20.
Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

3

Directives from FERC Order No. 822
Paragraph

Directive Language
the integrity of bulk electric system data
involves maintaining and ensuring the accuracy and
consistency of inter-Control Center communications.
Protecting the availability of bulk electric system data
involves ensuring that required data is available when
needed for bulk electric system operations.
61 Moreover, in order for certain responsible entities to
adequately perform their Reliability Functions, the
associated control centers must be capable of receiving
and storing a variety of sensitive data as specified by the
IRO and TOP Standards. For instance, pursuant to
Reliability Standard TOP-003-3, Requirements R1, R3
and R5, a transmission operator must maintain a
documented specification for data and distribute its
data specification to entities that have data required by
the transmission operator’s Operational Planning
Analyses, Real-time Monitoring and Real-time
Assessments. Entities receiving a data specification must
satisfy the obligation of the documented specification.
55. With regard to NERC’s development of modifications
responsive to our directive, we agree with NERC and
other commenters that NERC should have flexibility in
the manner in which it addresses the Commission’s
directive. Likewise, we find reasonable the principles
outlined by NERC that protections for communication

Consideration of Issue or Directive

60 Protecting

55

Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

The SDT drafted Reliability Standard CIP-012-1 to establish
requirements to mitigate the risk of the unauthorized disclosure
or modification of data used for Operational Planning Analysis,
Real-time Assessments, and Real-time monitoring and control
data while being transmitted between Control Centers. The SDT
developed
objective-based
rather
than
prescriptive
4

Directives from FERC Order No. 822
Paragraph

56

Directive Language
links and sensitive bulk electric system data
communicated between bulk electric system Control
Centers: (1) should not have an adverse effect on
reliability, including the recognition of instances where
the introduction of latency could have negative results;
(2) should account for the risk levels of assets and
information being protected, and require protections
that are commensurate with the risks presented; and (3)
should be results-based in order to provide flexibility to
account for the range of technologies and entities
involved in bulk electric system communications.62
Footnote:
62 See NERC Comments at 20-21.
56. We disagree with the assertion of NIPSCO and
G&T Cooperatives that the risk posed by bulk electric
system communication networks does not justify the
costs of implementing controls. Communications
between Control Centers over such networks are
fundamental to the operations of the bulk electric
system, and the record here does not persuade us
that controls for such networks are not available at a
reasonable cost (through encryption or otherwise).
Nonetheless, we recognize that not all communication
network components and data pose the same risk to

Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

Consideration of Issue or Directive
requirements. This approach will allow Responsible Entities
flexibility in protecting these communications networks and
sensitive BES data in a manner suited to each of their respective
operational environments. It will also allow Responsible Entities
to implement protection that considers the risks noted by the
Commission. The SDT identified a need to mitigate the risk of the
unauthorized disclosure or modification of data used for
Operational Planning Analysis, Real-time Assessment, and Realtime monitoring and control data regardless of asset risk level.
The proposal requires protection for all data used for Operational
Planning Analysis, Real-time Assessment, and Real-time
monitoring and control data while being transmitted between
Control Centers.
The SDT noted the FERC reference to additional Reliability
Standards (TOP-003-3 and IRO-010-2) and the responsibilities to
protect the data in accordance with those standards (TOP-003-3
and IRO-010-2).. The SDT interpreted these references as
examples of potentially sensitive BES data and chose to base the
CIP-012 requirements on the data specifications in these
standards.TOP-003-3 and IRO-010-2.. This consolidates scoping
and helps ensure that Responsible Entities mitigate the risk of
the unauthorized disclosure or modification of Operational
Planning Analysis, Real-time Assessment, and Real-time
monitoring and control data, rather than leaving the scoping of
5

Directives from FERC Order No. 822
Paragraph

58

Directive Language
bulk electric system reliability and may not require the
same level of protection. We expect NERC to develop
controls that reflect the risk posed by the asset or
data being protected, and that can be implemented in
a reasonable manner. It is important to recognize that
certain entities are already required to exchange
necessary real-time and operational planning data
through secured networks using a “mutually
agreeable security protocol,” regardless of the entity’s
size or impact level.63 NERC’s response to the
directives in this Final Rule should identify the scope
of sensitive bulk electric system data that must be
protected and specify how the confidentiality,
integrity, and availability of each type of bulk electric
system data should be protected while it is being
transmitted or at rest.
Footnote:
63 See Reliability Standards TOP-003-3, Requirement
R5 and IRO-010-2, Requirement R3.
58. Several commenters sought clarification whether
Control Centers owned by multiple registered entities
would be included under the Commission’s proposal.
We clarify that the scope of the directed modifications
apply to Control Center communications from

Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

Consideration of Issue or Directive
sensitive bulk electric system data to individual Responsible
Entities.
The SDT drafted CIP-012-1 to address confidentiality and
integrity of data used for Operational Planning Analysis, Realtime Assessment, and Real-time monitoring. These are
accommodated and control data. This was accomplished by
drafting the requirement to mitigate the risk from unauthorized
disclosure or modification. The SDT contendsasserts that the
availability of this data is already required by the performance
obligation of the OperatingTOP and PlanningIRO Reliability
Standards.
The SDT drafted CIP-012-1 to address the data while being
transmitted. The SDT contends that this data is maintained
within BES Cyber Systems, and is afforded the protections of
CIP-003 through CIP-011. while at rest.

The SDT created the standard and determined that it
appliesdrafted CIP-012-1 to apply to all impact levels of BES
Cyber Systems (i.e., high, medium, or low impact), regardless of
ownership. The SDT defineddesigned requirements that are
designed to mitigate the risk of the unauthorized disclosure or
6

Directives from FERC Order No. 822
Paragraph

62

Directive Language
facilities at all impact levels, regardless of ownership.
The directed modification should encompass
communication links and data for intra-Control Center
and inter-Control Center communications.
62. Several commenters addressed encryption and
latency. Based on the record in this proceeding, it is
reasonable to conclude that any lag in communication
speed resulting from implementation of protections
should only be measureable on the order of
milliseconds and, therefore, will not adversely impact
Control Center communications. Several commenters
raise possible technical implementation difficulties
with integrating encryption technologies into their
current communications networks. Such technical
issues should be considered by the standard drafting
team when developing modifications in response to
this directive, and may be resolved, e.g., by making
certain aspects of the revised CIP Standards eligible
for Technical Feasibility Exceptions.

Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

Consideration of Issue or Directive
modification of data used for Operational Planning Analysis,
Real-time Assessment, and Real-time monitoring and control
data while being transmitted between inter-entity and intraentity BES Control Centers.
The SDT developed objective-based rather than prescriptive
requirements. This approach will allow Responsible Entities
flexibility in mitigating the risk of the unauthorized disclosure or
modification of data used for Operational Planning Analysis,
Real-time Assessments, and Real-time monitoring data in a
manner suited to each of their respective operational
environments. It will also allow Responsible Entities to
implement protection that considers the risks noted by the
Commission.

7

Violation Risk Factor and Violation Severity Level Justifications
Project 2016-02 Modifications to CIP Standards
This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in CIP-012-1. Each requirement is assigned a VRF and a VSL. These elements support the determination of
an initial value range for the Base Penalty Amount regarding violations of requirements in FERC-approved Reliability Standards, as defined in
the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT applied the following NERC criteria and FERC Guidelines when
developing the VRFs and VSLs for the requirements.

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•

Emergency operations

•

Vegetation management

•

Operator personnel training

•

Protection systems and their coordination

•

Operating tools and backup facilities

•

Reactive power and voltage control

•

System modeling and data exchange

•

Communication protocol and facilities

•

Requirements to determine equipment ratings

•

Synchronized data recorders

•

Clearer criteria for operationally critical facilities

•

Appropriate use of transmission loading relief.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | October 2017

2

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | October 2017

3

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL

Moderate VSL

The performance or product
measured almost meets the full
intent of the requirement.

The performance or product
measured meets the majority of
the intent of the requirement.

High VSL

The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet
some of the intent.

Severe VSL

The performance or product
measured does not
substantively meet the intent of
the requirement.

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | October 2017

4

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justifications for CIP-012-1, Requirement R1

Proposed VRF

Medium

NERC VRF Discussion

A VRF of Medium was assigned to this requirement. Cyber security plans enable effective implementation
of the CIP standard’s requirements to mitigate the risk of the unauthorized disclosure or modification of
data used for Operational Planning Analysis, Real-time Assessments, and Real-time monitoring while being
transmitted between Control Centers.

FERC VRF G1 Discussion

N/A

Guideline 1- Consistency
with Blackout Report
FERC VRF G2 Discussion

N/A

Guideline 2- Consistency
within a Reliability Standard
FERC VRF G3 Discussion
Guideline 3- Consistency
among Reliability Standards
FERC VRF G4 Discussion
Guideline 4- Consistency
with NERC Definitions of
VRFs
FERC VRF G5 Discussion

The requirement complements CIP-005-1, Requirement R1, CIP-006-6, Requirement R1, and CIP-007-6,
Requirement R1 which are related to security of networks and communications components. The
proposed VRF is consistent with these related requirements.
Failure to have a cyber security plan would not, under Emergency, abnormal, or restorative conditions
anticipated by the preparations, be expected to adversely affect the electrical state or capability of the
Bulk Electric System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

N/A

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | October 2017

5

VRF Justifications for CIP-012-1, Requirement R1

Proposed VRF

Medium

Guideline 5- Treatment of
Requirements that Comingle More than One
Obligation
VSLs for CIP-012-1, Requirement R1

Lower
N/A

Moderate
The Responsible Entity
documented its plan(s) but
failed to include one of the
applicable parts of the plan as
specified in Requirement R1.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | October 2017

High
The Responsible Entity
documented its plan(s) but
failed to include two of the
applicable parts of the plan as
specified in Requirement R1.

Severe
The Responsible Entity failed to
document plan(s) for
Requirement R1.

6

VSL Justifications for CIP-012-1 Requirements R1

FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency
in the Determination of
Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent

The requirement is new. Therefore, the proposed VSL does not have the unintended consequence of
lowering the level of compliance.

The requirement is for the Responsible Entity to document include one or more plans as specified in
Requirement R1.
The moderate VSL addresses where the Responsible Entity documented its plan(s) but failed to include
one of the applicable parts of the plan as specified in Requirement R1.
The high VSL addresses where the Responsible Entity documented its plan(s) but failed to include two of
the applicable parts of the plan as specified in Requirement R1.
The severe VSL addresses where the Responsible Entity failed to document plan(s) for Requirement R1.

Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement

The proposed VSL uses the same terminology as used in the associated requirement and is, therefore,
consistent with the requirement.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | October 2017

7

FERC VSL G4

Each VSL is based on a single violation and not cumulative violations.

Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations

VRF Justifications for CIP-012-1, Requirement R2

Proposed VRF

Medium

NERC VRF Discussion

A VRF of Medium was assigned to this requirement. Implementation of required cyber security plans
enable effective implementation of the CIP standard’s requirements to mitigate the risk of the
unauthorized disclosure or modification of data used for Operational Planning Analysis, Real-time
Assessments, and Real-time monitoring while being transmitted between Control Centers.

FERC VRF G1 Discussion

N/A

Guideline 1- Consistency
with Blackout Report
FERC VRF G2 Discussion

N/A

Guideline 2- Consistency
within a Reliability Standard
FERC VRF G3 Discussion
Guideline 3- Consistency
among Reliability Standards
FERC VRF G4 Discussion

The requirement complements CIP-005-1, Requirement R1, CIP-006-6, Requirement R1, and CIP-007-6,
Requirement R1 which are related to security of networks and communications components. The
proposed VRF is consistent with these related requirements.
Failure to properly implement the cyber security plan would not, under Emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | October 2017

8

VRF Justifications for CIP-012-1, Requirement R2

Proposed VRF

Medium

Guideline 4- Consistency
with NERC Definitions of
VRFs

or capability of the Bulk Electric System, or the ability to effectively monitor, control, or restore the Bulk
Electric System.

FERC VRF G5 Discussion

N/A

Guideline 5- Treatment of
Requirements that Comingle More than One
Obligation
VSLs for CIP-012-1, Requirement R2

Lower
N/A

Moderate
N/A

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | October 2017

High
N/A

Severe
The Responsible Entity failed to
implement its plan(s) as
specified in Requirement R1,
except under CIP Exceptional
Circumstances.

9

VSL Justifications for CIP-012-1 Requirement R2

FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency
in the Determination of
Penalties

The requirement is new. Therefore, the proposed VSL does not have the unintended consequence of
lowering the level of compliance.

The proposed VSL is binary and is classified as severe. The VSL does not use any ambiguous terminology,
thereby supporting uniformity and consistency in the determination of similar penalties for similar
violations.

Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement

The proposed VSL uses the same terminology as used in the associated requirement and is, therefore,
consistent with the requirement.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | October 2017

10

FERC VSL G4

The VSL is based on a single violation and not cumulative violations.

Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | October 2017

11

Violation Risk Factor and Violation Severity Level Justifications
Project 2016-02 Modifications to CIP Standards
This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in CIP-012-1. Each requirement is assigned a VRF and a VSL. These elements support the determination of
an initial value range for the Base Penalty Amount regarding violations of requirements in FERC-approved Reliability Standards, as defined in
the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT applied the following NERC criteria and FERC Guidelines when
developing the VRFs and VSLs for the requirements.

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•

Emergency operations

•

Vegetation management

•

Operator personnel training

•

Protection systems and their coordination

•

Operating tools and backup facilities

•

Reactive power and voltage control

•

System modeling and data exchange

•

Communication protocol and facilities

•

Requirements to determine equipment ratings

•

Synchronized data recorders

•

Clearer criteria for operationally critical facilities

•

Appropriate use of transmission loading relief.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | JulyOctober 2017

2

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.
Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.
Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.
Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | JulyOctober 2017

3

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL

Moderate VSL

The performance or product
measured almost meets the full
intent of the requirement.

The performance or product
measured meets the majority of
the intent of the requirement.

High VSL

The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet
some of the intent.

Severe VSL

The performance or product
measured does not
substantively meet the intent of
the requirement.

FERC Order of Violation Severity Levels
The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.
Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | JulyOctober 2017

4

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justifications for CIP-012-1, Requirement R1

Proposed VRF

Medium

NERC VRF Discussion

A VRF of Medium was assigned to this requirement. Cyber security plans enable effective implementation
of the CIP standard’s requirements to mitigate the risk of the unauthorized disclosure or modification of
data used for Operational Planning Analysis, Real-time Assessments, and Real-time monitoring while being
transmitted between Control Centers.

FERC VRF G1 Discussion

N/A

Guideline 1- Consistency
with Blackout Report
FERC VRF G2 Discussion

N/A

Guideline 2- Consistency
within a Reliability Standard
FERC VRF G3 Discussion
Guideline 3- Consistency
among Reliability Standards
FERC VRF G4 Discussion
Guideline 4- Consistency
with NERC Definitions of
VRFs
FERC VRF G5 Discussion

The requirement complements CIP-005-1, Requirement R1, CIP-006-6, Requirement R1, and CIP-007-6,
Requirement R1 which are related to security of networks and communications components. The
proposed VRF is consistent with these related requirements.
Failure to have a cyber security plan would not, under Emergency, abnormal, or restorative conditions
anticipated by the preparations, be expected to adversely affect the electrical state or capability of the
Bulk Electric System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

N/A

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | JulyOctober 2017

5

VRF Justifications for CIP-012-1, Requirement R1

Proposed VRF

Medium

Guideline 5- Treatment of
Requirements that Comingle More than One
Obligation
VSLs for CIP-012-1, Requirement R1

Lower
N/A

Moderate
N/A

The Responsible Entity
documented its plan(s) but
failed to include one of the
applicable parts of the plan as
specified in Requirement R1.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | JulyOctober 2017

High
N/AThe Responsible Entity
documented its plan(s) but
failed to include two of the
applicable parts of the plan as
specified in Requirement R1.

Severe
The Responsible Entity failed to
document one or more plan(s)
that achieve the security
objective to mitigate the risk of
the unauthorized disclosure or
modification of data used for
Operational
Planning Analysis, Real-time
Assessments, and Real-time
monitoring while being
transmitted, excluding oral
communication, between
Controls Centers as specified in
Requirement R1.

6

VSL Justifications for CIP-012-1 Requirements R1

FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency
in the Determination of
Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent

The requirement is new. Therefore, the proposed VSL does not have the unintended consequence of
lowering the level of compliance.

The proposed VSL is binary and is classified as severe. The VSL does not use any ambiguous terminology,
thereby supporting uniformity and consistency in the determination of similar penalties for similar
violations.The requirement is for the Responsible Entity to document include one or more plans as
specified in Requirement R1.
The moderate VSL addresses where the Responsible Entity documented its plan(s) but failed to include
one of the applicable parts of the plan as specified in Requirement R1.
The high VSL addresses where the Responsible Entity documented its plan(s) but failed to include two of
the applicable parts of the plan as specified in Requirement R1.
The severe VSL addresses where the Responsible Entity failed to document plan(s) for Requirement R1.

Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement

The proposed VSL uses the same terminology as used in the associated requirement and is, therefore,
consistent with the requirement.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | JulyOctober 2017

7

FERC VSL G4

TheEach VSL is based on a single violation and not cumulative violations.

Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations

VRF Justifications for CIP-012-1, Requirement R2

Proposed VRF

Medium

NERC VRF Discussion

A VRF of Medium was assigned to this requirement. Implementation of required cyber security plans
enable effective implementation of the CIP standard’s requirements to mitigate the risk of the
unauthorized disclosure or modification of data used for Operational Planning Analysis, Real-time
Assessments, and Real-time monitoring while being transmitted between Control Centers.

FERC VRF G1 Discussion

N/A

Guideline 1- Consistency
with Blackout Report
FERC VRF G2 Discussion

N/A

Guideline 2- Consistency
within a Reliability Standard
FERC VRF G3 Discussion
Guideline 3- Consistency
among Reliability Standards
FERC VRF G4 Discussion

The requirement complements CIP-005-1, Requirement R1, CIP-006-6, Requirement R1, and CIP-007-6,
Requirement R1 which are related to security of networks and communications components. The
proposed VRF is consistent with these related requirements.
Failure to properly implement the cyber security plan would not, under Emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | JulyOctober 2017

8

VRF Justifications for CIP-012-1, Requirement R2

Proposed VRF

Medium

Guideline 4- Consistency
with NERC Definitions of
VRFs

or capability of the Bulk Electric System, or the ability to effectively monitor, control, or restore the Bulk
Electric System.

FERC VRF G5 Discussion

N/A

Guideline 5- Treatment of
Requirements that Comingle More than One
Obligation
VSLs for CIP-012-1, Requirement R2

Lower
N/A

Moderate
N/A

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | JulyOctober 2017

High
N/A

Severe
The Responsible Entity failed to
implement its plan to mitigate
the risk of the unauthorized
disclosure or modification of
data used for Operational,
Planning Analysis, Real-time
Assessments, and Real-time
monitoring while being
transmitted, excluding oral
communication, between
Controls Centers(s) as specified
in Requirement R1, except
under CIP Exceptional
Circumstances.

9

VSL Justifications for CIP-012-1 Requirement R2

FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency
in the Determination of
Penalties

The requirement is new. Therefore, the proposed VSL does not have the unintended consequence of
lowering the level of compliance.

The proposed VSL is binary and is classified as severe. The VSL does not use any ambiguous terminology,
thereby supporting uniformity and consistency in the determination of similar penalties for similar
violations.

Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement

The proposed VSL uses the same terminology as used in the associated requirement and is, therefore,
consistent with the requirement.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | JulyOctober 2017

10

FERC VSL G4

The VSL is based on a single violation and not cumulative violations.

Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | JulyOctober 2017

11

Reliability Standard Audit Worksheet1
CIP-012-1 – Cyber Security – Communications between Control Centers
This section to be completed by the Compliance Enforcement Authority.
Audit ID:
Registered Entity:
NCR Number:
Compliance Enforcement Authority:
Compliance Assessment Date(s) 2:
Compliance Monitoring Method:
Names of Auditors:

Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
Registered name of entity being audited
NCRnnnnn
Region or NERC performing audit
Month DD, YYYY, to Month DD, YYYY
[On-site Audit | Off-site Audit | Spot Check]
Supplied by CEA

Applicability of Requirements
R1
R2

BA
X
X

DP

GO
X
X

GOP
X
X

PA/PC

RC
X
X

Legend:
Text with blue background:
Text entry area with Green background:
Text entry area with white background:

RP

RSG

TO
X
X

TOP
X
X

TP

TSP

Fixed text – do not edit
Entity-supplied information
Auditor-supplied information

1 NERC developed this Reliability Standard Audit Worksheet (RSAW) language in order to facilitate NERC’s and the Regional Entities’ assessment of a registered entity’s
compliance with this Reliability Standard. The NERC RSAW language is written to specific versions of each NERC Reliability Standard. Entities using this RSAW should
choose the version of the RSAW applicable to the Reliability Standard being assessed. While the information included in this RSAW provides some of the methodology
that NERC has elected to use to assess compliance with the requirements of the Reliability Standard, this document should not be treated as a substitute for the
Reliability Standard or viewed as additional Reliability Standard requirements. In all cases, the Regional Entity should rely on the language contained in the Reliability
Standard itself, and not on the language contained in this RSAW, to determine compliance with the Reliability Standard. NERC’s Reliability Standards can be found on
NERC’s website. Additionally, NERC Reliability Standards are updated frequently, and this RSAW may not necessarily be updated with the same frequency. Therefore,
it is imperative that entities treat this RSAW as a reference document only, and not as a substitute or replacement for the Reliability Standard. It is the responsibility
of the registered entity to verify its compliance with the latest approved version of the Reliability Standards, by the applicable governmental authority, relevant to its
registration status.

The RSAW may provide a non-exclusive list, for informational purposes only, of examples of the types of evidence a registered entity may produce or may be asked to
produce to demonstrate compliance with the Reliability Standard. A registered entity’s adherence to the examples contained within this RSAW does not necessarily
constitute compliance with the applicable Reliability Standard, and NERC and the Regional Entity using this RSAW reserve the right to request additional evidence from
the registered entity that is not included in this RSAW. This RSAW may include excerpts from FERC Orders and other regulatory references which are provided for ease
of reference only, and this document does not necessarily include all applicable Order provisions. In the event of a discrepancy between FERC Orders, and the language
included in this document, FERC Orders shall prevail.
2

Compliance Assessment Date(s): The date(s) the actual compliance assessment (on-site audit, off-site spot check, etc.) occurs.

DRAFT NERC Reliability Standard Audit Worksheet

Findings
(This section to be completed by the Compliance Enforcement Authority)
Req.
Finding
Summary and Documentation
R1
R2

Req.

Areas of Concern

Req.

Recommendations

Req.

Positive Observations

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft2_v2 Revision Date: November 27, 2017 RSAW Template: RSAW2017R3.0
2

Functions Monitored

DRAFT NERC Reliability Standard Audit Worksheet

Subject Matter Experts
Identify the Subject Matter Expert(s) responsible for this Reliability Standard.
Registered Entity Response (Required; Insert additional rows if needed):
SME Name
Title
Organization

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft2_v2 Revision Date: November 27, 2017 RSAW Template: RSAW2017R3.0
3

Requirement(s)

DRAFT NERC Reliability Standard Audit Worksheet

Registered Entity Response (Required):
Question 1: Does the Registered Entity own or operate a Control Center? ☐ Yes ☐ No
If no:
1. Provide evidence in the space that the Registered Entity does not own or operate one or more Control
Centers. This evidence may include, but is not limited to:
• Evidence that the Registered Entity does not own or operate a Control Center; or
• Evidence or a reference to evidence from the Registered Entity’s CIP-002 compliance program
that demonstrates the entity does not own or operate a Control Center.
2. The remainder of this RSAW may be left blank.
[Note: A separate spreadsheet or other document may be used. If so, provide the document reference
below.]

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft2_v2 Revision Date: November 27, 2017 RSAW Template: RSAW2017R3.0
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DRAFT NERC Reliability Standard Audit Worksheet

R1 Supporting Evidence and Documentation
R1.

M1.

The Responsible Entity shall develop one or more documented plan(s) to mitigate the risk of unauthorized
disclosure or modification of Real-time Assessment and Real-time monitoring and control data while being
transmitted between any Control Centers. This requirement excludes oral communications. The plan shall
include: [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]
1.1

Identification of security protection used to mitigate the risk of unauthorized disclosure or modification of
Real-time Assessment and Real-time monitoring and control data while being transmitted between
Control Centers;

1.2

Identification of demarcation point(s) where security protection is applied for transmitting Real-time
Assessment and Real-time monitoring and control data between Control Centers; and

1.3

Identification of roles and responsibilities of each Responsible Entity for applying security protection to
the transmission of Real-time Assessment and Real-time monitoring and control data between Control
Centers, when the Control Centers are owned or operated by different Responsible Entities.

Evidence may include, but is not limited to, documented plan(s) that meet the security objective of Requirement
R1.

Registered Entity Response (Required):
Compliance Narrative:

Provide a brief explanation, in your own words, of how you comply with this Requirement. References to supplied
evidence, including links to the appropriate page, are recommended.

Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.
Relevant
Revision
Page(s)
or
Document
or
Description of Applicability
File Name
Document Title
Version
Date
Section(s)
of Document

Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft2_v2 Revision Date: November 27, 2017 RSAW Template: RSAW2017R3.0
5

DRAFT NERC Reliability Standard Audit Worksheet

Compliance Assessment Approach Specific to CIP-012-1, R1
This section to be completed by the Compliance Enforcement Authority
If the Registered Entity has answered “No” to Question 1, verify the Registered Entity does not own or
operate a Control Center.
Note: If the Registered Entity does not own or operate a Control Center, the remainder of this RSAW is
not applicable.
Verify the entity has developed one or more documented plan(s) to mitigate the risk of the
unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring and control
data while being transmitted between Control Centers.
Verify the documented plans collectively include identification of security protection used to mitigate
the risk of unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring
and control data while being transmitted between Control Centers.
Verify the documented plans collectively include identification of demarcation point(s) where security
protection is applied for transmitting Real-time Assessment and Real-time monitoring and control data
between Control Centers.
Verify the documented plans collectively include identification of roles and responsibilities of each
Responsible Entity for applying security protection to the transmission of Real-time Assessment and
Real-time monitoring and control data between Control Centers, when the Control Centers are owned
or operated by different Responsible Entities.
Verify the documented plans collectively achieve the security objective of mitigating the risk of the
unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring and control
data while being transmitted between Control Centers.
Note to Auditor:
1. Oral communications are not in scope for CIP-012-1.
Auditor Notes:

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft2_v2 Revision Date: November 27, 2017 RSAW Template: RSAW2017R3.0
6

DRAFT NERC Reliability Standard Audit Worksheet

R2 Supporting Evidence and Documentation
R2.

The Responsible Entity shall implement the plan(s) specified in Requirement R1, except under CIP Exceptional
Circumstances.

M2.

Evidence may include, but is not limited to, documentation to demonstrate implementation of methods to
mitigate the risk of the unauthorized disclosure or modification of data in Requirement R1.

Registered Entity Response (Required):
Compliance Narrative:

Provide a brief explanation, in your own words, of how you comply with this Requirement. References to supplied
evidence, including links to the appropriate page, are recommended.

Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.
Relevant
Revision
Page(s)
or
Document
or
Description of Applicability
File Name
Document Title
Version
Date
Section(s)
of Document

Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft2_v2 Revision Date: November 27, 2017 RSAW Template: RSAW2017R3.0
7

DRAFT NERC Reliability Standard Audit Worksheet

Compliance Assessment Approach Specific to CIP-012-1, R2
This section to be completed by the Compliance Enforcement Authority
Verify the entity has implemented one or more documented plan(s) to mitigate the risk of the
unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring and control
data while being transmitted between Control Centers.
Verify the entity has implemented the identified security protection used to mitigate the risk of
unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring and control
data while being transmitted between Control Centers.
Verify the entity has implemented the identified security protection at the identified demarcation
point(s) where security protection is applied for transmitting Real-time Assessment and Real-time
monitoring and control data between Control Centers; and
If Control Centers are not owned and operated by the same Responsible Entity, verify the entity has
identified roles and responsibilities of each Responsible Entity for applying security protection to the
transmission of Real-time Assessment and Real-time monitoring and control data between Control
Centers.
If the Responsible Entity has declared and responded to CIP Exceptional Circumstances, verify the
Responsible Entity has adhered to the applicable cyber security policies.
Note to Auditor:
The Responsible Entity may reference a separate set of documents to demonstrate its response to any
requirements impacted by CIP Exceptional Circumstances.
Auditor Notes:

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft2_v2 Revision Date: November 27, 2017 RSAW Template: RSAW2017R3.0
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DRAFT NERC Reliability Standard Audit Worksheet

Additional Information:
Reliability Standard
The full text of CIP-012-1 may be found on the NERC Web Site (www.nerc.com) under “Program Areas &
Departments”, “Standards,” “Reliability Standards.”
In addition to the Reliability Standard, there is an applicable Implementation Plan available on the NERC Web
Site.
In addition to the Reliability Standard, there is background information available on the NERC Web Site.
Capitalized terms in the Reliability Standard refer to terms in the NERC Glossary, which may be found on the
NERC Web Site.
Sampling Methodology
Sampling is essential for auditing compliance with NERC Reliability Standards since it is not always possible
or practical to test 100% of either the equipment, documentation, or both, associated with the full suite of
enforceable standards. The Sampling Methodology Guidelines and Criteria (see NERC website), or sample
guidelines, provided by the Electric Reliability Organization help to establish a minimum sample set for
monitoring and enforcement uses in audits of NERC Reliability Standards.
Regulatory Language
FERC Order 822 P53-56, 58, and 62
Selected Glossary Terms
The following Glossary terms are provided for convenience only. Please refer to the NERC web site for the
current enforceable terms.
CIP Exceptional Circumstance
A situation that involves or threatens to involve one or more of the following, or similar, conditions that
impact safety or BES reliability: a risk of injury or death; a natural disaster; civil unrest; an imminent or existing
hardware, software, or equipment failure; a Cyber Security Incident requiring emergency assistance; a
response by emergency services; the enactment of a mutual assistance agreement; or an impediment of large
scale workforce availability.
Control Center
One or more facilities hosting operating personnel that monitor and control the Bulk Electric System (BES) in
real-time to perform the reliability tasks, including their associated data centers, of: 1) a Reliability
Coordinator, 2) a Balancing Authority, 3) a Transmission Operator for transmission Facilities at two or more
locations, or 4) a Generator Operator for generation Facilities at two or more locations.
Real-time Assessment
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft2_v2 Revision Date: November 27, 2017 RSAW Template: RSAW2017R3.0
9

DRAFT NERC Reliability Standard Audit Worksheet

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.)
Real-time
Present time as opposed to future time.

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft2_v2 Revision Date: November 27, 2017 RSAW Template: RSAW2017R3.0
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DRAFT NERC Reliability Standard Audit Worksheet

Revision History for RSAW
Version
Draft1 v1
Draft1 v2
Draft1 v3

Date
07/28/2017
08/01/2017
08/02/2017

Reviewers
NERC Stds Group
RSAW Task Force
RSAW Task Force

Draft1 v4

08/07/2017

RSAW Task Force,
2016-02 SDT

Draft2 v1

10/27/2017

RSAW Task Force

Draft2 v2

11/27/2017

RSAW Task Force,
Standard Drafting
Team

Revision Description
New document
Modified Question to clarify applicability
Response to MRO comments. Moved Questions
1 and 2 above R1. Made text changes to Q1 and
to R2 Compliance Assessment Approach.
Response to TexasRE and SDT comments.
Clarified scope of Q1 to be data transmitted
between Control Centers. Removed extra space
from Auditor Notes.
Modified title.
Modified Q2 to conform with new language.
Modified R1 with new Requirement text and new
Compliance Assessment Approach.
Modified R2 with new Compliance Assessment
Approach.
Removed Operational Planning Analysis from the
Selected Glossary Terms.
Modified footer with revised version and date.
Response to comments:
• RF: Footnote 1 page 1 added space after
“references.”
• RF: Changed “Tasf” to “Task” in Revision
History.
• Response to SERC CIPC and Southern
Company comments to Draft 1.
• Modified Question 1 to include reference
to CIP-002.
• Added an item to the R1 Compliance
Assessment Approach to verify the
effectiveness of the process.
• Modified the R2 Compliance Assessment
Approaches to clarify that the review is
for implementation.

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft2_v2 Revision Date: November 27, 2017 RSAW Template: RSAW2017R3.0
11

Reliability Standard Audit Worksheet1
CIP-012-1 – Cyber Security – Communications between Control
CentersControl Center Communication Networks
This section to be completed by the Compliance Enforcement Authority.
Audit ID:
Registered Entity:
NCR Number:
Compliance Enforcement Authority:
Compliance Assessment Date(s) 2:
Compliance Monitoring Method:
Names of Auditors:

Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
Registered name of entity being audited
NCRnnnnn
Region or NERC performing audit
Month DD, YYYY, to Month DD, YYYY
[On-site Audit | Off-site Audit | Spot Check]
Supplied by CEA

Applicability of Requirements
R1
R2

BA
X
X

DP

GO
X
X

GOP
X
X

PA/PC

RC
X
X

Legend:
Text with blue background:
Text entry area with Green background:
Text entry area with white background:

RP

RSG

TO
X
X

TOP
X
X

TP

TSP

Fixed text – do not edit
Entity-supplied information
Auditor-supplied information

NERC developed this Reliability Standard Audit Worksheet (RSAW) language in order to facilitate NERC’s and the Regional Entities’ assessment of a registered entity’s
compliance with this Reliability Standard. The NERC RSAW language is written to specific versions of each NERC Reliability Standard. Entities using this RSAW should
choose the version of the RSAW applicable to the Reliability Standard being assessed. While the information included in this RSAW provides some of the methodology
that NERC has elected to use to assess compliance with the requirements of the Reliability Standard, this document should not be treated as a substitute for the
Reliability Standard or viewed as additional Reliability Standard requirements. In all cases, the Regional Entity should rely on the language contained in the Reliability
Standard itself, and not on the language contained in this RSAW, to determine compliance with the Reliability Standard. NERC’s Reliability Standards can be found on
NERC’s website. Additionally, NERC Reliability Standards are updated frequently, and this RSAW may not necessarily be updated with the same frequency. Therefore,
it is imperative that entities treat this RSAW as a reference document only, and not as a substitute or replacement for the Reliability Standard. It is the responsibility
of the registered entity to verify its compliance with the latest approved version of the Reliability Standards, by the applicable governmental authority, relevant to its
registration status.

1

The RSAW may provide a non-exclusive list, for informational purposes only, of examples of the types of evidence a registered entity may produce or may be asked to
produce to demonstrate compliance with the Reliability Standard. A registered entity’s adherence to the examples contained within this RSAW does not necessarily
constitute compliance with the applicable Reliability Standard, and NERC and the Regional Entity using this RSAW reserve the right to request additional evidence from
the registered entity that is not included in this RSAW. This RSAW may include excerpts from FERC Orders and other regulatory references which are provided for ease
of reference only, and this document does not necessarily include all applicable Order provisions. In the event of a discrepancy between FERC Orders, and the language
included in this document, FERC Orders shall prevail.
2

Compliance Assessment Date(s): The date(s) the actual compliance assessment (on-site audit, off-site spot check, etc.) occurs.

DRAFT NERC Reliability Standard Audit Worksheet

Findings
(This section to be completed by the Compliance Enforcement Authority)
Req.
Finding
Summary and Documentation
R1
R2

Req.

Areas of Concern

Req.

Recommendations

Req.

Positive Observations

Functions Monitored

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft2_v211_v4 Revision Date: August 7OctoberNovember 27, 2017 RSAW Template: RSAW2017R3.0
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DRAFT NERC Reliability Standard Audit Worksheet

Subject Matter Experts
Identify the Subject Matter Expert(s) responsible for this Reliability Standard.
Registered Entity Response (Required; Insert additional rows if needed):
SME Name
Title
Organization

Requirement(s)

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
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DRAFT NERC Reliability Standard Audit Worksheet

Registered Entity Response (Required):
Question 1[A1][A2]: Does the Registered Entity own or operate a Control Center? ☐ Yes ☐ No
If no:
1. Provide evidence in the space that the Registered Entity does not own or operate one or more Control
Centers. This evidence may include, but is not limited to:
• Evidence that the Registered Entity does not own or operate a Control Center; or
• Evidence or a reference to evidence from the Registered Entity’s CIP-002 compliance program
that demonstrates the entity does not own or operate a Control Center.
• Evidence that the Registered Entity’s asset list does not contain a Control Center.
2. The remainder of this RSAW may be left blank.
If yes, continue with Question 2.
[Note: A separate spreadsheet or other document may be used. If so, provide the document reference below.]

Question 2: Is data used for Operational Planning Analysis, Real-time Assessments, or Real-time monitoring
and control transmitted between Control Centers at any time by any Control Center owned or operated by the
Registered Entity? ☐ Yes ☐ No
If no:

Provide evidence in the space below supporting this assertion. This evidence may include, but is not
limited to:
• Evidence demonstrating data used for Operational Planning Analysis, Real-time Assessments, and
Real-time monitoring and control is not transmitted between Control Centers at any time by any
Control Center owned or operated by the Registered Entity.
1. The remainder of this RSAW may be left blank.

If yes, continue with the remainder of this RSAW.
[Note: A separate spreadsheet or other document may be used. If so, provide the document reference below.]

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft2_v211_v4 Revision Date: August 7OctoberNovember 27, 2017 RSAW Template: RSAW2017R3.0
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DRAFT NERC Reliability Standard Audit Worksheet

R1 Supporting Evidence and Documentation
R1.

The Responsible Entity shall develop one or more documented plan(s) to mitigate the risk of unauthorized
disclosure or modification of Real-time Assessment and Real-time monitoring and control data while being
transmitted between any Control Centers. This requirement excludes oral communications. The plan shall
include: [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]
1.1

Identification of security protection used to mitigate the risk of unauthorized disclosure or modification of
Real-time Assessment and Real-time monitoring and control data while being transmitted between
Control Centers;

1.2

Identification of demarcation point(s) where security protection is applied for transmitting Real-time
Assessment and Real-time monitoring and control data between Control Centers; and

1.3

Identification of roles and responsibilities of each Responsible Entity for applying security protection to
the transmission of Real-time Assessment and Real-time monitoring and control data between Control
Centers, when the Control Centers are owned or operated by different Responsible Entities.

The Responsible Entity shall develop one or more documented plan(s) to mitigate the risk of the unauthorized
disclosure or modification of data used for Operational Planning Analysis, Real-time Assessments, and Real-time
monitoring while being transmitted between Control Centers. This excludes oral communications. [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning]
1.1

Risk mitigation shall be accomplished by one or more of the following actions:
•

Physically protecting the communication links transmitting the data;

•

Logically protecting the data during transmission; or

•

Using an equally effective method to mitigate the risk of unauthorized disclosure or modification of
the data.

Note: If the Responsible Entity does not have a Control Center or it does not transmit the type of data
specified in Requirement R1 of CIP-012-1 between two Control Centers, the requirements in CIP-012-1
would not apply to that entity.
M1.

Evidence may include, but is not limited to, documented plan(s) that meet the security objective of Requirement
R1.

Registered Entity Response (Required):
Compliance Narrative:

Provide a brief explanation, in your own words, of how you comply with this Requirement. References to supplied
evidence, including links to the appropriate page, are recommended.

Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft2_v211_v4 Revision Date: August 7OctoberNovember 27, 2017 RSAW Template: RSAW2017R3.0
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DRAFT NERC Reliability Standard Audit Worksheet

File Name

Document Title

Revision
or
Version

Relevant
Page(s)
Document
or
Date
Section(s)

Description of Applicability
of Document

Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft2_v211_v4 Revision Date: August 7OctoberNovember 27, 2017 RSAW Template: RSAW2017R3.0
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DRAFT NERC Reliability Standard Audit Worksheet

Compliance Assessment Approach Specific to CIP-012-1, R1
This section to be completed by the Compliance Enforcement Authority
If the Registered Entity has answered “No” to either Question 1 or Question 2, verify:
Thethe Registered Entity does not own or operate a Control Center.
Note: If the Registered Entity does not own or operate a Control Center, the remainder of this RSAW is
not applicable.; or
The Registered Entity does not transmit data used for Operational Planning Analysis, Real-time
Assessments, or Real-time monitoring and control at any time between Control Centers.
Verify the entity has developed one or more documented plan(s) to mitigate the risk of the
unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring and control
data while being transmitted between Control Centers.
Verify the documented plans collectively include identification of security protection used to mitigate
the risk of unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring
and control data while being transmitted between Control Centers.
Verify the documented plans collectively include identification of demarcation point(s) where security
protection is applied for transmitting Real-time Assessment and Real-time monitoring and control data
between Control Centers.; and
If the Registered Entity has answered “Yes” to Question 2, verify:
The entity has developed one or more documented plans to mitigate the risk of the unauthorized
disclosure or modification of data used for Operational Planning Analysis, Real-time Assessments, and
Real-time monitoring and control data while being transmitted between Control Centers; and
The documented plans collectively include identification of security protection used to mitigate the risk
of unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring and
control data while being transmitted between Control Centers; and
The documented plans collectively include identification of demarcation point(s) where security
protection is applied for transmitting Real-time Assessment and Real-time monitoring and control data
between Control Centers; and
Verify the The documented plans collectively include identification of roles and responsibilities of each
Responsible Entity for applying security protection to the transmission of Real-time Assessment and
Real-time monitoring and control data between Control Centers, when the Control Centers are owned
or operated by different Responsible Entities.
The documented plan(s) collectively address all data used for Operational Planning Analysis, Real-time
Assessments, and Real-time monitoring transmitted between Control Centers; and
The documented plan(s) collectively accomplish risk mitigation by one or more of the following actions:
Physically protecting the communication links transmitting the data;
Logically protecting the data during transmission; or
Using an equally effective method to mitigate the risk of unauthorized disclosure or modification of the
data.
Verify the documented plans collectively achieve the security objective of mitigating the risk of the
unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring and control
data while being transmitted between Control Centers.
Note to Auditor:
1. Oral communications are not in scope for CIP-012-1.
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft2_v211_v4 Revision Date: August 7OctoberNovember 27, 2017 RSAW Template: RSAW2017R3.0
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DRAFT NERC Reliability Standard Audit Worksheet

Auditor Notes:

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft2_v211_v4 Revision Date: August 7OctoberNovember 27, 2017 RSAW Template: RSAW2017R3.0
8

DRAFT NERC Reliability Standard Audit Worksheet

R2 Supporting Evidence and Documentation
R2.

The Responsible Entity shall implement the plan(s) specified in Requirement R1, except under CIP Exceptional
Circumstances.

M2.

Evidence may include, but is not limited to, documentation to demonstrate implementation of methods to
mitigate the risk of the unauthorized disclosure or modification of data in Requirement R1.

Registered Entity Response (Required):
Compliance Narrative:

Provide a brief explanation, in your own words, of how you comply with this Requirement. References to supplied
evidence, including links to the appropriate page, are recommended.

Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.
Relevant
Revision
Page(s)
or
Document
or
Description of Applicability
File Name
Document Title
Version
Date
Section(s)
of Document

Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):

Compliance Assessment Approach Specific to CIP-012-1, R2
This section to be completed by the Compliance Enforcement Authority
If the Registered Entity has answered “Yes” to Question 2, verify with system-generated evidence
(where available) that the Registered Entity has implemented the plan(s) specified in Requirement R1,
except under CIP Exceptional Circumstances.
Verify the entity has implemented one or more documented plan(s) to mitigate the risk of the
unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring and control
data while being transmitted between Control Centers.
Verify the entity has identified security protection used to mitigate the risk of unauthorized disclosure or
modification of Real-time Assessment and Real-time monitoring and control data while being
transmitted between Control Centers.
Verify the entity has identified demarcation point(s) where security protection is applied for
transmitting Real-time Assessment and Real-time monitoring and control data between Control Centers;
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft2_v211_v4 Revision Date: August 7OctoberNovember 27, 2017 RSAW Template: RSAW2017R3.0
9

DRAFT NERC Reliability Standard Audit Worksheet

and
Verify the entity has identified roles and responsibilities of each Responsible Entity for applying security
protection to the transmission of Real-time Assessment and Real-time monitoring and control data
between Control Centers, when the Control Centers are owned or operated by different Responsible
Entities.
If the Responsible Entity has declared and responded to CIP Exceptional Circumstances, verify the
Responsible Entity has adhered to the applicable cyber security policies.
Note to Auditor:
The Responsible Entity may reference a separate set of documents to demonstrate its response to any
requirements impacted by CIP Exceptional Circumstances.

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft2_v211_v4 Revision Date: August 7OctoberNovember 27, 2017 RSAW Template: RSAW2017R3.0
10

DRAFT NERC Reliability Standard Audit Worksheet

Auditor Notes:

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft2_v211_v4 Revision Date: August 7OctoberNovember 27, 2017 RSAW Template: RSAW2017R3.0
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DRAFT NERC Reliability Standard Audit Worksheet

Additional Information:
Reliability Standard
The full text of CIP-012-1 may be found on the NERC Web Site (www.nerc.com) under “Program Areas &
Departments”, “Standards,” “Reliability Standards.”
In addition to the Reliability Standard, there is an applicable Implementation Plan available on the NERC Web
Site.
In addition to the Reliability Standard, there is background information available on the NERC Web Site.
Capitalized terms in the Reliability Standard refer to terms in the NERC Glossary, which may be found on the
NERC Web Site.
Sampling Methodology
Sampling is essential for auditing compliance with NERC Reliability Standards since it is not always possible
or practical to test 100% of either the equipment, documentation, or both, associated with the full suite of
enforceable standards. The Sampling Methodology Guidelines and Criteria (see NERC website), or sample
guidelines, provided by the Electric Reliability Organization help to establish a minimum sample set for
monitoring and enforcement uses in audits of NERC Reliability Standards.
Regulatory Language
FERC Order 822 P53-56, 58, and 62
Selected Glossary Terms
The following Glossary terms are provided for convenience only. Please refer to the NERC web site for the
current enforceable terms.
CIP Exceptional Circumstance
A situation that involves or threatens to involve one or more of the following, or similar, conditions that
impact safety or BES reliability: a risk of injury or death; a natural disaster; civil unrest; an imminent or existing
hardware, software, or equipment failure; a Cyber Security Incident requiring emergency assistance; a
response by emergency services; the enactment of a mutual assistance agreement; or an impediment of large
scale workforce availability.
Control Center
One or more facilities hosting operating personnel that monitor and control the Bulk Electric System (BES) in
real-time to perform the reliability tasks, including their associated data centers, of: 1) a Reliability
Coordinator, 2) a Balancing Authority, 3) a Transmission Operator for transmission Facilities at two or more
locations, or 4) a Generator Operator for generation Facilities at two or more locations.
Operational Planning Analysis
An evaluation of projected system conditions to assess anticipated (pre-Contingency) and potential (postContingency) conditions for next-day operations. The evaluation shall reflect applicable inputs including, but
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft2_v211_v4 Revision Date: August 7OctoberNovember 27, 2017 RSAW Template: RSAW2017R3.0
12

DRAFT NERC Reliability Standard Audit Worksheet

not limited to, load forecasts; generation output levels; Interchange; known Protection System and Special
Protection System status or degradation; Transmission outages; generator outages; Facility Ratings; and
identified phase angle and equipment limitations. (Operational Planning Analysis may be provided through
internal systems or through third-party services.)
Real-time Assessment
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.)
Real-time
Present time as opposed to future time.

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft2_v211_v4 Revision Date: August 7OctoberNovember 27, 2017 RSAW Template: RSAW2017R3.0
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DRAFT NERC Reliability Standard Audit Worksheet

Revision History for RSAW
Version
Draft1 v1
Draft1 v2
Draft1 v3

Date
07/28/2017
08/01/2017
08/02/2017

Reviewers
NERC Stds Group
RSAW Task Force
RSAW Task Force

Draft1 v4

08/07/2017

RSAW Taskf Force,
2016-02 SDT

Draft2 v1

10/27/2017

RSAW Task Force

Draft2 v2

11/27/2017

RSAW Task Force

Revision Description
New document
Modified Question to clarify applicability
Response to MRO comments. Moved Questions
1 and 2 above R1. Made text changes to Q1 and
to R2 Compliance Assessment Approach.
Response to TexasRE and SDT comments.
Clarified scope of Q1 to be data transmitted
between Control Centers. Removed extra space
from Auditor Notes.
Modified title.
Modified Q2 to conform with new language.
Modified R1 with new Requirement text and new
Compliance Assessment Approach.
Modified R2 with new Compliance Assessment
Approach.
Removed Operational Planning Analysis from the
Selected Glossary Terms.
Modified footer with revised version and date.
Response to comments:
• RF: Footnote 1 page 1 added space after
“references.”
• RF: Changed “Tasf” to “Task” in Revision
History
• Response to SERC CIPC and Southern
Company comments to Draft 1.
• Modified Question 1 to include reference
to CIP-002.
• Added an item to the R1 Compliance
Assessment Approach to verify the
effectiveness of the process.
• Modified the R2 Compliance Assessment
Approaches to clarify that the review is
for implementation.

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft2_v211_v4 Revision Date: August 7OctoberNovember 27, 2017 RSAW Template: RSAW2017R3.0
14

Standards Announcement
Reminder

Project 2016-02 Modifications to CIP Standards
Additional Ballot and Non-binding Poll Open through December 11, 2017
Now Available

An additional ballot for CIP-012-1 – Cyber Security – Communications between Control Centers and
non-binding poll of the associated Violation Risk Factors and Violation Severity Levels are open
through 8 p.m. Eastern, Monday, December 11, 2017.
The standard drafting team’s consideration of the responses received from the last comment period are
reflected in this draft of the standard.
Balloting

Members of the ballot pools associated with this project can log in and submit their votes by accessing
the Standards Balloting and Commenting System (SBS) here. If you experience any difficulties navigating
the SBS, contact Wendy Muller.
•

If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential error
messages, or system lock-out, contact NERC IT support directly at https://support.nerc.net/ (Monday
– Friday, 8 a.m. - 5 p.m. Eastern).

•

Passwords expire every 6 months and must be reset.

•

The SBS is not supported for use on mobile devices.

•

Please be mindful of ballot and comment period closing dates. We ask to allow at least 48 hours for
NERC support staff to assist with inquiries. Therefore, it is recommended that users try logging into
their SBS accounts prior to the last day of a comment/ballot period.

Note: If a member cast a vote in the previous ballot, that vote will not carry over to this additional
ballot. It is the responsibility of the registered voter in the ballot pool to cast a vote again in this ballot.
To ensure a quorum is reached, if you do not want to vote affirmative or negative, cast an abstention.
Next Steps

The ballot results will be announced and posted on the project page. The drafting team will review all
responses received during the comment period and determine the next steps of the project.

For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Katherine Street at (404) 446-9702 or Mat Bunch at (404) 4469785.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement | CIP-012-1 Ballot Open Reminder
Project 2016-02 Modifications to CIP Standards | December 1, 2017

2

Standards Announcement

Project 2016-02 Modifications to CIP Standards
Formal Comment Period Open through December 11, 2017
Now Available

A 45-day formal comment period for CIP-012-1 - Cyber Security – Communications between Control
Centers is open through 8 p.m. Eastern, Monday, December 11, 2017.
The standard drafting team’s considerations of the responses received from the last comment period are
reflected in this draft of the standard.
Commenting

Use the Standards Balloting and Commenting System (SBS) to submit comments. If you experience issues
navigating the SBS, contact Wendy Muller. An unofficial Word version of the comment form is posted on
the project page.
•

If you are having difficulty accessing the SBS due to a forgotten password, incorrect
credential error messages, or system lock-out, contact NERC IT support directly at
https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5 p.m. Eastern).

•

Passwords expire every 6 months and must be reset.

•

The SBS is not supported for use on mobile devices.

•

Please be mindful of ballot and comment period closing dates. We ask to allow at least 48
hours for NERC support staff to assist with inquiries. Therefore, it is recommended that users try
logging into their SBS accounts prior to the last day of a comment/ballot period.

Next Steps

An additional ballot for the standard and non-binding poll of the associated Violation Risk Factors and
Violation Severity Levels will be conducted December 1-11, 2017.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Katherine Street at (404) 446-9702 or Mat Bunch at (404) 4469785.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Index - NERC Balloting Tool

NERC Balloting Tool (/)

Page 1 of 19

Dashboard (/)

Users

Ballots

Comment Forms

Login (/Users/Login) / Register (/Users/Register)

BALLOT RESULTS
Comment: View Comment Results (/CommentResults/Index/113)
Ballot Name: 2016-02 Modifications to CIP Standards CIP-012-1 AB 2 ST
Voting Start Date: 12/1/2017 12:01:00 AM
Voting End Date: 12/11/2017 8:00:00 PM
Ballot Type: ST
Ballot Activity: AB
Ballot Series: 2
Total # Votes: 239
Total Ballot Pool: 309
Quorum: 77.35
Weighted Segment Value: 63.91

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Negative
Fraction
w/
Comment

Segment:
1

80

1

30

0.556

24

0.444

3

7

16

Segment:
2

7

0.5

4

0.4

1

0.1

0

0

2

Segment:
3

73

1

31

0.596

21

0.404

1

3

17

Segment:
4

17

1

7

0.583

5

0.417

0

0

5

Segment:
5

73

1

24

0.5

24

0.5

1

3

21

Segment:
6

46

1

21

0.583

15

0.417

1

1

8

Segment:
7

2

0.1

1

0.1

0

0

0

0

1

Segment:
8

3

0.3

3

0.3

0

0

0

0

0

Segment:
9

1

0.1

1

0.1

0

0

0

0

0

1

0.1

0

1

0

Segment

Segment: 7
0.6
5
0.5
© 2018
NERC
Ver
4.2.1.0
Machine
Name:
ERODVSBSWB02
10

https://sbs.nerc.net/BallotResults/Index/227

Negative
Votes
w/o
Comment

Abstain

No
Vote

9/10/2018

Index - NERC Balloting Tool

Page 2 of 19

Segment

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Totals:

309

6.6

127

4.218

91

Negative
Fraction
w/
Comment

Negative
Votes
w/o
Comment

Abstain

No
Vote

2.382

6

15

70

BALLOT POOL MEMBERS
Show All

Segment

 entries

Organization

Search: Search

Voter

Designated
Proxy

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Negative

Comments
Submitted

1

Allete - Minnesota Power, Inc.

Jamie Monette

Abstain

N/A

1

American Transmission
Company, LLC

Douglas
Johnson

Negative

No Comment
Submitted

1

APS - Arizona Public Service
Co.

Michelle
Amarantos

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

John Shaver

None

N/A

1

Associated Electric
Cooperative, Inc.

Mark Riley

Affirmative

N/A

1

Austin Energy

Thomas
Standifur

None

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Negative

Comments
Submitted

1

Basin Electric Power
Cooperative

David Rudolph

None

N/A

1

BC Hydro and Power Authority

Patricia
Robertson

None

N/A

Negative

Comments
Submitted

1

Berkshire Hathaway Energy Terry Harbour
MidAmerican Energy Co.
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Joe Tarantino

9/10/2018

Index - NERC Balloting Tool

Segment

Page 3 of 19

Designated
Proxy

Voter

1

Bonneville Power
Administration

Kammy
RogersHolliday

Negative

Comments
Submitted

1

Brazos Electric Power
Cooperative, Inc.

Tony Kroskey

Negative

No Comment
Submitted

1

Cedar Falls Utilities

Adam Peterson

None

N/A

1

CenterPoint Energy Houston
Electric, LLC

John Brockhan

Negative

Comments
Submitted

1

Central Electric Power
Cooperative (Missouri)

Michael Bax

None

N/A

1

Central Hudson Gas & Electric
Corp.

Frank Pace

Affirmative

N/A

1

City Utilities of Springfield,
Missouri

Michael Buyce

Affirmative

N/A

1

CMS Energy - Consumers
Energy Company

James
Anderson

None

N/A

1

Con Ed - Consolidated Edison
Co. of New York

Daniel
Grinkevich

Affirmative

N/A

1

Dominion - Dominion Virginia
Power

Larry Nash

Negative

Comments
Submitted

1

Duke Energy

Laura Lee

Affirmative

N/A

1

Edison International Southern California Edison
Company

Steven Mavis

Affirmative

N/A

1

Entergy - Entergy Services,
Inc.

Oliver Burke

Abstain

N/A

1

Eversource Energy

Quintin Lee

None

N/A

1

Exelon

Chris Scanlon

Affirmative

N/A

1

FirstEnergy - FirstEnergy
Corporation

Karen Yoder

Affirmative

N/A

1

Great Plains Energy - Kansas
City Power and Light Co.

James McBee

Affirmative

N/A

1

Great River Energy

Gordon Pietsch

None

N/A

1

Hydro One Networks, Inc.

Payam

Negative

Comments
Submitted

Farahbakhsh
© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB02

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Douglas Webb

Oshani
Pathirane

Ballot

NERC
Memo

Organization

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 4 of 19

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Hydro-Qu?bec TransEnergie

Nicolas
Turcotte

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Laura Nelson

Abstain

N/A

1

Imperial Irrigation District

Jesus Sammy
Alcaraz

Abstain

N/A

1

International Transmission
Company Holdings
Corporation

Michael
Moltane

Negative

Third-Party
Comments

1

Lincoln Electric System

Danny Pudenz

Negative

Third-Party
Comments

1

Long Island Power Authority

Robert Ganley

Affirmative

N/A

1

Los Angeles Department of
Water and Power

faranak sarbaz

None

N/A

1

Lower Colorado River
Authority

Michael Shaw

Affirmative

N/A

1

M and A Electric Power
Cooperative

William Price

Affirmative

N/A

1

Manitoba Hydro

Mike Smith

Affirmative

N/A

1

MEAG Power

David Weekley

Abstain

N/A

1

Memphis Light, Gas and
Water Division

Allan Long

None

N/A

1

Minnkota Power Cooperative
Inc.

Theresa Allard

Negative

Third-Party
Comments

1

Muscatine Power and Water

Andy Kurriger

Negative

Third-Party
Comments

1

N.W. Electric Power
Cooperative, Inc.

Mark Ramsey

Affirmative

N/A

1

National Grid USA

Michael Jones

Negative

Third-Party
Comments

1

Nebraska Public Power
District

Jamison
Cawley

Negative

Third-Party
Comments

1

New York Power Authority

Salvatore
Spagnolo

Affirmative

N/A

Stephanie
Burns

Scott Miller

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 5 of 19

Voter

Designated
Proxy

Ballot

NERC
Memo

1

NextEra Energy - Florida
Power and Light Co.

Mike ONeil

None

N/A

1

NiSource - Northern Indiana
Public Service Co.

Steve
Toosevich

Affirmative

N/A

1

Northeast Missouri Electric
Power Cooperative

Kevin White

Affirmative

N/A

1

OGE Energy - Oklahoma Gas
and Electric Co.

Terri Pyle

Abstain

N/A

1

Ohio Valley Electric
Corporation

Scott
Cunningham

Negative

Third-Party
Comments

1

Omaha Public Power District

Doug
Peterchuck

None

N/A

1

Oncor Electric Delivery

Lee Maurer

Abstain

N/A

1

OTP - Otter Tail Power
Company

Charles
Wicklund

Negative

Third-Party
Comments

1

Peak Reliability

Scott Downey

Affirmative

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Laurie Williams

Affirmative

N/A

1

PPL Electric Utilities
Corporation

Brenda Truhe

Affirmative

N/A

1

PSEG - Public Service Electric
and Gas Co.

Joseph Smith

Affirmative

N/A

1

Public Utility District No. 1 of
Chelan County

Jeff Kimbell

Negative

Comments
Submitted

1

Public Utility District No. 1 of
Snohomish County

Long Duong

Negative

Third-Party
Comments

1

Puget Sound Energy, Inc.

Theresa
Rakowsky

Affirmative

N/A

1

Sacramento Municipal Utility
District

Arthur
Starkovich

Negative

Comments
Submitted

1

Salt River Project

Steven Cobb

None

N/A

1

Santee Cooper

Shawn Abrams

Negative

No Comment
Submitted

Tho Tran

Joe Tarantino

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 6 of 19

Voter

Designated
Proxy

Ballot

NERC
Memo

1

SCANA - South Carolina
Electric and Gas Co.

Tom Hanzlik

None

N/A

1

Seattle City Light

Pawel Krupa

Negative

Third-Party
Comments

1

Seminole Electric Cooperative,
Inc.

Mark Churilla

Negative

Comments
Submitted

1

Sempra - San Diego Gas and
Electric

Martine Blair

Negative

Third-Party
Comments

1

Sho-Me Power Electric
Cooperative

Peter Dawson

Affirmative

N/A

1

Southern Company - Southern
Company Services, Inc.

Katherine
Prewitt

Affirmative

N/A

1

Southern Indiana Gas and
Electric Co.

Steve
Rawlinson

Affirmative

N/A

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

Negative

Comments
Submitted

1

Tennessee Valley Authority

Howell Scott

Affirmative

N/A

1

Tri-State G and T Association,
Inc.

Tracy Sliman

Affirmative

N/A

1

U.S. Bureau of Reclamation

Richard
Jackson

Negative

Comments
Submitted

1

Westar Energy

Kevin Giles

Affirmative

N/A

1

Western Area Power
Administration

sean erickson

Negative

Comments
Submitted

1

Xcel Energy, Inc.

Dean Schiro

None

N/A

2

California ISO

Richard Vine

Affirmative

N/A

2

Electric Reliability Council of
Texas, Inc.

Elizabeth
Axson

Affirmative

N/A

2

Independent Electricity
System Operator

Leonard Kula

Affirmative

N/A

2

ISO New England, Inc.

Michael Puscas

None

N/A

2

Midcontinent ISO, Inc.

Ellen Oswald

Negative

Third-Party
Comments

Jeff Johnson

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 7 of 19

Voter

Designated
Proxy

Ballot

NERC
Memo

2

New York Independent
System Operator

Gregory
Campoli

None

N/A

2

PJM Interconnection, L.L.C.

Mark Holman

Affirmative

N/A

3

AEP

Aaron Austin

Negative

Comments
Submitted

3

AES - Indianapolis Power and
Light Co.

Bette White

None

N/A

3

APS - Arizona Public Service
Co.

Vivian Vo

Affirmative

N/A

3

Arkansas Electric Cooperative
Corporation

Mark Gann

None

N/A

3

Associated Electric
Cooperative, Inc.

Todd Bennett

Affirmative

N/A

3

Austin Energy

W. Dwayne
Preston

Negative

Comments
Submitted

3

Basin Electric Power
Cooperative

Jeremy Voll

Affirmative

N/A

3

BC Hydro and Power Authority

Hootan
Jarollahi

None

N/A

3

Berkshire Hathaway Energy MidAmerican Energy Co.

Annette
Johnston

Negative

Comments
Submitted

3

Bonneville Power
Administration

Rebecca
Berdahl

Negative

Comments
Submitted

3

Central Electric Power
Cooperative (Missouri)

Adam Weber

Affirmative

N/A

3

City of Farmington

Linda
JacobsonQuinn

None

N/A

3

City of Leesburg

Chris Adkins

Affirmative

N/A

3

City of Vero Beach

Ginny Beigel

Affirmative

N/A

3

City Utilities of Springfield,
Missouri

Scott Williams

Affirmative

N/A

3

Cleco Corporation

Michelle Corley

Negative

Third-Party
Comments

Brandon
McCormick

Louis Guidry

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 8 of 19

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Con Ed - Consolidated Edison
Co. of New York

Peter Yost

Affirmative

N/A

3

Cowlitz County PUD

Russell Noble

None

N/A

3

Duke Energy

Lee Schuster

Affirmative

N/A

3

Edison International Southern California Edison
Company

Romel Aquino

None

N/A

3

Empire District Electric Co.

Kalem Long

None

N/A

3

Eversource Energy

Sharon
Flannery

None

N/A

3

Exelon

John Bee

Affirmative

N/A

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

Affirmative

N/A

3

Georgia System Operations
Corporation

Scott McGough

None

N/A

3

Great Plains Energy - Kansas
City Power and Light Co.

Jessica Tucker

Affirmative

N/A

3

Great River Energy

Brian Glover

Negative

Third-Party
Comments

3

Hydro One Networks, Inc.

Paul
Malozewski

None

N/A

3

KAMO Electric Cooperative

Ted Hilmes

None

N/A

3

Lincoln Electric System

Jason Fortik

Negative

Third-Party
Comments

3

M and A Electric Power
Cooperative

Stephen Pogue

Affirmative

N/A

3

Manitoba Hydro

Karim AbdelHadi

Affirmative

N/A

3

MEAG Power

Roger Brand

Scott Miller

Abstain

N/A

3

Modesto Irrigation District

Jack Savage

Nick Braden

Affirmative

N/A

3

Muscatine Power and Water

Seth
Shoemaker

Negative

Third-Party
Comments

3

National Grid USA

Negative

Third-Party
Comments

Brian
Shanahan
© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB02

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Douglas Webb

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 9 of 19

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Nebraska Public Power
District

Tony Eddleman

Negative

Third-Party
Comments

3

New York Power Authority

David Rivera

Affirmative

N/A

3

NiSource - Northern Indiana
Public Service Co.

Aimee Harris

Affirmative

N/A

3

North Carolina Electric
Membership Corporation

doug white

Affirmative

N/A

3

Northeast Missouri Electric
Power Cooperative

Skyler
Wiegmann

None

N/A

3

NW Electric Power
Cooperative, Inc.

John Stickley

Affirmative

N/A

3

Ocala Utility Services

Neville Bowen

None

N/A

3

OGE Energy - Oklahoma Gas
and Electric Co.

Donald
Hargrove

Abstain

N/A

3

OTP - Otter Tail Power
Company

Wendi Olson

Negative

Third-Party
Comments

3

Owensboro Municipal Utilities

Thomas Lyons

Affirmative

N/A

3

Platte River Power Authority

Jeff Landis

Negative

Third-Party
Comments

3

PNM Resources - Public
Service Company of New
Mexico

Lynn Goldstein

Affirmative

N/A

3

Portland General Electric Co.

Angela Gaines

Affirmative

N/A

3

PPL - Louisville Gas and
Electric Co.

Charles
Freibert

Affirmative

N/A

3

PSEG - Public Service Electric
and Gas Co.

Jeffrey Mueller

Affirmative

N/A

3

Public Utility District No. 1 of
Chelan County

Joyce Gundry

Negative

Comments
Submitted

3

Puget Sound Energy, Inc.

Lynda Kupfer

Affirmative

N/A

3

Rutherford EMC

Tom Haire

Abstain

N/A

3

Sacramento Municipal Utility
District

Nicole Looney

Negative

Comments
Submitted

Scott Brame

Joe Tarantino

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 10 of 19

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Salt River Project

Rudy Navarro

Negative

Comments
Submitted

3

Santee Cooper

James Poston

Negative

No Comment
Submitted

3

SCANA - South Carolina
Electric and Gas Co.

Scott Parker

None

N/A

3

Seattle City Light

Tuan Tran

Negative

Third-Party
Comments

3

Seminole Electric Cooperative,
Inc.

James Frauen

Negative

Comments
Submitted

3

Sempra - San Diego Gas and
Electric

Bridget Silvia

Negative

Third-Party
Comments

3

Sho-Me Power Electric
Cooperative

Jeff Neas

Affirmative

N/A

3

Silicon Valley Power - City of
Santa Clara

Val Ridad

None

N/A

3

Snohomish County PUD No. 1

Mark Oens

Negative

Third-Party
Comments

3

Southern Company - Alabama
Power Company

Joel
Dembowski

Affirmative

N/A

3

Southern Indiana Gas and
Electric Co.

Fred Frederick

None

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

Marc
Donaldson

Negative

Comments
Submitted

3

TECO - Tampa Electric Co.

Ronald
Donahey

Affirmative

N/A

3

Tennessee Valley Authority

Ian Grant

Affirmative

N/A

3

Tri-State G and T Association,
Inc.

Janelle Marriott
Gill

None

N/A

3

WEC Energy Group, Inc.

Thomas
Breene

Affirmative

N/A

3

Westar Energy

Bo Jones

Affirmative

N/A

3

Xcel Energy, Inc.

Michael Ibold

Negative

Comments
Submitted

Harold Sherrill

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 11 of 19

Voter

Designated
Proxy

Ballot

NERC
Memo

4

American Public Power
Association

Jack Cashin

None

N/A

4

Arkansas Electric Cooperative
Corporation

Alice Wright

None

N/A

4

Austin Energy

Esther Weekes

Negative

Comments
Submitted

4

City of Clewiston

Lynne Mila

Affirmative

N/A

4

City Utilities of Springfield,
Missouri

John Allen

Affirmative

N/A

4

FirstEnergy - FirstEnergy
Corporation

Aubrey Short

Affirmative

N/A

4

Georgia System Operations
Corporation

Guy Andrews

Affirmative

N/A

4

Indiana Municipal Power
Agency

Jack Alvey

None

N/A

4

National Rural Electric
Cooperative Association

Barry Lawson

Affirmative

N/A

4

North Carolina Electric
Membership Corporation

John Lemire

Affirmative

N/A

4

Public Utility District No. 1 of
Snohomish County

John Martinsen

Negative

Third-Party
Comments

4

Sacramento Municipal Utility
District

Beth Tincher

Negative

Comments
Submitted

4

Seattle City Light

Hao Li

Negative

Third-Party
Comments

4

Seminole Electric Cooperative,
Inc.

Charles
Wubbena

Negative

Comments
Submitted

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

None

N/A

4

Utility Services, Inc.

Brian EvansMongeon

None

N/A

4

WEC Energy Group, Inc.

Anthony
Jankowski

Affirmative

N/A

None

N/A

5
Acciona Energy North America
George Brown
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Brandon
McCormick

Scott Berry

Scott Brame

Joe Tarantino

Shirley Eshbach

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 12 of 19

Voter

Designated
Proxy

Ballot

NERC
Memo

5

AEP

Thomas Foltz

Negative

Comments
Submitted

5

Ameren - Ameren Missouri

Sam Dwyer

Abstain

N/A

5

APS - Arizona Public Service
Co.

Linda
Henrickson

Affirmative

N/A

5

Arkansas Electric Cooperative
Corporation

Moses Harris

None

N/A

5

Associated Electric
Cooperative, Inc.

Brad Haralson

Affirmative

N/A

5

Austin Energy

Jeanie Doty

Negative

Comments
Submitted

5

Avista - Avista Corporation

Glen Farmer

Affirmative

N/A

5

Basin Electric Power
Cooperative

Mike Kraft

None

N/A

5

BC Hydro and Power Authority

Helen Hamilton
Harding

None

N/A

5

Boise-Kuna Irrigation District Lucky Peak Power Plant
Project

Mike Kukla

Negative

Third-Party
Comments

5

Bonneville Power
Administration

Francis Halpin

Negative

Comments
Submitted

5

BP Wind Energy North
America Inc.

Carla Holly

None

N/A

5

Choctaw Generation Limited
Partnership, LLLP

Rob Watson

None

N/A

5

Cleco Corporation

Stephanie
Huffman

Negative

Third-Party
Comments

5

CMS Energy - Consumers
Energy Company

David
Greyerbiehl

Negative

Comments
Submitted

5

Colorado Springs Utilities

Jeff Icke

Negative

Comments
Submitted

5

Con Ed - Consolidated Edison
Co. of New York

William Winters

Affirmative

N/A

5

Dairyland Power Cooperative

Tommy Drea

Negative

Third-Party
Comments

Louis Guidry

Alyson Slanover

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Index - NERC Balloting Tool

Segment

Organization

Page 13 of 19

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Dominion - Dominion
Resources, Inc.

Lou Oberski

Negative

Comments
Submitted

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Edison International Southern California Edison
Company

Selene Willis

None

N/A

5

EDP Renewables North
America LLC

Heather
Morgan

None

N/A

5

Entergy

Jamie Prater

Affirmative

N/A

5

Exelon

Ruth Miller

Affirmative

N/A

5

FirstEnergy - FirstEnergy
Solutions

Robert Loy

Affirmative

N/A

5

Great Plains Energy - Kansas
City Power and Light Co.

Harold Wyble

Affirmative

N/A

5

Great River Energy

Preston Walsh

Negative

Third-Party
Comments

5

Gridforce Energy
Management, LLC

David
Blackshear

None

N/A

5

Hydro-Qu?bec Production

Junji
Yamaguchi

None

N/A

5

JEA

John Babik

None

N/A

5

Kissimmee Utility Authority

Mike Blough

Affirmative

N/A

5

Lakeland Electric

Jim Howard

None

N/A

5

Lincoln Electric System

Kayleigh
Wilkerson

Negative

Third-Party
Comments

5

Los Angeles Department of
Water and Power

Glenn Barry

None

N/A

5

Manitoba Hydro

Yuguang Xiao

Affirmative

N/A

5

Massachusetts Municipal
Wholesale Electric Company

David Gordon

Affirmative

N/A

5

MEAG Power

Steven Grego

Abstain

N/A

5

Muscatine Power and Water

Neal Nelson

None

N/A

Abstain

N/A

5
NB Power Corporation
Laura McLeod
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Douglas Webb

Scott Miller

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 14 of 19

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Nebraska Public Power
District

Don Schmit

Negative

Third-Party
Comments

5

New York Power Authority

Randy
Crissman

Affirmative

N/A

5

NextEra Energy

Allen Schriver

None

N/A

5

NiSource - Northern Indiana
Public Service Co.

Dmitriy
Bazylyuk

Affirmative

N/A

5

North Carolina Electric
Membership Corporation

Robert Beadle

Affirmative

N/A

5

Northern California Power
Agency

Marty Hostler

None

N/A

5

OGE Energy - Oklahoma Gas
and Electric Co.

John Rhea

None

N/A

5

Omaha Public Power District

Mahmood Safi

Negative

Third-Party
Comments

5

Ontario Power Generation Inc.

David
Ramkalawan

Affirmative

N/A

5

OTP - Otter Tail Power
Company

Cathy Fogale

Negative

Third-Party
Comments

5

Portland General Electric Co.

Ryan Olson

Affirmative

N/A

5

PPL - Louisville Gas and
Electric Co.

Dan Wilson

Affirmative

N/A

5

PSEG - PSEG Fossil LLC

Tim Kucey

Affirmative

N/A

5

Public Utility District No. 1 of
Chelan County

Haley Sousa

Negative

Comments
Submitted

5

Public Utility District No. 1 of
Snohomish County

Sam Nietfeld

Negative

Third-Party
Comments

5

Puget Sound Energy, Inc.

Eleanor Ewry

Affirmative

N/A

5

Sacramento Municipal Utility
District

Susan Oto

Negative

Comments
Submitted

5

Salt River Project

Kevin Nielsen

Negative

Comments
Submitted

5

Santee Cooper

Tommy Curtis

Negative

No Comment
Submitted

Scott Brame

Joe Tarantino

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Segment

Organization

Page 15 of 19

Voter

Designated
Proxy

Ballot

NERC
Memo

5

SCANA - South Carolina
Electric and Gas Co.

Alyssa
Hubbard

None

N/A

5

Seattle City Light

Mike Haynes

Negative

Third-Party
Comments

5

Seminole Electric Cooperative,
Inc.

Brenda Atkins

None

N/A

5

Sempra - San Diego Gas and
Electric

Jerome Gobby

Negative

Third-Party
Comments

5

Silicon Valley Power - City of
Santa Clara

Sandra
Pacheco

None

N/A

5

Southern Company - Southern
Company Generation

William D.
Shultz

Affirmative

N/A

5

SunPower

Bradley Collard

None

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Negative

Comments
Submitted

5

Talen Generation, LLC

Donald Lock

Negative

Comments
Submitted

5

TECO - Tampa Electric Co.

R James
Rocha

Affirmative

N/A

5

Tennessee Valley Authority

M Lee Thomas

Affirmative

N/A

5

U.S. Bureau of Reclamation

Wendy Center

Negative

Comments
Submitted

5

WEC Energy Group, Inc.

Linda Horn

Affirmative

N/A

5

Xcel Energy, Inc.

Gerry Huitt

Negative

Comments
Submitted

6

APS - Arizona Public Service
Co.

Jonathan
Aragon

Affirmative

N/A

6

Arkansas Electric Cooperative
Corporation

Bruce Walkup

None

N/A

6

Austin Energy

Andrew Gallo

Negative

Comments
Submitted

6

Basin Electric Power
Cooperative

Paul Huettl

Affirmative

N/A

6

Berkshire Hathaway -

Sandra Shaffer

None

N/A

Andrey
Komissarov

PacifiCorp
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Segment

Organization

Page 16 of 19

Voter

6

Bonneville Power
Administration

Andrew Meyers

6

Cleco Corporation

Robert Hirchak

6

Con Ed - Consolidated Edison
Co. of New York

6

Designated
Proxy

Ballot

NERC
Memo

Negative

Comments
Submitted

Negative

Third-Party
Comments

Robert Winston

Affirmative

N/A

Dominion - Dominion
Resources, Inc.

Sean Bodkin

Negative

Comments
Submitted

6

Duke Energy

Greg Cecil

Affirmative

N/A

6

Edison International Southern California Edison
Company

Kenya Streeter

None

N/A

6

Entergy

Julie Hall

Affirmative

N/A

6

Exelon

Becky Webb

Affirmative

N/A

6

FirstEnergy - FirstEnergy
Solutions

Ann Ivanc

Affirmative

N/A

6

Florida Municipal Power Pool

Tom Reedy

Brandon
McCormick

Affirmative

N/A

6

Great Plains Energy - Kansas
City Power and Light Co.

Jim Flucke

Douglas Webb

Affirmative

N/A

6

Lincoln Electric System

Eric Ruskamp

Negative

Third-Party
Comments

6

Los Angeles Department of
Water and Power

Anton Vu

Affirmative

N/A

6

Luminant - Luminant Energy

Brenda
Hampton

Affirmative

N/A

6

Manitoba Hydro

Blair Mukanik

Affirmative

N/A

6

Modesto Irrigation District

James McFall

Affirmative

N/A

6

Muscatine Power and Water

Ryan Streck

Negative

Third-Party
Comments

6

NextEra Energy - Florida
Power and Light Co.

Silvia Mitchell

None

N/A

6

NiSource - Northern Indiana
Public Service Co.

Joe O'Brien

Abstain

N/A

Louis Guidry

Nick Braden

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Segment

Organization

Page 17 of 19

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Northern California Power
Agency

Dennis Sismaet

None

N/A

6

OGE Energy - Oklahoma Gas
and Electric Co.

Sing Tay

None

N/A

6

Omaha Public Power District

Joel Robles

None

N/A

6

Portland General Electric Co.

Daniel Mason

Affirmative

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

Affirmative

N/A

6

Public Utility District No. 1 of
Chelan County

Janis Weddle

Negative

Comments
Submitted

6

Public Utility District No. 2 of
Grant County, Washington

LeRoy
Patterson

None

N/A

6

Sacramento Municipal Utility
District

Jamie Cutlip

Negative

Comments
Submitted

6

Salt River Project

Bobby Olsen

Negative

Comments
Submitted

6

Santee Cooper

Michael Brown

Negative

No Comment
Submitted

6

Seattle City Light

Charles
Freeman

Negative

Third-Party
Comments

6

Seminole Electric Cooperative,
Inc.

Trudy Novak

Negative

Comments
Submitted

6

Snohomish County PUD No. 1

Franklin Lu

Negative

Third-Party
Comments

6

Southern Company - Southern
Company Generation and
Energy Marketing

Jennifer Sykes

Affirmative

N/A

6

Southern Indiana Gas and
Electric Co.

Brad Lisembee

Affirmative

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Rick Applegate

Negative

Comments
Submitted

6

Talen Energy Marketing, LLC

Jennifer
Hohenshilt

Negative

Comments
Submitted

6

TECO - Tampa Electric Co.

Benjamin Smith

Affirmative

N/A

Joe Tarantino

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Segment

Organization

Page 18 of 19

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Tennessee Valley Authority

Marjorie
Parsons

Affirmative

N/A

6

WEC Energy Group, Inc.

Scott Hoggatt

Affirmative

N/A

6

Westar Energy

Megan Wagner

Affirmative

N/A

6

Xcel Energy, Inc.

Carrie Dixon

Negative

Comments
Submitted

7

Exxon Mobil

Jay Barnett

None

N/A

7

Luminant Mining Company
LLC

Stewart Rake

Affirmative

N/A

8

David Kiguel

David Kiguel

Affirmative

N/A

8

Massachusetts Attorney
General

Frederick Plett

Affirmative

N/A

8

Roger Zaklukiewicz

Roger
Zaklukiewicz

Affirmative

N/A

9

Commonwealth of
Massachusetts Department of
Public Utilities

Donald Nelson

Affirmative

N/A

10

Midwest Reliability
Organization

Russel
Mountjoy

Abstain

N/A

10

New York State Reliability
Council

ALAN
ADAMSON

Affirmative

N/A

10

Northeast Power Coordinating
Council

Guy V. Zito

Affirmative

N/A

10

ReliabilityFirst

Anthony
Jablonski

Affirmative

N/A

10

SERC Reliability Corporation

Drew Slabaugh

Affirmative

N/A

10

Texas Reliability Entity, Inc.

Rachel Coyne

Negative

Comments
Submitted

10

Western Electricity
Coordinating Council

Steven
Rueckert

Affirmative

N/A

Previous

1

Next

Showing 1 to 309 of 309 entries

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Page 19 of 19

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NERC Balloting Tool (/)

Dashboard (/)

Page 1 of 17

Users

Ballots

Comment Forms

Login (/Users/Login) / Register (/Users/Register)

BALLOT RESULTS
Ballot Name: 2016-02 Modifications to CIP Standards CIP-012-1 Non-binding Poll AB 2 NB
Voting Start Date: 12/1/2017 12:01:00 AM
Voting End Date: 12/12/2017 8:00:00 PM
Ballot Type: NB
Ballot Activity: AB
Ballot Series: 2
Total # Votes: 228
Total Ballot Pool: 290
Quorum: 78.62
Weighted Segment Value: 60.44
Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes

Negative
Fraction

Abstain

No
Vote

Segment:
1

75

1

28

0.56

22

0.44

15

10

Segment:
2

7

0.5

4

0.4

1

0.1

0

2

Segment:
3

70

1

27

0.614

17

0.386

12

14

Segment:
4

14

0.9

6

0.6

3

0.3

0

5

Segment:
5

69

1

19

0.5

19

0.5

11

20

Segment:
6

42

1

17

0.63

10

0.37

5

10

Segment:
7

2

0.1

1

0.1

0

0

0

1

Segment:
8

3

0.3

3

0.3

0

0

0

0

Segment:
9

1

0.1

1

0.1

0

0

0

0

Segment:
10

7

0.4

4

0.4

0

0

3

0

72

2.097

46

62

Segment

Totals:
290
6.3
110
4.203
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Page 2 of 17

BALLOT POOL MEMBERS
Show All

Segment

 entries

Organization

Search: Search

Voter

Designated
Proxy

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Negative

Comments
Submitted

1

American Transmission
Company, LLC

Douglas Johnson

Negative

Comments
Submitted

1

APS - Arizona Public Service
Co.

Michelle
Amarantos

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

John Shaver

None

N/A

1

Associated Electric
Cooperative, Inc.

Mark Riley

Affirmative

N/A

1

Austin Energy

Thomas
Standifur

None

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Negative

Comments
Submitted

1

Basin Electric Power
Cooperative

David Rudolph

Affirmative

N/A

1

BC Hydro and Power
Authority

Patricia
Robertson

Abstain

N/A

1

Berkshire Hathaway Energy MidAmerican Energy Co.

Terry Harbour

Negative

Comments
Submitted

1

Bonneville Power
Administration

Kammy RogersHolliday

Negative

Comments
Submitted

1

Brazos Electric Power
Cooperative, Inc.

Tony Kroskey

Negative

Comments
Submitted

1

Cedar Falls Utilities

Adam Peterson

None

N/A

Negative

Comments
Submitted

1

CenterPoint Energy Houston
John Brockhan
Electric,
LLC
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Segment

Organization

Page 3 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Central Electric Power
Cooperative (Missouri)

Michael Bax

None

N/A

1

Central Hudson Gas &
Electric Corp.

Frank Pace

Affirmative

N/A

1

City Utilities of Springfield,
Missouri

Michael Buyce

Affirmative

N/A

1

Con Ed - Consolidated
Edison Co. of New York

Daniel Grinkevich

Affirmative

N/A

1

Dominion - Dominion Virginia
Power

Larry Nash

Abstain

N/A

1

Duke Energy

Laura Lee

Affirmative

N/A

1

Edison International Southern California Edison
Company

Steven Mavis

Affirmative

N/A

1

Entergy - Entergy Services,
Inc.

Oliver Burke

Abstain

N/A

1

Eversource Energy

Quintin Lee

Affirmative

N/A

1

Exelon

Chris Scanlon

Abstain

N/A

1

FirstEnergy - FirstEnergy
Corporation

Karen Yoder

Affirmative

N/A

1

Great Plains Energy - Kansas
City Power and Light Co.

James McBee

Affirmative

N/A

1

Great River Energy

Gordon Pietsch

None

N/A

1

Hydro One Networks, Inc.

Payam
Farahbakhsh

Negative

Comments
Submitted

1

Hydro-Qu?bec TransEnergie

Nicolas Turcotte

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Laura Nelson

Affirmative

N/A

1

Imperial Irrigation District

Jesus Sammy
Alcaraz

Abstain

N/A

1

International Transmission
Company Holdings
Corporation

Michael Moltane

Negative

Comments
Submitted

1

Lincoln Electric System

Danny Pudenz

Abstain

N/A

Douglas Webb

Oshani
Pathirane

Stephanie
Burns

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Segment

Organization

Page 4 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Long Island Power Authority

Robert Ganley

Abstain

N/A

1

Los Angeles Department of
Water and Power

faranak sarbaz

None

N/A

1

Lower Colorado River
Authority

Michael Shaw

Affirmative

N/A

1

M and A Electric Power
Cooperative

William Price

Affirmative

N/A

1

Manitoba Hydro

Mike Smith

Affirmative

N/A

1

MEAG Power

David Weekley

Abstain

N/A

1

Memphis Light, Gas and
Water Division

Allan Long

Affirmative

N/A

1

Minnkota Power Cooperative
Inc.

Theresa Allard

Abstain

N/A

1

Muscatine Power and Water

Andy Kurriger

Negative

Comments
Submitted

1

N.W. Electric Power
Cooperative, Inc.

Mark Ramsey

Affirmative

N/A

1

National Grid USA

Michael Jones

Negative

Comments
Submitted

1

Nebraska Public Power
District

Jamison Cawley

Abstain

N/A

1

New York Power Authority

Salvatore
Spagnolo

Affirmative

N/A

1

NextEra Energy - Florida
Power and Light Co.

Mike ONeil

None

N/A

1

NiSource - Northern Indiana
Public Service Co.

Steve Toosevich

Affirmative

N/A

1

Northeast Missouri Electric
Power Cooperative

Kevin White

Affirmative

N/A

1

OGE Energy - Oklahoma Gas
and Electric Co.

Terri Pyle

Abstain

N/A

1

Ohio Valley Electric
Corporation

Scott
Cunningham

Negative

Comments
Submitted

1

Omaha Public Power District

Doug Peterchuck

Negative

Comments
Submitted

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Segment

Organization

Page 5 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

1

OTP - Otter Tail Power
Company

Charles Wicklund

Negative

Comments
Submitted

1

Peak Reliability

Scott Downey

None

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Laurie Williams

Affirmative

N/A

1

PPL Electric Utilities
Corporation

Brenda Truhe

Abstain

N/A

1

PSEG - Public Service
Electric and Gas Co.

Joseph Smith

Abstain

N/A

1

Public Utility District No. 1 of
Chelan County

Jeff Kimbell

None

N/A

1

Public Utility District No. 1 of
Snohomish County

Long Duong

Negative

Comments
Submitted

1

Puget Sound Energy, Inc.

Theresa
Rakowsky

Affirmative

N/A

1

Sacramento Municipal Utility
District

Arthur Starkovich

Negative

Comments
Submitted

1

Salt River Project

Steven Cobb

None

N/A

1

Santee Cooper

Shawn Abrams

Abstain

N/A

1

SCANA - South Carolina
Electric and Gas Co.

Tom Hanzlik

Abstain

N/A

1

Seattle City Light

Pawel Krupa

Negative

Comments
Submitted

1

Seminole Electric
Cooperative, Inc.

Mark Churilla

Negative

Comments
Submitted

1

Sempra - San Diego Gas and
Electric

Martine Blair

Negative

Comments
Submitted

1

Sho-Me Power Electric
Cooperative

Peter Dawson

Affirmative

N/A

1

Southern Company Southern Company Services,
Inc.

Katherine Prewitt

Affirmative

N/A

Negative

Comments
Submitted

1

Tacoma Public Utilities
John Merrell
(Tacoma, WA)
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Jeff Johnson

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Segment

Organization

Page 6 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Tennessee Valley Authority

Howell Scott

Affirmative

N/A

1

Tri-State G and T
Association, Inc.

Tracy Sliman

Affirmative

N/A

1

U.S. Bureau of Reclamation

Richard Jackson

Negative

Comments
Submitted

1

Westar Energy

Kevin Giles

Affirmative

N/A

1

Western Area Power
Administration

sean erickson

Negative

Comments
Submitted

2

California ISO

Richard Vine

Affirmative

N/A

2

Electric Reliability Council of
Texas, Inc.

Elizabeth Axson

Affirmative

N/A

2

Independent Electricity
System Operator

Leonard Kula

Affirmative

N/A

2

ISO New England, Inc.

Michael Puscas

None

N/A

2

Midcontinent ISO, Inc.

Ellen Oswald

Negative

Comments
Submitted

2

New York Independent
System Operator

Gregory Campoli

None

N/A

2

PJM Interconnection, L.L.C.

Mark Holman

Affirmative

N/A

3

AEP

Aaron Austin

Negative

Comments
Submitted

3

AES - Indianapolis Power
and Light Co.

Bette White

Affirmative

N/A

3

APS - Arizona Public Service
Co.

Vivian Vo

Affirmative

N/A

3

Arkansas Electric
Cooperative Corporation

Philip Huff

Affirmative

N/A

3

Associated Electric
Cooperative, Inc.

Todd Bennett

Affirmative

N/A

3

Austin Energy

W. Dwayne
Preston

Negative

Comments
Submitted

3

Basin Electric Power
Cooperative

Jeremy Voll

Affirmative

N/A

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Segment

Organization

Page 7 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Berkshire Hathaway Energy MidAmerican Energy Co.

Annette Johnston

Negative

Comments
Submitted

3

Bonneville Power
Administration

Rebecca Berdahl

Negative

Comments
Submitted

3

Central Electric Power
Cooperative (Missouri)

Adam Weber

Affirmative

N/A

3

City of Farmington

Linda JacobsonQuinn

None

N/A

3

City of Leesburg

Chris Adkins

Affirmative

N/A

3

City of Vero Beach

Ginny Beigel

Affirmative

N/A

3

City Utilities of Springfield,
Missouri

Scott Williams

Affirmative

N/A

3

Cleco Corporation

Michelle Corley

Abstain

N/A

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Affirmative

N/A

3

Cowlitz County PUD

Russell Noble

None

N/A

3

Duke Energy

Lee Schuster

Affirmative

N/A

3

Edison International Southern California Edison
Company

Romel Aquino

None

N/A

3

Eversource Energy

Sharon Flannery

None

N/A

3

Exelon

John Bee

Abstain

N/A

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

Affirmative

N/A

3

Georgia System Operations
Corporation

Scott McGough

None

N/A

3

Great Plains Energy - Kansas
City Power and Light Co.

Jessica Tucker

Affirmative

N/A

3

Great River Energy

Brian Glover

Negative

Comments
Submitted

3

Hydro One Networks, Inc.

Paul Malozewski

None

N/A

3

KAMO Electric Cooperative

Ted Hilmes

None

N/A

Brandon
McCormick

Louis Guidry

Douglas Webb

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Segment

Organization

Page 8 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Lincoln Electric System

Jason Fortik

Abstain

N/A

3

M and A Electric Power
Cooperative

Stephen Pogue

Affirmative

N/A

3

Manitoba Hydro

Karim Abdel-Hadi

Affirmative

N/A

3

MEAG Power

Roger Brand

Scott Miller

Abstain

N/A

3

Modesto Irrigation District

Jack Savage

Nick Braden

Abstain

N/A

3

Muscatine Power and Water

Seth Shoemaker

Negative

Comments
Submitted

3

National Grid USA

Brian Shanahan

Negative

Comments
Submitted

3

Nebraska Public Power
District

Tony Eddleman

Abstain

N/A

3

New York Power Authority

David Rivera

Affirmative

N/A

3

NiSource - Northern Indiana
Public Service Co.

Aimee Harris

Affirmative

N/A

3

North Carolina Electric
Membership Corporation

doug white

Affirmative

N/A

3

Northeast Missouri Electric
Power Cooperative

Skyler Wiegmann

None

N/A

3

NW Electric Power
Cooperative, Inc.

John Stickley

Affirmative

N/A

3

Ocala Utility Services

Neville Bowen

None

N/A

3

OGE Energy - Oklahoma Gas
and Electric Co.

Donald Hargrove

Abstain

N/A

3

OTP - Otter Tail Power
Company

Wendi Olson

Negative

Comments
Submitted

3

Owensboro Municipal Utilities

Thomas Lyons

Affirmative

N/A

3

Platte River Power Authority

Jeff Landis

Negative

Comments
Submitted

3

PNM Resources - Public
Service Company of New
Mexico

Lynn Goldstein

Affirmative

N/A

3

Portland General Electric Co.

Angela Gaines

Affirmative

N/A

Scott Brame

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Index - NERC Balloting Tool

Segment

Organization

Page 9 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

3

PPL - Louisville Gas and
Electric Co.

Charles Freibert

None

N/A

3

PSEG - Public Service
Electric and Gas Co.

Jeffrey Mueller

Abstain

N/A

3

Public Utility District No. 1 of
Chelan County

Joyce Gundry

Negative

Comments
Submitted

3

Puget Sound Energy, Inc.

Lynda Kupfer

Affirmative

N/A

3

Rutherford EMC

Tom Haire

Abstain

N/A

3

Sacramento Municipal Utility
District

Nicole Looney

Negative

Comments
Submitted

3

Salt River Project

Rudy Navarro

Negative

Comments
Submitted

3

Santee Cooper

James Poston

Abstain

N/A

3

SCANA - South Carolina
Electric and Gas Co.

Scott Parker

None

N/A

3

Seattle City Light

Tuan Tran

Negative

Comments
Submitted

3

Seminole Electric
Cooperative, Inc.

James Frauen

Negative

Comments
Submitted

3

Sempra - San Diego Gas and
Electric

Bridget Silvia

Negative

Comments
Submitted

3

Sho-Me Power Electric
Cooperative

Jeff Neas

Affirmative

N/A

3

Silicon Valley Power - City of
Santa Clara

Val Ridad

None

N/A

3

Snohomish County PUD No.
1

Mark Oens

Negative

Comments
Submitted

3

Southern Company Alabama Power Company

Joel Dembowski

Affirmative

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

Marc Donaldson

Negative

Comments
Submitted

3

TECO - Tampa Electric Co.

Ronald Donahey

None

N/A

3

Tennessee Valley Authority

Ian Grant

Abstain

N/A

Joe Tarantino

Harold Sherrill

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Index - NERC Balloting Tool

Segment

Organization

Page 10 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Tri-State G and T
Association, Inc.

Janelle Marriott
Gill

None

N/A

3

WEC Energy Group, Inc.

Thomas Breene

Affirmative

N/A

3

Westar Energy

Bo Jones

Affirmative

N/A

3

Xcel Energy, Inc.

Michael Ibold

Abstain

N/A

4

American Public Power
Association

Jack Cashin

None

N/A

4

Austin Energy

Esther Weekes

Affirmative

N/A

4

City of Clewiston

Lynne Mila

Affirmative

N/A

4

City Utilities of Springfield,
Missouri

John Allen

Affirmative

N/A

4

Georgia System Operations
Corporation

Guy Andrews

Affirmative

N/A

4

Indiana Municipal Power
Agency

Jack Alvey

Scott Berry

None

N/A

4

North Carolina Electric
Membership Corporation

John Lemire

Scott Brame

Affirmative

N/A

4

Public Utility District No. 1 of
Snohomish County

John Martinsen

Negative

Comments
Submitted

4

Sacramento Municipal Utility
District

Beth Tincher

Negative

Comments
Submitted

4

Seattle City Light

Hao Li

Negative

Comments
Submitted

4

Seminole Electric
Cooperative, Inc.

Charles
Wubbena

None

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

None

N/A

4

Utility Services, Inc.

Brian EvansMongeon

None

N/A

4

WEC Energy Group, Inc.

Anthony
Jankowski

Affirmative

N/A

5

Acciona Energy North
America

George Brown

None

N/A

Brandon
McCormick

Joe Tarantino

Shirley Eshbach

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Index - NERC Balloting Tool

Segment

Organization

Page 11 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

5

AEP

Thomas Foltz

Negative

Comments
Submitted

5

Ameren - Ameren Missouri

Sam Dwyer

Abstain

N/A

5

APS - Arizona Public Service
Co.

Linda Henrickson

Affirmative

N/A

5

Associated Electric
Cooperative, Inc.

Brad Haralson

Affirmative

N/A

5

Austin Energy

Jeanie Doty

Affirmative

N/A

5

Avista - Avista Corporation

Glen Farmer

Affirmative

N/A

5

Basin Electric Power
Cooperative

Mike Kraft

Affirmative

N/A

5

BC Hydro and Power
Authority

Helen Hamilton
Harding

None

N/A

5

Boise-Kuna Irrigation District Lucky Peak Power Plant
Project

Mike Kukla

Negative

Comments
Submitted

5

Bonneville Power
Administration

Francis Halpin

Negative

Comments
Submitted

5

BP Wind Energy North
America Inc.

Carla Holly

None

N/A

5

Choctaw Generation Limited
Partnership, LLLP

Rob Watson

None

N/A

5

Cleco Corporation

Stephanie
Huffman

Abstain

N/A

5

CMS Energy - Consumers
Energy Company

David
Greyerbiehl

Negative

Comments
Submitted

5

Colorado Springs Utilities

Jeff Icke

Negative

Comments
Submitted

5

Con Ed - Consolidated
Edison Co. of New York

William Winters

Affirmative

N/A

5

Dairyland Power Cooperative

Tommy Drea

Negative

Comments
Submitted

5

Dominion - Dominion
Resources, Inc.

Lou Oberski

Negative

Comments
Submitted

Affirmative

N/A

5 - NERC Ver 4.2.1.0
Duke Energy
Dale Goodwine
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Louis Guidry

Alyson Slanover

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 12 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Edison International Southern California Edison
Company

Selene Willis

None

N/A

5

EDP Renewables North
America LLC

Heather Morgan

None

N/A

5

Entergy

Jamie Prater

Affirmative

N/A

5

Exelon

Ruth Miller

Abstain

N/A

5

FirstEnergy - FirstEnergy
Solutions

Robert Loy

Affirmative

N/A

5

Great Plains Energy - Kansas
City Power and Light Co.

Harold Wyble

Affirmative

N/A

5

Great River Energy

Preston Walsh

Negative

Comments
Submitted

5

Hydro-Qu?bec Production

Junji Yamaguchi

None

N/A

5

JEA

John Babik

Negative

Comments
Submitted

5

Kissimmee Utility Authority

Mike Blough

Affirmative

N/A

5

Lakeland Electric

Jim Howard

None

N/A

5

Lincoln Electric System

Kayleigh
Wilkerson

Abstain

N/A

5

Los Angeles Department of
Water and Power

Glenn Barry

None

N/A

5

Manitoba Hydro

Yuguang Xiao

Affirmative

N/A

5

Massachusetts Municipal
Wholesale Electric Company

David Gordon

Abstain

N/A

5

MEAG Power

Steven Grego

Abstain

N/A

5

Muscatine Power and Water

Neal Nelson

None

N/A

5

NB Power Corporation

Laura McLeod

Abstain

N/A

5

Nebraska Public Power
District

Don Schmit

Abstain

N/A

5

New York Power Authority

Randy Crissman

Affirmative

N/A

5

NextEra Energy

Allen Schriver

None

N/A

Douglas Webb

Scott Miller

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Index - NERC Balloting Tool

Segment

Organization

Page 13 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

5

NiSource - Northern Indiana
Public Service Co.

Dmitriy Bazylyuk

Affirmative

N/A

5

Northern California Power
Agency

Marty Hostler

None

N/A

5

OGE Energy - Oklahoma Gas
and Electric Co.

John Rhea

None

N/A

5

Omaha Public Power District

Mahmood Safi

Negative

Comments
Submitted

5

Ontario Power Generation
Inc.

David
Ramkalawan

Affirmative

N/A

5

OTP - Otter Tail Power
Company

Cathy Fogale

Negative

Comments
Submitted

5

Portland General Electric Co.

Ryan Olson

Affirmative

N/A

5

PPL - Louisville Gas and
Electric Co.

JULIE
HOSTRANDER

None

N/A

5

PSEG - PSEG Fossil LLC

Tim Kucey

Abstain

N/A

5

Public Utility District No. 1 of
Chelan County

Haley Sousa

Negative

Comments
Submitted

5

Public Utility District No. 1 of
Snohomish County

Sam Nietfeld

Negative

Comments
Submitted

5

Puget Sound Energy, Inc.

Eleanor Ewry

Affirmative

N/A

5

Sacramento Municipal Utility
District

Susan Oto

Negative

Comments
Submitted

5

Salt River Project

Kevin Nielsen

Negative

Comments
Submitted

5

Santee Cooper

Tommy Curtis

Abstain

N/A

5

SCANA - South Carolina
Electric and Gas Co.

Alyssa Hubbard

None

N/A

5

Seattle City Light

Mike Haynes

Negative

Comments
Submitted

5

Seminole Electric
Cooperative, Inc.

Brenda Atkins

None

N/A

5

Sempra - San Diego Gas and
Electric

Jerome Gobby

Negative

Comments
Submitted

Joe Tarantino

Andrey
Komissarov

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Index - NERC Balloting Tool

Segment

Organization

Page 14 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Silicon Valley Power - City of
Santa Clara

Sandra Pacheco

None

N/A

5

Southern Company Southern Company
Generation

William D. Shultz

Affirmative

N/A

5

SunPower

Bradley Collard

None

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Negative

Comments
Submitted

5

Talen Generation, LLC

Matthew
McMillan

None

N/A

5

TECO - Tampa Electric Co.

Frank L Busot

None

N/A

5

Tennessee Valley Authority

M Lee Thomas

Abstain

N/A

5

U.S. Bureau of Reclamation

Wendy Center

Negative

Comments
Submitted

5

Westar Energy

Laura Cox

Affirmative

N/A

6

APS - Arizona Public Service
Co.

Jonathan Aragon

Affirmative

N/A

6

Arkansas Electric
Cooperative Corporation

Bruce Walkup

None

N/A

6

Austin Energy

Andrew Gallo

Affirmative

N/A

6

Basin Electric Power
Cooperative

Paul Huettl

Affirmative

N/A

6

Berkshire Hathaway PacifiCorp

Sandra Shaffer

Negative

Comments
Submitted

6

Cleco Corporation

Robert Hirchak

Abstain

N/A

6

Con Ed - Consolidated
Edison Co. of New York

Robert Winston

Affirmative

N/A

6

Dominion - Dominion
Resources, Inc.

Sean Bodkin

Negative

Comments
Submitted

6

Duke Energy

Greg Cecil

Affirmative

N/A

6

Edison International Southern California Edison
Company

Kenya Streeter

None

N/A

Affirmative

N/A

6 - NERC Ver 4.2.1.0
EntergyMachine Name: ERODVSBSWB02
Julie Hall
© 2018

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Louis Guidry

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 15 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Exelon

Becky Webb

Abstain

N/A

6

FirstEnergy - FirstEnergy
Solutions

Ann Ivanc

Affirmative

N/A

6

Florida Municipal Power Pool

Tom Reedy

Brandon
McCormick

Affirmative

N/A

6

Great Plains Energy - Kansas
City Power and Light Co.

Jim Flucke

Douglas Webb

Affirmative

N/A

6

Lincoln Electric System

Eric Ruskamp

Negative

Comments
Submitted

6

Los Angeles Department of
Water and Power

Anton Vu

Affirmative

N/A

6

Luminant - Luminant Energy

Brenda Hampton

Affirmative

N/A

6

Manitoba Hydro

Blair Mukanik

Affirmative

N/A

6

Muscatine Power and Water

Ryan Streck

Negative

Comments
Submitted

6

NextEra Energy - Florida
Power and Light Co.

Silvia Mitchell

None

N/A

6

NiSource - Northern Indiana
Public Service Co.

Joe O'Brien

Affirmative

N/A

6

Northern California Power
Agency

Dennis Sismaet

None

N/A

6

OGE Energy - Oklahoma Gas
and Electric Co.

Sing Tay

None

N/A

6

Omaha Public Power District

Joel Robles

None

N/A

6

Portland General Electric Co.

Daniel Mason

Abstain

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

None

N/A

6

Public Utility District No. 1 of
Chelan County

Janis Weddle

Negative

Comments
Submitted

6

Public Utility District No. 2 of
Grant County, Washington

LeRoy Patterson

None

N/A

6

Sacramento Municipal Utility
District

Jamie Cutlip

Negative

Comments
Submitted

Joe Tarantino

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 16 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Salt River Project

Bobby Olsen

Negative

Comments
Submitted

6

Santee Cooper

Michael Brown

Abstain

N/A

6

Seattle City Light

Charles Freeman

Negative

Comments
Submitted

6

Seminole Electric
Cooperative, Inc.

Trudy Novak

Negative

Comments
Submitted

6

Snohomish County PUD No.
1

Franklin Lu

None

N/A

6

Southern Company Southern Company
Generation and Energy
Marketing

Jennifer Sykes

Affirmative

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Rick Applegate

Negative

Comments
Submitted

6

Talen Energy Marketing, LLC

Jennifer
Hohenshilt

None

N/A

6

TECO - Tampa Electric Co.

Benjamin Smith

Affirmative

N/A

6

Tennessee Valley Authority

Marjorie Parsons

Abstain

N/A

6

WEC Energy Group, Inc.

Scott Hoggatt

Affirmative

N/A

6

Westar Energy

Megan Wagner

Affirmative

N/A

7

Exxon Mobil

Jay Barnett

None

N/A

7

Luminant Mining Company
LLC

Stewart Rake

Affirmative

N/A

8

David Kiguel

David Kiguel

Affirmative

N/A

8

Massachusetts Attorney
General

Frederick Plett

Affirmative

N/A

8

Roger Zaklukiewicz

Roger
Zaklukiewicz

Affirmative

N/A

9

Commonwealth of
Massachusetts Department
of Public Utilities

Donald Nelson

Affirmative

N/A

10

Midwest Reliability
Organization

Russel Mountjoy

Abstain

N/A

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Segment

Organization

Page 17 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

10

New York State Reliability
Council

ALAN
ADAMSON

Affirmative

N/A

10

Northeast Power
Coordinating Council

Guy V. Zito

Affirmative

N/A

10

ReliabilityFirst

Anthony
Jablonski

Affirmative

N/A

10

SERC Reliability Corporation

Drew Slabaugh

Affirmative

N/A

10

Texas Reliability Entity, Inc.

Rachel Coyne

Abstain

N/A

10

Western Electricity
Coordinating Council

Steven Rueckert

Abstain

N/A

Previous

1

Next

Showing 1 to 290 of 290 entries

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Standards Announcement

Project 2016-02 Modifications to CIP Standards
Formal Comment Period Open through December 11, 2017
Now Available

A 45-day formal comment period for CIP-012-1 - Cyber Security – Communications between Control
Centers is open through 8 p.m. Eastern, Monday, December 11, 2017.
The standard drafting team’s considerations of the responses received from the last comment period are
reflected in this draft of the standard.
Commenting

Use the Standards Balloting and Commenting System (SBS) to submit comments. If you experience issues
navigating the SBS, contact Wendy Muller. An unofficial Word version of the comment form is posted on
the project page.
•

If you are having difficulty accessing the SBS due to a forgotten password, incorrect
credential error messages, or system lock-out, contact NERC IT support directly at
https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5 p.m. Eastern).

•

Passwords expire every 6 months and must be reset.

•

The SBS is not supported for use on mobile devices.

•

Please be mindful of ballot and comment period closing dates. We ask to allow at least 48
hours for NERC support staff to assist with inquiries. Therefore, it is recommended that users try
logging into their SBS accounts prior to the last day of a comment/ballot period.

Next Steps

An additional ballot for the standard and non-binding poll of the associated Violation Risk Factors and
Violation Severity Levels will be conducted December 1-11, 2017.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Katherine Street at (404) 446-9702 or Mat Bunch at (404) 4469785.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Comment Report
Project Name:

2016-02 Modifications to CIP Standards | CIP-012-1

Comment Period Start Date:

10/27/2017

Comment Period End Date:

12/11/2017

Associated Ballots:

2016-02 Modifications to CIP Standards CIP-012-1 AB 2 ST

There were 61 sets of responses, including comments from approximately 168 different people from approximately 117 companies
representing 10 of the Industry Segments as shown in the table on the following pages.

Questions
1. Requirement R1: The SDT drafted CIP-012-1 Requirement R1 for the Responsible Entity to develop one or more documented plan(s) to
mitigate the risk of the unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring and control data while
being transmitted between any Control Centers. Do you agree with this revision? If not, please provide the basis for your disagreement and
an alternate proposal.

2. Requirement R1: The SDT seeks comment on scoping sensitive BES data as it applies to Real-time Assessment and Real-time monitoring
and control data. Do you agree with scoping CIP-012-1 Requirement R1 in this manner? Please provide comment in support of your
response.

3. Requirement R2: The SDT drafted CIP-012-1 Requirement R2 for the Responsible Entity to implement the plan(s) specified in Requirement
R1, except under CIP Exceptional Circumstances. Do you agree with this revision? If not, please provide the basis for your disagreement and
an alternate proposal.

4. Implementation Plan: The SDT revised the Implementation Plan to make the standard effective the first day of the first calendar quarter that
is twenty-four (24) calendar months after the effective date of the applicable governmental authority’s order approving the standard, or as
otherwise provided for by the applicable governmental authority. Do you agree with this proposal? If you think an alternate implementation
time period is needed, please provide a detailed explanation of actions and time needed to meet the implementation deadline.

5. The SDT believes proposed CIP-012-1 provides entities with flexibility to meet the reliability objectives in a cost effective manner. Do you
agree? If you do not agree, or if you agree but have suggestions for improvement to enable more cost effective approaches, please provide
your recommendation and, if appropriate, technical justification.

6. If you have additional comments on the proposed CIP-012-1 – Cyber Security – Communications between Control Centers drafted in
response to the FERC directive that you have not provided in response to the questions above, please provide them here.

Organization
Name

Name

Segment(s)

FirstEnergy - Aaron
3
FirstEnergy Ghodooshim
Corporation

Southern
Brandon
Company Cain
Southern
Company
Services, Inc.

Brandon
McCormick

Brandon
McCormick

1,3,5,6

Region

RF

FRCC,MRO,NPCC,SERC,SPP
RE,Texas RE,WECC

FRCC

Group
Name

Group
Member
Name

Group Member
Organization

Group
Group
Member
Member
Segment(s) Region

FirstEnergy FirstEnergy
Corporation

4

RF

Aubrey
Short

FirstEnergy FirstEnergy
Corporation

1

RF

Theresa
Ciancio

FirstEnergy FirstEnergy
Corporation

3

RF

Robert Loy

FirstEnergy FirstEnergy
Solutions

5

RF

Ann Ivanc

FirstEnergy FirstEnergy
Solutions

6

RF

Katherine
Prewitt

Southern
Company Southern
Company
Services, Inc.

1

SERC

R. Scott
Moore

Southern
3
Company Alabama Power
Company

SERC

William D.
Shultz

Southern
Company Southern
Company
Generation

5

SERC

Jennifer
Sykes

Southern
6
Company Southern
Company
Generation and
Energy
Marketing

SERC

Tim Beyrle

City of New
4
Smyrna Beach
Utilities
Commission

FRCC

FirstEnergy Aaron
Corporation Ghdooshim

Southern
Company

FMPA

Jim Howard Lakeland
Electric

5

FRCC

Tennessee
Valley
Authority

Brian Millard 1,3,5,6

Duke Energy Colby
Bellville

SRC

David
Francis

1,3,5,6

2

SERC

FRCC,RF,SERC

Lynne Mila

City of
Clewiston

4

FRCC

Javier
Cisneros

Fort Pierce
Utilities
Authority

3

FRCC

Randy Hahn Ocala Utility
Services

3

FRCC

Don Cuevas Beaches
Energy
Services

1

FRCC

Jeffrey
Partington

Keys Energy
Services

4

FRCC

Tom Reedy

Florida
Municipal
Power Pool

6

FRCC

Steven
Lancaster

Beaches
Energy
Services

3

FRCC

Mike Blough Kissimmee
5
Utility Authority

FRCC

Chris Adkins City of
Leesburg

3

FRCC

Ginny Beigel City of Vero
Beach

3

FRCC

Tennessee Scott,
Tennessee
1
Valley
Howell D.
Valley Authority
Authority
Grant, Ian S. Tennessee
3
Valley Authority

SERC

Thomas, M. Tennessee
5
Lee
Valley Authority

SERC

Parsons,
Marjorie S.

Tennessee
6
Valley Authority

SERC

Doug Hils

Duke Energy

1

RF

Lee
Schuster

Duke Energy

3

FRCC

Dale
Goodwine

Duke Energy

5

SERC

Greg Cecil

Duke Energy

6

RF

Gregory
Campoli

New York
Independent
System
Operator

2

NPCC

Duke
Energy

FRCC,MRO,NPCC,RF,SERC,SPP SRC +
RE,Texas RE,WECC
SWG

SERC

Seattle City
Light

Ginette
Lacasse

1,3,4,5,6

WECC

Mark
Holman

PJM
2
Interconnection,
L.L.C.

RF

Charles
Yeung

Southwest
Power Pool,
Inc. (RTO)

2

SPP RE

Terry BIlke

Midcontinent
ISO, Inc.

2

RF

Elizabeth
Axson

Electric
Reliability
Council of
Texas, Inc.

2,3

Texas RE

Ben Li

IESO

1

MRO

Drew Bonser SWG

NA - Not
Applicable

NA - Not
Applicable

Darrem
Lamb

CAISO

2

WECC

Matt
Goldberg

ISONE

2

NPCC

1

WECC

4

WECC

Seattle City
Light

6

WECC

Mike Haynes Seattle City
Light

5

WECC

Michael
Watkins

1,4

WECC

Faz Kasraie Seattle City
Light

5

WECC

John Clark

Seattle City
Light

6

WECC

Tuan Tran

Seattle City
Light

3

WECC

Laurrie
Hammack

Seattle City
Light

3

WECC

Haley Sousa Public Utility
5
District No. 1 of
Chelan County

WECC

Joyce
Gundry

WECC

Seattle City Pawel Krupa Seattle City
Light Ballot
Light
Body
Hao Li
Seattle City
Light
Bud
(Charles)
Freeman

Public Utility Janis
District No. 1 Weddle
of Chelan
County

6

Chelan
PUD

Seattle City
Light

Public Utility
3
District No. 1 of
Chelan County

DTE Energy - Karie
Detroit
Barczak
Edison
Company

Northeast
Ruida Shu
Power
Coordinating
Council

3,4,5

1,2,3,4,5,6,7,8,9,10 NPCC

DTE
Energy DTE
Electric

RSC no
Dominion
and ISONE

Jeff Kimbell

Public Utility
1
District No. 1 of
Chelan County

WECC

Janis
Weddle

Public Utility
6
District No. 1 of
Chelan County

WECC

Jeffrey
Depriest

DTE Energy DTE Electric

5

RF

Daniel
Herring

DTE Energy DTE Electric

4

RF

Karie
Barczak

DTE Energy DTE Electric

3

RF

Guy V. Zito

Northeast
Power
Coordinating
Council

10

NPCC

Randy
MacDonald

New Brunswick 2
Power

NPCC

Wayne
Sipperly

New York
4
Power Authority

NPCC

Glen Smith

Entergy
Services

4

NPCC

Brian
Robinson

Utility Services 5

NPCC

Bruce
Metruck

New York
6
Power Authority

NPCC

Alan
Adamson

New York State 7
Reliability
Council

NPCC

Edward
Bedder

Orange &
Rockland
Utilities

1

NPCC

David Burke Orange &
Rockland
Utilities

3

NPCC

Michele
Tondalo

UI

1

NPCC

Laura
Mcleod

NB Power

1

NPCC

David
Ontario Power 5
Ramkalawan Generation Inc.

NPCC

Quintin Lee

Eversource
Energy

1

NPCC

Paul
Malozewski

Hydro One
Networks, Inc.

3

NPCC

Helen Lainis IESO

2

NPCC

Michael
Schiavone

National Grid

1

NPCC

Michael
Jones

National Grid

3

NPCC

Greg
Campoli

NYISO

2

NPCC

Sylvain
Clermont

Hydro Quebec

1

NPCC

Chantal
Mazza

Hydro Quebec

2

NPCC

Silvia
Mitchell

NextEra Energy 6
- Florida Power
and Light Co.

NPCC

Michael
Forte

Con Ed Consolidated
Edison

1

NPCC

Daniel
Grinkevich

Con Ed Consolidated
Edison Co. of
New York

1

NPCC

Peter Yost

Con Ed Consolidated
Edison Co. of
New York

3

NPCC

Brian
O'Boyle

Con Ed Consolidated
Edison

5

NPCC

4

NPCC

Sean Cavote PSEG
Midwest
Russel
Reliability
Mountjoy
Organization

10

MRO
NSRF

Joseph
DePoorter

Madison Gas & 3,4,5,6
Electric

MRO

Larry
Heckert

Alliant Energy

4

MRO

Amy
Casucelli

Xcel Energy

1,3,5,6

MRO

Michael
Brytowski

Great River
Energy

1,3,5,6

MRO

1,6

MRO

Jodi Jensen Western Area
Power
Administratino
Kayleigh
Wilkerson

Lincoln Electric 1,3,5,6
System

MRO

Mahmood
Safi

Omaha Public
Power District

MRO

1,3,5,6

Dominion Dominion
Resources,
Inc.

PSEG

Southwest
Power Pool,
Inc. (RTO)

Sean Bodkin 6

Sean
Cavote

Shannon
Mickens

1,3,5,6

2

Dominion

NPCC,RF

SPP RE

Brad Parret

Minnesota
Power

1,5

MRO

Terry
Harbour

MidAmerican
Energy
Company

1,3

MRO

Tom Breene Wisconsin
Public Service

3,5,6

MRO

Jeremy Volls Basin Electric
Power Coop

1

MRO

Kevin Lyons Central Iowa
Power
Cooperative

1

MRO

Mike Morrow Midcontinent
Independent
System
Operator

2

MRO

Dominion 3
Dominion
Resources, Inc.

NA - Not
Applicable

Lou Oberski Dominion 5
Dominion
Resources, Inc.

NA - Not
Applicable

Larry Nash

Dominion Dominion
Virginia Power

1

NA - Not
Applicable

PSEG REs Tim Kucey

PSEG - PSEG
Fossil LLC

5

NPCC

SPP
Standards
Review
Group

Connie
Lowe

Karla Barton PSEG - PSEG 6
Energy
Resources and
Trade LLC

RF

Jeffrey
Mueller

PSEG - Public 3
Service Electric
and Gas Co.

RF

Joseph
Smith

PSEG - Public 1
Service Electric
and Gas Co.

RF

Shannon
Mickens

Southwest
2
Power Pool Inc.

SPP RE

Megan
Wagner

Westar Energy 6

SPP RE

Louis Guidry Cleco
Corporation

1,3,5,6

Robert Gray Board of Public NA - Not
Utilities (BPU), Applicable

SPP RE
NA - Not
Applicable

Kansas City,
KS
Ron Spicer
PPL Louisville
Gas and
Electric Co.

Shelby
Wade

1,3,5,6

RF,SERC

EDF
Renewables

5

SPP RE

LG&E and KU
Energy, LLC

3

SERC

PPL Electric
Utilities
Corporation

1

RF

Dan Wilson

LG&E and KU
Energy, LLC

5

SERC

Linn Oelker

LG&E and KU
Energy, LLC

6

SERC

PPL NERC Charlie
Registered Freibert
Affiliates
Brenda
Truhe

1. Requirement R1: The SDT drafted CIP-012-1 Requirement R1 for the Responsible Entity to develop one or more documented plan(s) to
mitigate the risk of the unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring and control data while
being transmitted between any Control Centers. Do you agree with this revision? If not, please provide the basis for your disagreement and
an alternate proposal.
Kristine Ward - Seminole Electric Cooperative, Inc. - 1,3,4,5,6 - FRCC
Answer

No

Document Name
Comment
Comments: The standard would be more effective if it more specifically identified the security objective described in FERC Order No. 822 paragraph 54,
of “maintaining the integrity and availability of sensitive BES data”.

With regard to R1.3, the standard should better reflect FERC Order No. 822 paragraph 55, specifically to address that protections should not adversely
affect BES reliability, should account for the risk of CYBER assets, and that the information being protected should be results –based and not zerodefect.
Likes

0

Dislikes

0

Response

Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer

No

Document Name
Comment
Dominion Energy recommends changing Measure M1 to the following:
“Evidence may include, but is not limited to, documented plan(s) that meet the criteria identified in Requirement R1.”
Likes

0

Dislikes

0

Response

Janis Weddle - Public Utility District No. 1 of Chelan County - 6, Group Name Chelan PUD
Answer
Document Name

No

Comment
CHPD is generally in agreement with the Draft 2 revision. However; we request that the newly-introduced terms “monitoring data” and “control data”
either be replaced by “BES Data” (a new NERC-defined Glossary term) or themselves be defined in the NERC Glossary. Additionally, the concept of
“demarcation point(s)” should be constrained to the entity’s equipment, for example “1.2 Identification of the Responsible Entity’s demarcation
point(s)…” The current wording implies that each entity should document their local demarcation point and also any demarcation point(s) that exist at
each neighboring system. A change to a demarcation point in one system should not create a paperwork or compliance issue for a neighbor or vice
versa. Alternatively, consider defining the term “demarcation point” in the NERC glossary and identify the scope within the definition of the term.
Likes

5

Dislikes

Public Utility District No. 1 of Snohomish County, 5, Nietfeld Sam; Snohomish County PUD No. 1, 6, Lu
Franklin; Public Utility District No. 1 of Snohomish County, 1, Duong Long; Snohomish County PUD No. 1,
3, Oens Mark; Public Utility District No. 1 of Snohomish County, 4, Martinsen John
0

Response

Aaron Austin - AEP - 3
Answer

No

Document Name
Comment
AEP agrees with the SDT on removal of Operational and Planning data from the scope of the Standard, but feels the data specification
remains loose. AEP operates in three markets with three RTOs. Our Balancing Authority has requested market related data as part of the
TOP-003-3 implementation data specifications. We feel that this market data is out of scope for CIP-012 and the Standard could be further
improved by specifying that market related data does not meet the intent for Real-time Assessment and Real time monitoring and control
data. Appropriate exclusion language in the Implementation Guidance and Technical rationale may be satisfactory.
Likes

0

Dislikes

0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
BPA appreciates the revisions that the SDT has made based on industry feedback on the initial draft, such as adding demarcation points.
BPA reiterates its position as documented in BPA’s SAR and initial draft comments that CIP-012-1 is not necessary. We continue to believe that the
objectives can be met by coordinating with existing standards such as CIP-003 and CIP-005. However, if the SDT proceeds with CIP-012-1, BPA
remains concerned with the technical feasibility of the standard.

Points of discussion:
•

Encryption may not be feasible due to availability concerns. (e.g., failure of encryption keys or latency problems with encryption for availability
requirements.)

•

Additionally, entities and common carriers use a variety of media to carry traffic, and will undoubtedly use traffic shaping to maintain service
levels: routing becomes unpredictable; each packet could take a different route from point A to B.

•

Even if a single entity owns the entire communication network, this is still a problem. Modern routing protocols will try to deliver packets over a
system with inoperable equipment, severed links, etc. The only remedy is to physically protect the entire communication system in advance of
system faults to satisfy CIP-012. If one packet traverses a link due to a system fault that is not protected – it would be a violation.

Likes

0

Dislikes

0

Response

Russel Mountjoy - Midwest Reliability Organization - 10, Group Name MRO NSRF
Answer

No

Document Name
Comment
The NSRF does not agree with two separate requirements, one for a plan and one to implementation. We recommend following precedent in the other
CIP standards, for example, CIP-004-6. The obligation can be accomplished with one requirement, as follows.
R1. “The Responsible Entity shall implement one or more documented process(es) to mitigate the risk of the unauthorized disclosure or modification of
Real-time Assessments and Real-time monitoring and control data while being transmitted between any Control Centers, except under CIP Exceptional
Circumstances. This excludes oral communications. The process(es) shall identify:
R1.1 security protection used to mitigate risk of unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring and control
data while being transmitted between Control Centers,
R1.2 demarcation point(s) where security protection is applied for transmitting Real-time Assessment and Real-time monitoring and control data
between Control Centers. Demarcation points identified by the Responsible Entity do not add additional Cyber Assets to the scope of the CIP Reliability
Standards; and
For R1.3, please see our rational in question 6. R1.3 Identify each Responsible Entity for applying security protection(s) to the transmission of
Real-time Assessment and Real-time monitoring and control data between Control Centers, when the Control Centers are owned or operated by
different Responsible Entities.”
This also includes important scoping from the implementation guidance that belongs in the requirement, that demarcation points don’t add additional
Cyber Assets to the scope of the CIP standards.
Likes

0

Dislikes
Response

0

Donald Lock - Talen Generation, LLC - 5
Answer

No

Document Name
Comment
We have no technical concerns with the proposed standard, but it is unclear how 3rd party-owned Control Centers that GO/GOPs use through an
agency relationship are to be addressed. CIP-012-1 states in sect. 4.1, “The requirements in this standard apply to the following functional entities,
referred to as ‘Responsible Entities,’ that own or operate a Control Center,”… “4.1.2. Generator Operator,”…”4.1.3. Generator Owner.” GO/GOPs do
not operate agency-relationship Control Centers any more than they own them, so CIP-012-1 responsibilities apparently rest with the owners of 3rdparty Control Centers and not with the GO/GOPs that hire them. It is unclear how these obligations are communicated and administered, however,
since 3rd-party Control Center owners are not (and cannot be) NERC-registered entities.
Likes

0

Dislikes

0

Response

Paul Huettl - Basin Electric Power Cooperative - 6
Answer

No

Document Name
Comment
Please refer to NRECA comments.
Likes

0

Dislikes

0

Response

Richard Jackson - U.S. Bureau of Reclamation - 1
Answer

No

Document Name
Comment
Reclamation disagrees that having a plan adds to the reliability of protecting data used for Operational Planning Analysis, Real-time Assessment, and
Real-time monitoring. A plan is an unwarranted layer of compliance that is not needed and the present proposed language is too broad and could be
interpreted to apply to data or Control Centers over which an entity has no influence.
Reclamation recommends the SDT implement the following:

•

Clearly specify that each Responsible Entity is required to mitigate the risk of unauthorized disclosure or modification of its own BES Data
between its own BES Control Centers.

Replace the term “plan” with “process,” and specify the requirements pertain to BES Data and Control Centers.
•

Change Requirement R1:

from: The Responsible Entity shall develop one or more documented plan(s) to mitigate the risk of unauthorized disclosure or modification of Real-time
Assessment and Real-time monitoring and control data while being transmitted between any Control Centers. This requirement excludes oral
communications.
to: Each Responsible Entity shall have one or more documented processes in place to mitigate the risk of unauthorized disclosure or modification of
BES Data being transmitted between its own Control Centers. This requirement excludes oral and non-electronic communications.
•

Add the following definitions to the NERC Glossary of Terms:

BES Data: BES reliability operating services information related to the entity’s high and medium impact Control Centers which affects Operational
Planning Analysis, Real-time Assessments, and Real-time monitoring and control of the facility, and would affect the operation of the BES if
compromised.
Likes

0

Dislikes

0

Response

Andrew Gallo - Austin Energy - 6
Answer

No

Document Name
Comment
Austin Energy (AE) agrees the referenced data deserves protection to ensure it has not been modified and FERC directed NERC to “specify how the
confidentiality, integrity, and availability of...data should be protected while...transmitted.” However, AE disagrees with the extent to which the proposed
standard requires the data be protected. FERC Order 822 states (on page 36), “…we recognize that not all communication network components and
data pose the same risk to bulk electric system reliability and may not require the same level of protection.” The proposed standard applies the same
protection criteria across all in-scope data. AE does not agree viewing Real-time Assessment and monitoring/control data without context will adversely
affect the reliability of the BES. Confidentiality need not be protected for all in-scope data.
Additionally, AE realizes the SDT does not specifying controls to protect confidentiality and integrity, but the only method available to achieve the
proposed requirement is encryption. FERC Order 822 states (on page 39), “it is reasonable to conclude that any lag in communication speed resulting
from implementation of protections [encryption technologies] should only be measureable on the order of milliseconds and, therefore, will not adversely
impact Control Center communications,” but AE believes that statement refers only to a single data stream. Encryption of multiple data streams at once
- from one to many points, - may add latency require more computing resources.
Likes

0

Dislikes
Response

0

Nicholas Lauriat - Network and Security Technologies - 1
Answer

No

Document Name
Comment
N&ST is concerned with the fact the draft Implementation Guidance for CIP-012 describes a scenario in which BES Control Centers are exchanging
data with a “3rd party” (Figure 4, “Network Diagram depicting communications through a 3rd party”). Although the SDT clearly believes that such
communications would be in scope for CIP-012 R1, it is N&ST’s opinion that as presently written, R1 would not apply. Figure 4 depicts two Control
Centers communicating with a 3rd party, not with each other.
Suggested rewording: REPLACE: “...develop one or more documented plan(s) to mitigate the risk of the unauthorized disclosure or modification of
Real-time Assessment and Real-time monitoring and control data while being transmitted between any Control Centers.”
WITH: “...develop one or more documented plan(s) to mitigate the risk of the unauthorized disclosure or modification of Real-time Assessment and
Real-time monitoring and control data while being transmitted between (1) any two Control Centers, or (2) between a Control Center and a third-party
that provides Real-time Assessment data.”
Likes

0

Dislikes

0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

No

Document Name
Comment
The SPP Standards Review Group appreciates the time and effort expended by the drafting team to further this effort and supports the current
standard’s development as an objective based standard, rather than as a prescriptive based standard.
The SPP Standards Review Group appreciates the time and effort expended by the drafting team to further this effort and supports the current
standard’s development as an objective based standard, rather than as a prescriptive based standard. The SPP Standards Review Group would
recommend a formal definition for “Demarcation Point” be included in the NERC Glossary of Terms and define the protection, if required. Additionally,
the SPP Standards Review Group requests clarification whether Demarcation Points need to be classified as CIP Assets or just identified in the
documented plan(s)?

Likes

0

Dislikes
Response

0

Barry Lawson - National Rural Electric Cooperative Association - 4
Answer

No

Document Name
Comment
NRECA supports the structure of R1 and we appreciate the removal of “data used for Operational Planning Analysis” language. However, new
language was also added to R1 and we are unsure of what qualifies as “control data” as used in this requirement. NRECA reviewed the related draft
Implementation Guidance and draft Technical Rationale and we did not see any information that explained what “control data” is. Please provide clarity
on what “control data” means.
Likes

0

Dislikes

0

Response

Terry Harbour - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1
Answer

No

Document Name
Comment
We do not agree with two separate requirements, one for a plan and one to implement. We recommend following precedent in the other CIP standards,
for example, CIP-004-011. The obligation can be accomplished with one requirement, as follows. “The Responsible Entity shall implement one or more
documented process(es) to mitigate the risk of the unauthorized disclosure or modification of Real-time Assessments and Real-time monitoring and
control data while being transmitted between any Control Centers, except under CIP Exceptional Circumstances. This excludes oral communications.
The process(es) shall identify: 1.1 security protection used to mitigate risk of unauthorized disclosure or modification of Real-time Assessment and
Real-time monitoring and control data while being transmitted between Control Centers. 1.2 demarcation point(s) where security protection is applied for
transmitting Real-time Assessment and Real-time monitoring and control data between Control Centers. Demarcation points identified by the
Responsible Entity do not add additional Cyber Assets to the scope of the CIP Reliability Standards; and 1.3 roles and responsibilities of each
Responsible Entity for applying security protection to the transmission of Real-time Assessment and Real-time monitoring and control data between
Control Centers, when the Control Centers are owned or operated by different Responsible Entities.” This also includes important scoping from the
implementation guidance that belongs in the requirement, that demarcation points don’t add additional Cyber Assets to the scope of the CIP standards.
Likes

0

Dislikes

0

Response

Lona Calderon - Salt River Project - 1,3,5,6 - WECC
Answer
Document Name
Comment

No

SRP agrees the data should be protected. SRP also agrees the protections for the data in scope must ensure the data has not been modified, and that
FERC directed NERC to “specify how the confidentiality, integrity, and availability of each type of bulk electric system data should be protected while it
is being transmitted.” However, SRP takes exception to the extent the proposed standard requires the data in scope to be protected. FERC Order 822
states on page 36, “…we recognize that not all communication network components and data pose the same risk to bulk electric system reliability and
may not require the same level of protection.” However, the proposed standard applies the same criteria of protection against unauthorized disclosure
across all of the data within the defined scope. SRP does not agree viewing of the Real-time Assessment and Real-time monitoring and control data
without context will decrease the reliable operation of the BES and asserts confidentiality does not need to be protected for all data under this scope.
Additionally, SRP recognizes the SDT is not specifying the controls used to protect confidentiality and integrity. However, the only method available to
achieve the proposed required objective is to implement encryption. FERC Order 822 states on page 39, “it is reasonable to conclude that any lag in
communication speed resulting from implementation of protections [encryption technologies] should only be measureable on the order of milliseconds
and, therefore, will not adversely impact Control Center communications,” but SRP asserts this statement only refers to a single data stream. It is
unknown what encryption will do when dealing with multiple data streams being transmitted at once, from one to many points, not only to the latency
added for the reliable operation of the BES, but also to the computing resources.
Likes

0

Dislikes

0

Response

Annette Johnston - Berkshire Hathaway Energy - MidAmerican Energy Co. - 3
Answer

No

Document Name
Comment
Support Terry Harbour comments (Berhshire Hathaway - MidAmerican Energy Company)
Likes

0

Dislikes

0

Response

Oshani Pathirane - Oshani Pathirane On Behalf of: Payam Farahbakhsh, Hydro One Networks, Inc., 1, 3; - Oshani Pathirane
Answer

No

Document Name
Comment
While Hydro One supports the general intent of the Standard, we request that our suggestions below are incorporated. We do not agree with the
addition of R1.3. We believe that this wording does not sufficiently address potential disagreements between entities. The Standard should address a
situation in which two entities at each end of a communication link cannot reach an agreement on the level of protection that needs to be applied to the
communication link between their Control Centres, or, the situation in which one entity’s plan does not align with another entity’s plan.

In addition, it is not clear how the Standard addresses Control Centres that will be built in the future. The term “plan” and verbiage of Requirement 1
suggests that this may be a one-time plan that will address existing Control Centres only.

An alternative approach may be to remove the word “plan” and simply require entities to implement logical/physical controls that both entities agree
upon. If the entities cannot reach an agreement, a third party can be selected to provide a resolution.

In addition, the measures (M1) do not sufficiently describe how compliance would be demonstrated.
Likes

0

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0

Response

Lan Nguyen - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
No, CenterPoint Energy Houston Electric, LLC (“CenterPoint Energy”) does not agree with this revision. CenterPoint Energy recommends the following
revisions to proposed Requirement R1:
The Responsible Entity shall develop one or more documented plan(s) to mitigate the risk of unauthorized disclosure or modification of Real-time
Assessment and Real-time monitoring data while being transmitted between Control Centers. This requirement excludes oral communications. The plan
shall include: [Violation Risk Factor: Medium] [Time Horizon: Operations Planning].
CenterPoint Energy recommends the SDT remove the phrase “and control” from the expanded phrase “Real-time monitoring and control data.” The
inclusion of the phrase “and control” may create confusion and does not align with TOP-003 and IRO-010 data specification
Requirements. Additionally, the phrase was not mentioned in FERC Order 822. The SDT recognizes in the corresponding Technical Rationale
document that “in practice Real-time control data is not transmitted separately from Real-time monitoring data.” Given this practice, the introduction of
the concept of separately transmitted “Real-time control data” may create confusion on whether there are additional data specification responsibilities
besides those detailed in TOP-003 and IRO-010. Additionally, when control signals that result in the physical operation of BES elements are transmitted
between Control Centers, such control signals receive the same protection from unauthorized disclosure or modification as the data and information
identified as necessary to perform Real-time Assessments and Real-time monitoring. Thus, there is no need for the additional language to the phrase
and no additional benefit to the industry or Reliability.
CenterPoint Energy also recommends removing the word “any” from the phrase “any Control Center” because the word is too broad and does not add
value or clarity to the requirement.
CenterPoint Energy also notes that the definition of Control Center is currently being revised. CenterPoint Energy recommends that the definition of
Control Center be finalized before the final ballot of CIP-012-1.
Likes

0

Dislikes

0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

No

Document Name
Comment
While the SDT believes the “integrity and availability of sensitive bulk electric system data”, as noted in FERC Order No. 822, paragraph 54, is
addressed in R1, Texas RE notes the use of the term “or”: Identification of security protection used to mitigate the risk of unauthorized disclosure or
modification of Real-time Assessment and Real-time monitoring and control data while being transmitted between Control Centers. In its response, the
SDT specifically referenced the Consideration of Issue or Directive document. In that document, the SDT makes clear that entities may elect, solely at
their discretion, to protect communications links, data, or both.

Texas RE believes this directly conflicts with the plain language in FERC Order No. 822, P. 54. FERC made it clear that protections should apply to
both communication links and sensitive data. However, the SDT has specified such protections could be potentially applied solely to communications
links or sensitive data. That is, the SDT has endorsed permitting responsible entities to simply elect to plan and implement physical protections for
communications links. This would “mitigate” the risk of an unauthorized disclosure or modification of data using one of the delineated methods. As
such, the responsible entity would potentially be compliant with the standard without proposing or implementing any logical protections for sensitive data
during its transmission. This appears counter to FERC’s intent to protect “both the integrity and availability of sensitive bulk electric system
data.” FERC Order No. 822, P. 54. Texas RE maintains its recommendation to 1) change “or” to “and”; and 2) change the phrase risk of unauthorized
disclosure or modification to integrity and availability of sensitive bulk electric system data.

Additionally, Since GO does not appear in the definition of Control Center, Texas RE suggests removing GO from the applicability section.
Likes

0

Dislikes

0

Response

Jennifer Hohenshilt - Talen Energy Marketing, LLC - 6
Answer

No

Document Name
Comment
We have no technical concerns with the proposed standard, but it is unclear how 3rd party-owned Control Centers that GO/GOPs use through an
agency relationship are to be addressed. CIP-012-1 states in sect. 4.1, “The requirements in this standard apply to the following functional entities,
referred to as ‘Responsible Entities,’ that own or operate a Control Center,”… “4.1.2. Generator Operator,”…”4.1.3. Generator Owner.” GO/GOPs do
not operate agency-relationship Control Centers any more than they own them, so CIP-012-1 responsibilities apparently rest with the owners of 3rd-

party Control Centers and not with the GO/GOPs that hire them. It is unclear how these obligations are communicated and administered, however,
since 3rd-party Control Center owners are not (and cannot be) NERC-registered entities.
Likes

0

Dislikes

0

Response

Jeanne Kurzynowski - Consumers Energy Company - 1,3,4,5 - RF
Answer

No

Document Name
Comment
The requirement as written does not provide clear threshold on the type of Control Centers that should be in scope for this standard, i.e. does this
requirement apply to high/medium impact BES Cyber Systems, or it also applies to low impact BES Cyber System. Please clarify. Please also consider
how to incorporate the scoping criteria into CIP-002 standard.
Likes

0

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0

Response

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer

No

Document Name
Comment
We support SRP and Chelan PUD comments.
Likes

0

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0

Response

Joe Tarantino - Joe Tarantino On Behalf of: Arthur Starkovich, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Beth Tincher, Sacramento
Municipal Utility District, 4, 1, 5, 6, 3; Jamie Cutlip, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Kevin Smith, Balancing Authority of
Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Susan Oto, Sacramento Municipal Utility District, 4, 1,
5, 6, 3; - Joe Tarantino
Answer
Document Name

No

Comment

It not clear who will maintain responsibility for compliance with the standard and who will be audited.

Likes

0

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0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer

No

Document Name
Comment
We are still unclear on the included data. For R1.2, recommend that the Entities should mutually agree on the demarcation points. For R1.3, we are
concerned with resolution of disagreements between different Entities.
Likes

0

Dislikes

0

Response

Kevin Salsbury - Berkshire Hathaway - NV Energy - 5
Answer

No

Document Name
Comment
It is unnecessary to have 2 Requirements for this Standard, especially with each Requirement currently identified to have the same enforceable date.
NV Energy recommends following precedence of other Standards and combining the Requirements into a single requirement that states, "An entity
shall implement one or more document processes/plans....". .
Likes

0

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0

Response

sean erickson - Western Area Power Administration - 1

Answer

No

Document Name
Comment
WAPA does not agree with two separate requirements, one for a plan and one for implementation. We recommend following precedent in the other CIP
standards, for example, CIP-004-6. The obligation can be accomplished with one requirement, as follows.
R1. “The Responsible Entity shall implement one or more documented process(es) to mitigate the risk of the unauthorized disclosure or modification of
Real-time Assessments and Real-time monitoring and control data while being transmitted between any Control Centers, except under CIP Exceptional
Circumstances. This excludes oral communications. The process(es) shall identify:
R1.1 security protection used to mitigate risk of unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring and control
data while being transmitted and received between Control Centers,
R1.2 demarcation point(s) where security protection is applied for transmitting Real-time Assessment and Real-time monitoring and control data
between Control Centers. Demarcation points identified by the Responsible Entity do not add additional Cyber Assets to the scope of the CIP Reliability
Standards; and
R1.3. Identification of roles and responsibilities of each Responsible Entity for applying security protection to the transmission of Real-time Assessment
and Real-time monitoring and control data between Control Centers, when the Control Centers are owned or operated by different Responsible Entities.
Other changes in this recommended language:
R1.1 was changed to clarify that data is being protected while being “transmitted and received” between Control Centers.
R1.2 was changed to include important scoping from the implementation guidance that belongs in the requirement, that demarcation points don’t add
additional Cyber Assets to the scope of the CIP standards.
Likes

0

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0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion and ISO-NE
Answer

No

Document Name
Comment
We are still unclear on the included data. For R1.2, recommend that the Entities should mutually agree on the demarcation points. For R1.3, we are
concerned with resolution of disagreements between different Entities.
Likes

0

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Response

0

Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 6
Answer

No

Document Name
Comment
Tacoma Power endorses the draft comments shared with it by Salt River Project (SRP), which follow:
SRP agrees the data should be protected. SRP also agrees the protections for the data in scope must ensure the data has not been modified, and that
FERC directed NERC to “specify how the confidentiality, integrity, and availability of each type of bulk electric system data should be protected while it
is being transmitted.” However, SRP takes exception to the extent the proposed standard requires the data in scope to be protected. FERC Order 822
states on page 36, “…we recognize that not all communication network components and data pose the same risk to bulk electric system reliability and
may not require the same level of protection.” However, the proposed standard applies the same criteria of protection against unauthorized disclosure
across all of the data within the defined scope. SRP does not agree viewing of the Real-time Assessment and Real-time monitoring and control data
without context will decrease the reliable operation of the BES and asserts confidentiality does not need to be protected for all data under this scope.
Additionally, SRP recognizes the SDT is not specifying the controls used to protect confidentiality and integrity. However, the only method available to
achieve the proposed required objective is to implement encryption. FERC Order 822 states on page 39, “it is reasonable to conclude that any lag in
communication speed resulting from implementation of protections [encryption technologies] should only be measureable on the order of milliseconds
and, therefore, will not adversely impact Control Center communications,” but SRP asserts this statement only refers to a single data stream. It is
unknown what encryption will do when dealing with multiple data streams being transmitted at once, from one to many points, not only to the latency
added for the reliable operation of the BES, but also to the computing resources.
Likes

0

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0

Response

Richard Vine - California ISO - 2
Answer

Yes

Document Name
Comment
The California ISO supports the comments of the IRC Security Working Group (SWG)
Likes

0

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0

Response

Sean Cavote - PSEG - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer
Document Name

Yes

Comment
PSEG agrees with the revision; however, the SDT should clarify that it is permissible for the demarcation point to be located outside the ESP/PSP.
Likes

4

Dislikes

PSEG - Public Service Electric and Gas Co., 1, Smith Joseph; PSEG - Public Service Electric and Gas Co.,
3, Mueller Jeffrey; Long Island Power Authority, 1, Ganley Robert; PSEG - PSEG Fossil LLC, 5, Kucey
Tim
0

Response

Ronald Donahey - TECO - Tampa Electric Co. - 3
Answer

Yes

Document Name
Comment
TEC wishes to endorse the comment of the Edison Electric Institute.
Likes

0

Dislikes

0

Response

Lynn Goldstein - PNM Resources - Public Service Company of New Mexico - 3
Answer

Yes

Document Name
Comment
PNMR Agrees with the SDT and AEP's comments to remove Operational and Planning data from the scope of the Standard. However we do not share
AEP’s concerns and comments regarding market related data.
Likes

0

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0

Response

Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer
Document Name

Yes

Comment
Duke Energy agrees with the revision, however, we feel that in order to ensure consistency throughout the industry, the drafting team should consider
developing definitions for Real-time Monitoring and Real-time Control Data. Neither of these terms are NERC defined, and could lead to varying
interpretations throughout the industry. Does the Real-time Monitoring data only include the data specified in TOP-003 and IRO-010? Does it include
SCADA data used specifically to control field assets like generators (AGC) , circuit breakers, relays, etc.? The standard would be improved with
additional clarity around these terms.
Likes

0

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0

Response

Shannon Fair - Colorado Springs Utilities - 1,3,5,6
Answer

Yes

Document Name
Comment
CSU agrees the data should be protected. SRP also agrees the protections for the data in scope must ensure the data has not been modified, and that
FERC directed NERC to “specify how the confidentiality, integrity, and availability of each type of bulk electric system data should be protected while it
is being transmitted.” However, CSU takes exception to the extent the proposed standard requires the data in scope to be protected. FERC Order 822
states on page 36, “…we recognize that not all communication network components and data pose the same risk to bulk electric system reliability and
may not require the same level of protection.” However, the proposed standard applies the same criteria of protection against unauthorized disclosure
across all of the data within the defined scope. CSU does not agree viewing of the Real-time Assessment and Real-time monitoring and control data
without context will decrease the reliable operation of the BES and asserts confidentiality does not need to be protected for all data under this scope.
Likes

0

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0

Response

Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer

Yes

Document Name
Comment
Xcel Energy agrees with the removal of language related to Planning Analysis, but continues to have concerns with implementation of this Standards as
related to the term and definition of Control Center. Specifically, Xcel Energy is concerenced with the definition of "associated data centeres" as part of
the Control Center. The Standard does not appear to apply to communication between the control center and a field device (per reference model on
page 5 of Technical Rationale). However, if there is a control center communicating with a device that aggregates multiple field devices, such as a dual
ported RTU, is that aggregating device location considered an associated data center?
Likes

0

Dislikes

0

Response

Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment
ERCOT signs onto the comments of the SRC/ITC/SWG of the IRC, pasted below.

Comments: The SRC & ITC SWG offers the following comment and recommendation. To draw a more clear line to the TOP-003 and IRO-010
standards, the SWG recommends revising Requirement R1 as follows, “For Real-time Assessment and Real-time monitoring and control data, as
documented by a Reliability Coordinator, Transmission Operator, or Balancing Authority, the Responsible Entity shall develop one or more documented
plan(s) to mitigate the risk of the unauthorized disclosure or modification of the data while it is being transmitted between Control Centers. This excludes
oral communications, regardless of transport means.”
Likes

0

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0

Response

Chantal Mazza - Hydro-Qu?bec TransEnergie - 2 - NPCC
Answer

Yes

Document Name
Comment
R1 addresses developing a plan and R2 implementing the plan. In numerous EOP standards involving plans as well as in IRO-014, the terminology
used is “develop, maintain and implement”. Maintenance of a plan i.e. keeping it up to date is essential. Thus we recommend modifying R1 so that it
reads :
R1. The Responsible Entity shall develop and maintain one or more documented plan(s) to mitigate (…)
This comment is more of a comprehension question. If we take for example the following : we have two control centers and the distance between the
two control centers is approximately 20 miles (32Km) .
One control center has two buildings and the distance between the two buildings is approximately 70 miles (112Km). One building is for the Operating
personnel hosting facility, which has a defined PSP and an ESP. The other building, is the data Center (hosting RAS servers), which has a defined PSP
and an ESP.
There is a communication link (70 miles (112Km)) between the Operating personnel hosting building and the data center building. This communication
link would not be subject of CIP-012. The communication link (20 miles (32Km)) between the two control centers would be subject to the CIP-012.

Is this comprehension correct?

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0

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0

Response

Andrey Komissarov - Andrey Komissarov On Behalf of: Jerome Gobby, Sempra - San Diego Gas and Electric, 5, 3, 1; - Andrey Komissarov
Answer

Yes

Document Name
Comment
SDG&E is in agreement with Duke Energy's comments
Likes

0

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0

Response

Laurie Williams - PNM Resources - Public Service Company of New Mexico - 1
Answer

Yes

Document Name
Comment
PNMR Agrees with the SDT and AEP’s comments to remove Operational and Planning data from the scope of the Standard. However we do not share
AEP’s concerns and comments regarding market related data.
Likes

0

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0

Response

Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer
Document Name
Comment

Yes

Scoping to real-time data is appropriate as entities share significant amounts of data between control centers for coordination, safety, and operations
that would not have an 15 minute impact on the BES. The requirement should only apply to real-time data that would impact BES operations.
Likes

0

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0

Response

David Francis - SRC - 2 - MRO,Texas RE,NPCC,SERC,RF, Group Name SRC + SWG
Answer

Yes

Document Name
Comment
Comments: The SRC & ITC SWG offers the following comment and recommendation. To draw a more clear line to the TOP-003 and IRO-010
standards, the SWG recommends revising Requirement R1 as follows, “For Real-time Assessment and Real-time monitoring and control data, as
documented by a Reliability Coordinator, Transmission Operator, or Balancing Authority, the Responsible Entity shall develop one or more documented
plan(s) to mitigate the risk of the unauthorized disclosure or modification of the data while it is being transmitted between Control Centers. This excludes
oral communications, regardless of transport means.”

Likes

0

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0

Response

Steven Powell - Trans Bay Cable LLC - NA - Not Applicable - WECC
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Kara White - NRG - NRG Energy, Inc. - 3,4,5,6 - FRCC,MRO,WECC,Texas RE,NPCC,SERC,SPP RE,RF

Answer

Yes

Document Name
Comment

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0

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0

Response

Brian Millard - Tennessee Valley Authority - 1,3,5,6 - SERC, Group Name Tennessee Valley Authority
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 3, Group Name FirstEnergy Corporation
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Glen Farmer - Avista - Avista Corporation - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Vivian Vo - APS - Arizona Public Service Co. - 3
Answer

Yes

Document Name
Comment

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0

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0

Response

Eleanor Ewry - Puget Sound Energy, Inc. - 5
Answer

Yes

Document Name
Comment

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0

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0

Response

Chris Scanlon - Exelon - 1
Answer

Yes

Document Name
Comment

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0

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0

Response

Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

Yes

Document Name
Comment

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0

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0

Response

Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Brandon McCormick - Brandon McCormick On Behalf of: Ginny Beigel, City of Vero Beach, 3; Lynne Mila, City of Clewiston, 4; Tom Reedy,
Florida Municipal Power Pool, 6; - Brandon McCormick, Group Name FMPA
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Douglas Webb - Douglas Webb On Behalf of: Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; James McBee,
Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; Jessica Tucker, Great Plains Energy - Kansas City Power and Light Co., 5,
1, 3, 6; Jim Flucke, Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; - Douglas Webb
Answer

Yes

Document Name
Comment

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0

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0

Response

larry brusseau - Corn Belt Power Cooperative - 1
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

RoLynda Shumpert - SCANA - South Carolina Electric and Gas Co. - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC

Answer

Yes

Document Name
Comment

Likes

0

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0

Response

W. Dwayne Preston - Austin Energy - 3
Answer
Document Name
Comment
I support Andrew Gallo's Comments from Austin Energy.
Likes

0

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Response

0

2. Requirement R1: The SDT seeks comment on scoping sensitive BES data as it applies to Real-time Assessment and Real-time monitoring
and control data. Do you agree with scoping CIP-012-1 Requirement R1 in this manner? Please provide comment in support of your
response.
sean erickson - Western Area Power Administration - 1
Answer

No

Document Name
Comment
WAPA agrees with the removal of “data related to Operational Planning Analysis” from R1. However, clarification is needed to ensure that the “control
data” term is consistently applied and clearly addresses the intent of FERC’s directive. Additionally, important scoping from the implementation
guidance belongs in the requirement, that demarcation points don’t add additional Cyber Assets to the scope of the CIP standards.
Likes

0

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0

Response

Andrey Komissarov - Andrey Komissarov On Behalf of: Jerome Gobby, Sempra - San Diego Gas and Electric, 5, 3, 1; - Andrey Komissarov
Answer

No

Document Name
Comment
SDG&E is in agreement with Xcel Energy's comments
Likes

0

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0

Response

Joe Tarantino - Joe Tarantino On Behalf of: Arthur Starkovich, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Beth Tincher, Sacramento
Municipal Utility District, 4, 1, 5, 6, 3; Jamie Cutlip, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Kevin Smith, Balancing Authority of
Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Susan Oto, Sacramento Municipal Utility District, 4, 1,
5, 6, 3; - Joe Tarantino
Answer
Document Name
Comment

No

We have a concern regarding real time assessment, the real time assessment is a study about the system condition and is not going to change the status
of the power system. The data does not need to be protected to this level because knowledge of the data would not lead to scenario that would impact
the BES within 15 minutes. Additionally, the operators validate the data through reasonable tests before they make operational actions.

Likes

0

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0

Response

Jeanne Kurzynowski - Consumers Energy Company - 1,3,4,5 - RF
Answer

No

Document Name
Comment
Please clarify the scope of the standard and requirement.
Likes

0

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0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

No

Document Name
Comment
Texas RE notes the SDT modified R1 to apply to Real-time Assessment (RTA) and Real-time monitoring to be consistent with the definition of Control
Center, however, Texas RE recommends including Operational Planning Analysis (OPA). The SDT’s position is that OPA data for the next day, if
rendered unavailable, would not adversely impact the reliable operation of the BES within 15 minutes. However, impact to the reliable operation of the
BES within 15 minutes should not be the only consideration for protection of OPA data. Texas RE notes that OPA and RTA data are distinguishable
only by the period that data is actually used. Most important, OPA’s data risk of unauthorized disclosure should be mitigated consistent with other
similar sensitive data. For example, if a registered entity’s communications between Control Centers were compromised, OPA data may be useful in the
planning of future attacks on the BES. The OPA data includes information such an evaluation of projected system conditions to assess anticipated (preContingency) and potential (post-Contingency) conditions for next-day operations. The evaluation also reflects load forecasts; generation output levels;
Interchange; known Protection System and Special Protection System status or degradation. It is not difficult to think of a scenario whereby
unauthorized disclosure of OPA data, may adversely impact the reliable operation of the BES within 15 minutes.

Since the SDT is electing not to directly reference other standards, the SDT could change the language of R1 to say: The Responsible Entity shall
develop one or more documented plan(s) to mitigate the risk of unauthorized disclosure or modification of data as defined by the data specification

required to fulfill operational and planning responsibilities while being transmitted between any Control Centers. This would make CIP-012-1 consistent
with the IRO-010 and TOP-003 Standards, as well as include the OPA data.

Since the terms “Real-time monitoring” and “control data”, used in part 1.3, is not defined, Texas RE requests the SDT provide examples of this type of
data. This could be done as part of the Implementation Guidance document.

Texas RE requests the SDT describe the types of controls it expects to see that are not covered by IRO-010 and TOP-003.
Likes

0

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0

Response

Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer

No

Document Name
Comment
Xcel Energy believes that the types of data to be within scope, as identified by data specification lists orginating from Requirements TOP-003 and IRO010 are not specific enough to determine or limit the types of data or communciation methods that would need to be protected as Real Time
Assessment, Real Time Monitoring, or Control Data. These lists contain data and methods of communicating data that Xcel Energy would not clasify as
Real Time Assessment, Real Time Monitoring, or Control Data. Xcel Energy's concern is that NERC and/or Regional Entites may. The inclusion of all
data types and methods on these lists could bring systems like corporate email into scope, which Xcel Energy would adamantly oppose. We suggest
adding further clarification as to what types of data are included as Real Time Assessment, Real Time Monitoring and Control Data.
Likes

0

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0

Response

Lan Nguyen - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
As mentioned in the Response to Question No. 1, the phrase “and control” should be removed from the requirement.
Likes
Dislikes

0
0

Response

Annette Johnston - Berkshire Hathaway Energy - MidAmerican Energy Co. - 3
Answer

No

Document Name
Comment
Support Terry Harbour comments (Berhshire Hathaway - MidAmerican Energy Company)
Likes

0

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0

Response

Terry Harbour - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1
Answer

No

Document Name
Comment
Important scoping from the implementation guidance belongs in the requirement, that demarcation points don’t add additional Cyber Assets to the
scope of the CIP standards.
Likes

0

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0

Response

Barry Lawson - National Rural Electric Cooperative Association - 4
Answer

No

Document Name
Comment
Same comments as question 1 above.
Likes

0

Dislikes
Response

0

Richard Jackson - U.S. Bureau of Reclamation - 1
Answer

No

Document Name
Comment
Reclamation does not agree with the scope of CIP-012-1 Requirement R1.
Reclamation recommends the SDT implement the following:
•

Clearly specify that each Responsible Entity is required to mitigate the risk of unauthorized disclosure or modification of its own BES Data
between its own Control Centers.

Add the following definition to the NERC Glossary of Terms:
BES Data: BES reliability operating services information related to the entity’s high and medium impact Control Centers which affects Operational
Planning Analysis, Real-time Assessments, and Real-time monitoring and control of the facility, and would affect the operation of the BES if
compromised.
Likes

0

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0

Response

Paul Huettl - Basin Electric Power Cooperative - 6
Answer

No

Document Name
Comment
Please refer to NRECA comments.
Likes

0

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0

Response

Russel Mountjoy - Midwest Reliability Organization - 10, Group Name MRO NSRF
Answer
Document Name
Comment

No

We agree with the removal of “data related to Operational Planning Analysis” from R1. However, clarification is needed to ensure that the “control data”
term is consistently applied and clearly addresses the intent of FERC’s directive. Additionally, important scoping from the implementation guidance
belongs in the requirement, that demarcation points don’t add additional Cyber Assets to the scope of the CIP standards.
Likes

0

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0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
While BPA agrees with the exclusion of Operational Planning Analysis from the scope of R1, we still do not agree with the need for CIP-012.
Likes

0

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0

Response

Janis Weddle - Public Utility District No. 1 of Chelan County - 6, Group Name Chelan PUD
Answer

No

Document Name
Comment
CHPD requests more formal definition of terms that describe the data in question. Consider a NERC Glossary term of “BES data” (used in this
question) to address “monitoring” and “control” data types in a single definition. A potential, admittedly simple, initial definition to consider:
BES Data – Electronic data used by BES Cyber Systems to perform Supervisory Control and Data Acquisition (SCADA).
If the STD believes that monitoring and control data should be defined separately, then CHPD instead requests new NERC Glossary terms for
“monitoring data” and “control data” in place of a combined definition.
Likes

5

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Response

Public Utility District No. 1 of Snohomish County, 5, Nietfeld Sam; Snohomish County PUD No. 1, 6, Lu
Franklin; Public Utility District No. 1 of Snohomish County, 1, Duong Long; Snohomish County PUD No. 1,
3, Oens Mark; Public Utility District No. 1 of Snohomish County, 4, Martinsen John
0

Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer

No

Document Name
Comment
The term “control data” is not defined. Dominion Energy recommends either defining the term or providing additional guidance on its meaning in the
GTB.
In addition, Part 1.3 is strictly administrative in nature and does not enhance the reliability of the BES. We recommend that this part be removed in its
entirety.
Finally, Dominion Energy is concerned that the demarcation line between Entities is not clearly defined.
Likes

0

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0

Response

Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 6
Answer

Yes

Document Name
Comment
Tacoma Power endorses the draft comments shared with it by Salt River Project (SRP), which follow:
SRP agrees scoping CIP-012-1 Requirement R1 in this manner and thanks the SDT for the opportunity to comment on the scope. However, as stated in
SRP’s response to question 1, SRP does not agree viewing of the Real-time Assessment and Real-time monitoring and control data without context will
decrease the reliable operation of the BES and asserts confidentiality does not need to be protected for all data under this scope.
Likes

0

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0

Response

David Francis - SRC - 2 - MRO,Texas RE,NPCC,SERC,RF, Group Name SRC + SWG
Answer
Document Name
Comment
None

Yes

Likes

0

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0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion and ISO-NE
Answer

Yes

Document Name
Comment
We conceptually agree with the scoping but need more details on “monitoring and control data.” We agree with the removal of “Operational Planning
Analysis.”
Likes

0

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0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment
We conceptually agree with the scoping but need more details on “monitoring and control data.” We agree with the removal of “Operational Planning
Analysis.”
Likes

0

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0

Response

Brandon McCormick - Brandon McCormick On Behalf of: Ginny Beigel, City of Vero Beach, 3; Lynne Mila, City of Clewiston, 4; Tom Reedy,
Florida Municipal Power Pool, 6; - Brandon McCormick, Group Name FMPA
Answer

Yes

Document Name
Comment
FMPA agrees with the removal of data used for Operational Planning Analysis

Likes

0

Dislikes

0

Response

Laurie Williams - PNM Resources - Public Service Company of New Mexico - 1
Answer

Yes

Document Name
Comment
PNMR agrees with the scoping of sensitive BES data to Real-time Assessment and Real-time monitoring and control data. While others have
commented a concern regarding a lack of formal NERC Glossary of Terms definition, PNMR does not share this concern. If this concept was used
beyond this standard then a formal defined term would be appropriate.
Likes

0

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0

Response

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer

Yes

Document Name
Comment
We support SRP and Chelan PUD comments.
Likes

0

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0

Response

Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
Sensitive BES data required Real-time Assessments, Real-time Monitoring and Control data is the appropriate scope in CIP-012-1 Requirement R1
Likes

0

Dislikes

0

Response

Shannon Fair - Colorado Springs Utilities - 1,3,5,6
Answer

Yes

Document Name
Comment
CSU agrees scoping CIP-012-1 Requirement R1 in this manner and thanks the SDT for the opportunity to comment on the scope. However, as stated
in SRP’s response to question 1, SRP does not agree viewing of the Real-time Assessment and Real-time monitoring and control data without context
will decrease the reliable operation of the BES and asserts confidentiality does not need to be protected for all data under this scope.
Likes

0

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0

Response

Lona Calderon - Salt River Project - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
SRP agrees scoping CIP-012-1 Requirement R1 in this manner and thanks the SDT for the opportunity to comment on the scope. However, as stated in
SRP’s response to question 1, SRP does not agree viewing of the Real-time Assessment and Real-time monitoring and control data without context will
decrease the reliable operation of the BES and asserts confidentiality does not need to be protected for all data under this scope.
Likes

0

Dislikes

0

Response

Lynn Goldstein - PNM Resources - Public Service Company of New Mexico - 3
Answer

Yes

Document Name
Comment
PNMR agrees with the scoping of sensitive BES data to Real-time Assessment and Real-time monitoring and control data. While others have
commented a concern regarding a lack of formal NERC Glossary of Terms definition, PNMR does not share this concern. If this concept was used
beyond this standard then a formal defined term would be appropriate.

Likes

0

Dislikes

0

Response

Andrew Gallo - Austin Energy - 6
Answer

Yes

Document Name
Comment
AE does not, however, agree viewing Real-time Assessment and monitoring/control data without context will adversely affect reliable operation of the
BES and believes not all in-scope data requires the same level of confidentiality.
Likes

0

Dislikes

0

Response

Vivian Vo - APS - Arizona Public Service Co. - 3
Answer

Yes

Document Name
Comment
The revised scoping appropriately omits operational planning.
Likes

0

Dislikes

0

Response

Ronald Donahey - TECO - Tampa Electric Co. - 3
Answer

Yes

Document Name
Comment
TEC wishes to endorse the comment of the Edison Electric Institute.
Likes
Dislikes

0
0

Response

Richard Vine - California ISO - 2
Answer

Yes

Document Name
Comment
The California ISO supports the comments of the IRC Security Working Group (SWG)
Likes

0

Dislikes

0

Response

Brian Millard - Tennessee Valley Authority - 1,3,5,6 - SERC, Group Name Tennessee Valley Authority
Answer

Yes

Document Name
Comment
TVA agrees that the proposed scoping of sensitive BES data consistent with existing standards is appropriate. This approach helps clarify what data to
protect should the entity choose an application layer protection, and may also aid in identifying the links to which the controls are applied.
Likes

0

Dislikes

0

Response

Aaron Austin - AEP - 3
Answer

Yes

Document Name
Comment
AEP believes this aligns with CIP-002 identification processes and narrows the scope appropriately.
Likes

0

Dislikes
Response

0

Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

RoLynda Shumpert - SCANA - South Carolina Electric and Gas Co. - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Kevin Salsbury - Berkshire Hathaway - NV Energy - 5
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

larry brusseau - Corn Belt Power Cooperative - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Douglas Webb - Douglas Webb On Behalf of: Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; James McBee,
Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; Jessica Tucker, Great Plains Energy - Kansas City Power and Light Co., 5,
1, 3, 6; Jim Flucke, Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; - Douglas Webb
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Jennifer Hohenshilt - Talen Energy Marketing, LLC - 6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Chris Scanlon - Exelon - 1
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

Oshani Pathirane - Oshani Pathirane On Behalf of: Payam Farahbakhsh, Hydro One Networks, Inc., 1, 3; - Oshani Pathirane
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Nicholas Lauriat - Network and Security Technologies - 1

Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Eleanor Ewry - Puget Sound Energy, Inc. - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Glen Farmer - Avista - Avista Corporation - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Sean Cavote - PSEG - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer
Document Name
Comment

Yes

Likes

2

Dislikes

PSEG - Public Service Electric and Gas Co., 1, Smith Joseph; PSEG - Public Service Electric and Gas Co.,
3, Mueller Jeffrey
0

Response

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 3, Group Name FirstEnergy Corporation
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Donald Lock - Talen Generation, LLC - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Kara White - NRG - NRG Energy, Inc. - 3,4,5,6 - FRCC,MRO,WECC,Texas RE,NPCC,SERC,SPP RE,RF
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Steven Powell - Trans Bay Cable LLC - NA - Not Applicable - WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

W. Dwayne Preston - Austin Energy - 3
Answer
Document Name
Comment
I support Andrew Gallo's Comments from Austin Energy.
Likes

0

Dislikes
Response

0

3. Requirement R2: The SDT drafted CIP-012-1 Requirement R2 for the Responsible Entity to implement the plan(s) specified in Requirement
R1, except under CIP Exceptional Circumstances. Do you agree with this revision? If not, please provide the basis for your disagreement and
an alternate proposal.
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
While BPA agrees with the language of R2, we still do not agree with the need for CIP-012, or with the standard as currently drafted.
Likes

0

Dislikes

0

Response

Russel Mountjoy - Midwest Reliability Organization - 10, Group Name MRO NSRF
Answer

No

Document Name
Comment
The NSRF does not agree with two separate requirements, one for a plan and one to implementation. We recommend following precedent in the other
CIP standards, for example, CIP-004-6. The obligation can be accomplished with one requirement, as follows.
R1. “The Responsible Entity shall implement one or more documented process(es) to mitigate the risk of the unauthorized disclosure or modification of
Real-time Assessments and Real-time monitoring and control data while being transmitted between any Control Centers, except under CIP Exceptional
Circumstances. This excludes oral communications. The process(es) shall identify:
R1.1 security protection used to mitigate risk of unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring and control
data while being transmitted between Control Centers,
R1.2 demarcation point(s) where security protection is applied for transmitting Real-time Assessment and Real-time monitoring and control data
between Control Centers. Demarcation points identified by the Responsible Entity do not add additional Cyber Assets to the scope of the CIP Reliability
Standards; and
For R1.3, please see our rational in question 6. R1.3 Identify each Responsible Entity for applying security protection(s) to the transmission of
Real-time Assessment and Real-time monitoring and control data between Control Centers, when the Control Centers are owned or operated by
different Responsible Entities.”
This also includes important scoping from the implementation guidance that belongs in the requirement, that demarcation points don’t add additional
Cyber Assets to the scope of the CIP standards.
Likes
Dislikes

0
0

Response

Richard Jackson - U.S. Bureau of Reclamation - 1
Answer

No

Document Name
Comment
Reclamation recommends the SDT implement the following:
•

Replace the term “plan” with “process” for consistency with other CIP standards.

•

Change Requirement R2:

from: The Responsible Entity shall implement the plan(s) specified in Requirement R1, except under CIP Exceptional Circumstances
to: The Responsible Entity shall implement the process(s) specified in Requirement R1, except under CIP Exceptional Circumstances
Likes

0

Dislikes

0

Response

Terry Harbour - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1
Answer

No

Document Name
Comment
We do not agree with two separate requirements, one for a plan and one to implement. We recommend following precedent in the other CIP standards,
for example, CIP-004-011. The obligation can be accomplished with one requirement, as follows. “The Responsible Entity shall implement one or more
documented process(es) to mitigate the risk of the unauthorized disclosure or modification of Real-time Assessments and Real-time monitoring and
control data while being transmitted between any Control Centers, except under CIP Exceptional Circumstances. This excludes oral communications.
The process(es) shall identify: 1.1 security protection used to mitigate risk of unauthorized disclosure or modification of Real-time Assessment and
Real-time monitoring and control data while being transmitted between Control Centers. 1.2 demarcation point(s) where security protection is applied for
transmitting Real-time Assessment and Real-time monitoring and control data between Control Centers. Demarcation points identified by the
Responsible Entity do not add additional Cyber Assets to the scope of the CIP Reliability Standards; and 1.3 roles and responsibilities of each
Responsible Entity for applying security protection to the transmission of Real-time Assessment and Real-time monitoring and control data between
Control Centers, when the Control Centers are owned or operated by different Responsible Entities.” This also includes important scoping from the
implementation guidance that belongs in the requirement, that demarcation points don’t add additional Cyber Assets to the scope of the CIP standards.
Likes

0

Dislikes
Response

0

Annette Johnston - Berkshire Hathaway Energy - MidAmerican Energy Co. - 3
Answer

No

Document Name
Comment
Support Terry Harbour comments (Berhshire Hathaway - MidAmerican Energy Company)
Likes

0

Dislikes

0

Response

Oshani Pathirane - Oshani Pathirane On Behalf of: Payam Farahbakhsh, Hydro One Networks, Inc., 1, 3; - Oshani Pathirane
Answer

No

Document Name
Comment
We require clarity on how the implementation plan will address Control Centres that will be built in the future.
Likes

0

Dislikes

0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

No

Document Name
Comment
Texas RE appreciates the SDT’s response. As Texas RE previously noted, it does not necessarily oppose a CIP Exceptional Circumstances exception
from the implementation requirements set forth in CIP-012-1 R2. However, despite the SDT’s response, it remains unclear why certain CIP exception
conditions, such as an imminent hardware failure, should necessarily trigger a relaxation of physical security protections for communications links
transmitted sensitive data in all circumstances.
Likes

0

Dislikes
Response

0

Jeanne Kurzynowski - Consumers Energy Company - 1,3,4,5 - RF
Answer

No

Document Name
Comment
Requirement R2 can be combined with Requirement R1 so that it is written in a consistent approach with other FERC approved CIP requirements.
Likes

0

Dislikes

0

Response

Kevin Salsbury - Berkshire Hathaway - NV Energy - 5
Answer

No

Document Name
Comment
It is unnecessary to have 2 Requirements for this Standard, especially with each Requirement currently identified to have the same enforceable date.
NV Energy recommends following precedence of other Standards and combining the Requirements into a single requirement that states, "An entity
shall implement one or more document processes/plans....". .
Likes

0

Dislikes

0

Response

sean erickson - Western Area Power Administration - 1
Answer

No

Document Name
Comment
WAPA does not agree with two separate requirements, one for a plan and one for implementation. We recommend following precedent in the other CIP
standards, for example, CIP-004-6. The obligation can be accomplished with one requirement. See response to question 1.
Likes

0

Dislikes
Response

0

Paul Huettl - Basin Electric Power Cooperative - 6
Answer

Yes

Document Name
Comment
Please refer to NRECA comments.
Likes

0

Dislikes

0

Response

Richard Vine - California ISO - 2
Answer

Yes

Document Name
Comment
The California ISO supports the comments of the IRC Security Working Group (SWG)
Likes

0

Dislikes

0

Response

Glen Farmer - Avista - Avista Corporation - 5
Answer

Yes

Document Name
Comment
A plan would be created to outline protections and classify BES data moving between control centers.
Likes

0

Dislikes

0

Response

Lona Calderon - Salt River Project - 1,3,5,6 - WECC

Answer

Yes

Document Name
Comment
SRP agrees on implementing a plan and agrees a CIP Exceptional Circumstance is in order.
Likes

0

Dislikes

0

Response

Shannon Fair - Colorado Springs Utilities - 1,3,5,6
Answer

Yes

Document Name
Comment
CSU agrees on implementing a plan and agrees a CIP Exceptional Circumstance is in order.
Likes

0

Dislikes

0

Response

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer

Yes

Document Name
Comment
We support SRP and Chelan PUD comments.
Likes

0

Dislikes

0

Response

David Francis - SRC - 2 - MRO,Texas RE,NPCC,SERC,RF, Group Name SRC + SWG
Answer
Document Name

Yes

Comment
None
Likes

0

Dislikes

0

Response

Steven Powell - Trans Bay Cable LLC - NA - Not Applicable - WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Kara White - NRG - NRG Energy, Inc. - 3,4,5,6 - FRCC,MRO,WECC,Texas RE,NPCC,SERC,SPP RE,RF
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer

Yes

Document Name
Comment

Likes
Dislikes

0
0

Response

Janis Weddle - Public Utility District No. 1 of Chelan County - 6, Group Name Chelan PUD
Answer

Yes

Document Name
Comment

Likes

5

Dislikes

Public Utility District No. 1 of Snohomish County, 5, Nietfeld Sam; Snohomish County PUD No. 1, 6, Lu
Franklin; Public Utility District No. 1 of Snohomish County, 1, Duong Long; Snohomish County PUD No. 1,
3, Oens Mark; Public Utility District No. 1 of Snohomish County, 4, Martinsen John
0

Response

Aaron Austin - AEP - 3
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Brian Millard - Tennessee Valley Authority - 1,3,5,6 - SERC, Group Name Tennessee Valley Authority
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Donald Lock - Talen Generation, LLC - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 3, Group Name FirstEnergy Corporation
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Sean Cavote - PSEG - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer

Yes

Document Name
Comment

Likes

2

Dislikes

PSEG - Public Service Electric and Gas Co., 1, Smith Joseph; PSEG - Public Service Electric and Gas Co.,
3, Mueller Jeffrey
0

Response

Vivian Vo - APS - Arizona Public Service Co. - 3
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Andrew Gallo - Austin Energy - 6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Lynn Goldstein - PNM Resources - Public Service Company of New Mexico - 3
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Eleanor Ewry - Puget Sound Energy, Inc. - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Nicholas Lauriat - Network and Security Technologies - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Barry Lawson - National Rural Electric Cooperative Association - 4
Answer

Yes

Document Name
Comment

Likes
Dislikes

0
0

Response

Lan Nguyen - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Chris Scanlon - Exelon - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Laura Nelson - IDACORP - Idaho Power Company - 1
Answer
Document Name

Yes

Comment

Likes

0

Dislikes

0

Response

Jennifer Hohenshilt - Talen Energy Marketing, LLC - 6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Joe Tarantino - Joe Tarantino On Behalf of: Arthur Starkovich, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Beth Tincher, Sacramento
Municipal Utility District, 4, 1, 5, 6, 3; Jamie Cutlip, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Kevin Smith, Balancing Authority of
Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Susan Oto, Sacramento Municipal Utility District, 4, 1,
5, 6, 3; - Joe Tarantino
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Chantal Mazza - Hydro-Qu?bec TransEnergie - 2 - NPCC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Andrey Komissarov - Andrey Komissarov On Behalf of: Jerome Gobby, Sempra - San Diego Gas and Electric, 5, 3, 1; - Andrey Komissarov
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Laurie Williams - PNM Resources - Public Service Company of New Mexico - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Brandon McCormick - Brandon McCormick On Behalf of: Ginny Beigel, City of Vero Beach, 3; Lynne Mila, City of Clewiston, 4; Tom Reedy,
Florida Municipal Power Pool, 6; - Brandon McCormick, Group Name FMPA
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Douglas Webb - Douglas Webb On Behalf of: Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; James McBee,
Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; Jessica Tucker, Great Plains Energy - Kansas City Power and Light Co., 5,
1, 3, 6; Jim Flucke, Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; - Douglas Webb
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

larry brusseau - Corn Belt Power Cooperative - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

RoLynda Shumpert - SCANA - South Carolina Electric and Gas Co. - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC

Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Ronald Donahey - TECO - Tampa Electric Co. - 3
Answer
Document Name
Comment
TEC wishes to endorse the comment of the Edison Electric Institute.
Likes

0

Dislikes

0

Response

W. Dwayne Preston - Austin Energy - 3
Answer
Document Name
Comment

I support Andrew Gallo's Comments from Austin Energy.
Likes

0

Dislikes
Response

0

4. Implementation Plan: The SDT revised the Implementation Plan to make the standard effective the first day of the first calendar quarter that
is twenty-four (24) calendar months after the effective date of the applicable governmental authority’s order approving the standard, or as
otherwise provided for by the applicable governmental authority. Do you agree with this proposal? If you think an alternate implementation
time period is needed, please provide a detailed explanation of actions and time needed to meet the implementation deadline.
Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 6
Answer

No

Document Name
Comment
Tacoma Power endorses the draft comments shared with it by Salt River Project (SRP), which follow:
Overall, SRP does not agree with twenty-four (24) calendar months for the implementation of Requirements R1 and R2. Although SRP recognizes the
SDT is not specifying the controls to be used to protect confidentiality and integrity, the only examples provided in the implementation guidance includes
encryption. If there are other methods available to achieve the security objective, SRP asks the SDT to provide them. However, the only method
available to achieve the proposed required objective, on the ICCP network, is to implement encryption. As FERC order 822 states on page 37, “if
several registered entities have joint responsibility for a cryptographic key management system used between their respective Control Centers, they
should have the prerogative to come to a consensus on which organization administers that particular key management system.” Furthermore, the
FERC order states on page 38, “While responsible entities are required to exchange real-time and operational planning data necessary to operate the
bulk electric system using mutually agreeable security protocols, there is no technical specification for how this transfer of information should
incorporate mandatory security controls.” These are activities and specifications that must be created and agreed upon by all registered entities involved
in the data transfer. As such the timeline is reliant on registered entities working together on a common solution and would not be achievable within 24
calendar months.
Additionally, if encryption fails, SRP would lose Real-time Assessment and Real-time monitoring and control data. There are many opportunities for
encryption to fail that must be addressed. The implementation of encryption requires a pilot to truly understand and address the mechanisms of failure,
the impacts encryption would cause on the exchange of the data, and the computing resources required. A pilot also requires a great amount of
coordination to execute, not only within the industry, but may also include carriers, vendors, and possibly third-party encryption key program managers.
Because of the aforementioned reasons and concerns, SRP is recommending a phased implementation for CIP-012-1. A 24 month implementation is
appropriate, but only for Requirement R1. The 24 months for R1 would provide time to coordinate and create an industry-wide solution. SRP is
proposing the SDT include an additional 12 months for Requirement R2. The additional 12 months would be used for a pilot and course correction if
needed, in addition to understanding, formulating, and executing maintenance strategies.
Likes

0

Dislikes

0

Response

Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer
Document Name
Comment

No

This seems to be an excessively long period of time to implement this proposed standard. The security of real-time data is important and should be
prioritized. Yes, entities must communicate and develop joint plans to implement, but allowing a long horizon for implementation will not enable this
communication to occur faster.
Likes

0

Dislikes

0

Response

sean erickson - Western Area Power Administration - 1
Answer

No

Document Name
Comment
WAPA recommends an increase to at least three years in order to coordinate with other entities, including specification, design,
budgeting, implementation and testing.
Likes

0

Dislikes

0

Response

Andrey Komissarov - Andrey Komissarov On Behalf of: Jerome Gobby, Sempra - San Diego Gas and Electric, 5, 3, 1; - Andrey Komissarov
Answer

No

Document Name
Comment
SDG&E is in agreement with BPA's comments
Likes

0

Dislikes

0

Response

Joe Tarantino - Joe Tarantino On Behalf of: Arthur Starkovich, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Beth Tincher, Sacramento
Municipal Utility District, 4, 1, 5, 6, 3; Jamie Cutlip, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Kevin Smith, Balancing Authority of
Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Susan Oto, Sacramento Municipal Utility District, 4, 1,
5, 6, 3; - Joe Tarantino
Answer
Document Name

No

Comment

:Agreements between entities takes time and is it is dependent on items an entity cannot control. We recommend at least 36 months.

Likes

0

Dislikes

0

Response

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer

No

Document Name
Comment
We support SRP and Chelan PUD comments.
Likes

0

Dislikes

0

Response

Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer

No

Document Name
Comment
Xcel Energy does not agree with the proposed Implementation timeline. We share real time data with Registed Entities (REs) such as the Reliability
Coordinators (RCs) including MISO, SPP and PEAK. Additionally, we share data with many utilties with Control Centers across our service
territory. Finding a common technological solution to implement the proposed mitigating activities in the Requirements will take a substantial effort of
the part of all REs. Once a common technology and all legal agreements between REs are in place, Xcel Energy may still have to purchanse and
implement those technology solutions.
We suggest that NERC should advise and collaborate with all RCs to agree upon a common technology first and then drive those solutions from the RC
down to each utility in scope.
Likes

0

Dislikes
Response

0

Annette Johnston - Berkshire Hathaway Energy - MidAmerican Energy Co. - 3
Answer

No

Document Name
Comment
Support Terry Harbour comments (Berhshire Hathaway - MidAmerican Energy Company)
Likes

0

Dislikes

0

Response

Shannon Fair - Colorado Springs Utilities - 1,3,5,6
Answer

No

Document Name
Comment
Overall, CSU does not agree with twenty-four (24) calendar months for the implementation of Requirements R1 and R2. Although CSU recognizes the
SDT is not specifying the controls to be used to protect confidentiality and integrity, the only examples provided in the implementation guidance includes
encryption. If there are other methods available to achieve the security objective, we ask the SDT to provide them. However, the only method available
to achieve the proposed required objective, on the ICCP network, is to implement encryption. As FERC order 822 states on page 37, “if several
registered entities have joint responsibility for a cryptographic key management system used between their respective Control Centers, they should
have the prerogative to come to a consensus on which organization administers that particular key management system.” Furthermore, the FERC order
states on page 38, “While responsible entities are required to exchange real-time and operational planning data necessary to operate the bulk electric
system using mutually agreeable security protocols, there is no technical specification for how this transfer of information should incorporate mandatory
security controls.” These are activities and specifications that must be created and agreed upon by all registered entities involved in the data transfer.
As such the timeline is reliant on registered entities working together on a common solution and would not be achievable within 24 calendar months.
Because of the aforementioned reasons and concerns, CSU is recommending a phased implementation for CIP-012-1. A 24 month implementation is
appropriate, but only for Requirement R1. The 24 months for R1 would provide time to coordinate and create an industry-wide solution. SRP is
proposing the SDT include an additional 12 months for Requirement R2. The additional 12 months would be used for a pilot and course correction if
needed, in addition to understanding, formulating, and executing maintenance strategies.
Likes

0

Dislikes

0

Response

Lona Calderon - Salt River Project - 1,3,5,6 - WECC
Answer
Document Name

No

Comment
Overall, SRP does not agree with twenty-four (24) calendar months for the implementation of Requirements R1 and R2. Although SRP recognizes the
SDT is not specifying the controls to be used to protect confidentiality and integrity, the only examples provided in the implementation guidance includes
encryption. If there are other methods available to achieve the security objective, SRP asks the SDT to provide them. However, the only method
available to achieve the proposed required objective, on the ICCP network, is to implement encryption. As FERC order 822 states on page 37, “if
several registered entities have joint responsibility for a cryptographic key management system used between their respective Control Centers, they
should have the prerogative to come to a consensus on which organization administers that particular key management system.” Furthermore, the
FERC order states on page 38, “While responsible entities are required to exchange real-time and operational planning data necessary to operate the
bulk electric system using mutually agreeable security protocols, there is no technical specification for how this transfer of information should
incorporate mandatory security controls.” These are activities and specifications that must be created and agreed upon by all registered entities involved
in the data transfer. As such the timeline is reliant on registered entities working together on a common solution and would not be achievable within 24
calendar months.
Additionally, if encryption fails, SRP would lose Real-time Assessment and Real-time monitoring and control data. There are many opportunities for
encryption to fail that must be addressed. The implementation of encryption requires a pilot to truly understand and address the mechanisms of failure,
the impacts encryption would cause on the exchange of the data, and the computing resources required. A pilot also requires a great amount of
coordination to execute, not only within the industry, but may also include carriers, vendors, and possibly third-party encryption key program managers.
Because of the aforementioned reasons and concerns, SRP is recommending a phased implementation for CIP-012-1. A 24 month implementation is
appropriate, but only for Requirement R1. The 24 months for R1 would provide time to coordinate and create an industry-wide solution. SRP is
proposing the SDT include an additional 12 months for Requirement R2. The additional 12 months would be used for a pilot and course correction if
needed, in addition to understanding, formulating, and executing maintenance strategies.
Likes

0

Dislikes

0

Response

Terry Harbour - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1
Answer

No

Document Name
Comment
At least three years are needed to coordinate with other entities, including specification, design, budgeting, implementation and testing.
Likes

0

Dislikes

0

Response

Andrew Gallo - Austin Energy - 6
Answer
Document Name

No

Comment
Overall, AE does not agree with twenty-four (24) calendar months for R1 and R2. Although AE recognizes the SDT does not specify the controls to
protect confidentiality and integrity, the only examples provided in the implementation guidance include encryption. If other methods exist, AE believes
the SDT should provide them.
The only way to achieve the proposed requirement on the ICCP network is encryption. As FERC Order 822 states (on page 37), “if several registered
entities have joint responsibility for a cryptographic key management system used between their respective Control Centers, they should have the
prerogative to come to a consensus on which organization administers that particular key management system.” The FERC order also states (on page
38), “While responsible entities are required to exchange real-time and operational planning data necessary to operate the bulk electric system using
mutually agreeable security protocols, there is no technical specification for how this transfer of information should incorporate mandatory security
controls.” These specifications must be created and agreed upon by all registered entities involved in the data transfer. Consequently, the time to
comply depends on registered entities working together on a common solution and will likely take more than 24 months.
Additionally, if encryption fails, AE would lose Real-time monitoring and control data. Encryption may fail for many reasons. Implementing encryption
should involve a pilot period to assess and address the mechanisms of failure, impacts on data exchange and the requisite computing resources. A pilot
also requires coordination, not only for the industry, but also carriers, vendors, and, possibly, third-party encryption key program managers.
Consequently, AE recommends a phased implementation for CIP-012-1. A 24 month implementation is appropriate for R1 because it would provide
time to coordinate and create an industry-wide solution. AE proposes the SDT grant an extra 12 months for R2 to allow for a pilot and adjustments, if
needed.
Likes

0

Dislikes

0

Response

Russel Mountjoy - Midwest Reliability Organization - 10, Group Name MRO NSRF
Answer

No

Document Name
Comment
The NRSF recommends an increase to at least three years in order to coordinate with other entities, including specification, design, budgeting,
implementation and testing.
Likes

0

Dislikes

0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name
Comment

No

BPA appreciates the increase to 24 months but recommends 36 months due to BPA’s large amount of applicable data, access to funds and resources
to perform work required.
Likes

0

Dislikes

0

Response

David Francis - SRC - 2 - MRO,Texas RE,NPCC,SERC,RF, Group Name SRC + SWG
Answer

Yes

Document Name
Comment
None
Likes

0

Dislikes

0

Response

Brandon McCormick - Brandon McCormick On Behalf of: Ginny Beigel, City of Vero Beach, 3; Lynne Mila, City of Clewiston, 4; Tom Reedy,
Florida Municipal Power Pool, 6; - Brandon McCormick, Group Name FMPA
Answer

Yes

Document Name
Comment
FMPA supports the additional time this implementation plan provides.
Likes

0

Dislikes

0

Response

Laurie Williams - PNM Resources - Public Service Company of New Mexico - 1
Answer
Document Name
Comment

Yes

A quick internal review by PNMR SMEs indicates that this implementation plan is reasonable for the proposed standard.
Likes

0

Dislikes

0

Response

Barry Lawson - National Rural Electric Cooperative Association - 4
Answer

Yes

Document Name
Comment
NRECA appreciates the change from 12 months to 24 months in the Implementation Plan.
Likes

0

Dislikes

0

Response

Vivian Vo - APS - Arizona Public Service Co. - 3
Answer

Yes

Document Name
Comment
The period of 24 months will likely be reasonable; however, agreement with neighboring entities poses an unpredictable step in terms of time for
completion.
Likes

0

Dislikes

0

Response

Richard Vine - California ISO - 2
Answer

Yes

Document Name
Comment
The California ISO supports the comments of the IRC Security Working Group (SWG)

Likes

0

Dislikes

0

Response

Paul Huettl - Basin Electric Power Cooperative - 6
Answer

Yes

Document Name
Comment
Please refer to NRECA comments.
Likes

0

Dislikes

0

Response

Brian Millard - Tennessee Valley Authority - 1,3,5,6 - SERC, Group Name Tennessee Valley Authority
Answer

Yes

Document Name
Comment
The proposed time period allows entities sufficient time to develop internal plans to implement the enhanced security requirements, negotiate the
necessary security changes between entities, and to make appropriate contract adjustments with service providers.
Likes

0

Dislikes

0

Response

Aaron Austin - AEP - 3
Answer

Yes

Document Name
Comment
AEP believes a 24 month Implementation Plan is adequate provided the TOP-003 and IRO-010 Real-time data and the mutually agreeable
security protocols are defined prior to the beginning of the CIP-012 implementation period.
Likes

0

Dislikes

0

Response

Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

RoLynda Shumpert - SCANA - South Carolina Electric and Gas Co. - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Kevin Salsbury - Berkshire Hathaway - NV Energy - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

larry brusseau - Corn Belt Power Cooperative - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Douglas Webb - Douglas Webb On Behalf of: Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; James McBee,
Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; Jessica Tucker, Great Plains Energy - Kansas City Power and Light Co., 5,
1, 3, 6; Jim Flucke, Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; - Douglas Webb
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Chantal Mazza - Hydro-Qu?bec TransEnergie - 2 - NPCC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Jeanne Kurzynowski - Consumers Energy Company - 1,3,4,5 - RF
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Jennifer Hohenshilt - Talen Energy Marketing, LLC - 6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Chris Scanlon - Exelon - 1
Answer

Yes

Document Name
Comment

Likes
Dislikes

0
0

Response

Lan Nguyen - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Oshani Pathirane - Oshani Pathirane On Behalf of: Payam Farahbakhsh, Hydro One Networks, Inc., 1, 3; - Oshani Pathirane
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer
Document Name

Yes

Comment

Likes

0

Dislikes

0

Response

Nicholas Lauriat - Network and Security Technologies - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Eleanor Ewry - Puget Sound Energy, Inc. - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Lynn Goldstein - PNM Resources - Public Service Company of New Mexico - 3
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Glen Farmer - Avista - Avista Corporation - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Sean Cavote - PSEG - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer

Yes

Document Name
Comment

Likes

2

Dislikes

PSEG - Public Service Electric and Gas Co., 1, Smith Joseph; PSEG - Public Service Electric and Gas Co.,
3, Mueller Jeffrey
0

Response

Richard Jackson - U.S. Bureau of Reclamation - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 3, Group Name FirstEnergy Corporation
Answer
Document Name

Yes

Comment

Likes

0

Dislikes

0

Response

Donald Lock - Talen Generation, LLC - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Janis Weddle - Public Utility District No. 1 of Chelan County - 6, Group Name Chelan PUD
Answer

Yes

Document Name
Comment

Likes

5

Dislikes

Public Utility District No. 1 of Snohomish County, 5, Nietfeld Sam; Snohomish County PUD No. 1, 6, Lu
Franklin; Public Utility District No. 1 of Snohomish County, 1, Duong Long; Snohomish County PUD No. 1,
3, Oens Mark; Public Utility District No. 1 of Snohomish County, 4, Martinsen John
0

Response

Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer

Yes

Document Name
Comment

Likes
Dislikes

0
0

Response

Kara White - NRG - NRG Energy, Inc. - 3,4,5,6 - FRCC,MRO,WECC,Texas RE,NPCC,SERC,SPP RE,RF
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Steven Powell - Trans Bay Cable LLC - NA - Not Applicable - WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion and ISO-NE
Answer
Document Name
Comment
We are concerned about equipment under existing contracts. We suggest a solution similar to CIP-013.
Likes

0

Dislikes

0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer

Document Name
Comment
We are concerned about equipment under existing contracts. We suggest a solution similar to CIP-013.
Likes

0

Dislikes

0

Response

W. Dwayne Preston - Austin Energy - 3
Answer
Document Name
Comment
I support Andrew Gallo's Comments from Austin Energy.
Likes

0

Dislikes

0

Response

Ronald Donahey - TECO - Tampa Electric Co. - 3
Answer
Document Name
Comment
TEC wishes to endorse the comment of the Edison Electric Institute.
Likes

0

Dislikes
Response

0

5. The SDT believes proposed CIP-012-1 provides entities with flexibility to meet the reliability objectives in a cost effective manner. Do you
agree? If you do not agree, or if you agree but have suggestions for improvement to enable more cost effective approaches, please provide
your recommendation and, if appropriate, technical justification.
Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer

No

Document Name
Comment
At this time Dominion Energy has no information to assess the cost of a plan that has yet to be developed.
Likes

0

Dislikes

0

Response

Janis Weddle - Public Utility District No. 1 of Chelan County - 6, Group Name Chelan PUD
Answer

No

Document Name
Comment
CHPD cannot determine if the objectives may be accomplished in a cost-effective manner until further clarification is provided for the terms “monitoring
data” and “control data” (separate definitions) or “BES data” (combined definition). CHPD also has concerns with vendor availability, with respect to the
system software implementation that will be required for all entities industry-wide. The comments provided by other entities to develop an industry-wide
encryption specification is appealing and CHPD believes that would provide a better method for achieving the desired intra-entity security.
Likes

5

Dislikes

Public Utility District No. 1 of Snohomish County, 5, Nietfeld Sam; Snohomish County PUD No. 1, 6, Lu
Franklin; Public Utility District No. 1 of Snohomish County, 1, Duong Long; Snohomish County PUD No. 1,
3, Oens Mark; Public Utility District No. 1 of Snohomish County, 4, Martinsen John
0

Response

Aaron Austin - AEP - 3
Answer

No

Document Name
Comment
AEP believes communication network security requires “mutually agreed upon: formats, processes for resolving conflicts and security
protocols” between entities. However in practice, there is little that is mutually agreed upon in the data specification documents as they

relate to IRO-010 and TOP-003. The Balancing Authority, Transmission Operator and Reliability Coordinator specify the data they want to
receive in the manner they want to receive it. Others receiving the requests are obligated to comply. Without additional specificity, most
entities will be at the mercy of what their BAs, TOPs and RCs require. AEP believes this dependency creates only the presumption that
solutions will be cost effective.
Likes

0

Dislikes

0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
BPA’s believes that if the data must be protected throughout the transmission, it would seem that could only be accomplished with encryption. For
cases where the existing equipment is not capable of encryption, replacement will be costly and implementation lengthy.
Due to BPA’s large amount of applicable data, access to funds and resources to perform work required, the solution will be costly.
Likes

0

Dislikes

0

Response

Donald Lock - Talen Generation, LLC - 5
Answer

No

Document Name
Comment
See our response to question #1
Likes

0

Dislikes

0

Response

Andrew Gallo - Austin Energy - 6
Answer
Document Name

No

Comment
AE does not agree the proposal can be implemented in a cost-effective manner. Encryption is the only available solution to protect in-scope data
confidentiality and integrity. If the implementation period remains 24 months, entities will expend more resources and capital than using a phased
implementation. A phased implementation provides the ability to ensure the most effective plan and plan more accurately within budget cycles. Also, if
encryption fails, AE would lose Real-time monitoring and control data. AE believes a 24 month implementation timeline will impact reliability because
many opportunities exist for encryption to fail and those challenges must be addressed, which has a direct affect on cost.
Likes

0

Dislikes

0

Response

Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

No

Document Name
Comment
We are unable to answer this question in full at this time. The cost of implementation cannot be adequately assessed until discussion and coordination
with our neighboring entities (control centers) has taken place. We do not know what additional protections or updates may need to be put in place until
said discussions occur.
Likes

0

Dislikes

0

Response

Lona Calderon - Salt River Project - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
SRP does not agree the current standard and implementation plan can be executed in a cost effective manner. Encryption is the only solution available
to protect both confidentiality and integrity for the data within this scope. If the implementation timeframe remains at 24 months, more resources and
capital will be required versus a phased implementation. A phased implementation provides the ability to not only ensure the most effective plan, but
also provides the ability to plan more accurately within budget cycles. More importantly, if encryption fails, SRP would lose Real-time Assessment and
Real-time monitoring and control data. SRP is concerned a 24 month implementation timeline would impact reliability as there are many opportunities
for encryption to fail that must be addressed. This has a direct correlation on cost when addressing those opportunities during this timeframe.
Likes
Dislikes

0
0

Response

Shannon Fair - Colorado Springs Utilities - 1,3,5,6
Answer

No

Document Name
Comment
CSU does not agree the current standard and implementation plan can be executed in a cost effective manner. Encryption is the only solution available
to protect both confidentiality and integrity for the data within this scope. If the implementation timeframe remains at 24 months, more resources and
capital will be required versus a phased implementation. A phased implementation provides the ability to not only ensure the most effective plan, but
also provides the ability to plan more accurately within budget cycles. More importantly, if encryption fails, CSU would lose Real-time Assessment and
Real-time monitoring and control data. CSU is concerned a 24 month implementation timeline would impact reliability as there are many opportunities
for encryption to fail that must be addressed. This has a direct correlation on cost when addressing those opportunities during this timeframe.
Likes

0

Dislikes

0

Response

Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer

No

Document Name
Comment
We believe that the cost effectiveness of implementation would depend on the technology that would need to be deployed. Similar to response to
question 4, NERC should advise and work with all RCs to agree upon a common technology and drive those solutions from the RC down to each utility
in order to ensure cost effectiveness. The implementation of several different technologies to communicate with several different RCs and utilities
would be overly burdensome and at a cost that would not be effective.
Likes

0

Dislikes

0

Response

Jennifer Hohenshilt - Talen Energy Marketing, LLC - 6
Answer
Document Name
Comment

No

See response to Q1
Likes

0

Dislikes

0

Response

Jeanne Kurzynowski - Consumers Energy Company - 1,3,4,5 - RF
Answer

No

Document Name
Comment
More flexibility and less guidance could lead to inconsistency on requirement implementation among different entities.
Likes

0

Dislikes

0

Response

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer

No

Document Name
Comment
We support SRP and Chelan PUD comments.
Likes

0

Dislikes

0

Response

Joe Tarantino - Joe Tarantino On Behalf of: Arthur Starkovich, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Beth Tincher, Sacramento
Municipal Utility District, 4, 1, 5, 6, 3; Jamie Cutlip, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Kevin Smith, Balancing Authority of
Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Susan Oto, Sacramento Municipal Utility District, 4, 1,
5, 6, 3; - Joe Tarantino
Answer
Document Name
Comment

No

We recommend that an encryption standard is published to guide entities. Developing protocols between entities is time consuming and
costly. An exception process can be defined if needed to offer flexibility.

Likes

0

Dislikes

0

Response

Andrey Komissarov - Andrey Komissarov On Behalf of: Jerome Gobby, Sempra - San Diego Gas and Electric, 5, 3, 1; - Andrey Komissarov
Answer

No

Document Name
Comment
SDG&E is in agreement with BPA's comments
Likes

0

Dislikes

0

Response

RoLynda Shumpert - SCANA - South Carolina Electric and Gas Co. - 1,3,5,6 - SERC
Answer

No

Document Name
Comment
SCE&G has already implemented the controls to protect sensitive Bulk Electric System (BES) data while being transmitted over communications
links between BES Control Centers.
Likes

0

Dislikes

0

Response

Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 6
Answer

No

Document Name
Comment
Tacoma Power endorses the draft comments shared with it by Salt River Project (SRP), which follow:
SRP does not agree the current standard and implementation plan can be executed in a cost effective manner. Encryption is the only solution available
to protect both confidentiality and integrity for the data within this scope. If the implementation timeframe remains at 24 months, more resources and
capital will be required versus a phased implementation. A phased implementation provides the ability to not only ensure the most effective plan, but
also provides the ability to plan more accurately within budget cycles. More importantly, if encryption fails, SRP would lose Real-time Assessment and
Real-time monitoring and control data. SRP is concerned a 24 month implementation timeline would impact reliability as there are many opportunities
for encryption to fail that must be addressed. This has a direct correlation on cost when addressing those opportunities during this timeframe.
Likes

0

Dislikes

0

Response

Oshani Pathirane - Oshani Pathirane On Behalf of: Payam Farahbakhsh, Hydro One Networks, Inc., 1, 3; - Oshani Pathirane
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Russel Mountjoy - Midwest Reliability Organization - 10, Group Name MRO NSRF
Answer

Yes

Document Name
Comment
As noted in earlier comments, clarification of the “control data” term is needed to fully assess our ability to address the standard in a cost effective
manner. The flexibility built in to the current revision of R1 should support consideration of cost effective alternatives.

Likes

0

Dislikes
Response

0

Richard Vine - California ISO - 2
Answer

Yes

Document Name
Comment
The California ISO supports the comments of the IRC Security Working Group (SWG)
Likes

0

Dislikes

0

Response

Lynn Goldstein - PNM Resources - Public Service Company of New Mexico - 3
Answer

Yes

Document Name
Comment
PNMR believes the reliability objectives can be met in a cost effective manner for any internal links. However it is difficult to determine if links to
external Entities can be met in a cost effective manner. PNMR agrees with AEP’s concern of “mutually agreed upon: formats, processes for resolving
conflicts and security protocols” can affect the cost of implementation. Yet PNMR currently does not see an instance where this would greatly impact
the cost of implementation.
Likes

0

Dislikes

0

Response

Annette Johnston - Berkshire Hathaway Energy - MidAmerican Energy Co. - 3
Answer

Yes

Document Name
Comment
no comments
Likes

0

Dislikes
Response

0

Lan Nguyen - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

Yes

Document Name
Comment
The proposed Standard, as written, provides entities flexibility on implementation.
Likes

0

Dislikes

0

Response

Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

Yes

Document Name
Comment
Infrastructure will have to be added, and the standard allows for flexibility. There are some concerts that data exchange with other entities may become
difficult, and it may become costly to support that infrastructure.
Likes

0

Dislikes

0

Response

Laurie Williams - PNM Resources - Public Service Company of New Mexico - 1
Answer

Yes

Document Name
Comment
PNMR believes the reliability objectives can be met in a cost effective manner for any internal links. However it is difficult to determine if links to
external Entities can be met in a cost effective manner. PNMR agrees with AEP’s concern of “mutually agreed upon: formats, processes for resolving
conflicts and security protocols” can affect the cost of implementation. Yet PNMR currently does not see an instance where this would greatly impact
the cost of implementation.
Likes

0

Dislikes
Response

0

sean erickson - Western Area Power Administration - 1
Answer

Yes

Document Name
Comment
As noted in earlier comments, clarification of the “control data” term is needed to fully assess our ability to address the standard in a cost effective
manner. The flexibility built in to the current revision of R1 should support consideration of cost effective alternatives.
Likes

0

Dislikes

0

Response

David Francis - SRC - 2 - MRO,Texas RE,NPCC,SERC,RF, Group Name SRC + SWG
Answer

Yes

Document Name
Comment
None
Likes

0

Dislikes

0

Response

Steven Powell - Trans Bay Cable LLC - NA - Not Applicable - WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Kara White - NRG - NRG Energy, Inc. - 3,4,5,6 - FRCC,MRO,WECC,Texas RE,NPCC,SERC,SPP RE,RF

Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Brian Millard - Tennessee Valley Authority - 1,3,5,6 - SERC, Group Name Tennessee Valley Authority
Answer

Yes

Document Name
Comment

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0

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0

Response

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 3, Group Name FirstEnergy Corporation
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Richard Jackson - U.S. Bureau of Reclamation - 1
Answer

Yes

Document Name
Comment

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0

Dislikes

0

Response

Sean Cavote - PSEG - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer

Yes

Document Name
Comment

Likes

2

Dislikes

PSEG - Public Service Electric and Gas Co., 1, Smith Joseph; PSEG - Public Service Electric and Gas Co.,
3, Mueller Jeffrey
0

Response

Glen Farmer - Avista - Avista Corporation - 5
Answer

Yes

Document Name
Comment

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0

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0

Response

Vivian Vo - APS - Arizona Public Service Co. - 3
Answer

Yes

Document Name
Comment

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0

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0

Response

Eleanor Ewry - Puget Sound Energy, Inc. - 5

Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Nicholas Lauriat - Network and Security Technologies - 1
Answer

Yes

Document Name
Comment

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0

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0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

Yes

Document Name
Comment

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0

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0

Response

Terry Harbour - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1
Answer

Yes

Document Name
Comment

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0

Dislikes

0

Response

Chris Scanlon - Exelon - 1
Answer

Yes

Document Name
Comment

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0

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0

Response

Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment

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0

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0

Response

Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment

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0

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0

Response

Chantal Mazza - Hydro-Qu?bec TransEnergie - 2 - NPCC
Answer

Yes

Document Name
Comment

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0

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0

Response

David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment

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0

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0

Response

Brandon McCormick - Brandon McCormick On Behalf of: Ginny Beigel, City of Vero Beach, 3; Lynne Mila, City of Clewiston, 4; Tom Reedy,
Florida Municipal Power Pool, 6; - Brandon McCormick, Group Name FMPA
Answer

Yes

Document Name
Comment

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0

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0

Response

Douglas Webb - Douglas Webb On Behalf of: Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; James McBee,
Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; Jessica Tucker, Great Plains Energy - Kansas City Power and Light Co., 5,
1, 3, 6; Jim Flucke, Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; - Douglas Webb
Answer
Document Name
Comment

Yes

Likes

0

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0

Response

larry brusseau - Corn Belt Power Cooperative - 1
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Kevin Salsbury - Berkshire Hathaway - NV Energy - 5
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC

Answer

Yes

Document Name
Comment

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0

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0

Response

Ronald Donahey - TECO - Tampa Electric Co. - 3
Answer
Document Name
Comment
TEC wishes to endorse the comment of the Edison Electric Institute.
Likes

0

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0

Response

W. Dwayne Preston - Austin Energy - 3
Answer
Document Name
Comment
I support Andrew Gallo's Comments from Austin Energy.
Likes

0

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0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment

Texas RE does not have comments on this question.
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0

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0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer
Document Name
Comment
Cost effectiveness will be determined by the Entity’s implementation and existing contracts.
Likes

0

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0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion and ISO-NE
Answer
Document Name
Comment
Cost effectiveness will be determined by the Entity’s implementation and existing contracts.
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0

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0

6. If you have additional comments on the proposed CIP-012-1 – Cyber Security – Communications between Control Centers drafted in
response to the FERC directive that you have not provided in response to the questions above, please provide them here.
Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 6
Answer
Document Name
Comment
Thank you for your consideration.
Likes

0

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0

Response

Brandon Cain - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - FRCC,MRO,WECC,Texas RE,SERC,SPP RE, Group Name
Southern Company
Answer
Document Name
Comment
Overall, Southern Company is concerned that the scope of data is too broad and subject to interpretation during audits without direct ties to the IRO and
TOP standards requiring identification of the subject data. The nature of the data in Control Center environments is such that its criticality often
changes based on the current situation. Entities performing TOP and BA functions, in particular, receive data from a variety of entities, each with its
own data provision capabilities. A variety of data formats and delivery mechanisms are accommodated, and not all data received is needed at all
times. Groupings of data and how those groupings are defined is important. Without endorsed Technical Rationale and Implementation Guidance,
development of an appropriate technical plan to address this requirement and support successful audits of it remain a concern.
Southern Company feels that 12 months is appropriate to develop a plan, but an additional 24 months beyond planning may be needed to implement a
reliable technical solution. Given the need to perform a proper engineering study on network infrastructure to assess current state and adapt it to meet
the new requirements, additional time is needed to assess how changes may impact system and network response (loading, latency, etc). It will also be
necessary to review and / or establish contracts and memorandums of understanding to ensure that we continue to reliably receive the data we need
and to deliver the data that others may need from us. Inherent in these studies and implementations are additional costs that may be impacted by
budget cycles, as well as the costs attributable to resource constraints given the constant environment of standards changes currently. These factors
prevent any realistic analysis at this time of the cost-effectiveness of such implementations.
Apart from those noted above, Southern Company does not have any additional specific objections to the CIP-012-1 requirements, the draft Technical
Rationale, or the draft Implementation Guidance. It is important to note that the Proposed Reliability Standard currently does not have endorsed
Technical Rationale and Implementation Guidance. Due to this, Southern Company currently supports (with comments) the Proposed Reliability
Standard with the understanding that NERC’s endorsement of the Implementation Guidance may impact our support for a final ballot of the standard.
Likes
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0
0

Response

Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Answer
Document Name
Comment
There was a proposed revision to the definition of Control Center that was posted concurrently with the 1st posting of CIP-012-1. What is the status of
that definition? Will both of these be Petitioned to FERC on the same filing? Could one get approved before the other?
Likes

0

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0

Response

David Francis - SRC - 2 - MRO,Texas RE,NPCC,SERC,RF, Group Name SRC + SWG
Answer
Document Name
Comment
Comments: The SWG supports the objective-based requirements as written. The objective-based approach allows for Responsible Entities to select
and implement the controls appropriate to their organization.
Likes

0

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0

Response

Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer
Document Name
Comment
None at this time.
Likes

0

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Response

0

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion and ISO-NE
Answer
Document Name
Comment
Removal of the SDT’s Guidance and Technical Basis (GTB) from the Standard makes it difficult to 1) understand the intent and 2) evaluate this version.
If the GTB is not restored, we recommend posting the GTB information simultaneous with the Standard.
Likes

0

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0

Response

Kevin Salsbury - Berkshire Hathaway - NV Energy - 5
Answer
Document Name
Comment
If the demarcation point for communication is a CIP Cyber Asset, communication of this information and responsibilities between entities for R1.2 may
require NDAs between entities.
Likes

0

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0

Response

Douglas Webb - Douglas Webb On Behalf of: Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; James McBee,
Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; Jessica Tucker, Great Plains Energy - Kansas City Power and Light Co., 5,
1, 3, 6; Jim Flucke, Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; - Douglas Webb
Answer
Document Name
Comment
None.
Likes

0

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Response

0

Leonard Kula - Independent Electricity System Operator - 2
Answer
Document Name
Comment
Removal of the SDT’s Guidance and Technical Basis (GTB) from the Standard makes it difficult to 1) understand the intent and 2) evaluate this version.
If the GTB is not restored, we recommend posting the GTB information simultaneous with the Standard.
Likes

0

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0

Response

David Ramkalawan - Ontario Power Generation Inc. - 5
Answer
Document Name
Comment
In the case of Medium and High Control Centers, if it is intended that communication be protected up to an EAP on the ESP and/or the PSP, then it is
suggested that this demarcation point requirement should be clearly stated, possibly in an additional (sub-)requirement.
Likes

0

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0

Response

Laurie Williams - PNM Resources - Public Service Company of New Mexico - 1
Answer
Document Name
Comment
While some entities have raised a concern that encryption or other security efforts could impact availability and thus nullify the FERC mandate regarding
availability, PNMR does not believe that such security measure can have a significant detrimental effect on availability if such measures are properly
designed and implemented. PNMR believes that this standard really addresses the Confidentiality and Integrity of sensitive BES data while TOP-001-4
addresses the Availability of such data between primary Control Centers. Thus the standards are better ensuring all aspects of the ConfidentialityIntegrity-Availability triad are addresses in some way. All three aspects can be maintained in unison. Implementing processes and procedures to
address one aspect does not implicitly result in the absence or detriment of the other two.
Likes

0

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0

Response

Melanie Seader - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
While EEI does not currently have any specific objections to CIP-012-1 Requirements, Implementation Plan or the flexibility to meet the reliability
objectives in a cost-effective manner, we do note that the Proposed Reliability Standard lacks sufficient specificity (i.e., sufficient to stand on its own),
without endorsed Technical Rationale and Implementation Guidance.
Relative to the draft Implementation Guidance document, EEI notes that Industry will likely find it difficult to make any final judgements on the proposed
Reliability Standard without the ERO Enterprise’s endorsement of the draft Implementation Guidance. We trust that once the Proposed Reliability
Standard gets closer to a final ballot, the ERO Enterprise will endorse the final draft of the Implementation Guidance in accordance with the Compliance
Guidance Policy. In the event, that doesn’t occur, the approval of this standard may be at risk.
Likes

0

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0

Response

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer
Document Name
Comment
City Light would like to thank everyone for their efforts towards making this viable.
Likes

0

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0

Response

Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer
Document Name
Comment

Comments: The SWG supports the objective-based requirements as written. The objective-based approach allows for Responsible Entities to select
and implement the controls appropriate to their organization.
Likes

0

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0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE appreciates the SDT’s efforts to better clarify the data protection obligations by establishing a requirement to create “demarcation points”
between Control Centers. In particular, Texas RE applauds the SDT’s amendment to recognize that communications between “any” Control Center
should be protected. However, while this injects clarity into the standard, it does not completely address Texas RE’s fundamental concerns with the
proposed CIP-012 Standard language.

As Texas RE noted previously, Texas RE remains concerned that the proposed CIP-012-1 Standard may result in confusion, particularly among
Generation Operators with Control Centers subject to the standard regarding the scope of their compliance obligations or, alternatively, may
inadvertently result in a significant reliability gap given the structure of the ERCOT market. In ERCOT, generators do not communicate directly with the
regional Reliability Coordinator (ERCOT). Instead, generators are required to communicate through designated entities known as Qualified Scheduling
Entities (QSEs). In many instances, these QSEs are third-party entities. Within the NERC regulatory construct, Generator Operators have delegated
certain NERC compliance functions to these entities, including providing data used for Operational Planning Analysis, Real-time Assessments, and
Real-time monitoring. Critically, Generator Operators remain responsible for all compliance obligations associated with QSE activities in the ERCOT
region.

Texas RE continues to believe that CIP-012-1 must require Generator Operators possessing Control Centers to take steps to mitigate the risk of
unauthorized data disclosures at every step along the communication chain between its Control Center and the ERCOT Control Center, including steps
to protect this data at third-party intermediary QSEs. Otherwise, the proposed draft of CIP-012-1 would result in a significant reliability gap as QSE
communications links and data passing from the QSE to ERCOT could be potentially unsecure. Given this fact, Generator Operators will likely need to
take steps to ensure that their third-party QSEs have accorded designated sensitive data appropriate protections, which could in turn require
incorporating such requirements into QSE agreements or other steps.

Permitting Generator Operators to merely designate a demarcation point potentially permits such entities to unduly restrict their compliance
obligations. Generator Operators could set the demarcation point at their Control Center and the QSE. As a result, data and communication links
between the QSE and the ERCOT Control Center could potentially be excluded from CIP-012 protections, resulting in a fundamental reliability gap.

Texas RE continues to recommend that the SDT clarify that communications between QSEs (or equivalent in other Regions) and the RC are subject to
CIP-012-1 requirements and that Responsible Entities must take steps to address mitigate the risk of unauthorized data disclosures for these
communications as well in order to ensure that Responsible Entities have sufficient notice of these compliance obligations.
Likes

0

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0

Response

Chris Scanlon - Exelon - 1
Answer
Document Name
Comment
While Exelon does not have any specific objections to CIP-012-1 Requirements, Implementation Plan or the flexibility to meet the reliability objectives in
a cost-effective manner, we do note that the Proposed Reliability Standard lacks sufficient specificity (i.e., sufficient to stand on its own), without an
endorsed Technical Rationale and Implementation Guidance. Relative to the draft Implementation Guidance document, Exelon notes that Industry will
likely find it difficult to make any final judgments on the proposed Reliability Standard without NERC's endorsement of the draft Implementation
Guidance. We trust that once the Proposed Reliability Standard gets closer to a final ballot NERC will endorse the final draft of the Implementation
Guidance.
Likes

0

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0

Response

Lan Nguyen - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer
Document Name
Comment
The VRF/VSL for proposed Requirement R2 should be revised to include a moderate and high VSL, similar to the proposed Requirement
R1. Implementation of the plan, but failure to implement one of the applicable parts of the plan should be Moderate VSL. Implementation of the plan,
but failure to implement two of the applicable parts should be High VSL.
As stated in Response to Question No. 1, the proposed Standard should not move into final ballot until the definition of Control Center has been
finalized.
Likes

0

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0

Annette Johnston - Berkshire Hathaway Energy - MidAmerican Energy Co. - 3
Answer
Document Name
Comment
Support Terry Harbour comments (Berhshire Hathaway - MidAmerican Energy Company)
We don't see the reason for two requirements.
Implementation Guidance with approved ERO deference is essential for an affirmative ballot.
Likes

0

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0

Response

Shannon Fair - Colorado Springs Utilities - 1,3,5,6
Answer
Document Name
Comment
N/A
Likes

0

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0

Response

Lona Calderon - Salt River Project - 1,3,5,6 - WECC
Answer
Document Name
Comment
SRP would like to thank the SDT for their efforts. This is an extremely difficult topic to handle and SRP appreciates all of the outreach the SDT has
done.
Likes
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0
0

Response

Terry Harbour - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1
Answer
Document Name
Comment
The Proposed Reliability Standard lacks sufficient specificity (i.e., sufficient to stand on its own), without an endorsed Technical Rationale and
Implementation Guidance. Relative to the draft Implementation Guidance document, MEC agrees with EEI that Industry will likely find it difficult to make
any final judgments on the proposed Reliability Standard without NERC's endorsement of the draft Implementation Guidance. We trust that once the
Proposed Reliability Standard gets closer to a final ballot NERC will endorse the final draft of the Implementation Guidance. In the event, that doesn't
occur, we fear the approval of this standard may be at risk.
Likes

0

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0

Response

W. Dwayne Preston - Austin Energy - 3
Answer
Document Name
Comment
I support Andrew Gallo's Comments from Austin Energy.
Likes

0

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0

Response

Barry Lawson - National Rural Electric Cooperative Association - 4
Answer
Document Name
Comment
NRECA requests additional information on how the draft revised Control Center definition and the draft new CIP-12-1 will move forward after this
comment period. We believe they should move forward together in any next steps in the standard development process. Currently, when reviewing the
draft new CIP-12-1 it is unclear if the current approved Control Center definition or the draft revised Control Center definition is what the drafting team
intends the reader to use.

NRECA appreciates the efforts of the drafting team.
Likes

0

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0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer
Document Name
Comment
The SPP Standards Review Group proposes a few minor non-substantive edits to CIP-012-1 at Requirement R1 and Measurement M2. The edits will
reference the term “plan(s)” and ensures consistent use of vernacular is used throughout the standard (see below for proposed language- in bold).
R1. The Responsible Entity shall develop one or more documented plan(s) to mitigate the risk of unauthorized disclosure or modification of Real-time
Assessment and Real-time monitoring and control data while being transmitted between any Control Centers. This requirement excludes oral
communications. The plan(s) shall include: [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]
M2. Evidence may include, but is not limited to, documentation demonstrating implementation of the plan(s) developed pursuant to Requirement R1.
Likes

0

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0

Response

Nicholas Lauriat - Network and Security Technologies - 1
Answer
Document Name
Comment
(No additional comments)
Likes

0

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0

Response

Eleanor Ewry - Puget Sound Energy, Inc. - 5

Answer
Document Name
Comment
Please refer to EEI's comments regarding the Proposed Reliability Standard currently lacking sufficient specificity (i.e. sufficient to stand on its own)
without an endorsed Technical Rationale and Implementation Guidance.
Likes

0

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0

Response

Lynn Goldstein - PNM Resources - Public Service Company of New Mexico - 3
Answer
Document Name
Comment
While some entities have raised a concern that encryption or other security efforts could impact availability and thus nullify the FERC mandate regarding
availability, PNMR does not believe that such security measure can have a significant detrimental effect on availability if such measures are properly
designed and implemented. PNMR believes that this standard really addresses the Confidentiality and Integrity of sensitive BES data while TOP-001-4
addresses the Availability of such data between primary Control Centers. Thus the standards are better ensuring all aspects of the ConfidentialityIntegrity-Availability triad are addresses in some way. All three aspects can be maintained in unison. Implementing processes and procedures to
address one aspect does not implicitly result in the absence or detriment of the other two.
Likes

0

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0

Response

Andrew Gallo - Austin Energy - 6
Answer
Document Name
Comment
AE thanks the SDT for their hard work on a difficult topic and appreciates the SDT's outreach efforts.
Likes

0

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Response

0

Vivian Vo - APS - Arizona Public Service Co. - 3
Answer
Document Name
Comment
The application of any security controls requires bilateral consent. The first priority of Requirement 1 should be to identify the methods through with the
Responsible Entity determines and identifies these security controls and documentation the Responsible Entity intends to utilize throughout this
identification/determination process. AZPS respectfully submits, for the SDT’s consideration, the following revision of Requirement 1 to address the
above-referenced comments.
Proposed Revision to CIP-012-1 R1:
R1.1 Identification of methods and documentation through which the Responsible Entity will determine and identify security controls used to mitigate the
risk of unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring and control data while being transmitted between
Control Centers, and roles and responsibilities for implementation when the Control Centers are owned or operated by different Responsible Entities;
R1.2 Identification of security controls used to mitigate the risk of unauthorized disclosure or modification of Real-time Assessment and Real-time
monitoring and control data while being transmitted between Control Centers; and
R1.3 Identification of demarcation point(s) where security controls is applied for transmitting Real-time Assessment and Real-time monitoring and
control data between Control Centers.
Likes

0

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0

Response

Shelby Wade - PPL - Louisville Gas and Electric Co. - 1,3,5,6 - SERC,RF, Group Name PPL NERC Registered Affiliates
Answer
Document Name
Comment
PPL NERC Registered Affiliates supports EEI’s comments regarding CIP-012-1 – Cyber Security – Communications between Control Centers: “While
EEI does not have any specific objections to CIP-012-1 Requirements, Implementation Plan or the flexibility to meet the reliability objectives in a cost
effective manner, we do note that the Proposed Reliability Standard lacks sufficient specificity (i.e., sufficient to stand on its own), without an endorsed
Technical Rationale and Implementation Guidance. Relative to the draft Implementation Guidance document, EEI notes that Industry will likely find it
difficult to make any final judgements on the proposed Reliability Standard without the ERO Enterprise’s endorsement of the draft Implementation
Guidance. We trust that once the Proposed Reliability Standard gets closer to a final ballot, the ERO Enterprise will endorse the final draft of the
Implementation Guidance in accordance with the Compliance Guidance Policy. In the event that doesn’t occur, we fear the approval of this standard
may be at risk.”
Likes

0

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Response

0

Ronald Donahey - TECO - Tampa Electric Co. - 3
Answer
Document Name
Comment
TEC wishes to endorse the comment of the Edison Electric Institute.
Likes

0

Dislikes

0

Response

Richard Vine - California ISO - 2
Answer
Document Name
Comment
The California ISO supports the comments of the IRC Security Working Group (SWG)
Likes

0

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0

Response

Paul Huettl - Basin Electric Power Cooperative - 6
Answer
Document Name
Comment
Please refer to NRECA comments.
Likes

0

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0

Response

Russel Mountjoy - Midwest Reliability Organization - 10, Group Name MRO NSRF

Answer
Document Name
Comment
Per R1.3, may create a level of difficulty where “each Responsible Entity” will need to know each other’s “roles and responsibilities … for applying
security protection(s)”. The intent should be to assure that protections are in place and not create an administrative burden just to audit this. The use of
the wording of “roles and responsibilities” does not support the cyber security protections that this Standard is trying to accomplish. Different
responsible Entities may not be willing to share their “security protections” with other Entities as this may create a security gap or at the least, letting
others know what protections are in place. When each Entity becomes compliant with this Standard, their plans will assure that protections are in place
on “their end” of the data stream. This will assure that protections, which is the intent of this Standard.
The NSRF recommends R1.3 to read:
“Identify each Responsible Entity for applying security protection to the transmission of Real-time Assessment and Real-time monitoring and control
data between Control Centers, when the Control Centers are owned or operated by different Responsible Entities”.
This recommendation will assure that each Responsible Entity will know who is on “the other end” of their data stream, which supports data security and
intent of this Standard.
Likes

0

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0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name
Comment
None
Likes

0

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0

Response

Janis Weddle - Public Utility District No. 1 of Chelan County - 6, Group Name Chelan PUD
Answer
Document Name
Comment

Implementing industry-wide secure communication is a significant coordination challenge for entities and their associated vendors. The increase in
security also brings increased complexity, maintenance, and failure potential that may negatively impact the reliable operation of the BES. As a result,
coordination for encryption key management will become an essential activity and CHPD would, similar to other entity comments, appreciate guidance
for these activities.
CHPD also has general concerns that implementing encryption results in the loss of existing application-level protocol security. For example, current
security protections allow for the enforcement of specific ICCP protocol functions at the firewall perimeter. With end-to-end encryption in use (e.g.,
Secure ICCP) the firewall will no longer be able to inspect ICCP packets and will lose the ability to reject unauthorized commands (e.g., control, write,
etc.).
Likes

5

Dislikes

Public Utility District No. 1 of Snohomish County, 5, Nietfeld Sam; Snohomish County PUD No. 1, 6, Lu
Franklin; Public Utility District No. 1 of Snohomish County, 1, Duong Long; Snohomish County PUD No. 1,
3, Oens Mark; Public Utility District No. 1 of Snohomish County, 4, Martinsen John
0

Response

Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer
Document Name
Comment
The R1 VSL language does not accurately align with R1. Dominion Energy recommends adding the “develop” portion of R1 to the VSL language as
shown in the following example.
“The Responsible Entity failed to develop and document plan(s) for Requirement R1.”
In addition, the rationale developed by the SDT does not appear to have been included in the document or moved to any type of reference
document. The lack of any contextual documents creates a gap in understanding the intent of the SDT. Coupled with the lack of approved
Implementation Guidance, it is difficult to support the Requirements as written.
Likes

0

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0

Response

Kara White - NRG - NRG Energy, Inc. - 3,4,5,6 - FRCC,MRO,WECC,Texas RE,NPCC,SERC,SPP RE,RF
Answer
Document Name
Comment
N/A

Likes

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0

Standards Announcement

Project 2016-01 Modifications to CIP Standards
Draft Reliability Standard Audit Worksheet (RSAW) Posted for Industry
Comment through December 11, 2017
Now Available
The draft RSAW for CIP-012-1 − Cyber Security – Control Center Communication Networks is
posted on the project page for industry comment through 8 p.m. Eastern, Monday, December 11,
2017. Submit feedback regarding the draft RSAW to [email protected].
For more information or assistance, contact Katherine Street at (404) 446-9702 or Mat Bunch at (404) 4469785.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Project 2016-02
Modifications to CIP Standards
Consideration of Comments to CIP-012-1
(Comment Period: October 27 – December 11, 2017)

March 2018

NERC | Report Title | Report Date
I

Table of Contents
Preface ...................................................................................................................................................................... iii
Introduction .............................................................................................................................................................. iv
Consideration of Comments – Summary Responses ................................................................................................. 5
Creation of CIP-012-1 ............................................................................................................................................. 5
Requirement 1 ........................................................................................................................................................ 6
Requirement 2 ........................................................................................................................................................ 7
Identification of Data.............................................................................................................................................. 7
Control Data ........................................................................................................................................................... 8
Data Centers ........................................................................................................................................................... 8
Administrative Burden ........................................................................................................................................... 8
VSL Language .......................................................................................................................................................... 9
Defining Other Terms ............................................................................................................................................. 9
Alignment to TOP-003 and IRO-010 ....................................................................................................................... 9
Third Parties ......................................................................................................................................................... 10
Demarcation Point................................................................................................................................................ 10
Implementation .................................................................................................................................................... 10
Cost Effectiveness................................................................................................................................................. 11
Guideline and Technical Basis/Rationale ............................................................................................................. 12
Control Center Definition ..................................................................................................................................... 13
Medium/High Impact Control Centers ................................................................................................................. 13
CIP-012 Applicability............................................................................................................................................. 13
Compliance ........................................................................................................................................................... 13
FERC Directive 822................................................................................................................................................ 14

NERC | Consideration of Comments to CIP-012 | March 2018
ii

Preface
The North American Electric Reliability Corporation (NERC) is a not-for-profit international regulatory authority whose
mission is to assure the reliability and security of the bulk power system (BPS) in North America. NERC develops and
enforces Reliability Standards; annually assesses seasonal and long‐term reliability; monitors the BPS through system
awareness; and educates, trains, and certifies industry personnel. NERC’s area of responsibility spans the continental
United States, Canada, and the northern portion of Baja California, Mexico. NERC is the Electric Reliability
Organization (ERO) for North America, subject to oversight by the Federal Energy Regulatory Commission (FERC) and
governmental authorities in Canada. NERC’s jurisdiction includes users, owners, and operators of the BPS, which
serves more than 334 million people.
The North American BPS is divided into eight Regional Entity (RE) boundaries as shown in the map and corresponding
table below.

The North American BPS is divided into eight RE boundaries. The highlighted areas denote overlap as some load-serving entities
participate in one Region while associated transmission owners/operators participate in another.

FRCC

Florida Reliability Coordinating Council

MRO

Midwest Reliability Organization

NPCC

Northeast Power Coordinating Council

RF

ReliabilityFirst

SERC

SERC Reliability Corporation

SPP RE

Southwest Power Pool Regional Entity

Texas RE

Texas Reliability Entity

WECC

Western Electricity Coordinating Council

NERC | Consideration of Comments to CIP-012 | March 2018
iii

Introduction
The standard drafting team (SDT) appreciates industry comments on the proposed Reliability Standard, CIP-012. The
SDT considered the comments submitted during the additional posting of the proposed Reliability Standard, and
adapted its revision approach for the third proposal currently posted. Additionally, the SDT conducted substantial
outreach during the revision process, through in-person meetings, conference calls, and stakeholder organization
presentations.
On January 21, 2016, the Federal Energy Regulatory Commission (FERC) issued Order No. 822 Revised Critical
Infrastructure Protection Reliability Standards. In this order, FERC approved revisions to version 5 of the CIP
standards.
Response to Comments
The SDT has carefully reviewed each stakeholder comment and has revised language where suggested changes are
consistent with SDT intent and industry consensus. The SDT reviewed and responded to each comment in summary
form below.
There were 61 sets of comments comprised of approximately 168 different people across approximately 117
companies representing 10 of the Industry Segments.
All comments submitted can be reviewed in their original format on the project page.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give every
comment serious consideration in this process. If you feel there has been an error or omission, you can contact the
Senior Director of Standards, Howard Gugel (via email) or at (404) 446‐9693.

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Consideration of Comments – Summary Responses
Creation of CIP-012-1
•

Multiple commenters noted that CIP-012 is not needed and can be accommodated within existing CIP
Standards. The commenters also noted that encryption may not be feasible and the only remedy is to
physically protect the entire communication system.
The SDT contends that CIP-012 is needed as the application of protection is different for in-scope data while
being transmitted between Control Centers than it is with other standards, such as CIP-005. CIP-012
addresses applicable data transmitted between Control Centers and backup Control Centers regardless of
BES Cyber System impact rating. CIP-005 is applicable only to high and medium BES Cyber Systems. The SDT
disagrees that the only way to achieve the security objective is to physically protect the entire
communication system. Further, the SDT asserts that an entity can apply any combination of controls it
sees fit to achieve the security objective. CIP-006 even acknowledges that physical protection may not be
the only solution. Geographic distance is just one factor that needs to be evaluated that may preclude the
use of physical protection alone.

•

Several commenters provided support of CIP-012 and the requirements, noting the results-based approach
allows Responsible Entities to select and implement the controls appropriate to their organization.
The SDT thanks you for the comments.

•

A commenter noted CIP-012 is not needed.
The SDT contends that CIP-012 is needed. Applying protection for in-scope data while being transmitted
between Control Centers in CIP-012 is different from applying data protection in other standards. CIP-012
is also applicable to all impact levels, unlike CIP-002 through CIP-011

•

A commenter remains concerned that the proposed CIP-012 Standard may result in confusion, particularly
among Generation Operators with Control Centers subject to the standard regarding the scope of their
compliance obligations or, alternatively, may inadvertently result in a significant reliability gap given the
structure of the ERCOT market. In ERCOT, generators do not communicate directly with the regional
Reliability Coordinator (ERCOT). Instead, generators are required to communicate through designated
entities known as Qualified Scheduling Entities (QSEs). In many instances, these QSEs are third-party entities.
Within the NERC regulatory construct, Generator Operators have delegated certain NERC compliance
functions to these entities, including providing data used for Operational Planning Analysis, Real-time
Assessments, and Real-time monitoring. Critically, Generator Operators remain responsible for all
compliance obligations associated with QSE activities in the ERCOT region.
The Responsible Entity that delegates its functional responsibilities to a third party agent through a
contract or otherwise, continues to be responsible for compliance with NERC Reliability Standards. CIP-0121 is applicable to NERC-registered Generator Operators and Generator Owners. Responsible Entities are to
ensure that Real-time Assessment and Real-time monitoring data is protected throughout the transmission
between each Control Center, regardless of any other third party in the middle of the transmission of the
data. To address the concerns with coordination between Responsible Entities, modified the requirement
to include, “If the Control Centers are owned or operated by different Responsible Entities, identify the
responsibilities of each Responsible Entity for applying security protection to the transmission of Real-time

NERC | Consideration of Comments to CIP-012 | March 2018
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Consideration of Comments – Summary Responses

Assessment and Real-time monitoring data between those Control Centers”. This requires entities to
participate in this coordination while maintaining flexibility on implementation of this requirement.

Requirement 1
•

A commenter requested that the requirement be modified to require each Responsible Entity to mitigate the
risk of unauthorized disclosure or modification of its own BES data between its own Control Centers.
FERC Order 822 specifically notes that the protection of sensitive BES data transmitted between Control
Centers should be implemented for both inter- and intra-entity transmissions of data. The SDT developed
CIP-012 in response to the FERC Order.

•

A commenter recommended a change in the order of the three sub-requirements in Requirement R1.
The SDT has identified the required actions to be taken within Requirement R1. During SDT discussions,
entities varied on which step they would complete first. The requirement parts can be completed in any
order. Requirement R1.3 is listed last since it may not be applicable to all entities

•

A commenter proposed a few minor non-substantive edits to CIP-012 Requirement R1 and Measurement
M2. The edits reference the term “plan(s)” and ensures consistent use throughout the standard
The SDT has modified Requirement R1 as noted and has combined Requirements R1 and R2.

•

Commenters noted concerns regarding the resolution of disagreements under Requirement R1.3.
The SDT asserts that it is every Responsible Entity’s obligation as defined in CIP-012, to protect data while
being transmitted between Control Centers. The SDT cannot comment on specific approaches to resolve
conflicts that arise in defining responsibilities between entities. Entities should consider working with the
Regional Entity where there are unresolved disagreements.

•

A commenter noted it is not clear how Requirement R1 addresses future Control Centers since the
requirement suggests a one-time plan.
The SDT asserts that Requirement R1 is not intended to be a one-time plan. A Responsible Entity will need
to produce a plan to protect all in-scope data while being transmitted between Control Centers. This plan
will need to apply to all Control Centers that a given entity owns or operates. As the number of Control
Centers within an entity’s purview changes, so should the plan and implementation of the plan be changed.

•

A commenter noted that the requirement should specify creation of a documented process instead of a
documented plan.
The SDT disagrees regarding the use of the term “process” instead of “plan,” the SDT notes that the term
‘documented process’ refers to a set of required instructions specific to the Responsible Entity developed to
achieve a specific outcome. The plan to meet Requirement R1 may simply be a documentation of the
architecture in place to provide the defined security protection and not a series of instructions or steps to
be followed.

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Consideration of Comments – Summary Responses

Requirement 2
•

Commenters requested that the SDT consider consolidating Requirement R2 into Requirement R1, noting it
is unnecessary to have two requirements. The commenters also noted that the requirement should specify
creation of a documented process instead of a documented plan.
The SDT agrees with comments regarding a single requirement and has modified Requirement R1
accordingly. With regard to the use of the term “process” instead of “plan”, the SDT notes that the term
documented process refers to a set of required instructions specific to the Responsible Entity, designed to
achieve a specific outcome. The plan to meet Requirement R1 may simply be a documentation of the
architecture in place to provide the defined security protection and not a series of instructions or steps to
be followed.

•

Commenters requested that the SDT consider consolidating Requirement R2 into Requirement R1, noting it
is unnecessary to have two requirements.
The SDT agrees with comments regarding a single requirement and has modified Requirement R1
accordingly.

Identification of Data
•

A commenter requested that CIP-012-1 or supporting documents explicitly state that market data is out of
scope.
The SDT asserts that the data a Balancing Authority requires to perform Real-time monitoring and Realtime Assessments is the appropriate data to be protected under CIP-012-1. Where there is information
being requested by a Balancing Authority or other Responsible Entity performing Real-time monitoring and
Real-time Assessments, the SDT advises coordination between the Responsible Entities to ensure the
correct data is identified and protected accordingly.

•

Multiple commenters noted that all data elements should be evaluated in their unique context and that
confidentiality protection is not needed for all data.
The SDT has established the security objective in Requirement R1 to address the Commission’s directive on
protecting the confidentiality (unauthorized disclosure) and integrity (unauthorized modification) of the
data being transmitted. The SDT asserts that data used for Real-time monitoring and Real-time Assessment
is critical to the reliable operation of the Bulk Electric System and needs to be protected from unauthorized
disclosure and modification. The SDT determined it would be a complex and difficult exercise for an Entity
to define the protection required for various data elements in every situation. Therefore, the SDT chose to
high water mark all of the in-scope data. In addition, the SDT notes that most, if not all of the methods
applied to protect the integrity of data also inherently protect the confidentiality of the data.

•

Commenters noted that viewing Real-time Assessment and monitoring/control data without context will
adversely affect reliable operation of the BES and believes not all in-scope data requires the same level of
confidentiality.

The SDT has established the security objective in Requirement R1 to address the Commission’s directive
on protecting the confidentiality (unauthorized disclosure) and integrity (unauthorized modification)
of the data being transmitted. The SDT asserts that data used for Real-time monitoring and Real-time
Assessment is critical to the reliable operation of the Bulk Electric System, and thus needs to be protected
from unauthorized disclosure and modification. The SDT determined it be a complex and difficult exercise
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Consideration of Comments – Summary Responses

for an Entity to define the protection required for various data elements in every situation. Therefore, the
SDT chose to high water mark all of the in-scope data. The SDT also notes that most, if not all, of the
methods applied to protect the integrity of data also inherently protect the confidentiality of data.
•

A commenter is concerned that the scope of data is too broad and subject to interpretation during audits
without direct ties to the IRO and TOP standards requiring identification of the subject data.
The SDT discussed referencing the two applicable standards in the requirement language and determined
that a number of issues could arise by directly referencing applicable IRO/TOP requirements. Possible issues
include, but are not limited to, applicability issues and the required coordination of future revisions of the
IRO/TOP standards and proposed Reliability Standard CIP-012.

Control Data
•

Multiple commenters noted concerns with the meaning of “control data,” noting it may create confusion and
does not align with TOP-003 and IRO-010 data specification requirement.
The SDT agrees with the comments and has removed “and control” from Requirement R1.

Data Centers
•

One commenter noted a concern with the definition of Control Center including associated data centers,
specifically noting aggregating devices such as a dual port RTU could be interpreted as an associated data
center to a Control Center.
As shown in the reference models and noted in the applicability section, communication between Control
Centers and field devices, such as RTUs, are not in scope for CIP-012. The in-scope communications
considered in CIP-012-1 are between two Control Centers, as defined in the NERC Glossary of Terms Used
in Reliability Standards. Additionally, a data center not associated with the Control Center would be out of
scope of CIP-012-1.

•

A commenter noted that the communication link between Control Centers is in scope for CIP-012, but the
link between Control Center and Data Center is not.
The SDT agrees that a Responsible Entity needs to protect the in-scope data while being transmitted
between Control Centers. The SDT notes that the Control Center by definition includes the associated data
center and should, therefore be included with protecting intra-Control Center communications. The SDT
envisions a scenario where intra-Control Center communications not afforded protection elsewhere in the
Reliability Standards would need to be protected under CIP-012 R1.

Administrative Burden
•

A commenter noted that defining “roles and responsibilities” may create an administrative burden. They
noted that different Responsible Entities may not be willing to share their “security protections” with other
entities as this may create a security gap or at the least, letting others know what protections are in place.
When each Entity becomes compliant with this Standard, their plans will assure that protections are in place
on “their end” of the data stream. This will assure that protections, which is the intent of this Standard.
The SDT developed Requirement R1.3 to only apply to situations where multiple entities are involved in the
transmission of the applicable data. Those entities must have an agreement on security protection in order
for the transmission to actually happen. The intent is for the entities to agree upon and document who is
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Consideration of Comments – Summary Responses

responsible for the various aspects of the protection. It may not be practical for both entities to try to
control encryption keys, etc.

VSL Language
•

Commenters noted concerns with the VSLs for the requirements. First, the VSL for Requirement R2 should
be revised to include a moderate and high VSL. Second, it was recommended to add “develop” to the VSL
language for Requirement R1.
The SDT combined Requirement R2 into Requirement R1 and revised the VSLs. The SDT removed “develop”
from the language of Requirement R1.

Defining Other Terms
•

Commenters requested that the SDT define Real-time monitoring.
The SDT asserts that Real-time monitoring is a well understood concept that is included in the TOP and IRO
standards.

•

Commenters noted that viewing Real-time Assessment and monitoring/control data without context will
adversely affect reliable operation of the BES and believes not all in-scope data requires the same level of
confidentiality.
The SDT has established the security objective in Requirement R1 to address the Commission’s directive on
protecting the confidentiality (unauthorized disclosure) and integrity (unauthorized modification) of the
data being transmitted. The SDT asserts that data used for Real-time monitoring and Real-time Assessment
is critical to the reliable operation of the Bulk Electric System, and thus needs to be protected from
unauthorized disclosure and modification. The SDT determined it be a complex and difficult exercise for an
Entity to define the protection required for various data elements in every situation. Therefore, the SDT
chose to high water mark all of the in-scope data. The SDT also notes that most, if not all, of the methods
applied to protect the integrity of data also inherently protect the confidentiality of data.

Alignment to TOP-003 and IRO-010
•

Commenters requested the SDT add functional registrations noted in TOP and IRO standards to CIP-012 in
order to draw a more clear line to Entities responsible for defining the Real-time Assessment and Real-time
monitoring data under TOP-003 and IRO-010.
The SDT agrees with the comments and supports that this provides clarity and prevents all entities subject
to CIP-012-1 from creating their own identification of Real-time Assessment and Real-time monitoring
data. The SDT has modified Requirement R1 to address this recommendation.

•

Commenters noted that the types of data to be within scope, as identified by data specification lists
originating from Requirements TOP-003 and IRO-010 are not specific enough to determine or limit the types
of data, or communication methods that would need to be protected the data. These lists contain data and
methods of communicating data that may not be considered relevant to the scope of CIP-012.
The SDT agrees and has removed “and control” from Requirement R1. The SDT asserts that the data listed
in the data specifications required to perform Real-time monitoring and Real-time Assessments is the
appropriate data to be protected under CIP-012-1. Where there are concerns with information being
requested by another Responsible Entity performing Real-time monitoring and Real-time Assessments,

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Consideration of Comments – Summary Responses

coordination between the Responsible Entities is advised to ensure the correct data is identified and
protected accordingly.

Third Parties
•

Commenters noted that the guidance regarding third parties involved in the communication of Real-time
Assessment and Real-time monitoring data is unclear. Further, some Generator Owners and Generator
Operators neither own nor operate Control Centers due to agency relationships or through contracts with
companies that are not NERC registered entities.
The SDT agrees with the comments regarding the guidance on third parties and has removed the content.
The Responsible Entity that delegates its functional responsibilities to a third party agent through a
contract or otherwise, continues to be responsible for compliance with NERC Reliability Standards.

Demarcation Point
•

Commenters noted that the demarcation point should be constrained to entity’s equipment and not include
an implied requirement that each entity document both their demarcation points and the demarcation points
on neighboring systems.
The SDT agrees and has modified the draft requirement accordingly.

•

Commenters noted the importance of clarifying that demarcation points do not add additional Cyber Assets
to the scope of the CIP standards CIP-002 through CIP-011.
The SDT does not intend for CIP-012 to modify the list of Cyber Assets managed under CIP-002 thru CIP-011.
This has been addressed within the Technical Rationale and Justification for Reliability Standard CIP-0121.

Implementation
•

A majority of commenters indicated that twenty-four months is an adequate standard implementation
timeline. It allows entities sufficient time to develop internal plans to implement the enhanced security
requirements. It also provides time to negotiate the necessary security changes between entities, and to
make appropriate contract adjustments with service providers.
The SDT thanks you for your comments.

•

A commenter noted that the CIP-012 implementation period seems to be an excessively long to implement
this proposed standard since security of real-time data is important and should be prioritized.
The SDT determined that the complexity of the implementation needed an allowance of up to twenty-four
(24) months for implementation. Entities have the flexibility to phase in their implementation of the
requirement as long as all activities are completed within 24 months.

•

Several commenters noted that more time is needed for implementation of CIP-012. Reasons included
coordination with other entities, as well as specification, design, budgeting, implementation, and testing.
Commenters also raised concerns on the impact to existing contractual agreements.
The SDT carefully considered all comments and concluded that many factors should be considered to
determine an implementation period. These factors include complexity of technology solutions, quantity of
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Consideration of Comments – Summary Responses

telecommunications lines requiring controls and coordination with other Responsible Entities/solution
providers. The SDT concluded that a twenty-four (24) month implementation period is appropriate.
•

A commenter feels that 12 months is appropriate to develop a plan, but an additional 24 months beyond
planning may be needed to implement a reliable technical solution. Given the need to perform a proper
engineering study on network infrastructure to assess current state and adapt it to meet the new
requirements, additional time is needed to assess how changes may impact system and network response
(loading, latency, etc.). It will also be necessary to review and / or establish contracts and memorandums of
understanding to ensure that we continue to reliably receive the data we need and to deliver the data that
others may need from us. Inherent in these studies and implementations are additional costs that may be
impacted by budget cycles, as well as the costs attributable to resource constraints given the constant
environment of standards changes currently. These factors prevent any realistic analysis at this time of the
cost-effectiveness of such implementations.
The SDT carefully considered all comments and concluded that many factors should be considered to
determine an implementation period. These factors include complexity of technology solutions, quantity of
telecommunications lines requiring controls and coordination with other Responsible Entities/solution
providers. The SDT concluded that a twenty-four (24) month implementation period is appropriate. Entities
have the flexibility to phase in their implementation of the requirement as long as all activities are
completed within 24 months.

Cost Effectiveness
•

Several commenters noted they were unable to address the issue of cost effectiveness in full at this time.
They noted the cost of implementation could not be adequately assessed until discussion and coordination
with our neighboring entities. Cost effectiveness of implementation will depend on the technology deployed.
Infrastructure may need to be added to support the requirement and may be costly to contract and support.

The SDT carefully considered all comments and concluded that many factors should be considered to
determine an implementation period. These factors include complexity of technology solutions,
quantity of telecommunications lines requiring controls and coordination with other Responsible
Entities/solution providers. CIP-012 has been written to allow entities flexibility in determining the
solutions that work best for the organization and those they share this information with.
•

Several commenters noted the need for an encryption standard to be developed across the various regions.
The implementation of several different technologies to communicate with several different Reliability
Coordinators and utilities would be overly burdensome and at a cost that would not be effective. It was noted
that there is little that is mutually agreed upon in the data specification documents as they relate to IRO-010
and TOP-003. The Balancing Authority, Transmission Operator, and Reliability Coordinator specify the data
they want to receive in the manner they want to receive it. Others receiving the requests are obligated to
comply. Additionally, a commenter noted that the lack of guidance could lead to inconsistency of
implementation.
The SDT agrees a common standard would be highly beneficial to those operating in multiple regions. The
SDT will refer the issue to the CIPC for review and consideration as a guideline.

•

Several commenters noted the proposal cannot be implemented in a cost-effective manner within twentyfour (24) months. If the implementation period remains 24 months, entities will expend more resources and
capital than using a phased implementation. A phased implementation provides the ability to ensure the
most effective plan and plan more accurately within budget cycles. Commenters noted a 24-month
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Consideration of Comments – Summary Responses

implementation timeline could affect reliability because many opportunities exist for encryption to fail and
those challenges must be addressed, which has a direct effect on cost.

The SDT carefully considered all comments and concluded that many factors should be considered to
determine an implementation period. These factors include complexity of technology solutions,
quantity of telecommunications lines requiring controls and coordination with other Responsible
Entities/solution providers. The SDT concluded that a twenty-four (24) month implementation period
is appropriate. Entities have the flexibility to phase in their implementation of the requirement as long
as all activities are completed within 24 months.
•

One commenter recommended development of an exception process can be defined if needed to offer
flexibility.
In order to evaluate this request, the SDT needs additional information and invites the commenter to
participate in the regularly scheduled meetings.

Guideline and Technical Basis/Rationale
•

Several commenters raised concerns with the lack of a Guidelines and Technical Basis (GTB) section of CIP012. They noted the lack of GTB makes it difficult to understand the drafting team’s intent, and evaluate the
standard.
The SDT developed and posted Technical Rationale and Implementation Guidance documents to support
CIP-012. The SDT will submit the Implementation Guidance for ERO endorsement once the requirement
language is finalized.

•

Several commenters discussed the criticality of having the Technical Rationale completed and
Implementation Guidance endorsed for CIP-012. They noted industry will likely find it difficult to make any
final judgments on the proposed Reliability Standard without NERC's endorsement of the draft
Implementation Guidance. In the event the Implementation Guidance is not endorsed, there are fears the
approval of this standard may be at risk.
The SDT developed and posted Technical Rationale and Implementation Guidance documents to support
CIP-012. The SDT will submit the Implementation Guidance for ERO endorsement once the requirement
language is finalized.

•

Another commenter requested that the SDT provide a rationale for including the phrase “CIP Exceptional
Circumstances.” The same commenter further stated that it is particularly unclear why certain CIP
exception conditions necessarily trigger CIP Exceptional Circumstances events. For example, why would
an imminent hardware failure under all circumstances require a relaxation of physical security protection
for communications links transmitting sensitive data?
The SDT drafted the requirement with the understanding that there may be instances where a
Responsible Entity may not be able to maintain compliance with the requirement because of a CIP
Exceptional Circumstance. Responsible Entities may need to use alternate, as-yet-unidentified data
transmission methods because of a CIP Exceptional Circumstance event. This allowance will enable
Responsible Entities to focus on reliability without the risk of a compliance issue.

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Consideration of Comments – Summary Responses

Control Center Definition
•

Commenters raised questions on the prior proposal for modifying the definition of Control Center. The
commenters noted modifications to the definition and CIP-012 should move forward together in future steps
in the standard development process. They also noted that when reviewing the new current draft of CIP012, it is unclear if the current approved Control Center definition or the draft revised Control Center
definition is what the drafting team intends the reader to use.
The SDT has developed and posted modifications to the Control Center definition.

Medium/High Impact Control Centers
•

Commenters questioned in the case of medium and high impact Control Centers, whether it is intended for
the communication to be protected up to an Electronic Access Point on the Electronic Security Perimeter
and/or the Physical Security Perimeter. If that is the intent, it is suggested that the demarcation point
requirement clearly state this. It was also noted that if the demarcation point for communication is a CIP
Cyber Asset, communication of this information and responsibilities between entities may require NDAs
between entities.
The SDT does not intend for CIP-012 to prescribe the point where security protection is applied. Depending
on the entity, it may be at an ESP or it may not. It is the point where the protection can be applied before
it is transmitted to another Control Center. The same consideration should be made in determining the
physical protection. The SDT agrees that proper care should be taken with sharing information that could
be considered BES Cyber System Information.

CIP-012 Applicability
•

A commenter requested clarification on which Control Centers are applicable under CIP-012.
The SDT drafted CIP-012 to apply to all types of Control Centers, regardless of the impact rating associated
with the Control Centers’ BES Cyber Systems.

•

A commenter noted that Generator Owners are not listed in the Control Center definition and should be
removed from applicability of CIP-012.

The SDT modified the applicability of the Standard as, “The requirements in this standard apply to the
following functional entities, referred to as “Responsible Entities,” that own or operate a Control
Center.” The SDT intends for the standard to include Generator Owners and Transmission Owners that
own or operate a Control Center. The Control Center definition as written addresses the reliability tasks
of an RC, BA, TOP, and GOP irrespective of registration. The SDT has developed and posted modifications
to the Control Center definition.

Compliance
•

A commenter requested clarification on the responsibility for compliance, including who will be audited
under CIP-012.
The SDT asserts that entities that own and/or operate Control Centers, per Section 4 “Applicability” are
responsible to document and implement a plan to protect the data specified in CIP-012. The Responsible
Entity that delegates its functional responsibilities to a third party agent through a contract or otherwise,
continues to be responsible for compliance with NERC Reliability Standards.

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Consideration of Comments – Summary Responses

FERC Directive 822
•

A commenter noted it would be more effective if the SDT specifically identified the security objective
described in FERC Order No. 822 paragraph 54, of “maintaining the integrity and availability of sensitive BES
data”, should account for risk of cyber assets, and should be results based and not zero-defect.
The SDT asserts that the security objective is clear and aligns with FERC Order 822, taking into consideration
the sensitivity of the data being transmitted. As drafted, the development and implementation of a plan
allows entities to tailor protection to their environment.

NERC | CIP-012-1 Consideration of Comments | March 2018
14

DRAFT
Cyber Security –
Communications
Between Control
Centers
Technical Rationale and Justification for
Reliability Standard CIP-012-1
November 2017

NERC | Technical Rationale and Justification for Reliability Standard CIP-012-1 | Draft: November 2017
i

Table of Contents
Introduction ............................................................................................................................................................... iii
Requirement R1..........................................................................................................................................................4
General Considerations for Requirement R1 ......................................................................................................4
Overview of confidentiality and integrity ...........................................................................................................4
Alignment with IRO and TOP standards ..............................................................................................................4
Demarcation Points .............................................................................................................................................5
Control Center Ownership ..................................................................................................................................5
Requirement R2..........................................................................................................................................................6
General Considerations for R2 ............................................................................................................................6
References ..................................................................................................................................................................7

NERC | Technical Rationale and Justification for Reliability Standard CIP-012-1 | Draft: November 2017
ii

Introduction
On January 21, 2016, the Federal Energy Regulatory Commission (FERC or Commission) issued Order No. 822,
approving seven Critical Infrastructure Protection (CIP) Reliability Standards and new or modified terms in the
Glossary of Terms Used in NERC Reliability Standards, and directing modifications to the CIP Reliability Standards.
Among others, the Commission directed the North American Electric Reliability Corporation (NERC) to “develop
modifications to the CIP Reliability Standards to require Responsible Entities1 to implement controls to protect, at
a minimum, communication links and sensitive bulk electric system data communicated between bulk electric
system Control Centers in a manner that is appropriately tailored to address the risks posed to the bulk electric
system by the assets being protected (i.e., high, medium, or low impact).” (Order 822, Paragraph 53)
In response to the directive in Order No. 822, the Project 2016-02 standard drafting team (SDT) drafted Reliability
Standard CIP-012-1 to require Responsible Entities to implement controls to protect sensitive Bulk Electric System
(BES) data and communications links between BES Control Centers. Due to the sensitivity of the data being
communicated between Control Centers, as defined in the Glossary of Terms Used in NERC Reliability Standards,
the standard applies to all impact levels (i.e., high, medium, or low impact).
Although the Commission directed NERC to develop modifications to CIP-006, the SDT determined that
modifications to CIP-006 would not be appropriate. There are differences between the plan(s) required to be
developed and implemented for CIP-012-1 and the protection required in CIP-006-6 Requirement R1 Part 1.10.
CIP-012-1 Requirements R1 and R2 protect the applicable data during transmission between two separate Control
Centers. CIP-006 Requirement R1 Part 1.10 protects nonprogrammable communication components within an
Electronic Security Perimeter (ESP) but outside of a Physical Security Perimeter (PSP). The transmission of
applicable data between Control Centers takes place outside of an ESP. Therefore, the protection contained in
CIP-006-6 Requirement R1 Part 1.10 does not apply.
The SDT drafted requirements to provide Responsible Entities the latitude to protect the communication links,
the data, or both, to satisfy the security objective consistent with the capabilities of the Responsible Entity’s
operational environment. Requirement R1 requires Responsible Entities to document one or more plans that
protect Real-time Assessment and Real-time monitoring and control data while being transmitted between
Control Centers. The plan(s) must address how the Responsible Entity will mitigate the risk of unauthorized
disclosure or modification of the applicable data. Requirement R2 covers implementation of the plan developed
according to Requirement R1.
This technical rationale and justification document explains the technical rationale for the proposed Reliability
Standard. It will provide stakeholders and the ERO Enterprise with an understanding of the technology and
technical requirements in the Reliability Standard. It also contains information on the SDT’s intent in drafting the
requirements.

1

As used in the CIP Standards, a Responsible Entity refers to the registered entities subject to the CIP Standards.
NERC | Technical Rationale and Justification for Reliability Standard CIP-012-1 | Draft: November 2017
iii

Requirement R1
R1.

The Responsible Entity shall develop one or more documented plan(s) to mitigate the risk of
unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring
and control data while being transmitted between any Control Centers. This requirement
excludes oral communications. The plan shall include: [Violation Risk Factor: Medium] [Time
Horizon: Operations Planning]
1.1 Identification of security protection used to mitigate the risk of unauthorized disclosure or
modification of Real-time Assessment and Real-time monitoring and control data while being
transmitted between Control Centers;
1.2 Identification of demarcation point(s) where security protection is applied for transmitting Realtime Assessment and Real-time monitoring and control data between Control Centers; and
1.3 Identification of roles and responsibilities of each Responsible Entity for applying security
protection to the transmission of Real-time Assessment and Real-time monitoring and control
data between Control Centers, when the Control Centers are owned or operated by different
Responsible Entities.

General Considerations for Requirement R1
Requirement R1 focuses on developing a plan to protect information that is critical to the real-time operations of
the Bulk Electric System while in transit between applicable Control Centers.
Overview of confidentiality and integrity
The SDT drafted CIP-012-1 to address confidentiality and integrity of Real-time Assessment and Real-time
monitoring and control data. This is accomplished by drafting the requirement to mitigate the risk of unauthorized
disclosure (confidentiality) or modification (integrity). For this Standard, the SDT relied on the definitions of
confidentiality and integrity as defined by National Institute of Standards and Technology (NIST):
 Confidentiality is defined as, “Preserving authorized restrictions on information access and disclosure,
including means for protecting personal privacy and proprietary information.”2
 Integrity is defined as, “Guarding against improper information modification or destruction, and includes
ensuring information non-repudiation and authenticity.”3
The SDT asserts that the availability of this data is already required by the performance obligation of the Operating
and Planning Reliability Standards. The SDT drafted CIP-012 to address the data while being transmitted. The SDT
maintains that this data resides within BES Cyber Systems, and while at rest is protected by CIP-003 through CIP011.
Alignment with IRO and TOP standards
The SDT recognized the FERC reference to additional Reliability Standards and the responsibilities to protect the
applicable data in accordance with NERC Reliability Standards TOP-003 and IRO-010. The SDT used these
references to drive the identification of sensitive BES data and chose to base the CIP-012 requirements on the
Real-time data specification elements in these standards. This approach provides consistent scoping of identified
data, and does not require each entity to devise its own list or inventory of this data. Many entities are required
to provide this data under agreements executed with their RC, BA or TOP, often without benefit of knowing how
those entities use that data.

2
3

NIST Special Publication 800-53A, Revision 4, page B-3
NIST Special Publication 800-53A, Revision 4, page B-6
NERC | Technical Rationale and Justification for Reliability Standard CIP-012-1 | Draft: November 2017
4

The SDT notes that it expanded the phrase “Real-time monitoring” data from TOP-003 and IRO-010 to “Real-time
monitoring and control” data. The SDT was concerned that data transmitted between Control Centers that results
in the physical operation of BES Elements was not explicitly included in Real-time monitoring data. The SDT
understands that in practice Real-time control data is not transmitted separately from Real-time monitoring data.
However, the SDT wanted to ensure that Real-time control data was included regardless of whether or not it is
transmitted along with Real-time monitoring data. If entities only transmit Real-time control data along with Realtime monitoring data, then the SDT does not intend for such entities to identify additional data beyond that Realtime monitoring data already included in the data specifications for TOP-003 and IRO-010.
Demarcation Points
The SDT noted the need for an entity to identify a demarcation point inside each Control Center where it will apply
protection for applicable data. The SDT used the demarcation point concept for implementing protection to
ensure entities could still take advantage of security measures, such as deep packet inspection, already
implemented at or near the EAP when ESPs are present, while maintaining the capability to protect the applicable
data being transmitted between Control Centers.
Control Center Ownership
The requirements address protection for Real-time Assessment and Real-time monitoring and control data while
being transmitted between Control Centers owned by a single Responsible Entity. They also cover the applicable
data transmitted between Control Centers owned by two or more separate Responsible Entities. Unlike protection
between a single Responsible Entity’s Control Centers, applying protection between Control Centers owned by
more than one Responsible Entity requires additional coordination. The requirements do not explicitly require
formal agreements between Responsible Entities partnering for protection of applicable data. It is strongly
recommended, however, that these partnering entities develop agreements, or use existing ones, to define
responsibilities to ensure adequate protection is applied. An example noted in FERC Order No. 822 Paragraph 59
is, “if several registered entities have joint responsibility for a cryptographic key management system used
between their respective Control Centers, they should have the prerogative to come to a consensus on which
organization administers that particular key management system."
As an example, the reference model below depicts some of the data transmissions between Control Centers that
a Responsible Entity should consider to be in-scope. The example does not include all possible scenarios. The
green solid lines are in-scope communications. The red dashed lines are out-of-scope communications.

This reference model is an example and does not include all possible scenarios.
NERC | Technical Rationale and Justification for Reliability Standard CIP-012-1 | Draft: November 2017
5

Requirement R2
R2.

The Responsible Entity shall implement the plan(s) specified in Requirement R1, except under CIP
Exceptional Circumstances.

General Considerations for R2
Responsible Entities can achieve the security objective of Requirement R1 through a variety of methods or
combinations of methods, such as site to site encryption, application layer encryption, physical protection, etc.
The protection must be designed to prevent unauthorized disclosure or modification of applicable data on the
applicable communication methods between Control Centers identified in Requirement R1.1. The Responsible
Entity has the discretion to implement any type of protection that meets the security objective.

NERC | Technical Rationale and Justification for Reliability Standard CIP-012-1 | Draft: November 2017
6

References
Here are several references to assist entities in developing plan(s) for protection of communication links:
 NIST Special Publication 800-53A, Revision 4: Security and Privacy Controls for Federal Information
Systems and Organizations
 NIST Special Publication 800-82: Guide to Industrial Control Systems (ICS) Security
 NIST Special Publication 800-175B: Guideline for Using Cryptographic Standards in the Federal
Government: Cryptographic Mechanisms
 NIST Special Publication 800-47: Security Guide for Interconnecting Information Technology Systems

NERC | Technical Rationale and Justification for Reliability Standard CIP-012-1 | Draft: November 2017
7

DRAFT
Cyber Security –
Communications
Between Control
Centers
Implementation Guidance for CIP-012-1

NERC | Report Title | Report Date
I

Table of Contents
Introduction ................................................................................................................................................................3
Requirements .............................................................................................................................................................4
General Considerations ..............................................................................................................................................5
General Considerations for R1 ............................................................................................................................5
Identification of Security Protection ...................................................................................................................5
Identification of Demarcation Point(s)................................................................................................................5
Identification of Roles and Responsibilities when the Control Centers are Owned or Operated by Different
Responsible Entities ............................................................................................................................................5
General Considerations for R2 ............................................................................................................................5
Identification of Security Protection ...................................................................................................................6
Identification of Demarcation Point(s)................................................................................................................6
Identification of Roles and Responsibilities when the Control Centers are Owned or Operated by Different
Responsible Entities ............................................................................................................................................6
Reference Models.......................................................................................................................................................7
Reference Model Discussion for Requirement R1 ..............................................................................................7
Identification of Security Protection ...................................................................................................................8
Identification of Demarcation Point(s)................................................................................................................9
Identification of Roles and Responsibilities when the Control Centers are Owned or Operated by Different
Responsible Entities ............................................................................................................................................9
Reference Model Discussion for Requirement R2 ........................................................................................... 13
Identification of Security Protection ................................................................................................................ 13
Identification of Demarcation Point(s)............................................................................................................. 13
Identification of Roles and Responsibilities when the Control Centers are Owned or Operated by Different
Responsible Entities ......................................................................................................................................... 13
References ............................................................................................................................................................... 14

NERC | Report Title | Report Date
2

Introduction
The Commission issued Order No. 822 on January 21, 2016. Order 822 approved seven CIP Reliability Standards
and new or modified definitions, and directed modifications be made to the CIP Reliability Standards. Among
other items, the Commission directed NERC to “develop modifications to the CIP Reliability Standards to require
responsible entities to implement controls to protect, at a minimum, communication links and sensitive bulk
electric system data communicated between bulk electric system Control Centers in a manner that is
appropriately tailored to address the risks posed to the bulk electric system by the assets being protected (i.e.,
high, medium, or low impact).” (Order 822, Paragraph 53)
In response to the directive in Order No. 822, the Project 2016-02 standard drafting team (SDT) drafted Reliability
Standard CIP-012-1 to require Responsible Entities to implement controls to protect sensitive Bulk Electric System
(BES) data and communications links between BES Control Centers. Due to the sensitivity of the data being
communicated between Control Centers, the standard applies to all impact levels (i.e., high, medium, or low
impact).
The SDT drafted requirements to provide Responsible Entities the latitude to protect the communication links,
the data, or both, to satisfy the security objective consistent with the capabilities of the Responsible Entity’s
operational environment. Requirement R1 requires Responsible Entities to document one or more plans that
protect Real-time Assessment and Real-time monitoring and control data while being transmitted between
Control Centers. The plan(s) must address how the Responsible Entity will mitigate the risk of unauthorized
disclosure or modification of the applicable data. Requirement R2 covers implementation of the plan developed
according to Requirement R1.
The Project 2016-02 SDT also drafted this Implementation Guidance document to provide examples of approaches
to comply with CIP-012-1. Implementation Guidance does not prescribe the only approach, but is intended to
highlight one or more approaches that would be effective ways to be compliant with the standard. As
Implementation Guidance is only meant to provide examples, entities may choose alternative approaches that
better fit their situation 1.
Responsible Entities may find it useful to consider this Implementation Guidance document along with the
additional context and background provided in the SDT developed Technical Rationale and Justification for CIP012-1 document.

1

NERC’s Compliance Guidance Policy
NERC | CIP-012-1 Implementation Guidance | Draft: November 2017
3

Requirements
R1. The Responsible Entity shall develop one or more documented plan(s) to mitigate the risk of unauthorized
disclosure or modification of Real-time Assessment and Real-time monitoring and control data while being
transmitted between any Control Centers. This requirement excludes oral communications. The plan shall
include: [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]
1.1.
Identification of security protection used to mitigate the risk of unauthorized disclosure or
modification of Real-time Assessment and Real-time monitoring and control data while being transmitted
between Control Centers;
1.2.
Identification of demarcation point(s) where security protection is applied for transmitting Realtime Assessment and Real-time monitoring and control data between Control Centers; and
1.3.
Identification of roles and responsibilities of each Responsible Entity for applying security
protection to the transmission of Real-time Assessment and Real-time monitoring and control data
between Control Centers, when the Control Centers are owned or operated by different Responsible
Entities.
R2. The Responsible Entity shall implement the plan(s) specified in Requirement R1, except under CIP
Exceptional Circumstances.

NERC | CIP-012-1 Implementation Guidance | Draft: November 2017
4

General Considerations
General Considerations for R1
As noted in the Technical Rationale and Justification for CIP-012-1, the focus of Requirement R1 is on developing
a plan to protect information that is critical to the real-time operations of the Bulk Electric System while in
transit between applicable Control Centers. The number of plan(s) and their content may depend on a
Responsible Entity's management structure and operating conditions. The Responsible Entity may document as
many plans as necessary to meet its needs. For instance, a Responsible Entity may choose to document one
plan per Control Center or it may choose to document everything in a single plan. A Responsible Entity may
choose to document one plan for communications between Control Centers it owns and a separate plan for
communications between its Control Centers and the Control Centers of a neighboring Entity. The number and
structure of the plans is at the discretion of the Responsible Entity as long as the plan(s) include the required
elements described in parts 1.1, 1.2, and 1.3 of Requirement 1.
Identification of Security Protection

Entities have latitude to determine which security protections are used to mitigate the risk of unauthorized
disclosure or modification of Real-time Assessment and Real-time monitoring and control data while being
transmitted between Control Centers and should identify those protections accordingly.
This security protection could consist of logical protection, physical protection, or some combination of both. To
determine security protection, the requirement specifies that it must mitigate the risk of unauthorized
disclosure or modification of applicable data.
Identification of Demarcation Point(s)

A Responsible Entity should consider its environment to determine an effective solution when identifying the
demarcation points where security protections are applied. One approach to identifying a demarcation point is
to place the demarcation point within the Control Center so the confidentiality and integrity of the data is
protected throughout the transmission. The Responsible Entity can choose either a physical or logical
demarcation point. Demarcation points identified by the Responsible Entity do not add additional assets to the
scope of the CIP Reliability Standards. The demarcation point identification ensures that each Responsible Entity
identifies clear demarcation of where the protection is applied to the in-scope data. Demarcation points may
vary based on many factors such as impact levels of the Control Center, different technologies, or
infrastructures.
Identification of Roles and Responsibilities when the Control Centers are Owned or Operated by
Different Responsible Entities

The Technical Rationale and Justification for CIP-012-1 identifies key considerations in the Control Center
Ownership section when communicating between Control Centers with different owners or operators. Most if
not all of the many relationships between Responsible Entities are unique. Consequently, there is no single way
to identify roles and responsibilities for applying security protection to the transmission of Real-time Assessment
and Real-time monitoring and control data between Control Centers. Responsible Entities may consider
identifying the roles and responsibilities for the following situations: (1) configuration of security protocols, (2)
responding to communication failures, and (3) responding to Cyber Security Incidents.
General Considerations for R2
Given the format of the requirements, the majority of the documentation is required under R1 while R2 requires
the implementation of the plan developed for R1. Compliance with R2 is established by implementing the
protection identified in a Responsible Entity’s R1 plan. The sections below outline examples of evidence that
may be provided in order to demonstrate the implementation of Entity Alpha’s CIP-012-1 R1 plan.
NERC | CIP-012-1 Implementation Guidance | Draft: November 2017
5

Identification of Security Protection

Implementation of the security protection can be demonstrated in many ways. If physical protection is used, a
Responsible Entity may demonstrate implementation through a floor plan which identifies the physical security
measures in place protecting the communication link. If logical protection is used, a Responsible Entity may
demonstrate implementation through an export of the device configuration which applies the security
protection. Alternatively, a Responsible Entity may demonstrate implementation through monitoring of the
security control such as a report generated from an automated tool that monitors the encryption service used to
protect a communications link.
Identification of Demarcation Point(s)

Identification of demarcation point(s) could be demonstrated with a diagram (physical or logical) or a list. This
diagram or list could be included within the plan developed for R1. A label could also be used to identify a
device as a demarcation point.
Identification of Roles and Responsibilities when the Control Centers are Owned or Operated by
Different Responsible Entities

Implementation of roles and responsibilities could also be demonstrated in many ways. Some examples include
a joint procedure, a memorandum of understanding or meeting minutes between the two parties where roles
and responsibilities are discussed.

NERC | CIP-012-1 Implementation Guidance | Draft: November 2017
6

Reference Models
For this Implementation Guidance, the SDT considers a basic reference model of Primary and Backup Control
Centers (Entity Alpha) to illustrate concepts necessary to demonstrate compliance. These Control Centers
communicate to each other and to a neighboring entity’s Control Center (Entity Beta) in configurations outlined
by the diagrams in this section. The SDT recognizes that the reference models do not contain many of the
complexities of a real Control Center. For this Implementation Guidance, the registration or functions
performed in the reference model Control Center are also not considered. A high level block diagram of the
basic reference model is shown below in Figure 1. This Implementation Guidance is developed from the
perspective of Entity Alpha.

Entity Alpha’s Primary
Control Center

Communication between Entity Alpha’s
Primary and Backup Control Center

Communication between Entity Alpha’s
Primary Control Center and Entity Beta’s Control Center

Entity Alpha’s Backup
Control Center

Communication between Entity Alpha’s
Backup Control Center and Entity Beta’s Control Center

Entity Beta’s Control
Center

Figure 1: High Level Block Diagram of Reference Model Control Centers

Reference Model Discussion for Requirement R1
Requirement R1 requires the development of a documented plan. To comply with requirement R1, one
approach to a plan is to first determine which communications require protection pursuant to CIP-012-1. There
are multiple ways to identify an entity’s scope in R1. For example, Entity Alpha in the reference model may first
identify the Control Centers with which it communicates. Entity Alpha would determine that there are three:
Entity Alpha’s Primary Control Center, Entity Alpha’s Backup Control Center, and Entity Beta’s Control Center.
Entity Alpha does not need to consider whether Entity Beta further shares its data with another Entity. That is
the responsibility of Entity Beta and is outside of Entity Alpha’s purview. Additionally, Entity Alpha does not
need to consider any communications to other non-Control Center facilities such as generating plants or
substations. These communications are out of scope for CIP-012-1.
Now that Entity Alpha has identified the Control Centers with which it communicates, Entity Alpha identifies
either: (1) the Real-time Assessment and Real-time monitoring and control data; or (2) communication links
which are used to transmit Real-time Assessment and Real-time monitoring and control data between Control
Centers. In either case, Entity Alpha may find it useful to refer to the data specification for Real-time
NERC | CIP-012-1 Implementation Guidance | Draft: November 2017
7

Assessment and Real-time monitoring data identified in TOP-003-3 and IRO-010-2. For this reference model
scenario, identifying the communication links used to transmit Real-time Assessment and Real-time monitoring
and control data may be the most straightforward approach. Through an evaluation of communication links
between Control Centers and an evaluation of how it transmits and receives Real-time Assessment and Realtime monitoring and control data, Entity Alpha determined that it communicates applicable data between its
primary and backup Control Centers across a single communication link. Entity Alpha also determined that it
communicates applicable data to and from Entity Beta’s Control Center across one of two links that originate
from either Entity Alpha’s primary or backup Control Center using the Inter-Control Center Communications
Protocol (ICCP).
With an identified scope of communications links, Entity Alpha now considers the three required elements of its
required communications between Control Centers for its plan.
Identification of Security Protection

2

•

Entity Alpha must ensure that protection is applied at the CIP-012-1 demarcation point. The protection
must also meet the security objective of mitigating the risk of unauthorized disclosure or modification of
applicable data while in transit between Control Centers for the entire distance between CIP-012-1
demarcation points. In a simple case where the demarcation point is sufficiently close to the Control
Center, such as within the Physical Security Perimeter of the Control Center, Entity Alpha may use a single
security protection method to meet the security objective. For this case, shown in Figure 2, Entity Alpha
documents in its plan that it uses a Virtual Private Network (VPN) connection across a private leased
communication circuit for each of its three in-scope communication links. To meet the security objective,
Entity Alpha further states that its VPN uses Internet Protocol security (IPsec) with AES-128 encryption.

•

For more complex scenarios, Entity Alpha may need to use a combination of security controls. For
instance, in Figure 3, Entity Alpha uses a combination of physical security controls (physical access control)
and logical security controls (encrypted communications consistent with the first scenario above) to meet
the security objective.

•

The complexity increases when Entity Alpha and Entity Beta exchange data through a 3rd party, such as in
Figure 4. In this scenario, Entity Alpha again uses a combination of logical controls. First, encrypted
communications are used between the CIP-012-1 demarcation point at Entity Alpha and extended to the
3rd party WAN router. Then, a number of security controls may be leveraged such as network
segmentation and system access control to protect the data as it transits the 3rd party network. Finally,
encrypted communications is used again to protect the data as it transits between the 3rd party network
and the CIP-012-1 demarcation point at Entity Beta.

•

While these scenarios are all specific to communication links, it is possible that Entity Alpha and Entity
Beta achieve the security objective by applying protection to the data rather than the communication
links. In this scenario, the application enabling the data exchange between Control Centers may be
capable of applying security controls directly to the data. These security controls mitigate the risk of
unauthorized disclosure or modification of applicable data rather than relying on lower level network
services to provide this security. For instance, Entity Alpha and Entity Beta may apply security protection
at the application layer by using Secure ICCP to exchange applicable data. According to a report released
by Sandia National Labs 2, Secure ICCP provides “data integrity indirectly by providing a cryptographic
checksum…Secure ICCP provides data confidentiality by encrypting ICCP data exchanges.” Methods other
than Secure ICCP could also be used to apply security protection to the data at the application layer.

•

It is theoretically possible that Entity Alpha and Entity Beta could exchange Real-time Assessment data
between Control Centers by email. In that scenario, one approach may be for Entity Alpha to email the

https://energy.gov/sites/prod/files/oeprod/DocumentsandMedia/19-Secure_ICCP_Integration.pdf
NERC | CIP-012-1 Implementation Guidance | Draft: November 2017
8

applicable data to Entity Beta’s Control Center in a protected container such as an encrypted zip file. Entity
Alpha and Entity Beta can then exchange the password to that encrypted container through another
method, such as by phone. While the notional example of protecting data exchanged by email is a useful
illustration of how to achieve the security objective of CIP-012-1, it is extremely unlikely to be used in
practice. The characteristics of email communication are inconsistent with the requirements of Real-time
data exchange.
Identification of Demarcation Point(s)

•

Figure 2 shows the identification of CIP-012-1 demarcation points for the Entity Alpha reference model.
Entity Alpha has identified its demarcation point at each of its Control Centers to be the external Ethernet
interface on the WAN router where the security protection is applied. It has also coordinated with Entity
Beta to identify a similar demarcation point at Entity Beta’s Control Center.

•

In some cases, it may be helpful to identify both the CIP-012-1 demarcation points and the
telecommunications carrier (telco) demarcation point. Figure 3 provides such an example where the telco
demarcation point may not be within the Control Center. In this scenario, Entity Alpha identifies the CIP012-1 demarcation point to be a point on the communications path adjacent to the outside interface on
the ESP firewall. Entity Alpha has also identified the telco demarcation point at a point in the
telecommunications cabling connecting to Entity Alpha’s WAN router, perhaps at a punch down block for
example. In Figure 3, the telco demarcation point is inside the same room as the WAN router. The telco
demarcation points are referenced in the drawing for clarity, but are not part of the plan.

•

Figure 4 shows the identification of possible CIP-012-1 demarcation points and telco demarcation points
when Entity Alpha and Entity Beta transmit the applicable data through a third party.

•

The data-centric scenario described above is less intuitive for identifying demarcation points. If security
protection is applied at the application layer (such as Secure ICCP), Entity Alpha could reasonably identify
the application or service applying the security (such as the Secure ICCP service) as the demarcation point.

Identification of Roles and Responsibilities when the Control Centers are Owned or Operated by
Different Responsible Entities

Entity Alpha and Entity Beta may determine they each are responsible for one end of the VPN configuration on
their respective WAN routers. Entity Alpha and Entity Beta have agreed to a 30 character pre-shared key for
IPSec authentication and have exchanged contact information for their Network Operations Centers to enable a
coordinated response to any communication failures. They have also exchanged contact information for their
Security Operations Centers to enable a coordinated response to any suspected Cyber Security Incidents.
Rather than use a pre-shared key, Entity Alpha and Entity Beta may decide to use digital certificates for the IPSec
authentication using a trusted certificate authority. In that scenario, Entity Alpha and Entity Beta would agree
on who is the party responsible for managing the certificate authority.
When using a third party as shown in Figure 4, Entity Alpha and Entity Beta will need to define who is
responsible for each part of the connection between them. Each entity may determine they are responsible for
only the connection from their CIP-012-1 demarcation point to the telco demarcation point at the 3rd party. The
3rd party may take responsibility for protecting the data transiting its network.

NERC | CIP-012-1 Implementation Guidance | Draft: November 2017
9

Demarcation
Point

Demarcation
Point

Entity Alpha’s Primary
Control Center

Entity Alpha’s Backup
Control Center

WAN Router

WAN Router

ESP Firewall

ESP Firewall

Operator Application Database
Workstations Server
Server

ICCP
Server

Operator Application Database
Workstations Server
Server

Communications Carrier

Demarcation
Point

Entity Beta’s
Control Center
WAN Router

ESP Firewall

Operator Application Database
Workstations Server
Server

ICCP
Server

Figure 2: Network diagram and identification of demarcation points

NERC | CIP-012-1 Implementation Guidance | Draft: November 2017
10

ICCP
Server

Physically secured area

Physically secured area

Entity Alpha’s Primary
Control Center
CIP-012
Demarcation
Point

WAN Router

ESP Firewall

Telco
Demarcation
Point

Entity Alpha’s Backup
Control Center CIP-012

Demarcation
Point

WAN Router
Telco
Demarcation
Point

ESP Firewall

Encrypted
Communications
Operator Application Database
Workstations Server
Server

ICCP
Server

Operator Application Database
Workstations Server
Server

Communications Carrier
CIP-012
Demarcation
Point

Entity Beta’s
Control Center
WAN Router

ESP Firewall

Operator Application Database
Workstations Server
Server

ICCP
Server

Figure 3: Network diagram using a combination of controls for CIP-012-1

NERC | CIP-012-1 Implementation Guidance | Draft: November 2017
11

ICCP
Server

CIP-012
Demarcation
Point

CIP-012
Demarcation
Point

Entity Alpha’s Primary
Control Center

WAN Router

Entity Beta’s
Control Center

Telco
Demarcation
Point

Telco
Demarcation
Point

ESP Firewall

Operator Application Database
Workstations Server
Server

WAN Router

ESP Firewall

ICCP
Server

Operator Application Database
Workstations Server
Server

Communications Carrier
Telco
Demarcation
Point

Telco
Demarcation
Point

3rd Party

WAN Router

WAN Router

Firewall

Firewall

Server

Server

Server

Figure 4: Network Diagram depicting communications through a 3rd party

NERC | CIP-012-1 Implementation Guidance | Draft: November 2017
12

ICCP
Server

Reference Model Discussion for Requirement R2
Entities must demonstrate implementation of their R1 plan. The sections below outline examples of evidence
that may be provided to demonstrate the implementation of Entity Alpha’s CIP-012-1 R1 plan.
Identification of Security Protection

Entity Alpha may demonstrate security protection implementation through the WAN router configuration which
shows that a site-to-site IPSec VPN with AES-128 encryption is in place.
When physical security controls are used, Entity Alpha may demonstrate the implementation of physical
protection using a floorplan diagram showing the physical access controls in place.
Identification of Demarcation Point(s)

Entity Alpha may demonstrate the identification of demarcation points through a network diagram very similar
to that shown in Figure 2.
Identification of Roles and Responsibilities when the Control Centers are Owned or Operated by
Different Responsible Entities

Entity Alpha may demonstrate the implementation of roles and responsibilities with Entity Beta through a
memorandum of understanding (MOU) signed by both parties.

NERC | CIP-012-1 Implementation Guidance | Draft: November 2017
13

References
Mitre Common Weakness Enumeration (CWE™) list of software weakness types
https://cwe.mitre.org/data/definitions/327.html
Cryptographic Standards and Guidelines
https://csrc.nist.gov/Projects/Cryptographic-Standards-and-Guidelines
NIST Special Publication 800-175B
Guideline for Using Cryptographic Standards in the Federal Government: Cryptographic Mechanisms
http://nvlpubs.nist.gov/nistpubs/SpecialPublications/NIST.SP.800-175B.pdf
Guide to Cryptography
https://www.owasp.org/index.php/Guide_to_Cryptography#Symmetric_Cryptography

NERC | CIP-012-1 Implementation Guidance | Draft: November 2017
14

Unofficial Comment Form

Project 2016-02 Modifications to CIP Standards
CIP-012-1
Do not use this form for submitting comments. Use the Standards Balloting and Commenting System
(SBS) to submit comments on the draft Technical Rationale and Justification and Implementation
Guidance for CIP-012-1. Comments must be submitted by 8 p.m. Eastern, Monday, December 11, 2017.
m. Eastern, Thursday, August 20, 2015
Additional information is available on the project page. If you have questions, contact Katherine Street at
(404) 446-9702 or Mat Bunch at (404) 446-9785.
Background Information

On January 21, 2016, the Commission issued Order No. 822, approving seven CIP Reliability Standards and
new or modified definitions, and directing modifications to the CIP Reliability Standards. Among others,
the Commission directed NERC to “develop modifications to the CIP Reliability Standards to require
responsible entities to implement controls to protect, at a minimum, communication links and sensitive
bulk electric system data communicated between bulk electric system Control Centers in a manner that is
appropriately tailored to address the risks posed to the bulk electric system by the assets being protected
(i.e., high, medium, or low impact).” (Order 822, Paragraph 53)
The Project 2016-02 Standard Drafting Team (SDT) drafted Reliability Standard CIP-012-1 to require
Responsible Entities to implement controls to protect sensitive Bulk Electric System (BES) data while being
transmitted over communications links between BES Control Centers. Due to the sensitivity of the data
being communicated between the Control Centers the standard applies to all impact levels (i.e., high,
medium, or low impact).
The SDT drafted Technical Rationale and Justification for Reliability Standard CIP-012-1 to explain the
technical rationale for the proposed Reliability Standard. It provides stakeholders and the ERO Enterprise
with an understanding of the technology and technical requirements in the Reliability Standard. It also
contains information on the SDT’s intent in drafting the requirements.
The SDT also drafted Implementation Guidance to provide examples of approaches to comply with CIP012-1. Implementation Guidance does not prescribe the only approach, but is intended to highlight one or
more approaches that would be effective ways to be compliant with the standard. As Implementation
Guidance is only meant to provide examples, entities may choose alternative approaches that better fit
their situation.

Questions

1. The SDT developed draft Technical Rationale and Justification for CIP-012 to assist in
understanding the technology and technical requirements in the Reliability Standard. It also
contains information on the SDT’s intent in drafting the requirements. Do you agree with the
technology and technical requirements in the draft Technical Rationale and Justification? If you do
not agree, or if you agree but have comments or suggestions for the draft Technical Rationale and
Justification, please provide your recommendation and explanation.
Yes
No
Comments:
2. The SDT developed draft Implementation Guidance for CIP-012 to provide examples of how a
Responsible Entity could comply with the requirements. The draft Implementation Guidance does
not prescribe the only approach to compliance. Rather, it describes some approaches the SDT
believes would be effective ways to comply with the standard. See NERC’s Compliance Guidance
policy for information on Implementation Guidance. Do you agree with the example approaches in
the draft Implementation Guidance? If you do not agree, or if you agree but have comments or
suggestions for the draft Implementation Guidance, please provide your recommendation and
explanation.
Yes
No
Comments:

Unofficial Comment Form | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | November-December, 2017

2

Standards Announcement

2016-02 Modifications to CIP Standards
Informal Comment Period Open through December 11, 2017
Now Available

An informal comment period is open through 8 p.m. Eastern, Monday, December 11, 2017, for
stakeholders to provide feedback on the draft Technical Rationale and Justification and
Implementation Guidance for CIP-012-1.
Commenting

Use the Standards Balloting and Commenting System (SBS) to submit comments. If you experience
difficulty navigating the SBS, contact Wendy Muller. An unofficial Word versions of the comment form is
posted on the project page.
If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential error
messages, or system lock-out, contact NERC IT support directly at https://support.nerc.net/ (Monday –
Friday, 8 a.m. - 5 p.m. Eastern).
•

Passwords expire every 6 months and must be reset.

•

The SBS is not supported for use on mobile devices.

•

Please be mindful of ballot and comment period closing dates. We ask to allow at least 48
hours for NERC support staff to assist with inquiries. Therefore, it is recommended that users try
logging into their SBS accounts prior to the last day of a comment/ballot period.

Next Steps

The drafting team will review all responses received and determine the next steps of the project.
For more information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Katherine Street at (404) 446-9702 or Mat Bunch at (404) 4469785.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Comment Report
Project Name:

2016-02 Modifications to CIP Standards | Technical Rationale and Justification and Implementation Guidance for
CIP-012-1

Comment Period Start Date:

11/20/2017

Comment Period End Date:

12/11/2017

Associated Ballots:

There were 30 sets of responses, including comments from approximately 84 different people from approximately 59 companies
representing 10 of the Industry Segments as shown in the table on the following pages.

Questions
1. The SDT developed draft Technical Rationale and Justification for CIP-012 to assist in understanding the technology and technical
requirements in the Reliability Standard. It also contains information on the SDT’s intent in drafting the requirements. Do you agree with the
technology and technical requirements in the draft Technical Rationale and Justification? If you do not agree, or if you agree but have
comments or suggestions for the draft Technical Rationale and Justification, please provide your recommendation and explanation.

2. The SDT developed draft Implementation Guidance for CIP-012 to provide examples of how a Responsible Entity could comply with the
requirements. The draft Implementation Guidance does not prescribe the only approach to compliance. Rather, it describes some
approaches the SDT believes would be effective ways to comply with the standard. See NERC’s Compliance Guidance policy for information
on Implementation Guidance. Do you agree with the example approaches in the draft Implementation Guidance? If you do not agree, or if you
agree but have comments or suggestions for the draft Implementation Guidance, please provide your recommendation and explanation.

Organization
Name

Name

SRC & SWG David
Francis

Seattle City
Light

Ginette
Lacasse

Segment(s)

2

1,3,4,5,6

Region

Group
Name

FRCC,MRO,NPCC,RF,SERC,SPP SRC +
RE,Texas RE,WECC
SWG

WECC

Seattle
City Light
Ballot
Body

Group
Member
Name
Gregory
Campoli

Group Member
Organization

Group
Member
Segment(s)

New York
Independent
System
Operator

2

Group
Member
Region
NPCC

Mark Holman PJM
2
Interconnection,
L.L.C.

RF

Charles
Yeung

Southwest
Power Pool,
Inc. (RTO)

2

SPP RE

Terry BIlke

Midcontinent
ISO, Inc.

2

RF

Elizabeth
Axson

Electric
Reliability
Council of
Texas, Inc.

2,3

Texas RE

Ben Li

IESO

1

MRO

Drew Bonser SWG

NA - Not
Applicable

NA - Not
Applicable

Darrem Lamb CAISO

2

WECC

Matt
Goldberg

ISONE

2

NPCC

Pawel Krupa

Seattle City
Light

1

WECC

Hao Li

Seattle City
Light

4

WECC

Bud (Charles) Seattle City
Freeman
Light

6

WECC

Mike Haynes Seattle City
Light

5

WECC

Michael
Watkins

Seattle City
Light

1,4

WECC

Faz Kasraie

Seattle City
Light

5

WECC

John Clark

Seattle City
Light

6

WECC

Tuan Tran

Seattle City
Light

3

WECC

Laurrie
Hammack

Seattle City
Light

3

WECC

Public Utility Janis
District No. 1 Weddle
of Chelan
County

DTE Energy - Karie
Detroit
Barczak
Edison
Company

Northeast
Ruida
Power
Shu
Coordinating
Council

1,3,5,6

3,4,5

1,2,3,4,5,6,7,8,9,10 NPCC

Chelan
PUD

DTE
Energy DTE
Electric

RSC no
Dominion
and ISONE

Haley Sousa

Public Utility
5
District No. 1 of
Chelan County

WECC

Joyce Gundry Public Utility
3
District No. 1 of
Chelan County

WECC

Jeff Kimbell

Public Utility
1
District No. 1 of
Chelan County

WECC

Janis Weddle Public Utility
6
District No. 1 of
Chelan County

WECC

Jeffrey
Depriest

DTE Energy DTE Electric

5

RF

Daniel
Herring

DTE Energy DTE Electric

4

RF

Karie Barczak DTE Energy DTE Electric

3

RF

Guy V. Zito

Northeast
Power
Coordinating
Council

10

NPCC

Randy
MacDonald

New Brunswick 2
Power

NPCC

Wayne
Sipperly

New York
4
Power Authority

NPCC

Glen Smith

Entergy
Services

4

NPCC

Brian
Robinson

Utility Services 5

NPCC

Bruce
Metruck

New York
6
Power Authority

NPCC

Alan
Adamson

New York State 7
Reliability
Council

NPCC

Edward
Bedder

Orange &
Rockland
Utilities

1

NPCC

David Burke

Orange &
Rockland
Utilities

3

NPCC

Michele
Tondalo

UI

1

NPCC

1

NPCC

Laura Mcleod NB Power

Southwest
Power Pool,
Inc. (RTO)

Shannon 2
Mickens

SPP RE

SPP
Standards
Review
Group

David
Ontario Power 5
Ramkalawan Generation Inc.

NPCC

Quintin Lee

Eversource
Energy

1

NPCC

Paul
Malozewski

Hydro One
Networks, Inc.

3

NPCC

Helen Lainis

IESO

2

NPCC

Michael
Schiavone

National Grid

1

NPCC

Michael
Jones

National Grid

3

NPCC

Greg Campoli NYISO

2

NPCC

Sylvain
Clermont

Hydro Quebec

1

NPCC

Chantal
Mazza

Hydro Quebec

2

NPCC

Silvia Mitchell NextEra Energy 6
- Florida Power
and Light Co.

NPCC

Michael Forte Con Ed Consolidated
Edison

1

NPCC

Daniel
Grinkevich

Con Ed Consolidated
Edison Co. of
New York

1

NPCC

Peter Yost

Con Ed Consolidated
Edison Co. of
New York

3

NPCC

Brian O'Boyle Con Ed Consolidated
Edison

5

NPCC

Sean Cavote PSEG

4

NPCC

Shannon
Mickens

Southwest
2
Power Pool Inc.

SPP RE

Megan
Wagner

Westar Energy 6

SPP RE

Louis Guidry

Cleco
Corporation

SPP RE

Robert Gray

Board of Public NA - Not
Utilities (BPU), Applicable
Kansas City,
KS

1,3,5,6

NA - Not
Applicable

Ron Spicer

EDF
Renewables

5

SPP RE

1. The SDT developed draft Technical Rationale and Justification for CIP-012 to assist in understanding the technology and technical
requirements in the Reliability Standard. It also contains information on the SDT’s intent in drafting the requirements. Do you agree with the
technology and technical requirements in the draft Technical Rationale and Justification? If you do not agree, or if you agree but have
comments or suggestions for the draft Technical Rationale and Justification, please provide your recommendation and explanation.
Janis Weddle - Public Utility District No. 1 of Chelan County - 1,3,5,6, Group Name Chelan PUD
Answer

No

Document Name
Comment
The technical guidance sections do a suitable job of describing the problem that the SDT is being asked to solve. The rationale for the alignment,
however, introduces concern given that the term “Real-time monitoring”, while aligned with IRO and TOP terminology, is not itself a NERC-defined term
and is also being further modified to create another new “Real-time monitoring and control” undefined term. Given that the term is already being
changed, CHPD requests that the STD instead consider creating a new “BES data” (a term used by the SDT in the Draft 2 Unofficial Comment Form)
NERC Glossary term to be used to clearly scope the data in question. Here is a potential, admittedly simple, initial definition to consider:
BES Data – Electronic data used by BES Cyber Systems to perform Supervisory Control and Data Acquisition (SCADA).
The intent of the concept of “demarcation points” is well-reasoned and CHPD supports this identification capability. CHPD requests that the Technical
Rationale and Justification (TR&J) for this section be more clearly aligned with the Requirement R1.2, which does not currently limit the scope to the
Responsible Entity’s Control Center. Consider the following revision:
“1.2 Identification of the Responsible Entity’s demarcation point(s)…”
A change to a demarcation point in one system should not create a paperwork or compliance issue for a neighbor or vice versa. Alternatively, consider
defining the term “demarcation point” in the NERC glossary to identify the scope within the definition of the term, rather than in the language of the
standard.
Likes

0

Dislikes

0

Response

Richard Jackson - U.S. Bureau of Reclamation - 1,5
Answer

No

Document Name
Comment
Reclamation also recommends the Drafting Team state clearly that examples provided in Technical Rationale and Justification documents are neither
mandatory, nor enforceable, nor the only method of achieving compliance.
Likes

0

Dislikes
Response

0

Andrew Gallo - Austin Energy - 1,3,4,5,6
Answer

No

Document Name
Comment
Austin Energy (AE) generally agrees with the Draft 2 revision. However, the SDT should define the new terms “monitoring data” and “control data” in the
NERC Glossary. Additionally, the concept of “demarcation point(s)” is unclear. The Standard should indicate a Registered Entity should identify the
Cyber Asset at which the Entity begins protected data and ceases to protect data. The current wording implies each entity should document its
demarcation point and any demarcation point(s) at a neighboring system. A change to a demarcation point for one entity should not create a paperwork
or compliance issue for a neighbor. Alternatively, the SDT could define “demarcation point.”
Also, while the Technical Rationale and Justification for CIP-012 addresses R1 (scope, demarcation points, roles and responsibilities), it does not
properly address R2. While physical protections may protect confidentiality between Control Centers owned by the same entity, it does not address nonrepudiation and, therefore, integrity as defined by NIST 800-53, Revision 4, page B-6. AE asks the SDT to provide additional rationale and justification
regarding how the protections are required “…in a manner that reflects the risks posed to bulk electric system reliability,” as stated on page 12 of FERC
Order No. 822.
Likes

0

Dislikes

0

Response

Nicholas Lauriat - Network and Security Technologies - 1
Answer

No

Document Name
Comment
N&ST believes the draft Technical Rationale and Justification fails to address the applicability of CIP-012 to the exchange of Real-time Assessment
data between a BES Control Center and a third party provider of such data. At the same time, the draft Implementation Guidance document clearly
indicates that the SDT believes this scenario would be in scope. If this is in fact true, then both the Technical Rationale and Justification and CIP-012
standard document should include explicit statements to that effect.
Likes

0

Dislikes

0

Response

Don Schmit - Nebraska Public Power District - 1,3,5
Answer
Document Name

No

Comment
See comments from the MRO NSRF for the ballot conducted for CIP-012-1 which closed on December 11, 2017.
Likes

0

Dislikes

0

Response

Terry Harbour - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1,3
Answer

No

Document Name
Comment
We do not agree with two separate requirements, one for a plan and one to implement. We recommend following precedent in the other CIP standards,
for example, CIP-004-011. The obligation can be accomplished with one requirement, as follows. “The Responsible Entity shall implement one or more
documented process(es) to mitigate the risk of the unauthorized disclosure or modification of Real-time Assessments and Real-time monitoring and
control data while being transmitted between any Control Centers, except under CIP Exceptional Circumstances. This excludes oral communications.
The process(es) shall identify: 1.1 security protection used to mitigate risk of unauthorized disclosure or modification of Real-time Assessment and
Real-time monitoring and control data while being transmitted between Control Centers. 1.2 demarcation point(s) where security protection is applied for
transmitting Real-time Assessment and Real-time monitoring and control data between Control Centers. Demarcation points identified by the
Responsible Entity do not add additional Cyber Assets to the scope of the CIP Reliability Standards; and 1.3 roles and responsibilities of each
Responsible Entity for applying security protection to the transmission of Real-time Assessment and Real-time monitoring and control data between
Control Centers, when the Control Centers are owned or operated by different Responsible Entities.” This also includes important scoping from the
implementation guidance that belongs in the requirement, that demarcation points don’t add additional Cyber Assets to the scope of the CIP standards.
Likes

0

Dislikes

0

Response

Lona Calderon - Salt River Project - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
While the Technical Rationale and Justification for CIP-012 goes into great detail for R1 to give an understanding and overview of the rationale behind
the scope, demarcation points, and the need for roles and responsibilities, SRP asserts it did not properly address Requirement 2.
While physical protections may satisfy the objective of protecting confidentiality between Control Centers owned by the same Registered Entity, it does
not address non-repudiation in any situation, and therefore integrity as it was defined by NIST 800-53, Revision 4, page B-6. SRP requests the SDT

provide more rationale and justification as to how these protections are being required “…in a manner that reflects the risks posed to bulk electric
system reliability,” as stated on page 12 of FERC Order No. 822.
Likes

0

Dislikes

0

Response

Annette Johnston - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1,3
Answer

No

Document Name
Comment
Support Terry Harbour comments (Berhshire Hathaway Company - MidAmerican Energy Company)
Likes

0

Dislikes

0

Response

Lan Nguyen - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
CenterPoint Energy Houston Electric, LLC (“CenterPoint Energy”) does not agree with certain comments in the draft Technical Rationale and
Justification. As detailed in its Comment Form for proposed CIP-012-1, CenterPoint Energy recommends that the phrase “and control” be removed
from proposed Requirement R1 on page 4 of the draft Technical Rationale and Justification. Inclusion of this phrase may create confusion and does not
align with TOP-003 and IRO-010 data specification Requirements. Additionally, the phrase was not mentioned in FERC Order 822. Thus, CenterPoint
Energy recommends corresponding revisions to the Technical Rational and Justification.
The SDT’s justification on page 5 of the draft Technical Rationale and Justification for adding “and control” to “Real-time monitoring and control data” is
unclear and confusing. The SDT recognizes that “in practice Real-time control data is not transmitted separately from Real-time monitoring
data.” Given this practice, the introduction of the concept of separately transmitted “Real-time control data” may create confusion on whether there are
additional data specification responsibilities besides those detailed in TOP-003 and IRO-010.
To align with the revisions recommended above and in its Comment Form for proposed CIP-012-1, CenterPoint Energy also recommends that the
following sentences be removed from the first paragraph of page 5 of the draft Technical Rationale and Justification:
“The SDT notes that it expanded the phrase ‘Real-time monitoring’ from TOP-003 and IRO-010 to ‘Real-time monitoring and control’ data.”
“However, the SDT wanted to ensure that Real-time control data was included regardless of whether or not it is transmitted along with Real-time
monitoring data.”

CenterPoint Energy believes the rest of the first paragraph on page 5 is appropriate to be included because it states the SDT’s thought process and
concern.
Likes

0

Dislikes

0

Response

Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer

No

Document Name
Comment
Under the General Considerations section of the Technical Rationale, Xcel Energy has concerns with implementation of this Standard as related to the
term and definition of Control Center. Specifically, we are concerned with the definition of an "associated data center" as part of the Control
Center. The Standard does not appear to apply to communication between the control center and a field device (per reference model on page 5 of
Technical Rationale). However, if we have a Control Center communicating with a device that aggregates multiple field devices, is that aggregating
device location considered an associated data center?
Under the Alignment with IRO and TOP Standards, we believe that the types of data to be within scope, as identified by data specification lists
originating from TOP-003 and IRO-010 are not specific enough to determine or limit the types of data or communication methods that would need to be
protected as Real Time Assessments, Real Time Monitoring, or Control Data. These lists contain data and methods of communicating data that Xcel
Energy would not classify as Real Time Assessment, Real Time Monitoring, or Control Data. Xcel Energy's concern is that NERC and Regional Entities
may. The inclusion of all data types and methods on these lists could bring systems like corporate email into scope, which we would adamantly
oppose. We suggest adding further clarification as to what types of data are included as Real Time Assessment, Real Time Monitoring, and Control
Data.
Likes

0

Dislikes

0

Response

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer

No

Document Name
Comment
We support SRP and Chelan PUD comments.
Likes

0

Dislikes
Response

0

Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6
Answer

No

Document Name
Comment
Tacoma Power endorses the draft comments shared with it by Salt River Project (SRP), which follow:
While the Technical Rationale and Justification for CIP-012 goes into great detail for R1 to give an understanding and overview of the rationale behind
the scope, demarcation points, and the need for roles and responsibilities, SRP asserts it did not properly address Requirement 2.
While physical protections may satisfy the objective of protecting confidentiality between Control Centers owned by the same Registered Entity, it does
not address non-repudiation in any situation, and therefore integrity as it was defined by NIST 800-53, Revision 4, page B-6. SRP requests the SDT
provide more rationale and justification as to how these protections are being required “…in a manner that reflects the risks posed to bulk electric
system reliability,” as stated on page 12 of FERC Order No. 822.
Likes

0

Dislikes

0

Response

John Tolo - Unisource - Tucson Electric Power Co. - 1
Answer

Yes

Document Name
Comment
This is reasonable given that some of the communications may flow on third-party networks. That said, there seems to be no discussion of protecting
the communications devices themselves. Recommend taking a “high watermark” approach to categorizing the importance and risk of communication
systems. Many utilities use internal communications between their PCC and BCC. If those links are not trusted and require the protections of CIP-012,
why trust the substation SCADA links feeding data to the control centers? Being more prescriptive would be helpful. Is the SDT mandating
encryption? What physical protections would be sufficient? Is OPGW fiber “protected” or just “difficult?”
Likes

0

Dislikes

0

Response

Steven Rueckert - Western Electricity Coordinating Council - 10
Answer
Document Name
Comment

Yes

Page 5 (Control Center Ownership) - Recommend changing ‘ensure adequate protection is applied’ to ‘ensure the security objective is met’ in the
sentence, ‘It is strongly recommended, however, that these partnering entities develop agreements, or use existing ones, to define responsibilities to
ensure adequate protection is applied.’
Likes

0

Dislikes

0

Response

Richard Vine - California ISO - 2
Answer

Yes

Document Name
Comment
The California ISO supports the comments of the IRC Security Working Group (SWG)
Likes

0

Dislikes

0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

Yes

Document Name
Comment
The SPP Standards Review Group proposes to include the defined terms “Confidentiality” and “Integrity” in the NERC Glossary of Terms or, at a
minimum, define the terms in the body of the standard. The current definitions are stated in the National Institute of Standards and Technology’s (NIST)
Special Publication 800-53A, Revision 4 (as footnoted in the Technical Rationale Documentation); however, the NIST document is non-governing and
could be revised outside the purview of NERC, which could have a negative impact on an entity’s compliance with standards such as CIP-012. The SPP
Standards Review Group would recommend utilizing the definitions for “Confidentiality” and “Integrity” as stated in the current Technical Rational and
Justification for CIP-012.
Additionally, the SPP Standards Review Group would recommend the same course of action be applicable to the term “Demarcation Point.”
Likes

0

Dislikes

0

Response

Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2

Answer

Yes

Document Name
Comment
ERCOT signs onto the comments of the SRC/ITC/SWG of the IRC, pasted below.

The SRC & ITC SWG offers the following comments and recommendations. To solidify the intent of the SDT, as noted in the response to comments,
the SRC & ITC SWG recommend that it be clarified in the Technical Rationale and Justification that CIP-012-1 is a standalone Standard similar to CIP014 and is not intended to increase the scope of applicable systems to be protected under CIP-003 thru CIP-011.
Likes

0

Dislikes

0

Response

David Francis - SRC & SWG - 2 - MRO,NPCC,SERC,RF, Group Name SRC + SWG
Answer

Yes

Document Name
Comment
Comments: The SRC & ITC SWG offers the following comments and recommendations. To solidify the intent of the SDT, as noted in the response to
comments, the SRC & ITC SWG recommend that it be clarified in the Technical Rationale and Justification that CIP-012-1 is a standalone Standard
similar to CIP-014 and is not intended to increase the scope of applicable systems to be protected under CIP-003 thru CIP-011.
Likes

0

Dislikes

0

Response

Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Glen Farmer - Avista - Avista Corporation - 1,3,5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Vivian Vo - APS - Arizona Public Service Co. - 1,3,5,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Eleanor Ewry - Puget Sound Energy, Inc. - 1,3,5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Chris Scanlon - Exelon - 1,3,5,6
Answer
Document Name
Comment

Yes

Likes

0

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0

Response

Laurie Williams - PNM Resources - Public Service Company of New Mexico - 1,3
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Douglas Webb - Great Plains Energy - Kansas City Power and Light Co. - 1,3,5,6 - SPP RE
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion and ISO-NE
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Brandon Cain - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - FRCC,MRO,WECC,Texas RE,SERC,SPP RE
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment

Texas RE is concerned about the use of the term “or” as used in Requirement R1. Please see Texas RE’s comments for Question #1 on the unofficial
comment form for the comment period ending on December 11, 2017.

Texas RE also has a concern about the difference between monitoring and control data. On page 5 of the Technical Rationale, the SDT notes that it
expanded the phrase “Real-time monitoring” data from TOP-003 and IRO-010 to “Real-time monitoring and control” data. The SDT was concerned that
data transmitted between Control Centers that results in the physical operation of BES Elements was not explicitly included in Real-time monitoring
data. The SDT understands that in practice Real-time control data is not transmitted separately from Real-time monitoring data. However, the SDT
wanted to ensure that Real-time control data was included regardless of whether or not it is transmitted along with Real-time monitoring data. If entities
only transmit Real-time control data along with Real-time monitoring data, then the SDT does not intend for such entities to identify additional data
beyond that Real-time monitoring data already included in the data specifications for TOP-003 and IRO-010. Texas RE is concerned that if there is a
need to expand the phrase to include control data in CIP-012-1, there might also be a need in IRO-010 and TOP-003.
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0

2. The SDT developed draft Implementation Guidance for CIP-012 to provide examples of how a Responsible Entity could comply with the
requirements. The draft Implementation Guidance does not prescribe the only approach to compliance. Rather, it describes some
approaches the SDT believes would be effective ways to comply with the standard. See NERC’s Compliance Guidance policy for information
on Implementation Guidance. Do you agree with the example approaches in the draft Implementation Guidance? If you do not agree, or if you
agree but have comments or suggestions for the draft Implementation Guidance, please provide your recommendation and explanation.
Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6
Answer

No

Document Name
Comment
Tacoma Power endorses the draft comments shared with it by Salt River Project (SRP), which follow:
The Implementation Guidance states “The protection must also meet the security objective of mitigating the risk of unauthorized disclosure or
modification of applicable data while in transit between Control Centers for the entire distance between CIP-012-1 demarcation points.” The document
also describes a situation where Entity Alpha exchanges data with Entity Beta through a “3rd party network.” The guidance asserts “a number of
security controls may be leveraged such as network segmentation and system access control to protect the data as it transits the 3rd party network.”
However, the document does not describe the implications if the third part circumvents these controls. Additionally, these controls within the 3rd party
network do not address non-repudiation, and therefore integrity as it was defined by NIST 800-53, Revision 4, page B-6. SRP asserts more explanation
is required within the Implementation Guidance to explain how the example approaches satisfy the security objective. If the approaches indeed satisfy
the security objective, then the requirement must be updated to fit the scenario.
Although the SDT states it does not specify controls, the only examples provided in the implementation guidance includes encryption. If there are other
methods available other than encryption to achieve the security objective, please provide them.
Likes

0

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0

Response

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer

No

Document Name
Comment
We support SRP and Chelan PUD comments.
Likes

0

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0

Response

Lan Nguyen - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE

Answer

No

Document Name
Comment
For the same reasons discussed in its Response to Question No. 1 and in its Comment Form for proposed CIP-012-1, CenterPoint Energy recommends
that the phrase “and control” be removed from Requirement R1on page 4 of the draft Implementation Guidance..
In accordance with Requirement R1.3, Responsible Entities are required to identify roles and responsibilities for applying security protections. However,
on page 5 of the Implementation Guidance, consideration of the following situations was listed: (1) configuration of security protocols, (2) responding to
communication failures, and (3) responding to Cyber Security Incidents. Items (2) and (3) go beyond the scope of Requirement R1.3 and, therefore,
should be removed from the Implementation Guidance.
Similarly, on page 9, the following example goes beyond the scope of Requirement 1.3 and should be removed from the Implementation Guidance:
“Entity Alpha and Entity Beta have agreed to a 30 character pre-shared key for coordinated response to any communication failures. They have also
exchanged contact information for their Security Operations Centers to enable a coordinated response to any suspected Cyber Security Incidents.”
Page 8 and page 13 lists “AES-128 encryption” as an example of protection; however, 128 bit encryption is the lowest key length. CenterPoint Energy
recommends removing “AES-128” and only stating the word “encryption.”
In the last paragraph of page 9, regarding communications through a third party, the Implementation Guidance should recommend stronger controls
around protecting the data being transmitted through a third party communication link. For example, Entity Alpha and Entity Beta should establish
agreements with the 3rd party responsible for the communication to protect the data transiting its network. The last sentence, “The 3rd party may take
responsibility for protecting the data transiting its network” does not allow for adequate protection of the data.
Likes

0

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0

Response

Annette Johnston - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1,3
Answer

No

Document Name
Comment
Support Terry Harbour comments (Berhshire Hathaway Company - MidAmerican Energy Company)
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0

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0

Response

Lona Calderon - Salt River Project - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
The Implementation Guidance states “The protection must also meet the security objective of mitigating the risk of unauthorized disclosure or
modification of applicable data while in transit between Control Centers for the entire distance between CIP-012-1 demarcation points.” The document
also describes a situation where Entity Alpha exchanges data with Entity Beta through a “3rd party network.” The guidance asserts “a number of
security controls may be leveraged such as network segmentation and system access control to protect the data as it transits the 3rd party network.”
However, the document does not describe the implications if the third part circumvents these controls. Additionally, these controls within the 3rd party
network do not address non-repudiation, and therefore integrity as it was defined by NIST 800-53, Revision 4, page B-6. SRP asserts more explanation
is required within the Implementation Guidance to explain how the example approaches satisfy the security objective. If the approaches indeed satisfy
the security objective, then the requirement must be updated to fit the scenario.
Although the SDT states it does not specify controls, the only examples provided in the implementation guidance includes encryption. If there are other
methods available other than encryption to achieve the security objective, please provide them.
Likes

0

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0

Response

Terry Harbour - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1,3
Answer

No

Document Name
Comment
We do not agree with two separate requirements, one for a plan and one to implement. We recommend following precedent in the other CIP standards,
for example, CIP-004-011. The obligation can be accomplished with one requirement, as follows. “The Responsible Entity shall implement one or more
documented process(es) to mitigate the risk of the unauthorized disclosure or modification of Real-time Assessments and Real-time monitoring and
control data while being transmitted between any Control Centers, except under CIP Exceptional Circumstances. This excludes oral communications.
The process(es) shall identify: 1.1 security protection used to mitigate risk of unauthorized disclosure or modification of Real-time Assessment and
Real-time monitoring and control data while being transmitted between Control Centers. 1.2 demarcation point(s) where security protection is applied for
transmitting Real-time Assessment and Real-time monitoring and control data between Control Centers. Demarcation points identified by the
Responsible Entity do not add additional Cyber Assets to the scope of the CIP Reliability Standards; and 1.3 roles and responsibilities of each
Responsible Entity for applying security protection to the transmission of Real-time Assessment and Real-time monitoring and control data between
Control Centers, when the Control Centers are owned or operated by different Responsible Entities.” This also includes important scoping from the
implementation guidance that belongs in the requirement, that demarcation points don’t add additional Cyber Assets to the scope of the CIP standards.
Also, the Proposed Reliability Standard lacks sufficient specificity (i.e., sufficient to stand on its own), without an endorsed Technical Rationale and
Implementation Guidance. Relative to the draft Implementation Guidance document, MEC agrees with EEI that Industry will likely find it difficult to make
any final judgments on the proposed Reliability Standard without NERC's endorsement of the draft Implementation Guidance. We trust that once the
Proposed Reliability Standard gets closer to a final ballot NERC will endorse the final draft of the Implementation Guidance. In the event that doesn't
occur, we fear the approval of this standard may be at risk.
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0

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0

Nicholas Lauriat - Network and Security Technologies - 1
Answer

No

Document Name
Comment
N&ST believes that Figure 4 (“Network Diagram depicting communications through a 3rd party”) and its accompanying discussion describe a scenario
for which CIP-012, as presently written, would not apply. As the figure is presently drawn, Control Centers “Alpha” and “Beta” are not communicating,
that is, exchanging data, with each other. Each one is communicating with the “3rd party.” The fact that the 3rd party is presumably forwarding data that
it has processed in some fashion to Beta after receiving it from Alpha, or vice-versa, does not, in N&ST’s opinion, constitute communications between
two BES Control Centers.
If the SDT believes that communication links carrying Real-time Assessment data between BES Control Centers and 3rd party providers of such data,
then CIP-012-1 should be modified to make this an explicit requirement.
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0

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Response

Andrew Gallo - Austin Energy - 1,3,4,5,6
Answer

No

Document Name
Comment
AE requests a formal definition of terms describing the data in question (e.g. “BES data” to address “monitoring” and “control” data types in a single
definition. BES Data could be defined as, “Electronic data in BES Cyber Systems used to perform Supervisory Control and Data Acquisition (SCADA).”
If the STD believes monitoring and control data should be defined separately, AE requests new NERC Glossary terms for “monitoring data” and “control
data.”
Additionally, the Implementation Guidance states “The protection must also meet the security objective of mitigating the risk of unauthorized disclosure
or modification of applicable data while in transit between Control Centers for the entire distance between CIP-012-1 demarcation points.” The
document describes a situation where Entity Alpha exchanges data with Entity Beta through a “3rd party network.” The guidance asserts “a number of
security controls may be leveraged such as network segmentation and system access control to protect the data as it transits the 3rd party network.”
The document does not, however, describe the implications of the 3rd party circumventing those controls. Additionally, the controls in the 3rd party
network do not address non-repudiation and, therefore, integrity as defined in NIST 800-53, Revision 4, page B-6. AE requests additional explanation to
explain how the example approaches meet the security objective.
Although the SDT states it does not specify controls, the only examples provided include encryption. If other methods exist, the SDT should provide
them.

Likes

0

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Response

Janis Weddle - Public Utility District No. 1 of Chelan County - 1,3,5,6, Group Name Chelan PUD
Answer

No

Document Name
Comment
The Technical Rationale and Justification (TR&J) does not currently provide any technical implementation guidelines to identify where protections may
be applied under the language of the CIP-012-1 standard. CHPD requests the addition of one or more sample connectivity drawings to the TR&J that
depict compliant topology configurations showing the R1.1 security protection and R1.2 demarcation point placement that could be applied to an
existing pair of in-scope Control Centers, including the associated BCS, ESP (EAP/EACMS), and PSP boundaries.
Likes

0

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0

Response

David Francis - SRC & SWG - 2 - MRO,NPCC,SERC,RF, Group Name SRC + SWG
Answer

Yes

Document Name
Comment
Comments: There are concerns regarding the statement, “Demarcation points identified by the Responsible Entity do not add additional assets to the
scope of the CIP Reliability Standards.” Entities may already include the demarcation points as Cyber Asset relevant to CIP-002 thru CIP-011. The
statement could be revised as, “Demarcation points identified by the Responsible Entity is not intended to add additional assets to the scope of the CIP
Reliability Standards.”
With regards to the references models and narrative, it would be helpful to have the narrative and the reference model together. It is cumbersome to
keep skipping back and forth in the document.

Likes

0

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0

Response

Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer
Document Name

Yes

Comment
Comments: There are concerns regarding the statement, “Demarcation points identified by the Responsible Entity do not add additional assets to the
scope of the CIP Reliability Standards.” Entities may already include the demarcation points as Cyber Asset relevant to CIP-002 thru CIP-011. The
statement could be revised as, “Demarcation points identified by the Responsible Entity are not intended to add additional assets to the scope of the
CIP Reliability Standards.”

With regards to the references models and narrative, it would be helpful to have the narrative and the reference model together. It is cumbersome to
keep skipping back and forth in the document.
Likes

0

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0

Response

Laurie Williams - PNM Resources - Public Service Company of New Mexico - 1,3
Answer

Yes

Document Name
Comment
While PNMR agrees with the example approaches in the draft Implementation Guidance there is one scenario that does not appear and possible
should. Some entities use mailbox or virtual RTUs to communicate data between Control Centers either as redundant method to or in lieu of
ICCP. Some Entities may forget that such communication could be in-scope of the standard especially if “Real-time Assessment and Real-time
monitoring and control data” is passed through these mailbox or virtual RTUs. Typically these have points to point serial protocols and those serial
connections would need to have protections applied. While PNMR does not know how many still use mailbox or virtual RTUs as an alternate means, it
is something the drafting team should take into consideration.
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0

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Response

Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer

Yes

Document Name
Comment
Xcel Energy agrees that the approaches offered in the CIP-012-2 Implementation Guidance are non-prescriptive and can be sufficient models to be
used in implementation. However, Xcel Energy cannot agree with the proposed timeline of 24 months. We share real-time data with Registered
Entities (REs) such as the Reliability Coordinators (RCs) including MISO, SPP and PEAK. Additionally, we would share data with many utilities with
Control Centers across our service territory. Finding a common technological solution to implement the proposed mitigating activities in the

Requirements will take a substantial effort on the part of all REs. Once a common technology and all legal agreements between REs are in place, Xcel
Energy may still have to purchase and implement those technology solutions.
Xcel Energy stakeholders suggest that NERC should advice and work with all RCs to agree upon a common technology first and then drive those
solutions from the RC down to each utility in scope.
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0

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Response

Chris Scanlon - Exelon - 1,3,5,6
Answer

Yes

Document Name
Comment
Exelon generally agrees with the approach in the draft Implementation Guidance, noting the following concerns and suggestions.
1. We have a concern that the CIP-012-1 Standard may be approved prior to NERC endorsement of the Technical Rationale and Justification and
the Implementation Guidance for CIP-012. Our approval of the CIP-012-1 Standard language as presented is in part predicated upon the
clarifications present within the Implementation Guidance. We would expect to see the endorsement by NERC of these supporting documents
before we vote for final approval of the Standard.
2. Within the Standard, Technical Rationale and Justification, and the Implementation Guidance, there is no mention of the scenario of data
transmission between a Control Center and its associated Data Center(s) located in separate physical locations. Clarification of whether this
intra-Control Center data transmission is in scope seems appropriate.
3. Our SMEs raised questions about data not currently determined to have a 15-minute impact and therefore out of scope for CIP-002 thru CIP011, e.g. synchrophasers data. Can we automatically assume then, that this same data is also currently out of scope for CIP-012? Looking for
clarification on this question within the Standard or supporting documents.
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0

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Response

Eleanor Ewry - Puget Sound Energy, Inc. - 1,3,5
Answer

Yes

Document Name
Comment
Further details about the technological controls required to meet the requirements would be helpful. Providing additional, specific examples about
appropriate approaches would help ensure entities implement sufficient protection mechanisms, per the requirements.

Likes

0

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0

Response

Richard Vine - California ISO - 2
Answer

Yes

Document Name
Comment
The California ISO supports the comments of the IRC Security Working Group (SWG)
Likes

0

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0

Response

Steven Rueckert - Western Electricity Coordinating Council - 10
Answer

Yes

Document Name
Comment
Page 1 Introduction - Recommend including in the Introduction the same paragraph found in the Technical Rationale and Justification Introduction as it
provides an important perspective that appears to not be fully understood.
‘Although the Commission directed NERC to develop modifications to CIP-006, the SDT determined that modifications to CIP-006 would not be
appropriate. There are differences between the plan(s) required to be developed and implemented for CIP-012-1 and the protection required in CIP006-6 Requirement R1 Part 1.10. CIP-012-1 Requirements R1 and R2 protect the applicable data during transmission between two separate Control
Centers. CIP-006 Requirement R1 Part 1.10 protects nonprogrammable communication components within an Electronic Security Perimeter (ESP) but
outside of a Physical Security Perimeter (PSP). The transmission of applicable data between Control Centers takes place outside of an ESP. Therefore,
the protection contained in CIP-006-6 Requirement R1 Part 1.10 does not apply.’
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0

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0

Response

John Tolo - Unisource - Tucson Electric Power Co. - 1
Answer
Document Name

Yes

Comment
Sometimes the lack of specifics causes confusion and lost time. Being more specific about the technological controls would be more helpful. For
instance, PCI-DSS specifically calls out when encryption is needed for data at-rest and in-transit. If the intent is to encrypt data, it would be better to say
so up-front and specify the protection boundaries. Some entities may decide to implement different protection mechanisms that may not be sufficient
from a security perspective and then through the course of presentations and guidance have to re-work.
TEP appreciates the opportunity to comment.
Likes

0

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0

Response

Brandon Cain - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - FRCC,MRO,WECC,Texas RE,SERC,SPP RE
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion and ISO-NE
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Douglas Webb - Great Plains Energy - Kansas City Power and Light Co. - 1,3,5,6 - SPP RE
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Vivian Vo - APS - Arizona Public Service Co. - 1,3,5,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Glen Farmer - Avista - Avista Corporation - 1,3,5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Richard Jackson - U.S. Bureau of Reclamation - 1,5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE has the following comments regarding the implementation guidance:

In the Identification of Security Protection section on page 6: “Alternatively, a Responsible Entity may demonstrate implementation through monitoring
of the security control such as a report generated from an automated tool that monitors the encryption service used to protect a communications link.”
•

Texas RE recommends adding monitoring and logging, monitors and logs.

In the Reference Model Discussion for Requirement R1 section on page 7:
“Additionally, Entity Alpha does not need to consider any communications to other non-Control Center facilities such as generating plants or
substations. These communications are out of scope for CIP-012-1.”
•

Although this may be out-of-scope as a best security practice, Texas RE recommend Entity Alpha should “consider any communications to
other non-Control Center facilities such as generating plants or substations.”

In the Identification of Security Protection section on page 13:
“When physical security controls are used, Entity Alpha may demonstrate the implementation of physical protection using a floorplan diagram
showing the physical access controls in place.”
•
Likes

Texas RE suggests including other types of evidence with a floorplan as a floorplan diagram alone would not be sufficient.
0

Dislikes
Response

0

Project 2016-02
Modifications to CIP Standards
Consideration of Comments Regarding
Implementation Guidance and Technical Rationale
and Justification for CIP-012

March 2018

NERC | Report Title | Report Date
I

Table of ContentsPreface .......................................................................................................................................... iii
Introduction .............................................................................................................................................................. iv
Consideration of Comments – Summary Responses ................................................................................................. 5
Implementation Guidance...................................................................................................................................... 5

NERC | CIP-012 Consideration of Comments | March 2018
ii

Preface
The North American Electric Reliability Corporation (NERC) is a not-for-profit international regulatory authority whose
mission is to assure the reliability and security of the bulk power system (BPS) in North America. NERC develops and
enforces Reliability Standards; annually assesses seasonal and long‐term reliability; monitors the BPS through system
awareness; and educates, trains, and certifies industry personnel. NERC’s area of responsibility spans the continental
United States, Canada, and the northern portion of Baja California, Mexico. NERC is the Electric Reliability
Organization (ERO) for North America, subject to oversight by the Federal Energy Regulatory Commission (FERC) and
governmental authorities in Canada. NERC’s jurisdiction includes users, owners, and operators of the BPS, which
serves more than 334 million people.
The North American BPS is divided into eight Regional Entity (RE) boundaries as shown in the map and corresponding
table below.

The North American BPS is divided into eight RE boundaries. The highlighted areas denote overlap as some load-serving entities
participate in one Region while associated transmission owners/operators participate in another.

FRCC

Florida Reliability Coordinating Council

MRO

Midwest Reliability Organization

NPCC

Northeast Power Coordinating Council

RF

ReliabilityFirst

SERC

SERC Reliability Corporation

SPP RE

Southwest Power Pool Regional Entity

Texas RE

Texas Reliability Entity

WECC

Western Electricity Coordinating Council

NERC | CIP-012 Consideration of Comments | March 2018
iii

Introduction
The standard drafting team (SDT) appreciates industry comments on the proposed Implementation Guidance and
Technical Rationale and Justification for CIP-012. The SDT considered the comments submitted during the posting of
the proposed Implementation Guidance and Technical Rationale and Justification for CIP-012, and adapted its
revision approach for the second proposal currently posted. Additionally, the SDT conducted substantial outreach
during the revision process, through in-person meetings, conference calls, and stakeholder organization
presentations.
On January 21, 2016, the Federal Energy Regulatory Commission (FERC) issued Order No. 822 Revised Critical
Infrastructure Protection Reliability Standards. In this order, FERC approved revisions to version 5 of the CIP
standards.
Response to Comments
The SDT has carefully reviewed each stakeholder comment and has revised language where suggested changes are
consistent with SDT intent and industry consensus. The SDT reviewed and responded to each comment in summary
form below.
There were 30 sets of comments, comprised of approximately 84 different people across approximately 59
companies representing 10 of the Industry Segments.
All comments submitted can be reviewed in their original format on the project page.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give every
comment serious consideration in this process. If you feel there has been an error or omission, you can contact the
Senior Director of Standards, Howard Gugel (via email) or at (404) 446‐9693.

NERC | CIP-012 Consideration of Comments | March 2018
iv

Consideration of Comments – Summary Responses
Implementation Guidance
•

Commenters recommended creating a new “BES data” NERC Glossary term to be used to clearly scope the
data in question. Commenters also recommended defining the terms “monitoring data” and “control data”
in the NERC Glossary.
The SDT asserts that Real-time monitoring is a well-understood concept that is included in the TOP and IRO
standards. Additionally, Real-time Assessment is a defined term within the NERC Glossary of Terms Used
in Reliability Standards. Creating new terms and definitions could cause unintended impacts on other
standards. The SDT removed “and control” from Requirement R1 and from the Technical Rationale.

•

A commenter noted the Technical Rationale and Justification document does not provide any technical
implementation guidelines to identify where protections may be applied under the language of the CIP-0121 standard. The commenter also requested the addition of one or more sample connectivity drawings to the
Technical Rationale and Justification document that depict compliant topology configurations showing the
R1.1 security protection and R1.2 demarcation point placement that could be applied to an existing pair of
in-scope Control Centers, including the associated BCS, ESP (EAP/EACMS), and PSP boundaries.
The Technical Rationale and Justification document explains the technical rationale for the proposed
Reliability Standard. This Technical Rationale and Justification document does not provide examples of how
to implement the requirements. However, the SDT has identified physically secure areas and ESP firewalls
in the diagrams in the Implementation Guidance for CIP-012-1.

•

A commenter recommended the following paragraph from the Technical Rationale and Justification
Introduction as it provides an important perspective that appears to not be fully understood. “Although the
Commission directed NERC to develop modifications to CIP-006, the SDT determined that modifications to CIP006 would not be appropriate. There are differences between the plan(s) required to be developed and
implemented for CIP-012-1 and the protection required in CIP-006-6 Requirement R1 Part 1.10. CIP-012-1
Requirements R1 and R2 protect the applicable data during transmission between two separate Control
Centers. CIP-006 Requirement R1 Part 1.10 protects nonprogrammable communication components within
an Electronic Security Perimeter (ESP) but outside of a Physical Security Perimeter (PSP). The transmission of
applicable data between Control Centers takes place outside of an ESP. Therefore, the protection contained
in CIP-006-6 Requirement R1 Part 1.10 does not apply.”
The SDT notes this paragraph is an explanation of the rationale behind developing CIP-012. It does not
include information on examples of implementation. The SDT has declined to add this to the
Implementation Guidance for these reasons.

•

A commenter recommended adding logging to the Identification of Security Protection section on page 7.
The commenter also recommended that entities should consider any communications to other non-Control
Center facilities such as generating plants or substations. The commenter also suggests including other types
of evidence with a floorplan as a floorplan diagram alone would not be sufficient.
The SDT thanks you for the comments. The SDT notes that the Implementation Guidance is providing a
small set of examples of implementation and has aligned the content to the requirement language only. It
is not the intent of the SDT to add more rigor in meeting best practice that may be outside the scope of the
requirement language. The SDT notes that additional Implementation Guidance documents can be drafted

NERC | CIP-012 Consideration of Comments | March 2018
5

Consideration of Comments – Summary Responses

for any standard. Individual entities are encouraged to work with pre-qualified organizations to submit
additional Implementation Guidance for consideration of endorsement by the ERO.
•

Commenters requested more examples of technical controls, noting that lack of specifics can cause confusion
and lost time. This will aid entities who may decide to implement protection mechanisms that may not be
sufficient from a security perspective and then through the course of presentations and guidance have to rework.
The SDT thanks you for the comments. The SDT notes that the Implementation Guidance is providing a
small set of examples of implementation. SDT notes that additional Implementation Guidance documents
can be drafted for any standard. Individual entities are encouraged to work with pre-qualified
organizations to submit additional Implementation Guidance for consideration of endorsement by the ERO.

•

Commenters noted the Implementation Guidance for CIP-012 does not address non-repudiation and,
therefore, integrity as defined by NIST 800-53, Revision 4, page B-6. The commenter requests that the SDT
provide additional implementation guidance regarding how the protections are required “…in a manner that
reflects the risks posed to bulk electric system reliability,” as stated on page 12 of FERC Order No. 822.
The SDT thanks you for the comments and has removed the example from the Implementation Guidance
document.

•

Commenters requested that the SDT consider consolidating Requirement R2 into Requirement R1, noting it
is unnecessary to have two requirements.
The SDT agrees with comments regarding a single requirement and has modified Requirement R1 and
updated the Implementation Guidance accordingly.

•

A commenter noted concerns related to mailbox or virtual RTUs used to communicate data between Control
Centers as a redundant method to, or in lieu, of ICCP. Some Entities may forget that such communication
could be in-scope of the standard especially if Real-time Assessment and Real-time monitoring and control
data is passed through these mailbox or virtual RTUs.
The SDT thanks you for the comments. As plans are developed, entities should be aware of the various
means that data is communicated between Control Centers and account for those means in the plan
document(s). The SDT notes that the Implementation Guidance is providing a small set of examples of
implementation. SDT notes that additional Implementation Guidance documents can be drafted for any
standard. Individual entities are encouraged to work with pre-qualified organizations to submit additional
Implementation Guidance for consideration of endorsement by the ERO.

•

A commenter noted concerns with the inclusion of “and control” in Requirement R1 and the Implementation
Guidance. They also questioned the need to identify roles and responsibilities for applying security
protections. They disagreed with including response in considering roles and responsibilities. They also
disagreed with specifying an encryption example (AES-128). They also recommended including guidance on
agreements with third parties handling data.
The SDT thanks you for the comments. The SDT notes that the Implementation Guidance is providing a
small set of examples of implementation. The SDT intended to provide some specific examples to aid
entities. Based on comments, the SDT removed “and control” and “roles” from Requirement R1 and the
Implementation Guidance. The SDT contends is it is necessary to document the responsibilities when
NERC | CIP-012 Consideration of Comments| March 2018
6

Consideration of Comments – Summary Responses

communication between Control Centers involves more than one entity and has left “responsibilities” in
Requirement R1 and the Implementation Guidance. The SDT removed the specific encryption example from
the Implementation Guidance. The SDT removed the example related to third parties from the
Implementation Guidance.
•

A commenter requested ERO endorsement of the Implementation Guidance before final ballot on CIP-012.
The SDT thanks you for the comment. The SDT is actively working with NERC staff to coordinate and gain
endorsement of the guidance in a timely manner.

•

One commenter noted a question of whether communication between a Control Center and associated data
centers would be in scope for CIP-012.
The SDT developed CIP-012 in response to FERC Order 822. Paragraph 58 of FERC Order 822 notes that the
requirement “should encompass communication links and data for intra-Control Center and inter-Control
Center communications.” Through discussions with FERC staff, the SDT came to understand that this
paragraph was intended to convey that the requirement should include communications between Control
Centers operated by a single entity (such as between a primary and backup Control Center) and
communications between Control Centers operated by neighboring entities (such as between a TOP and its
RC). The SDT notes that the Control Center by definition includes the associated data center and should,
therefore be included with protecting intra-Control Center communications. The SDT did not specify
protection for communication within a single Control Center as it did not intend to interfere or cause
unintended consequences with the inter-process communications that enable an EMS to function properly.

•

A commenter raised questions about data not currently determined to have a 15-minute impact and
therefore out of scope for CIP-002 thru CIP-011, e.g. synchrophasers data. The question if this data is out of
scope for CIP-012.
CIP-012 does not use the reference to 15-minute impact. If the data in question is used for Real-time
Assessment or Real-time monitoring, the data is in scope for CIP-012.

NERC | CIP-012 Consideration of Comments| March 2018
7

CIP-012-1 – Cyber Security – Communications between Control Centers

Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).

Description of Current Draft

This is the third draft of the proposed standard.
Completed Actions

Date

Standards Committee approved Standard Authorization Request
(SAR) for posting

March 9, 2016

SAR posted for comment

March 23 - April 21,
2016

SAR posted for comment

June 1 – June 30,
2016

Informal comment period

February 10- March
13, 2017

45-day formal comment period with initial ballot

July 27 – September
11, 2017

45-day formal comment period with additional ballot

October 27 –
December 11, 2017

45-day formal comment period with additional ballot

March 16 – April 30,
2018

Anticipated Actions

45-day formal comment period with additional ballot
10-day final ballot
NERC Board

Draft 3 of CIP-012-1
March 2018

Date

May 18 – July 2,
2018
July 30 – August 8,
2018
August 16, 2018

Page 1 of 6

CIP-012-1 – Cyber Security – Communications between Control Centers

A. Introduction
1.

Title: Cyber Security – Communications between Control Centers

2.

Number: CIP-012-1

3.

Purpose: To protect the confidentiality and integrity of Real-time Assessment and
Real-time monitoring data transmitted between Control Centers.

4.

Applicability:
4.1. Functional Entities: The requirements in this standard apply to the following
functional entities, referred to as “Responsible Entities,” that own or operate a
Control Center.
4.1.1. Balancing Authority
4.1.2. Generator Operator
4.1.3. Generator Owner
4.1.4. Reliability Coordinator
4.1.5. Transmission Operator
4.1.6. Transmission Owner
4.2. Exemptions: The following are exempt from Reliability Standard CIP-012-1:
4.2.1. Cyber Assets at Facilities regulated by the Canadian Nuclear Safety
Commission.
4.2.2. The systems, structures, and components that are regulated by the
Nuclear Regulatory Commission under a cyber security plan pursuant
to 10 C.F.R. Section 73.54.

5.

Effective Date: See Implementation Plan for CIP-012-1.

B. Requirements and Measures
R1.

The Responsible Entity shall implement one or more documented plan(s) to mitigate
the risk of unauthorized disclosure or modification of Real-time Assessment and Realtime monitoring data while being transmitted between any Control Centers. This
requirement excludes oral communications. The plan shall include: [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning]
1.1. Identification of security protection used to mitigate the risk of unauthorized
disclosure or modification of Real-time Assessment and Real-time monitoring
data while being transmitted between Control Centers;
1.2. Identification of where the Responsible Entity applied security protection for
transmitting Real-time Assessment and Real-time monitoring data between
Control Centers; and

Draft 3 of CIP-012-1
March 2018

Page 2 of 6

CIP-012-1 – Cyber Security – Communications between Control Centers

1.3. If the Control Centers are owned or operated by different Responsible Entities,
identify the responsibilities of each Responsible Entity for applying security
protection to the transmission of Real-time Assessment and Real-time
monitoring data between those Control Centers.
M1. Evidence may include, but is not limited to, documented plan(s) that meet the
security objective of Requirement R1 and documentation demonstrating the
implementation of the plan(s).

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority” (CEA)
means NERC, the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below
is shorter than the time since the last audit, the Compliance Enforcement
Authority may ask an entity to provide other evidence to show that it was
compliant for the full-time period since the last audit.
The Responsible Entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation.
•

The Responsible Entities shall keep data or evidence of each Requirement in
this Reliability Standard for three calendar years.

•

If a Responsible Entity is found non-compliant, it shall keep information
related to the non-compliance until mitigation is complete and approved or for
the time specified above, whichever is longer.

•

The Compliance Enforcement Authority shall keep the last audit records and
all requested and submitted subsequent audit records.

1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers
to the identification of the processes that will be used to evaluate data or
information for the purpose of assessing performance or outcomes with the
associated Reliability Standard.

Draft 3 of CIP-012-1
March 2018

Page 3 of 6

CIP-012-1 – Cyber Security – Communications between Control Centers

Violation Severity Levels
Violation Severity Levels

R#

R1.

Lower VSL

N/A

Moderate VSL

The Responsible Entity
documented its plan(s) but
failed to include one of the
applicable parts of the plan
as specified in Requirement
R1.

High VSL

The Responsible Entity
documented its plan(s) but
failed to include two of the
applicable parts of the plan
as specified in Requirement
R1.

Severe VSL

The Responsible Entity failed
to document plan(s) for
Requirement R1;
Or
The Responsible Entity failed
to implement any Part of its
plan(s) for Requirement R1,
except under CIP Exceptional
Circumstances.

D. Regional Variances
None.

E. Associated Documents
Implementation Plan.

Draft 3 of CIP-012-1
March 2018

Page 4 of 6

CIP-012-1 – Cyber Security – Communications between Control Centers

Version History
Version

Date

1

TBD

Draft 3 of CIP-012-1
March 2018

Action

Respond to FERC Order No. 822

Change
Tracking

N/A

Page 5 of 6

CIP-012-1 Supplemental Material

Standard Attachments
None.

Draft 3 of CIP-012-1
March 2018

Page 6 of 6

CIP-012-1 – Cyber Security – Communications between Control Centers

Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).

Description of Current Draft

This is the second third draft of the proposed standard.
Completed Actions

Date

Standards Committee approved Standard Authorization Request
(SAR) for posting

March 9, 2016

SAR posted for comment

March 23 - April 21,
2016

SAR posted for comment

June 1 – June 30,
2016

Informal comment period

February 10- March
13, 2017

45-day formal comment period with additional initial ballot

July 27 – September
11, 2017

45-day formal comment period with additional ballot

October 27 –
December 11, 2017

45-day formal comment period with additional ballot

TBDMarch 16 – April
30, 2018

Anticipated Actions

45-day formal comment period with additional ballot

Date

May 18 – July 2,
2018

10-day final ballot

TBDJuly 30 – August
8, 2018

NERC Board

TBDAugust 16, 2018

Draft 2 3 of CIP-012-1
January March 2018

Page 1 of 7

CIP-012-1 – Cyber Security – Communications between Control Centers

A. Introduction
1.

Title: Cyber Security – Communications between Control Centers

2.

Number: CIP-012-1

3.

Purpose: To protect the confidentiality and integrity of Real-time Assessment and
Real-time monitoring and control data transmitted between Control Centers.

4.

Applicability:
4.1. Functional Entities: The requirements in this standard apply to the following
functional entities, referred to as “Responsible Entities,” that own or operate a
Control Center.
4.1.1. Balancing Authority
4.1.2. Generator Operator
4.1.3. Generator Owner
4.1.4. Reliability Coordinator
4.1.5. Transmission Operator
4.1.6. Transmission Owner
4.2. Exemptions: The following are exempt from Reliability Standard CIP-012-1:
4.2.1. Cyber Assets at Facilities regulated by the Canadian Nuclear Safety
Commission.
4.2.2. The systems, structures, and components that are regulated by the
Nuclear Regulatory Commission under a cyber security plan pursuant
to 10 C.F.R. Section 73.54.

5.

Effective Date: See Implementation Plan for CIP-012-1.

B. Requirements and Measures
R1.

The Responsible Entity shall implement one or more documented plan(s) to mitigate
the risk of unauthorized disclosure or modification of Real-time Assessment and Realtime monitoring and control data while being transmitted between any Control
Centers. This requirement excludes oral communications. The plan shall include:
[Violation Risk Factor: Medium] [Time Horizon: Operations Planning]
1.1. Identification of security protection used to mitigate the risk of unauthorized
disclosure or modification of Real-time Assessment and Real-time monitoring
and control data while being transmitted between Control Centers;
1.2. Identification of demarcation point(s) where the Responsible Entity applied
security protection is applied for transmitting Real-time Assessment and Realtime monitoring and control data between Control Centers; and

Draft 2 3 of CIP-012-1
January March 2018

Page 2 of 7

CIP-012-1 – Cyber Security – Communications between Control Centers

1.3. If Identification of roles and responsibilities of each Responsible Entity for
applying security protection to the transmission of Real-time Assessment and
Real-time monitoring and control data between Control Centers, when the
Control Centers are owned or operated by different Responsible Entities,.
Iidentify the responsibilities of each Responsible Entity for applying security
protection to the transmission of Real-time Assessment and Real-time
monitoring data between those Control Centers.
M1. Evidence may include, but is not limited to, documented plan(s) that meet the
security objective of Requirement R1. and documentation demonstrating the
implementation of the plan(s).
R2. The Responsible Entity shall implement the plan(s) specified in Requirement R1,
except under CIP Exceptional Circumstances.
M2. Evidence may include, but is not limited to, documentation demonstrating
implementation of the plans developed pursuant to Requirement R1.

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority” (CEA)
means NERC, the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below
is shorter than the time since the last audit, the Compliance Enforcement
Authority may ask an entity to provide other evidence to show that it was
compliant for the full-time period since the last audit.
The Responsible Entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation.
•

The Responsible Entities shall keep data or evidence of each Requirement in
this Reliability Standard for three calendar years.

•

If a Responsible Entity is found non-compliant, it shall keep information
related to the non-compliance until mitigation is complete and approved or for
the time specified above, whichever is longer.

Draft 2 3 of CIP-012-1
January March 2018

Page 3 of 7

CIP-012-1 – Cyber Security – Communications between Control Centers

•

The Compliance Enforcement Authority (CEA) shall keep the last audit records
and all requested and submitted subsequent audit records.

1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers
to the identification of the processes that will be used to evaluate data or
information for the purpose of assessing performance or outcomes with the
associated Reliability Standard.

Draft 2 3 of CIP-012-1
January March 2018

Page 4 of 7

CIP-012-1 – Cyber Security – Communications between Control Centers

Violation Severity Levels
Violation Severity Levels

R#

R1.

R2.

Lower VSL

N/A

N/A

Moderate VSL

High VSL

Severe VSL

The Responsible Entity
documented its plan(s) but
failed to include one of the
applicable parts of the plan
as specified in Requirement
R1.

The Responsible Entity
documented its plan(s) but
failed to include two of the
applicable parts of the plan
as specified in Requirement
R1.

The Responsible Entity failed
to document plan(s) for
Requirement R1;.

N/A

N/A

The Responsible Entity failed
to implement its plan(s) as
specified in Requirement R1,
except under CIP Exceptional
Circumstances.

Or
The Responsible Entity failed
to implement any Part of its
plan(s) for Requirement R1,
except under CIP Exceptional
Circumstances.

D. Regional Variances
None.

E. Associated Documents
Implementation Plan.

Draft 32 of CIP-012-1
October March 20187

Page 5 of 7

CIP-012-1 – Cyber Security – Communications between Control Centers

Version History
Version

Date

1

TBD

Draft 32 of CIP-012-1
October March 20187

Action

Respond to FERC Order No. 822

Change
Tracking

N/A

Page 6 of 7

CIP-012-1 Supplemental Material

Standard Attachments
None.

Draft 2 3 of CIP-012-1
OctoberMarch 20187

Page 7 of 7

Implementation Plan

Project 2016-02 Modifications to CIP Standards
Reliability Standard CIP-012-1
Applicable Standard
•

Reliability Standard CIP-012-1 - Cyber Security – Communications between Control Centers

Requested Retirements
•

None

Prerequisite Standard

These standard(s) or definitions must be approved before the Applicable Standard becomes
effective:
•

None

Applicable Entities
•

Balancing Authority

•

Generator Operator

•

Generator Owner

•

Reliability Coordinator

•

Transmission Operator

•

Transmission Owner

Effective Date

Reliability Standard CIP-012-1 - Cyber Security – Communications between Control Centers
Where approval by an applicable governmental authority is required, Reliability Standard CIP-012-1
shall become effective on the first day of the first calendar quarter that is twenty-four (24) calendar
months after the effective date of the applicable governmental authority’s order approving the
standard, or as otherwise provided for by the applicable governmental authority.
Where approval by an applicable governmental authority is not required, Reliability Standard CIP012-1 shall become effective on the first day of the first calendar quarter that is twenty-four (24)
calendar months after the date the standard is adopted by the NERC Board of Trustees, or as
otherwise provided for in that jurisdiction.

Unofficial Comment Form

Project 2016-02 Modifications to CIP Standards
CIP-012-1
Do not use this form for submitting comments. Use the Standards Balloting and Commenting System
(SBS) to submit comments on CIP-012-1 – Cyber Security – Communications between Control Centers.
Comments must be submitted by 8 p.m. Eastern, Monday, April 30, 2018.
m. Eastern, Thursday, August 20, 2015
Additional information is available on the project page. If you have questions, contact Jordan Mallory at
(404) 446-2589 or Mat Bunch at (404) 446-9785.
Background Information

On January 21, 2016, the Commission issued Order No. 822, approving seven CIP Reliability Standards and
new or modified definitions, and directing modifications to the CIP Reliability Standards. Among others,
the Commission directed NERC to “develop modifications to the CIP Reliability Standards to require
responsible entities to implement controls to protect, at a minimum, communication links and sensitive
bulk electric system data communicated between bulk electric system Control Centers in a manner that is
appropriately tailored to address the risks posed to the bulk electric system by the assets being protected
(i.e., high, medium, or low impact).” (Order 822, Paragraph 53)
The Project 2016-02 Standard Drafting Team (SDT) drafted Reliability Standard CIP-012-1 to require
Responsible Entities to implement controls to protect sensitive Bulk Electric System (BES) data while being
transmitted over communications links between BES Control Centers. Due to the sensitivity of the data
being communicated between the Control Centers, the standard applies to all impact levels (i.e., high,
medium, or low impact).
The SDT drafted CIP-012-1 allowing Responsible Entities to apply protection to the links, the data, or both,
in order to satisfy the security objective consistent with the capabilities of the Responsible Entity’s
operational environment. Requirement R1 requires Responsible Entities to implement one or more
document plans that protect Real-time Assessment and Real-time monitoring data while being
transmitted between Control Centers. The plan(s) must address how the Responsible Entity will mitigate
the risk of unauthorized disclosure or modification of the applicable data.

Questions

1. Requirement R1: The SDT drafted CIP-012-1 Requirement R1 for the Responsible Entity to
implement one or more documented plan(s) to mitigate the risk of the unauthorized disclosure or
modification of Real-time Assessment and Real-time monitoring data while being transmitted
between any Control Centers. Do you agree with this revision? If not, please provide the basis for
your disagreement and an alternate proposal.
Yes
No
Comments:
2. Implementation Plan: The SDT established the Implementation Plan to make the standard
effective the first day of the first calendar quarter that is twenty-four (24) calendar months after
the effective date of the applicable governmental authority’s order approving the standard, or as
otherwise provided for by the applicable governmental authority. Do you agree with this
proposal? If you think an alternate implementation time period is needed, please provide a
detailed explanation of actions and time needed to meet the implementation deadline.
Yes
No
Comments:
3. The SDT modified the draft Technical Rationale and Justification for CIP-012 to assist in
understanding the technology and technical requirements in the Reliability Standard. It also
contains information on the SDT’s intent in drafting the requirements. Do you agree with the
technology and technical requirements in the draft Technical Rationale and Justification? If you do
not agree, or if you agree but have comments or suggestions for the draft Technical Rationale and
Justification, please provide your recommendation and explanation.
Yes
No
Comments:
4. The SDT modified the draft Implementation Guidance for CIP-012 to provide examples of how a
Responsible Entity could comply with the requirements. The draft Implementation Guidance does
not prescribe the only approach to compliance. Rather, it describes what the SDT believes would
be effective ways to comply with the standard. See NERC’s Compliance Guidance policy for
information on Implementation Guidance. Do you agree with the draft Implementation Guidance?

Unofficial Comment Form | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | March - April 2018

2

If you do not agree, or if you agree but have comments or suggestions for the draft
Implementation Guidance, please provide your recommendation and explanation.
Yes
No
Comments:
5. The SDT believes proposed CIP-012-1 provides entities with flexibility to meet the reliability
objectives in a cost effective manner. Do you agree? If you do not agree, or if you agree but have
suggestions for improvement to enable more cost effective approaches, please provide your
recommendation and, if appropriate, technical justification.
Yes
No
Comments:

Unofficial Comment Form | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | March - April 2018

3

Project 2016-02 Consideration of Issues and Directives
Federal Energy Regulatory Commission Order No. 822
March 2018

Directives from FERC Order No. 822
Paragraph
53

Directive Language

Consideration of Issue or Directive

53. As discussed in detail below, however, the
Commission concludes that modifications to CIP-006-6
to provide controls to protect, at a minimum,
communication links and data communicated
between bulk electric system Control Centers are
necessary in light of the critical role Control Center
communications play in maintaining bulk electric
system reliability. Therefore, we adopt the NOPR
proposal and direct that NERC, pursuant to section
215(d)(5) of the FPA, develop modifications to the CIP
Reliability Standards to require responsible entities to
implement controls to protect, at a minimum,
communication links and sensitive bulk electric system
data communicated between bulk electric system
Control Centers in a manner that is appropriately
tailored to address the risks posed to the bulk electric
system by the assets being protected (i.e., high,
medium, or low impact).

The Project 2016-02 Standard Drafting Team (SDT) drafted
Reliability Standard CIP-012-1 Requirement R1 to require
responsible entities to implement one or more documented
plan(s) to mitigate the risk of unauthorized disclosure or
modification of Real-time Assessment and Real-time
monitoring data while being transmitted between Bulk Electric
System (BES) Control Centers. Due to the sensitivity of the data
being transmitted between the Control Centers, the SDT
created the standard to apply to all impact levels of BES Cyber
Systems (i.e., high, medium, or low impact).
Based on operational risk, the SDT determined that Real-time
Assessments and Real-time monitoring data was the
appropriate scope of the requirement. This critical information
is necessary for immediate situational awareness and real-time
operation of the BES.
The SDT has drafted the requirement allowing Responsible
Entities the flexibility to apply protection to the

Directives from FERC Order No. 822
Paragraph

Directive Language

Consideration of Issue or Directive
communication links, the data, or both, consistent with their
operational environments to satisfy the security objective of
the Commission’s directive

54

54. NERC and other commenters recognize that interControl Center communications play a critical role in
maintaining bulk electric system reliability by, among
other things, helping to maintain situational awareness
and reliable bulk electric system operations through
timely and accurate communication between Control
Centers.59 We agree with this assessment. In order for
certain responsible entities such as reliability
coordinators, balancing authorities, and transmission
operators to adequately perform their reliability
functions, their associated control centers must be
capable of receiving and storing a variety of sensitive

Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

FERC Order No. 822 specifically references CIP-006-6, which
pertains to physical security controls. CIP-006-6, Requirement
R1, Part 1.10 focuses on protecting the nonprogrammable
communication components between Cyber Assets within the
same ESP for medium and high impact BES Cyber Systems. The
SDT asserts that most of the communications contemplated by
FERC Order No. 822 are not within the same ESP, and, as such,
CIP-006-6, Requirement R1, Part 1.10 would not be the
appropriate location for this requirement.
The SDT agrees that inter-Control Center communications play
a critical role in Bulk Electric System reliability. Responsible
Entities should therefore apply security measures to mitigate
the risk of unauthorized disclosure or modification of Realtime Assessment and Real-time monitoring data. Since the
current CIP Reliability Standards do not address this, the SDT
has designed the requirement to protect the data while it is
being transmitted between inter-entity and intra-entity
Control Centers.
The SDT has drafted a requirement that allows responsible
entities to apply protection to the communication links, the
2

Directives from FERC Order No. 822
Paragraph

Directive Language
bulk electric system data from interconnected entities.
Accordingly, we find that additional measures to protect
both the integrity and availability of sensitive bulk
electric system data are warranted.60 We also
understand that the attributes of the data managed by
responsible entities could require different information
protection controls. 61 For instance, certain types of
reliability data will be sensitive to data manipulation
type attacks, while other types of reliability data will be
sensitive to eavesdropping type attacks aimed at
collecting operational information (such as line and
equipment ratings and impedances). NERC should
consider the differing attributes of bulk electric system
data as it assesses the development of appropriate
controls.

Consideration of Issue or Directive
data, or both to satisfy the security objective consistent with
the capabilities of the responsible entity’s operational
environment.

Footnotes:
59 NERC Comments at 20.
60 Protecting the integrity of bulk electric system data
involves maintaining and ensuring the accuracy and
consistency of inter-Control Center communications.
Protecting the availability of bulk electric system data
involves ensuring that required data is available when
needed for bulk electric system operations.

Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

3

Directives from FERC Order No. 822
Paragraph

Directive Language

Consideration of Issue or Directive

Moreover, in order for certain responsible entities to
adequately perform their Reliability Functions, the
associated control centers must be capable of receiving
and storing a variety of sensitive data as specified by the
IRO and TOP Standards. For instance, pursuant to
Reliability Standard TOP-003-3, Requirements R1, R3
and R5, a transmission operator must maintain a
documented specification for data and distribute its
data specification to entities that have data required by
the transmission operator’s Operational Planning
Analyses, Real-time Monitoring and Real-time
Assessments. Entities receiving a data specification must
satisfy the obligation of the documented specification.
55. With regard to NERC’s development of modifications
responsive to our directive, we agree with NERC and
other commenters that NERC should have flexibility in
the manner in which it addresses the Commission’s
directive. Likewise, we find reasonable the principles
outlined by NERC that protections for communication
links and sensitive bulk electric system data
communicated between bulk electric system Control
Centers: (1) should not have an adverse effect on
reliability, including the recognition of instances where
the introduction of latency could have negative results;
(2) should account for the risk levels of assets and

The SDT drafted Reliability Standard CIP-012-1 to mitigate the
risk of unauthorized disclosure or modification of Real-time
Assessments and Real-time monitoring data while being
transmitted between Control Centers. The SDT developed and
objective-based rather than prescriptive requirement. This
approach will allow Responsible Entities flexibility in protecting
these communications networks and sensitive BES data in a
manner suited to each of their respective operational
environments. It will also allow Responsible Entities to
implement protection that considers the risks noted by the
Commission. The SDT identified a need to mitigate the risk of
unauthorized disclosure or modification of Real-time Assessment

61

55

Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

4

Directives from FERC Order No. 822
Paragraph

56

Directive Language

Consideration of Issue or Directive

information being protected, and require protections
that are commensurate with the risks presented; and (3)
should be results-based in order to provide flexibility to
account for the range of technologies and entities
involved in bulk electric system communications.62

and Real-time monitoring data regardless of asset risk level. The
proposal requires protection for all Real-time Assessment and
Real-time monitoring data while being transmitted between
Control Centers.

Footnote:
62 See NERC Comments at 20-21.
56. We disagree with the assertion of NIPSCO and
G&T Cooperatives that the risk posed by bulk electric
system communication networks does not justify the
costs of implementing controls. Communications
between Control Centers over such networks are
fundamental to the operations of the bulk electric
system, and the record here does not persuade us
that controls for such networks are not available at a
reasonable cost (through encryption or otherwise).
Nonetheless, we recognize that not all communication
network components and data pose the same risk to
bulk electric system reliability and may not require the
same level of protection. We expect NERC to develop
controls that reflect the risk posed by the asset or
data being protected, and that can be implemented in
a reasonable manner. It is important to recognize that
certain entities are already required to exchange

Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

The SDT noted the FERC reference to additional Reliability
Standards (TOP-003-3 and IRO-010-2) and the responsibilities to
protect the data in accordance with those standards. The SDT
interpreted these references as examples of potentially
sensitive BES data and chose to base the CIP-012 requirements
on the data specifications in TOP-003-3 and IRO-010-2. This
consolidates scoping and helps ensure that Responsible Entities
mitigate the risk of the unauthorized disclosure or modification
of Real-time Assessment and Real-time monitoring data, rather
than leaving the scoping of sensitive bulk electric system data to
individual Responsible Entities.
The SDT drafted CIP-012-1 to address confidentiality and
integrity of Real-time Assessment and Real-time monitoring
data. This was accomplished by drafting the requirement to
mitigate the risk from unauthorized disclosure or modification.
The SDT asserts that the availability of this data is already
5

Directives from FERC Order No. 822
Paragraph

Directive Language
necessary real-time and operational planning data
through secured networks using a “mutually
agreeable security protocol,” regardless of the entity’s
size or impact level.63 NERC’s response to the
directives in this Final Rule should identify the scope
of sensitive bulk electric system data that must be
protected and specify how the confidentiality,
integrity, and availability of each type of bulk electric
system data should be protected while it is being
transmitted or at rest.

58

Footnote:
63 See Reliability Standards TOP-003-3, Requirement
R5 and IRO-010-2, Requirement R3.
58. Several commenters sought clarification whether
Control Centers owned by multiple registered entities
would be included under the Commission’s proposal.
We clarify that the scope of the directed modifications
apply to Control Center communications from
facilities at all impact levels, regardless of ownership.
The directed modification should encompass
communication links and data for intra-Control Center
and inter-Control Center communications.

Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

Consideration of Issue or Directive
required by the performance obligation of the TOP and IRO
Reliability Standards.
The SDT drafted CIP-012-1 to address the data while being
transmitted. The SDT contends that this data is maintained
within BES Cyber Systems, and is afforded the protections of
CIP-003 through CIP-011 while at rest.

The SDT drafted CIP-012-1 to apply to all impact levels of BES
Cyber Systems (i.e., high, medium, or low impact), regardless of
ownership. The SDT designed the requirement to mitigate the
risk of unauthorized disclosure or modification of Real-time
Assessment and Real-time monitoring data while being
transmitted between inter-entity and intra-entity BES Control
Centers.

6

Directives from FERC Order No. 822
Paragraph
62

Directive Language

Consideration of Issue or Directive

62. Several commenters addressed encryption and
latency. Based on the record in this proceeding, it is
reasonable to conclude that any lag in communication
speed resulting from implementation of protections
should only be measureable on the order of
milliseconds and, therefore, will not adversely impact
Control Center communications. Several commenters
raise possible technical implementation difficulties
with integrating encryption technologies into their
current communications networks. Such technical
issues should be considered by the standard drafting
team when developing modifications in response to
this directive, and may be resolved, e.g., by making
certain aspects of the revised CIP Standards eligible
for Technical Feasibility Exceptions.

The SDT developed an objective-based rather than prescriptive
requirement. This approach will allow Responsible Entities
flexibility in mitigating the risk of unauthorized disclosure or
modification of Real-time Assessments and Real-time
monitoring data in a manner suited to each of their respective
operational environments. It will also allow Responsible Entities
to implement protection that considers the risks noted by the
Commission.

Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

7

Project 2016-02 Consideration of Issues and Directives
Federal Energy Regulatory Commission Order No. 822
October 27March, 20187

Directives from FERC Order No. 822
Paragraph
53

Directive Language
53. As discussed in detail below, however, the
Commission concludes that modifications to CIP-006-6
to provide controls to protect, at a minimum,
communication links and data communicated
between bulk electric system Control Centers are
necessary in light of the critical role Control Center
communications play in maintaining bulk electric
system reliability. Therefore, we adopt the NOPR
proposal and direct that NERC, pursuant to section
215(d)(5) of the FPA, develop modifications to the CIP
Reliability Standards to require responsible entities to
implement controls to protect, at a minimum,
communication links and sensitive bulk electric system
data communicated between bulk electric system
Control Centers in a manner that is appropriately
tailored to address the risks posed to the bulk electric
system by the assets being protected (i.e., high,
medium, or low impact).

Consideration of Issue or Directive
The Project 2016-02 Standard Drafting Team (SDT) drafted
Reliability Standard CIP-012-1 Requirement R1 to require
responsible entities to implement document one or more
documented plan(s) to mitigate the risk of unauthorized
disclosure or modification of Real-time Assessment and Realtime monitoring and control data while being transmitted
between Bulk Electric System (BES) Control Centers.
Requirement R2 requires implementation of the documented
plan(s). Due to the sensitivity of the data being transmitted
between the Control Centers, the SDT created the standard to
apply to all impact levels of BES Cyber Systems (i.e., high,
medium, or low impact).
Based on operational risk, the SDT determined that Real-time
Assessments and Real-time monitoring and control data was
the appropriate scope of the requirement. This critical
information is necessary for immediate situational awareness
and real-time operation of the BES.

Directives from FERC Order No. 822
Paragraph

Directive Language

Consideration of Issue or Directive
The SDT has drafted requirements the requirement allowing
Responsible Entities the flexibility to apply protection to the
communication links, the data, or both, consistent with their
operational environments to satisfy the security objective of
the Commission’s directive

54

54. NERC and other commenters recognize that interControl Center communications play a critical role in
maintaining bulk electric system reliability by, among
other things, helping to maintain situational awareness
and reliable bulk electric system operations through
timely and accurate communication between Control
Centers.59 We agree with this assessment. In order for
certain responsible entities such as reliability
coordinators, balancing authorities, and transmission
operators to adequately perform their reliability

Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

FERC Order No. 822 specifically references CIP-006-6, which
pertains to physical security controls. CIP-006-6, Requirement
R1, Part 1.10 focuses on protecting the nonprogrammable
communication components between Cyber Assets within the
same ESP for medium and high impact BES Cyber Systems. The
SDT asserts that most of the communications contemplated by
FERC Order No. 822 are not within the same ESP, and, as such,
CIP-006-6, Requirement R1, Part 1.10 would not be the
appropriate location for this requirement.
The SDT agrees that inter-Control Center communications play
a critical role in Bulk Electric System reliability. Responsible
Entities should therefore apply security measures to mitigate
the risk of unauthorized disclosure or modification of Realtime Assessment and Real-time monitoring and control data.
Since the current CIP Reliability Standards do not address this,
the SDT has designed the requirement requirements to protect
the data while it is being transmitted between inter-entity and
intra-entity Control Centers.

2

Directives from FERC Order No. 822
Paragraph

Directive Language
functions, their associated control centers must be
capable of receiving and storing a variety of sensitive
bulk electric system data from interconnected entities.
Accordingly, we find that additional measures to protect
both the integrity and availability of sensitive bulk
electric system data are warranted.60 We also
understand that the attributes of the data managed by
responsible entities could require different information
protection controls. 61 For instance, certain types of
reliability data will be sensitive to data manipulation
type attacks, while other types of reliability data will be
sensitive to eavesdropping type attacks aimed at
collecting operational information (such as line and
equipment ratings and impedances). NERC should
consider the differing attributes of bulk electric system
data as it assesses the development of appropriate
controls.

Consideration of Issue or Directive
The SDT has drafted requirements a requirement that allows
responsible entities to apply protection to the communication
links, the data, or both to satisfy the security objective
consistent with the capabilities of the responsible entity’s
operational environment.

Footnotes:
59 NERC Comments at 20.
60 Protecting the integrity of bulk electric system data
involves maintaining and ensuring the accuracy and
consistency of inter-Control Center communications.
Protecting the availability of bulk electric system data

Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

3

Directives from FERC Order No. 822
Paragraph

55

Directive Language

Consideration of Issue or Directive

involves ensuring that required data is available when
needed for bulk electric system operations.
61 Moreover, in order for certain responsible entities to
adequately perform their Reliability Functions, the
associated control centers must be capable of receiving
and storing a variety of sensitive data as specified by the
IRO and TOP Standards. For instance, pursuant to
Reliability Standard TOP-003-3, Requirements R1, R3
and R5, a transmission operator must maintain a
documented specification for data and distribute its
data specification to entities that have data required by
the transmission operator’s Operational Planning
Analyses, Real-time Monitoring and Real-time
Assessments. Entities receiving a data specification must
satisfy the obligation of the documented specification.
55. With regard to NERC’s development of modifications
responsive to our directive, we agree with NERC and
other commenters that NERC should have flexibility in
the manner in which it addresses the Commission’s
directive. Likewise, we find reasonable the principles
outlined by NERC that protections for communication
links and sensitive bulk electric system data
communicated between bulk electric system Control
Centers: (1) should not have an adverse effect on
reliability, including the recognition of instances where

The SDT drafted Reliability Standard CIP-012-1 requirements to
mitigate the risk of unauthorized disclosure or modification of
Real-time Assessments and Real-time monitoring and control
data while being transmitted between Control Centers. The SDT
developed and objective-based rather than prescriptive
requirements. This approach will allow Responsible Entities
flexibility in protecting these communications networks and
sensitive BES data in a manner suited to each of their respective
operational environments. It will also allow Responsible Entities
to implement protection that considers the risks noted by the

Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

4

Directives from FERC Order No. 822
Paragraph

56

Directive Language

Consideration of Issue or Directive

the introduction of latency could have negative results;
(2) should account for the risk levels of assets and
information being protected, and require protections
that are commensurate with the risks presented; and (3)
should be results-based in order to provide flexibility to
account for the range of technologies and entities
involved in bulk electric system communications.62

Commission. The SDT identified a need to mitigate the risk of
unauthorized disclosure or modification of Real-time Assessment
and Real-time monitoring and control data regardless of asset
risk level. The proposal requires protection for all Real-time
Assessment and Real-time monitoring and control data while
being transmitted between Control Centers.

Footnote:
62 See NERC Comments at 20-21.
56. We disagree with the assertion of NIPSCO and
G&T Cooperatives that the risk posed by bulk electric
system communication networks does not justify the
costs of implementing controls. Communications
between Control Centers over such networks are
fundamental to the operations of the bulk electric
system, and the record here does not persuade us
that controls for such networks are not available at a
reasonable cost (through encryption or otherwise).
Nonetheless, we recognize that not all communication
network components and data pose the same risk to
bulk electric system reliability and may not require the
same level of protection. We expect NERC to develop
controls that reflect the risk posed by the asset or
data being protected, and that can be implemented in

Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

The SDT noted the FERC reference to additional Reliability
Standards (TOP-003-3 and IRO-010-2) and the responsibilities to
protect the data in accordance with those standards. The SDT
interpreted these references as examples of potentially
sensitive BES data and chose to base the CIP-012 requirements
on the data specifications in TOP-003-3 and IRO-010-2... This
consolidates scoping and helps ensure that Responsible Entities
mitigate the risk of the unauthorized disclosure or modification
of Real-time Assessment and Real-time monitoring and control
data, rather than leaving the scoping of sensitive bulk electric
system data to individual Responsible Entities.
The SDT drafted CIP-012-1 to address confidentiality and
integrity of Real-time Assessment and Real-time monitoring and
control data. This was accomplished by drafting the
5

Directives from FERC Order No. 822
Paragraph

58

Directive Language

Consideration of Issue or Directive

a reasonable manner. It is important to recognize that
certain entities are already required to exchange
necessary real-time and operational planning data
through secured networks using a “mutually
agreeable security protocol,” regardless of the entity’s
size or impact level.63 NERC’s response to the
directives in this Final Rule should identify the scope
of sensitive bulk electric system data that must be
protected and specify how the confidentiality,
integrity, and availability of each type of bulk electric
system data should be protected while it is being
transmitted or at rest.

requirement to mitigate the risk from unauthorized disclosure
or modification. The SDT asserts that the availability of this data
is already required by the performance obligation of the TOP
and IRO Reliability Standards.

Footnote:
63 See Reliability Standards TOP-003-3, Requirement
R5 and IRO-010-2, Requirement R3.
58. Several commenters sought clarification whether
Control Centers owned by multiple registered entities
would be included under the Commission’s proposal.
We clarify that the scope of the directed modifications
apply to Control Center communications from
facilities at all impact levels, regardless of ownership.
The directed modification should encompass
communication links and data for intra-Control Center
and inter-Control Center communications.

Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

The SDT drafted CIP-012-1 to address the data while being
transmitted. The SDT contends that this data is maintained
within BES Cyber Systems, and is afforded the protections of
CIP-003 through CIP-011 while at rest.

The SDT drafted CIP-012-1 to apply to all impact levels of BES
Cyber Systems (i.e., high, medium, or low impact), regardless of
ownership. The SDT designed requirements the requirement to
mitigate the risk of unauthorized disclosure or modification of
Real-time Assessment and Real-time monitoring and control
data while being transmitted between inter-entity and intraentity BES Control Centers.

6

Directives from FERC Order No. 822
Paragraph
62

Directive Language

Consideration of Issue or Directive

62. Several commenters addressed encryption and
latency. Based on the record in this proceeding, it is
reasonable to conclude that any lag in communication
speed resulting from implementation of protections
should only be measureable on the order of
milliseconds and, therefore, will not adversely impact
Control Center communications. Several commenters
raise possible technical implementation difficulties
with integrating encryption technologies into their
current communications networks. Such technical
issues should be considered by the standard drafting
team when developing modifications in response to
this directive, and may be resolved, e.g., by making
certain aspects of the revised CIP Standards eligible
for Technical Feasibility Exceptions.

The SDT developed an objective-based rather than prescriptive
requirements. This approach will allow Responsible Entities
flexibility in mitigating the risk of unauthorized disclosure or
modification of Real-time Assessments and Real-time
monitoring data in a manner suited to each of their respective
operational environments. It will also allow Responsible Entities
to implement protection that considers the risks noted by the
Commission.

Consideration of Issues and Directives
Project 2016-02 Modifications to CIP Standards

7

Violation Risk Factor and Violation Severity Level
Justifications
Project 2016-02 Modifications to CIP Standards

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in CIP-012-1. Each requirement is assigned a VRF and a VSL. These elements support the determination of
an initial value range for the Base Penalty Amount regarding violations of requirements in FERC-approved Reliability Standards, as defined in
the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT applied the following NERC criteria and FERC Guidelines when
developing the VRFs and VSLs for the requirements.

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•

Emergency operations

•

Vegetation management

•

Operator personnel training

•

Protection systems and their coordination

•

Operating tools and backup facilities

•

Reactive power and voltage control

•

System modeling and data exchange

•

Communication protocol and facilities

•

Requirements to determine equipment ratings

•

Synchronized data recorders

•

Clearer criteria for operationally critical facilities

•

Appropriate use of transmission loading relief.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | March 2018

2

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | March 2018

3

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL

Moderate VSL

The performance or product
measured almost meets the full
intent of the requirement.

The performance or product
measured meets the majority of
the intent of the requirement.

High VSL

The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet
some of the intent.

Severe VSL

The performance or product
measured does not
substantively meet the intent of
the requirement.

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | March 2018

4

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justifications for CIP-012-1, Requirement R1

Proposed VRF

Medium

NERC VRF Discussion

A VRF of Medium was assigned to this requirement. Cyber security plans enable effective implementation
of the CIP standard’s requirements to mitigate the risk of the unauthorized disclosure or modification of
data used for Real-time Assessments and Real-time monitoring while being transmitted between Control
Centers.

FERC VRF G1 Discussion

N/A

Guideline 1- Consistency
with Blackout Report
FERC VRF G2 Discussion

N/A

Guideline 2- Consistency
within a Reliability Standard
FERC VRF G3 Discussion
Guideline 3- Consistency
among Reliability Standards
FERC VRF G4 Discussion
Guideline 4- Consistency
with NERC Definitions of
VRFs
FERC VRF G5 Discussion

The requirement complements CIP-005-1, Requirement R1, CIP-006-6, Requirement R1, and CIP-007-6,
Requirement R1 which are related to security of networks and communications components. The
proposed VRF is consistent with these related requirements.
Failure to have a cyber security plan would not, under Emergency, abnormal, or restorative conditions
anticipated by the preparations, be expected to adversely affect the electrical state or capability of the
Bulk Electric System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

N/A

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | March 2018

5

VRF Justifications for CIP-012-1, Requirement R1

Proposed VRF

Medium

Guideline 5- Treatment of
Requirements that Comingle More than One
Obligation
VSLs for CIP-012-1, Requirement R1

Lower
N/A

Moderate
The Responsible Entity
documented its plan(s) but
failed to include one of the
applicable parts of the plan as
specified in Requirement R1.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | March 2018

High
The Responsible Entity
documented its plan(s) but
failed to include two of the
applicable parts of the plan as
specified in Requirement R1.

Severe
The Responsible Entity failed to
document plan(s) for
Requirement R1;
Or
The Responsible Entity failed to
implement any Part of its plan(s)
for Requirement R1, except
under CIP Exceptional
Circumstances.

6

VSL Justifications for CIP-012-1 Requirements R1

FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency
in the Determination of
Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent

The requirement is new. Therefore, the proposed VSL does not have the unintended consequence of
lowering the level of compliance.

The requirement is for the Responsible Entity to implement one or more documented plan(s) as specified
in Requirement R1.
The moderate VSL addresses where the Responsible Entity documented its plan(s) but failed to include
one of the applicable parts of the plan as specified in Requirement R1.
The high VSL addresses where the Responsible Entity documented its plan(s) but failed to include two of
the applicable parts of the plan as specified in Requirement R1.
The severe VSL addresses where the Responsible Entity failed to document plan(s) for Requirement R1, or
where the Responsible Entity failed to implement plan(s) for Requirement R1.

Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement

The proposed VSL uses the same terminology as used in the associated requirement and is, therefore,
consistent with the requirement.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | March 2018

7

FERC VSL G4

Each VSL is based on a single violation and not cumulative violations.

Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | March 2018

8

Violation Risk Factor and Violation Severity Level
Justifications
Project 2016-02 Modifications to CIP Standards

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in CIP-012-1. Each requirement is assigned a VRF and a VSL. These elements support the determination of
an initial value range for the Base Penalty Amount regarding violations of requirements in FERC-approved Reliability Standards, as defined in
the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT applied the following NERC criteria and FERC Guidelines when
developing the VRFs and VSLs for the requirements.

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•

Emergency operations

•

Vegetation management

•

Operator personnel training

•

Protection systems and their coordination

•

Operating tools and backup facilities

•

Reactive power and voltage control

•

System modeling and data exchange

•

Communication protocol and facilities

•

Requirements to determine equipment ratings

•

Synchronized data recorders

•

Clearer criteria for operationally critical facilities

•

Appropriate use of transmission loading relief.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | October 2017March 2018

2

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | October 2017March 2018

3

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL

Moderate VSL

The performance or product
measured almost meets the full
intent of the requirement.

The performance or product
measured meets the majority of
the intent of the requirement.

High VSL

The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet
some of the intent.

Severe VSL

The performance or product
measured does not
substantively meet the intent of
the requirement.

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | October 2017March 2018

4

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justifications for CIP-012-1, Requirement R1

Proposed VRF

Medium

NERC VRF Discussion

A VRF of Medium was assigned to this requirement. Cyber security plans enable effective implementation
of the CIP standard’s requirements to mitigate the risk of the unauthorized disclosure or modification of
data used for Real-time Assessments and Real-time monitoring while being transmitted between Control
Centers.

FERC VRF G1 Discussion

N/A

Guideline 1- Consistency
with Blackout Report
FERC VRF G2 Discussion

N/A

Guideline 2- Consistency
within a Reliability Standard
FERC VRF G3 Discussion
Guideline 3- Consistency
among Reliability Standards
FERC VRF G4 Discussion
Guideline 4- Consistency
with NERC Definitions of
VRFs
FERC VRF G5 Discussion

The requirement complements CIP-005-1, Requirement R1, CIP-006-6, Requirement R1, and CIP-007-6,
Requirement R1 which are related to security of networks and communications components. The
proposed VRF is consistent with these related requirements.
Failure to have a cyber security plan would not, under Emergency, abnormal, or restorative conditions
anticipated by the preparations, be expected to adversely affect the electrical state or capability of the
Bulk Electric System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

N/A

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | October 2017March 2018

5

VRF Justifications for CIP-012-1, Requirement R1

Proposed VRF

Medium

Guideline 5- Treatment of
Requirements that Comingle More than One
Obligation
VSLs for CIP-012-1, Requirement R1

Lower
N/A

Moderate
The Responsible Entity
documented its plan(s) but
failed to include one of the
applicable parts of the plan as
specified in Requirement R1.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | October 2017March 2018

High
The Responsible Entity
documented its plan(s) but
failed to include two of the
applicable parts of the plan as
specified in Requirement R1.

Severe
The Responsible Entity failed to
document plan(s) for
Requirement R1;
Or
The Responsible Entity failed to
implement any Part of its plan(s)
for Requirement R1, except
under CIP Exceptional
Circumstances.

6

VSL Justifications for CIP-012-1 Requirements R1

FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency
in the Determination of
Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent

The requirement is new. Therefore, the proposed VSL does not have the unintended consequence of
lowering the level of compliance.

The requirement is for the Responsible Entity to implement one or more documented plan(s) as specified
in Requirement R1.
The moderate VSL addresses where the Responsible Entity documented its plan(s) but failed to include
one of the applicable parts of the plan as specified in Requirement R1.
The high VSL addresses where the Responsible Entity documented its plan(s) but failed to include two of
the applicable parts of the plan as specified in Requirement R1.
The severe VSL addresses where the Responsible Entity failed to document plan(s) for Requirement R1, or
where the Responsible Entity failed to implement plan(s) for Requirement R1..

Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement

The proposed VSL uses the same terminology as used in the associated requirement and is, therefore,
consistent with the requirement.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | October 2017March 2018

7

FERC VSL G4

Each VSL is based on a single violation and not cumulative violations.

Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | October 2017March 2018

8

DRAFT

Cyber Security –
Communications Between
Control Centers
Implementation Guidance for CIP-012-1
March 2018

NERC | Report Title | Report Date
I

Table of Contents
Introduction ................................................................................................................................................................3
Requirements .............................................................................................................................................................4
General Considerations ..............................................................................................................................................5
Identification of Security Protection ...................................................................................................................5
Identification of Where Security Protection is Applied by the Responsible Entity ............................................5
Reference Model ........................................................................................................................................................7
Reference Model Discussion ...............................................................................................................................7
Identification of Security Protection ...................................................................................................................8
Identification of Where Security Protection is Applied by the Responsible Entity.............................................9
Identification of Responsibilities when the Control Centers are Owned or Operated by Different Responsible
Entities.................................................................................................................................................................9
References ............................................................................................................................................................... 12

NERC | DRAFT CIP-012-1 Implementation Guidance | March 2018
2

Introduction
The Project 2016-02 SDT drafted this Implementation Guidance to provide example approaches for compliance
with CIP-012-1. Implementation Guidance does not prescribe the only approach, but highlights one or more
approaches that would be effective in achieving compliance with the standard. Because Implementation Guidance
only provides examples, entities may choose alternative approaches that better fit their individual situations 1.
Responsible Entities may find it useful to consider this Implementation Guidance document along with the
additional context and background provided in the SDT-developed Technical Rationale and Justification for CIP012-1 document.

Background

The Commission issued Order No. 822 on January 21, 2016. Order 822 approving seven CIP Reliability Standards
and new or modified definitions, and directed modifications be made to the CIP Reliability Standards. Among
other items, the Commission directed NERC to “develop modifications to the CIP Reliability Standards to require
responsible entities to implement controls to protect, at a minimum, communication links and sensitive bulk
electric system data communicated between bulk electric system Control Centers in a manner that is
appropriately tailored to address the risks posed to the bulk electric system by the assets being protected (i.e.,
high, medium, or low impact).” (Order 822, Paragraph 53)
In response to the directive in Order No. 822, the Project 2016-02 standard drafting team (SDT) drafted Reliability
Standard CIP-012-1 to require Responsible Entities to implement controls to protect sensitive Bulk Electric System
(BES) data and communications links between BES Control Centers. Due to the sensitivity of the data being
communicated between Control Centers, the standard applies to all impact levels (i.e., high, medium, or low
impact).
The SDT drafted requirements to provide Responsible Entities the latitude to protect the communication links,
the data, or both, to satisfy the security objective consistent with the capabilities of the Responsible Entity’s
operational environment.

1

NERC’s Compliance Guidance Policy
NERC | DRAFT CIP-012-1 Implementation Guidance | March 2018
3

Requirements
R1.

The Responsible Entity shall implement one or more documented plan(s) to mitigate the risk
of unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring
data while being transmitted between any Control Centers. This requirement excludes oral
communications. The plan shall include: [Violation Risk Factor: Medium] [Time Horizon:
Operations Planning]
1.1. Identification of security protection used to mitigate the risk of unauthorized disclosure
or modification of Real-time Assessment and Real-time monitoring data while being
transmitted between Control Centers;
1.2. Identification of where the Responsible Entity applied security protection for transmitting
Real-time Assessment and Real-time monitoring and control data between Control
Centers; and
1.3. If the Control Centers are owned or operated by different Responsible Entities, identify
the responsibilities of each Responsible Entity for applying security protection to the
transmission of Real-time Assessment and Real-time monitoring data between those
Control Centers.

NERC | DRAFT CIP-012-1 Implementation Guidance | March 2018
4

General Considerations
Plan Development
As noted in the Technical Rationale and Justification for CIP-012-1, the focus of Requirement R1 is implementing
a documented plan to protect information that is critical to the real-time operations of the Bulk Electric System
while in transit between applicable Control Centers. The number of plan(s) and their content may vary
depending on a Responsible Entity's management structure and operating conditions. The Responsible Entity
may document as many plans as necessary to meet its needs. For instance, a Responsible Entity may choose to
document one plan per Control Center or choose an all-inclusive, single plan for its Control Center
communication environment. A Responsible Entity may choose to document one plan for communications
between Control Centers it owns and a separate plan for communications between its Control Centers and the
Control Centers of a neighboring Entity. The number and structure of the plans is at the discretion of the
Responsible Entity as long as the plan(s) include the required elements described in parts 1.1, 1.2, and 1.3 of
Requirement R1.
Identification of Security Protection
Entities have latitude to identify and choose which security protection is used to mitigate the risk of
unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring data while being
transmitted between Control Centers.
This security protection could consist of logical protection, physical protection, or some combination of both. To
determine security protection, the requirement specifies that it must mitigate the risk of unauthorized disclosure
or modification of applicable data.
Security protection implementation can be demonstrated in many ways. If a Responsible Entity uses physical
protection, it may demonstrate implementation through review of an applicable Control Center floor plan with
details subsequently confirmed through visual inspection, which identifies the physical security measures in
place protecting the communication link. If the Responsible Entity uses logical protection, it may demonstrate
implementation through an export of the device configuration which applies the security protection.
Alternatively, a Responsible Entity may demonstrate implementation through security control monitoring, using
an automated monitoring tool to generate reports on the encryption service used to protect a communications
link.
Identification of Where Security Protection is Applied by the Responsible Entity
A Responsible Entity should consider its environment when identifying where security protections should be
applied. One approach is to implement security within the Control Center itself to ensure that data
confidentiality and integrity is protected throughout the transmission. The Responsible Entity can identify where
security protection is applied using a logical or physical location The application of security in accordance with
CIP-012 requirements does not add additional assets to the scope of the CIP Reliability Standards. Locations of
applied security protection may vary based on many factors such as impact levels of the Control Center,
different technologies, or infrastructures.
Identification of where a Responsible Entity applies security protection could be demonstrated with a list or a
Control Center diagram showing either physical or logical security controls. Physical diagrams may require visual
confirmation of these controls. These diagrams or a list could be included within the plan developed for R1. A
Responsible Entity could also use labels to identify on-site devices where CIP-012 security protection is applied.
When exchanging data between two entities, if a Responsible Entity only manages one end of a communication
link, the Responsible Entity is not responsible for identifying where the security protection is applied by the
neighboring entity with whom it is exchanging data. However, if a Responsible Entity has taken responsibility for
NERC | DRAFT CIP-012-1 Implementation Guidance | March 2018
5

both ends of the communication link (such as by placing a router within the neighboring entity’s data center),
then the Responsible Entity shall identify where the security protection is applied at both ends of the link.
Similarly, if a Responsible Entity owns and operates both Control Centers which are exchanging data (such as in
the case of a primary and backup Control Center), then the Responsible Entity shall identify where security
protection is applied at both ends of the link.
Identification of Responsibilities when the Control Centers are Owned or Operated by Different
Responsible Entities

The Technical Rationale and Justification for CIP-012-1 identifies key considerations in the Control Center
Ownership section when communications between Control Centers with different owners or operators. Many
operational relationships between Responsible Entities are unique. Consequently, there is no single way to
identify responsibilities for applying security protection to the transmission of Real-time Assessment and Realtime monitoring data between Control Centers.
Implementation of responsibilities could also be demonstrated in many ways. Some examples include a joint
procedure, a memorandum of understanding, or meeting minutes between the two parties where
responsibilities are defined.

NERC | DRAFT CIP-012-1 Implementation Guidance | March 2018
6

Reference Model
For this Implementation Guidance, the SDT uses a basic reference model of Primary and Backup Control Centers
(Entity Alpha) to illustrate approaches to demonstrating compliance. These Control Centers communicate to
each other and to a neighboring entity’s Control Center (Entity Beta) in configurations outlined by the diagrams
in this section. The SDT recognizes that the reference model does not contain many of the complexities of a real
Control Center. For this Implementation Guidance, the registration or functions performed in the reference
model Control Center are also not considered. A high level block diagram of the basic reference model is shown
below in Figure 1. This Implementation Guidance is developed from the perspective of Entity Alpha.

Entity Alpha’s Primary
Control Center

Communication between Entity Alpha’s
Primary and Backup Control Center

Communication between Entity Alpha’s
Primary Control Center and Entity Beta’s Control Center

Entity Alpha’s Backup
Control Center

Communication between Entity Alpha’s
Backup Control Center and Entity Beta’s Control Center

Entity Beta’s Control
Center

Figure 1: High Level Block Diagram of Reference Model Control Centers

Reference Model Discussion
Requirement R1 requires the implementation of a documented plan. To comply with requirement R1, one
approach to a plan is to first determine which communications are in scope of CIP-012-1. There are multiple
ways to identify an entity’s scope in R1. For example, Entity Alpha in the reference model may first identify the
Control Centers with which it communicates. Entity Alpha would determine that there are three: Entity Alpha’s
Primary Control Center, Entity Alpha’s Backup Control Center, and Entity Beta’s Control Center. Entity Alpha
does not need to consider whether Entity Beta further shares its data with another Entity. That is the
responsibility of Entity Beta and is outside of Entity Alpha’s purview. Additionally, Entity Alpha does not need to
consider any communications to other non-Control Center facilities such as generating plants or substations.
These communications are out of scope for CIP-012-1.
Now that Entity Alpha has identified the Control Centers with which it communicates, Entity Alpha identifies
either: (1) the Real-time Assessment and Real-time monitoring data; or (2) communication links which are used
to transmit Real-time Assessment and Real-time monitoring data between Control Centers. In either case, Entity
Alpha should refer to the data specification for Real-time Assessment and Real-time monitoring data identified
NERC | DRAFT CIP-012-1 Implementation Guidance | March 2018
7

in TOP-003-3 and IRO-010-2. For this reference model scenario, identifying the communication links used to
transmit Real-time Assessment and Real-time monitoring data may be the most straightforward approach.
Through an evaluation of communication links between Control Centers and an evaluation of how it transmits
and receives Real-time Assessment and Real-time monitoring data, Entity Alpha determined that it
communicates applicable data between its primary and backup Control Centers across a single communication
link. Entity Alpha also determined that it communicates applicable data to and from Entity Beta’s Control Center
across one of two links that originate from either Entity Alpha’s primary or backup Control Center using the
Inter-Control Center Communications Protocol (ICCP).
With an identified scope of communications links, Entity Alpha now considers the three required elements of its
required communications between Control Centers for its plan.
Identification of Security Protection

2

•

Entity Alpha must ensure that protection is applied where identified in its CIP-012-1 plan. The protection
must also meet the security objective of mitigating the risk of unauthorized disclosure or modification of
applicable data while in transit between Control Centers. The identification of security protection could
be demonstrated by a network diagram similar to that shown in Figure 2 or Figure 3.

•

In a simple case where the security protection is applied sufficiently close to the Control Center, such as
within the Physical Security Perimeter of the Control Center, Entity Alpha may use a single security
protection method to meet the security objective. For this case, shown in Figure 2, Entity Alpha
implements a Virtual Private Network (VPN) connection across a private leased communication circuit for
each of its three in-scope communication links. To meet the security objective, Entity Alpha further states
that its VPN uses Internet Protocol security (IPsec) with encryption.

•

For more complex scenarios, Entity Alpha may need to use a combination of security controls. For
instance, in Figure 3, Entity Alpha uses a combination of physical security controls (physical access control)
and logical security controls (encrypted communications consistent with the first scenario above) to meet
the security objective.

•

While these scenarios are all specific to communication links, it is possible that Entity Alpha and Entity
Beta achieve the security objective by applying protection to the data rather than the communication
links. In this scenario, the application enabling the data exchange between Control Centers may be
capable of applying security controls directly to the data. These security controls mitigate the risk of
unauthorized disclosure or modification of applicable data rather than relying on lower level network
services to provide this security. For instance, Entity Alpha and Entity Beta may apply security protection
at the application layer by using Secure ICCP to exchange applicable data. According to a report released
by Sandia National Labs 2, Secure ICCP provides “data integrity indirectly by providing a cryptographic
checksum. Secure ICCP provides data confidentiality by encrypting ICCP data exchanges.” Methods other
than Secure ICCP could also be used to apply security protection to the data at the application layer.

•

It is theoretically possible that Entity Alpha and Entity Beta could exchange Real-time Assessment data
between Control Centers by email. In that scenario, one approach may be for Entity Alpha to email the
applicable data to Entity Beta’s Control Center in a protected container such as an encrypted zip file. Entity
Alpha and Entity Beta can then exchange the password to that encrypted container through another
method, such as by phone. While the notional example of protecting data exchanged by email is a useful
illustration of how to achieve the security objective of CIP-012-1, it is extremely unlikely to be used in
practice. The characteristics of email communication are inconsistent with the requirements of Real-time
data exchange.

https://energy.gov/sites/prod/files/oeprod/DocumentsandMedia/19-Secure_ICCP_Integration.pdf
NERC | DRAFT CIP-012-1 Implementation Guidance | March 2018
8

Identification of Where Security Protection is Applied by the Responsible Entity

Similar to the identification of security protection above, the identification of where security protection is applied
can also be demonstrated by a network diagram similar to those found in Figures 2 and 3.
•

Figure 2 shows the identification where CIP-012-1 security protection is applied for the Entity Alpha
reference model when a single encrypted tunnel is used to implement the required protection. Entity
Alpha has identified that security protection is applied at each of its Control Centers on the external
Ethernet interface on the WAN router. While the diagram depicts where Entity Beta has applied security
protection for illustrative purposes, Entity Alpha is not responsible for identifying where Entity Beta has
applied security protection.

•

In order to understand the application of security protection in context of who controls the
communication link, it may be helpful to identify both where CIP-012-1 security protection is applied
and the location of the telecommunications carrier (telco) demarcation point. Figure 3 provides such an
example where the telco demarcation point may not be within the Control Center and based the facts
and circumstances surrounding this scenario, Entity Alpha has implemented a combination of security
controls to comply with CIP-012-1. In this scenario, Entity Alpha identifies that it has applied physical
security protection for its PSP and continuing for its WAN router and that it has applied logical security
protection (encryption) at the WAN router. Entity Alpha has also identified the telco demarcation point
at a point in the telecommunications cabling connecting to Entity Alpha’s WAN router, perhaps at a
punch down block for example. In Figure 3, the telco demarcation point is inside the same room as the
WAN router. The telco demarcation points are referenced in the drawing for clarity, but are not part of
the plan.

•

The data-centric scenario described above is less intuitive for identifying where security protection is
applied by Entity Alpha. If security protection is applied at the application layer (such as Secure ICCP),
Entity Alpha could reasonably identify the application or service applying the security (such as the Secure
ICCP service) as the location of where security protection is applied.

Identification of Responsibilities when the Control Centers are Owned or Operated by Different
Responsible Entities

Entity Alpha and Entity Beta may determine they each are responsible for one end of the VPN configuration on
their respective WAN routers. Entity Alpha and Entity Beta have agreed to a 30 character pre-shared key for
IPSec authentication.

Rather than use a pre-shared key, Entity Alpha and Entity Beta may decide to use digital certificates for the IPSec
authentication using a trusted certificate authority. In that scenario, Entity Alpha and Entity Beta would agree
on who is the party responsible for managing the certificate authority.

NERC | DRAFT CIP-012-1 Implementation Guidance | March 2018
9

Entity Alpha’s Primary
Control Center

Entity Alpha’s CIP-012
security protection applied
at the external interface of
the WAN router

Entity Alpha’s CIP-012
security protection applied
at the external interface of
the WAN router

Entity Alpha’s Backup
Control Center

WAN Router

WAN Router

ESP Firewall

ESP Firewall

Operator Application Database
Workstations Server
Server

Operator Application Database
Workstations Server
Server

ICCP
Server

Communications Carrier
Entity Beta’s CIP-012
security protection applied
at the external interface of
the WAN router

Entity Beta’s
Control Center
WAN Router

ESP Firewall

Operator Application Database
Workstations Server
Server

ICCP
Server

Figure 2: Network diagram and identification of where security protection is applied

NERC | DRAFT CIP-012-1 Implementation Guidance | March 2018
10

ICCP
Server

Entity Alpha’s CIP-012
physical security
protection applied

Physically secured area

Physically secured area

Entity Alpha’s Primary
Control Center

WAN Router
Entity Alpha’s CIP-012
logical security
protection applied

ESP Firewall

Entity Alpha’s Backup
Control Center

WAN Router
Telco
Demarcation
Point

Telco
Demarcation
Point

Entity Alpha’s CIP-012
physical security
protection applied

Entity Alpha’s CIP-012
logical security
protection applied

ESP Firewall

Encrypted
Communications
Operator Application Database
Workstations Server
Server

ICCP
Server

Operator Application Database
Workstations Server
Server

Communications Carrier
Entity Beta’s CIP-012
security protection
applied

Entity Beta’s
Control Center
WAN Router

ESP Firewall

Operator Application Database
Workstations Server
Server

ICCP
Server

Figure 3: Network diagram using a combination of controls for CIP-012-1

NERC | DRAFT CIP-012-1 Implementation Guidance | March 2018
11

ICCP
Server

References
Mitre Common Weakness Enumeration (CWE™) list of software weakness types
https://cwe.mitre.org/data/definitions/327.html
Cryptographic Standards and Guidelines
https://csrc.nist.gov/Projects/Cryptographic-Standards-and-Guidelines
NIST Special Publication 800-175B
Guideline for Using Cryptographic Standards in the Federal Government: Cryptographic Mechanisms
http://nvlpubs.nist.gov/nistpubs/SpecialPublications/NIST.SP.800-175B.pdf
Guide to Cryptography
https://www.owasp.org/index.php/Guide_to_Cryptography#Symmetric_Cryptography

NERC | DRAFT CIP-012-1 Implementation Guidance | March 2018
12

DRAFT

Cyber Security –
Communications Between
Control Centers
Implementation Guidance for CIP-012-1
NovemberMarch, 20187

NERC | Report Title | Report Date
I

Table of Contents
Introduction ................................................................................................................................................................3
Requirements .............................................................................................................................................................4
General Considerations ..............................................................................................................................................5
Identification of Security Protection ...................................................................................................................5
Identification of Where Security Protection is Applied by the Responsible Entity ............................................5
Reference Model ........................................................................................................................................................8
Reference Model Discussion ...............................................................................................................................8
Identification of Security Protection ...................................................................................................................9
Identification of Where Security Protection is Applied by the Responsible Entity.......................................... 10
Identification of Responsibilities when the Control Centers are Owned or Operated by Different Responsible
Entities.............................................................................................................................................................. 10
References ............................................................................................................................................................... 13

NERC | DRAFT CIP-012-1 Implementation Guidance | March 2018
2

Introduction
The Commission issued Order No. 822 on January 21, 2016. Order 822 approved seven CIP Reliability Standards
and new or modified definitions, and directed modifications be made to the CIP Reliability Standards. Among
other items, the Commission directed NERC to “develop modifications to the CIP Reliability Standards to require
responsible entities to implement controls to protect, at a minimum, communication links and sensitive bulk
electric system data communicated between bulk electric system Control Centers in a manner that is
appropriately tailored to address the risks posed to the bulk electric system by the assets being protected (i.e.,
high, medium, or low impact).” (Order 822, Paragraph 53)
In response to the directive in Order No. 822, the Project 2016-02 standard drafting team (SDT) drafted Reliability
Standard CIP-012-1 to require Responsible Entities to implement controls to protect sensitive Bulk Electric System
(BES) data and communications links between BES Control Centers. Due to the sensitivity of the data being
communicated between Control Centers, the standard applies to all impact levels (i.e., high, medium, or low
impact).
The SDT drafted requirements to provide Responsible Entities the latitude to protect the communication links,
the data, or both, to satisfy the security objective consistent with the capabilities of the Responsible Entity’s
operational environment. Requirement R1 requires Responsible Entities to document one or more plans that
protect Real-time Assessment and Real-time monitoring and control data while being transmitted between
Control Centers. The plan(s) must address how the Responsible Entity will mitigate the risk of unauthorized
disclosure or modification of the applicable data. Requirement R2 covers implementation of the plan developed
according to Requirement R1.
The Project 2016-02 SDT drafted this Implementation Guidance to provide example approaches for compliance
with CIP-012-1. Implementation Guidance does not prescribe the only approach, but highlights one or more
approaches that would be effective in achieving compliance with the standard. Because Implementation Guidance
only provides examples, entities may choose alternative approaches that better fit their individual situations 1.
Responsible Entities may find it useful to consider this Implementation Guidance document along with the
additional context and background provided in the SDT-developed Technical Rationale and Justification for CIP012-1 document.

Background

The Commission issued Order No. 822 on January 21, 2016. Order 822 approving approved seven CIP Reliability
Standards and new or modified definitions, and directed modifications be made to the CIP Reliability Standards.
Among other items, the Commission directed NERC to “develop modifications to the CIP Reliability Standards to
require responsible entities to implement controls to protect, at a minimum, communication links and sensitive
bulk electric system data communicated between bulk electric system Control Centers in a manner that is
appropriately tailored to address the risks posed to the bulk electric system by the assets being protected (i.e.,
high, medium, or low impact).” (Order 822, Paragraph 53)
In response to the directive in Order No. 822, the Project 2016-02 standard drafting team (SDT) drafted Reliability
Standard CIP-012-1 to require Responsible Entities to implement controls to protect sensitive Bulk Electric System
(BES) data and communications links between BES Control Centers. Due to the sensitivity of the data being
communicated between Control Centers, the standard applies to all impact levels (i.e., high, medium, or low
impact).
The SDT drafted requirements to provide Responsible Entities the latitude to protect the communication links,
the data, or both, to satisfy the security objective consistent with the capabilities of the Responsible Entity’s
operational environment.

1

NERC’s Compliance Guidance Policy
NERC | DRAFT CIP-012-1 Implementation Guidance | November 2017March 2018
3

Requirements
R1.

The Responsible Entity shall develop implement one or more documented plan(s) to mitigate
the risk of unauthorized disclosure or modification of Real-time Assessment and Real-time
monitoring and control data while being transmitted between any Control Centers. This
requirement excludes oral communications. The plan shall include: [Violation Risk Factor:
Medium] [Time Horizon: Operations Planning]
1.1. Identification of security protection used to mitigate the risk of unauthorized disclosure
or modification of Real-time Assessment and Real-time monitoring and control data
while being transmitted between Control Centers;
1.2. Identification of where the Responsible Entity applied demarcation point(s) where
security protection is applied for transmitting Real-time Assessment and Real-time
monitoring and control data between Control Centers; and
1.3. If the Control Centers are owned or operated Identification of roles and responsibilities of
each Responsible Entity for applying security protection to the transmission of Real-time
Assessment and Real-time monitoring and control data between Control Centers, when
the Control Centers are owned or operated by different Responsible Entities, identify the
responsibilities of each Responsible Entity for applying security protection to the
transmission of Real-time Assessment and Real-time monitoring data between those
Control Centers.
R2. The Responsible Entity shall implement the plan(s) specified in Requirement R1, except
under CIP Exceptional Circumstances.

NERC | DRAFT CIP-012-1 Implementation Guidance | November 2017March 2018
4

General Considerations
Plan Development
General Considerations for R1
As noted in the Technical Rationale and Justification for CIP-012-1, the focus of Requirement R1 is on developing
implementing a documented plan to protect information that is critical to the real-time operations of the Bulk
Electric System while in transit between applicable Control Centers. The number of plan(s) and their content
may vary depending on a Responsible Entity's management structure and operating conditions. The Responsible
Entity may document as many plans as necessary to meet its needs. For instance, a Responsible Entity may
choose to document one plan per Control Center or it may choose an all-inclusive, single plan for its Control
Center communication environment. to document everything in a single plan. A Responsible Entity may choose
to document one plan for communications between Control Centers it owns and a separate plan for
communications between its Control Centers and the Control Centers of a neighboring Entity. The number and
structure of the plans is at the discretion of the Responsible Entity as long as the plan(s) include the required
elements described in parts 1.1, 1.2, and 1.3 of Requirement R1.
Identification of Security Protection
Entities have latitude to identify and choose determine which security protections are is used to mitigate the risk
of unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring and control data
while being transmitted between Control Centers and should identify those protections accordingly.
This security protection could consist of logical protection, physical protection, or some combination of both. To
determine security protection, the requirement specifies that it must mitigate the risk of unauthorized disclosure
or modification of applicable data.
Security protection implementation can be demonstrated in many ways. If a Responsible Entity uses physical
protection, it may demonstrate implementation through review of an applicable Control Center floor plan, with
details subsequently confirmed through visual inspection, which identifies the physical security measures in
place protecting the communication link. If the Responsible Entity uses logical protection, it may demonstrate
implementation through an export of the device configuration which applies the security protection.
Alternatively, a Responsible Entity may demonstrate implementation through security control monitoring, using
an automated monitoring tool to generate reports on the encryption service used to protect a communications
link.
Identification of Demarcation Point(s) Where Security Protection is Applied by the
Responsible Entity
A Responsible Entity should consider its environment to determine an effective solution when identifying the
demarcation points where security protections are should be applied. One approach to identifying a
demarcation point is to implement security place the demarcation point within the Control Center so the
confidentiality and integrity of the data is protected throughout the transmissionitself to ensure that data
confidentiality and integrity is protected throughout the transmission. The Responsible Entity can choose either
a physical or logical demarcation point identify where security protection is applied using a logical or physical
location. Demarcation points identified by the Responsible Entity do not add additional assets to the scope of
the CIP Reliability Standards. The demarcation point identification ensures that each Responsible Entity
identifies clear demarcation of where the protection is applied to the in-scope data. Demarcation points The
application of security in accordance with CIP-012 requirements does not add additional assets to the scope of
the CIP Reliability Standards. Locations of applied security protection may vary based on many factors such as
impact levels of the Control Center, different technologies, or infrastructures.

NERC | DRAFT CIP-012-1 Implementation Guidance | November 2017March 2018
5

Identification of where a Responsible Entity applies security protection could be demonstrated with a list or a
Control Center diagram showing either physical or logical security controls. Physical diagrams may require visual
confirmation of these controls. These diagrams or a list could be included within the plan developed for R1. A
Responsible Entity could also use labels to identify on-site devices where CIP-012 security protection is applied.
When exchanging data between two entities, if a Responsible Entity only manages one end of a communication
link, the Responsible Entity is not responsible for identifying where the security protection is applied by the
neighboring entity with whom it is exchanging data. However, if a Responsible Entity has taken responsibility for
both ends of the communication link (such as by placing a router within the neighboring entity’s data center),
then the Responsible Entity shall identify where the security protection is applied at both ends of the link.
Similarly, if a Responsible Entity owns and operates both Control Centers which are exchanging data (such as in
the case of a primary and backup Control Center), then the Responsible Entity shall identify where security
protection is applied at both ends of the link.
Identification of Roles and Responsibilities when the Control Centers are Owned or Operated by
Different Responsible Entities

The Technical Rationale and Justification for CIP-012-1 identifies key considerations in the Control Center
Ownership section when communicationsing between Control Centers with different owners or operators. Most
if not all of the mMany operational relationships between Responsible Entities are unique. Consequently, there
is no single way to identify roles and responsibilities for applying security protection to the transmission of Realtime Assessment and Real-time monitoring and control data between Control Centers.
Implementation of Responsible Entities may consider identifying the roles and responsibilities could also be
demonstrated in many ways. for the following situations: (1) configuration of security protocols, (2) responding
to communication failures, and (3) responding to Cyber Security Incidents. Some examples include a joint
procedure, a memorandum of understanding, or meeting minutes between the two parties where
responsibilities are discusseddefined.

NERC | DRAFT CIP-012-1 Implementation Guidance | November 2017March 2018
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General Considerations for R2
Given the format of the requirements, the majority of the documentation is required under R1 while R2 requires
the implementation of the plan developed for R1. Compliance with R2 is established by implementing the
protection identified in a Responsible Entity’s R1 plan. The sections below outline examples of evidence that
may be provided in order to demonstrate the implementation of Entity Alpha’s CIP-012-1 R1 plan.
Identification of Security Protection

Implementation of the security protection can be demonstrated in many ways. If physical protection is used, a
Responsible Entity may demonstrate implementation through a floor plan which identifies the physical security
measures in place protecting the communication link. If logical protection is used, a Responsible Entity may
demonstrate implementation through an export of the device configuration which applies the security
protection. Alternatively, a Responsible Entity may demonstrate implementation through monitoring of the
security control such as a report generated from an automated tool that monitors the encryption service used to
protect a communications link.
Identification of Demarcation Point(s)

Identification of demarcation point(s) could be demonstrated with a diagram (physical or logical) or a list. This
diagram or list could be included within the plan developed for R1. A label could also be used to identify a device
as a demarcation point.
Identification of Roles and Responsibilities when the Control Centers are Owned or Operated by
Different Responsible Entities

Implementation of roles and responsibilities could also be demonstrated in many ways. Some examples include
a joint procedure, a memorandum of understanding or meeting minutes between the two parties where roles
and responsibilities are discussed.

NERC | DRAFT CIP-012-1 Implementation Guidance | November 2017March 2018
7

Reference Models
For this Implementation Guidance, the SDT uses a basic reference model of Primary and Backup Control Centers
(Entity Alpha) to illustrate approaches concepts necessary to demonstratinge compliance. These Control
Centers communicate to each other and to a neighboring entity’s Control Center (Entity Beta) in configurations
outlined by the diagrams in this section. The SDT recognizes that the reference models does not contain many of
the complexities of a real Control Center. For this Implementation Guidance, the registration or functions
performed in the reference model Control Center are also not considered. A high level block diagram of the
basic reference model is shown below in Figure 1. This Implementation Guidance is developed from the
perspective of Entity Alpha.

Entity Alpha’s Primary
Control Center

Communication between Entity Alpha’s
Primary and Backup Control Center

Communication between Entity Alpha’s
Primary Control Center and Entity Beta’s Control Center

Entity Alpha’s Backup
Control Center

Communication between Entity Alpha’s
Backup Control Center and Entity Beta’s Control Center

Entity Beta’s Control
Center

Figure 1: High Level Block Diagram of Reference Model Control Centers

Reference Model Discussion
Requirement R1 requires the implementation of a documented plan. To comply with requirement R1, one
approach to a plan is to first determine which communications require protection under are in scope of CIP-0121. There are multiple ways to identify an entity’s scope in R1. For example, Entity Alpha in the reference model
may first identify the Control Centers with which it communicates. Entity Alpha would determine that there are
three: Entity Alpha’s Primary Control Center, Entity Alpha’s Backup Control Center, and Entity Beta’s Control
Center. Entity Alpha does not need to consider whether Entity Beta further shares its data with another Entity.
That is the responsibility of Entity Beta and is outside of Entity Alpha’s purview. Additionally, Entity Alpha does
not need to consider any communications to other non-Control Center facilities such as generating plants or
substations. These communications are out of scope for CIP-012-1.
Now that Entity Alpha has identified the Control Centers with which it communicates, Entity Alpha identifies
either: (1) the Real-time Assessment and Real-time monitoring data; or (2) communication links which are used
to transmit Real-time Assessment and Real-time monitoring data between Control Centers. In either case, Entity
Alpha should refer to the data specification for Real-time Assessment and Real-time monitoring data identified
NERC | DRAFT CIP-012-1 Implementation Guidance | November 2017March 2018
8

in TOP-003-3 and IRO-010-2. For this reference model scenario, identifying the communication links used to
transmit Real-time Assessment and Real-time monitoring data may be the most straightforward approach.
Through an evaluation of communication links between Control Centers and an evaluation of how it transmits
and receives Real-time Assessment and Real-time monitoring data, Entity Alpha determined that it
communicates applicable data between its primary and backup Control Centers across a single communication
link. Entity Alpha also determined that it communicates applicable data to and from Entity Beta’s Control Center
across one of two links that originate from either Entity Alpha’s primary or backup Control Center using the
Inter-Control Center Communications Protocol (ICCP).
With an identified scope of communications links, Entity Alpha now considers the three required elements of its
required communications between Control Centers for its plan.
Identification of Security Protection

2

•

Entity Alpha must ensure that protection is applied where identified in its CIP-012-1 plan. The protection
must also meet the security objective of mitigating the risk of unauthorized disclosure or modification of
applicable data while in transit between Control Centers. The identification of security protection could
be demonstrated by a network diagram similar to that shown in Figure 2 or Figure 3.

•

In a simple case where the security protection is applied sufficiently close to the Control Center, such as
within the Physical Security Perimeter of the Control Center, Entity Alpha may use a single security
protection method to meet the security objective. For this case, shown in Figure 2, Entity Alpha
implements a Virtual Private Network (VPN) connection across a private leased communication circuit for
each of its three in-scope communication links. To meet the security objective, Entity Alpha further states
that its VPN uses Internet Protocol security (IPsec) with encryption.

•

For more complex scenarios, Entity Alpha may need to use a combination of security controls. For
instance, in Figure 3, Entity Alpha uses a combination of physical security controls (physical access control)
and logical security controls (encrypted communications consistent with the first scenario above) to meet
the security objective.

•

While these scenarios are all specific to communication links, it is possible that Entity Alpha and Entity
Beta achieve the security objective by applying protection to the data rather than the communication
links. In this scenario, the application enabling the data exchange between Control Centers may be
capable of applying security controls directly to the data. These security controls mitigate the risk of
unauthorized disclosure or modification of applicable data rather than relying on lower level network
services to provide this security. For instance, Entity Alpha and Entity Beta may apply security protection
at the application layer by using Secure ICCP to exchange applicable data. According to a report released
by Sandia National Labs 2, Secure ICCP provides “data integrity indirectly by providing a cryptographic
checksum. …Secure ICCP provides data confidentiality by encrypting ICCP data exchanges.” Methods
other than Secure ICCP could also be used to apply security protection to the data at the application layer.

•

It is theoretically possible that Entity Alpha and Entity Beta could exchange Real-time Assessment data
between Control Centers by email. In that scenario, one approach may be for Entity Alpha to email the
applicable data to Entity Beta’s Control Center in a protected container such as an encrypted zip file. Entity
Alpha and Entity Beta can then exchange the password to that encrypted container through another
method, such as by phone. While the notional example of protecting data exchanged by email is a useful
illustration of how to achieve the security objective of CIP-012-1, it is extremely unlikely to be used in
practice. The characteristics of email communication are inconsistent with the requirements of Real-time
data exchange.

https://energy.gov/sites/prod/files/oeprod/DocumentsandMedia/19-Secure_ICCP_Integration.pdf
NERC | DRAFT CIP-012-1 Implementation Guidance | November 2017March 2018
9

Identification of Where Security Protection is Applied by the Responsible Entity

Similar to the identification of security protection above, the identification of where security protection is applied
can also be demonstrated by a network diagram similar to those found in Figures 2 and 3.
•

Figure 2 shows the identification where CIP-012-1 security protection is applied for the Entity Alpha
reference model when a single encrypted tunnel is used to implement the required protection. Entity
Alpha has identified that security protection is applied at each of its Control Centers on the external
Ethernet interface on the WAN router. While the diagram depicts where Entity Beta has applied security
protection for illustrative purposes, Entity Alpha is not responsible for identifying where Entity Beta has
applied security protection.

•

In some cases order to understand the application of security protection in context of who controls the
communication link, it may be helpful to identify both where CIP-012-1 security protection is applied
and the location of the telecommunications carrier (telco) demarcation point. Figure 3 provides such an
example where the telco demarcation point may not be within the Control Center and based the facts
and circumstances surrounding this scenario, Entity Alpha has implemented a combination of security
controls to comply with CIP-012-1. In this scenario, Entity Alpha identifies that it has applied physical
security protection for its PSP and continuing for its WAN router and that it has applied logical security
protection (encryption) at the WAN router. Entity Alpha has also identified the telco demarcation point
at a point in the telecommunications cabling connecting to Entity Alpha’s WAN router, perhaps at a
punch down block for example. In Figure 3, the telco demarcation point is inside the same room as the
WAN router. The telco demarcation points are referenced in the drawing for clarity, but are not part of
the plan.

•

The data-centric scenario described above is less intuitive for identifying where security protection is
applied by Entity Alpha. If security protection is applied at the application layer (such as Secure ICCP),
Entity Alpha could reasonably identify the application or service applying the security (such as the Secure
ICCP service) as the location of where security protection is applied.

Identification of Responsibilities when the Control Centers are Owned or Operated by Different
Responsible Entities

Entity Alpha and Entity Beta may determine they each are responsible for one end of the VPN configuration on
their respective WAN routers. Entity Alpha and Entity Beta have agreed to a 30 character pre-shared key for
IPSec authentication.

Rather than use a pre-shared key, Entity Alpha and Entity Beta may decide to use digital certificates for the IPSec
authentication using a trusted certificate authority. In that scenario, Entity Alpha and Entity Beta would agree
on who is the party responsible for managing the certificate authority.

NERC | DRAFT CIP-012-1 Implementation Guidance | November 2017March 2018
10

Entity Alpha’s Primary
Control Center

Entity Alpha’s CIP-012
security protection applied
at the external interface of
the WAN router

Entity Alpha’s CIP-012
security protection applied
at the external interface of
the WAN router

Entity Alpha’s Backup
Control Center

WAN Router

WAN Router

ESP Firewall

ESP Firewall

Operator Application Database
Workstations Server
Server

Operator Application Database
Workstations Server
Server

ICCP
Server

Communications Carrier
Entity Beta’s CIP-012
security protection applied
at the external interface of
the WAN router

Entity Beta’s
Control Center
WAN Router

ESP Firewall

Operator Application Database
Workstations Server
Server

ICCP
Server

Figure 2: Network diagram and identification of where security protection is applied

NERC | DRAFT CIP-012-1 Implementation Guidance | November 2017March 2018
11

ICCP
Server

Entity Alpha’s CIP-012
physical security
protection applied

Physically secured area

Physically secured area

Entity Alpha’s Primary
Control Center

WAN Router
Entity Alpha’s CIP-012
logical security
protection applied

ESP Firewall

Entity Alpha’s Backup
Control Center

WAN Router
Telco
Demarcation
Point

Telco
Demarcation
Point

Entity Alpha’s CIP-012
physical security
protection applied

Entity Alpha’s CIP-012
logical security
protection applied

ESP Firewall

Encrypted
Communications
Operator Application Database
Workstations Server
Server

ICCP
Server

Operator Application Database
Workstations Server
Server

Communications Carrier
Entity Beta’s CIP-012
security protection
applied

Entity Beta’s
Control Center
WAN Router

ESP Firewall

Operator Application Database
Workstations Server
Server

ICCP
Server

Figure 3: Network diagram using a combination of controls for CIP-012-1

NERC | DRAFT CIP-012-1 Implementation Guidance | November 2017March 2018
12

ICCP
Server

References
Mitre Common Weakness Enumeration (CWE™) list of software weakness types
https://cwe.mitre.org/data/definitions/327.html
Cryptographic Standards and Guidelines
https://csrc.nist.gov/Projects/Cryptographic-Standards-and-Guidelines
NIST Special Publication 800-175B
Guideline for Using Cryptographic Standards in the Federal Government: Cryptographic Mechanisms
http://nvlpubs.nist.gov/nistpubs/SpecialPublications/NIST.SP.800-175B.pdf
Guide to Cryptography
https://www.owasp.org/index.php/Guide_to_Cryptography#Symmetric_Cryptography

NERC | DRAFT CIP-012-1 Implementation Guidance | November 2017March 2018
13

DRAFT

Cyber Security –
Communications between
Control Centers
Technical Rationale and Justification for
Reliability Standard CIP-012-1

March 2018

NERC | Report Title | Report Date
I

Table of Contents
Preface ...................................................................................................................................................................... iii
Introduction .............................................................................................................................................................. iv
Requirement R1 ......................................................................................................................................................... 1
General Considerations for Requirement R1...................................................................................................... 1
Overview of confidentiality and integrity ........................................................................................................... 1
Alignment with IRO and TOP standards ............................................................................................................. 1
Identification of Where Security Protection is Applied by the Responsible Entity ............................................ 2
Control Center Ownership .................................................................................................................................. 2
References.................................................................................................................................................................. 4

NERC | Technical Rationale and Justification for Reliability Standard CIP-002-1| March 2018
ii

Preface
The vision for the Electric Reliability Organization (ERO) Enterprise, which is comprised of the North American Electric
Reliability Corporation (NERC) and the eight Regional Entities (REs), is a highly reliable and secure North American
bulk power system (BPS). Our mission is to assure the effective and efficient reduction of risks to the reliability and
security of the grid.
The North American BPS is divided into eight RE boundaries as shown in the map and corresponding table below.

The North American BPS is divided into eight RE boundaries. The highlighted areas denote overlap as some load-serving entities
participate in one Region while associated Transmission Owners/Operators participate in another.

FRCC

Florida Reliability Coordinating Council

MRO

Midwest Reliability Organization

NPCC

Northeast Power Coordinating Council

RF

ReliabilityFirst

SERC

SERC Reliability Corporation

SPP RE

Southwest Power Pool Regional Entity

Texas RE

Texas Reliability Entity

WECC

Western Electricity Coordinating Council

NERC | Technical Rationale and Justification for Reliability Standard CIP-002-1| March 2018
iii

Introduction
This document explains the technical rationale and justification for the proposed Reliability Standard CIP-012-1. It
will provide stakeholders and the ERO Enterprise with an understanding of the technology and technical
requirements in the Reliability Standard. It also contains information on the SDT’s intent in drafting the requirements.
This Technical Rationale and Justification for CIP-012-1 is not a Reliability Standard and should not be considered
mandatory and enforceable.
On January 21, 2016, the Federal Energy Regulatory Commission (FERC or Commission) issued Order No. 822,
approving seven Critical Infrastructure Protection (CIP) Reliability Standards and new or modified terms in the
Glossary of Terms Used in NERC Reliability Standards, and directing modifications to the CIP Reliability Standards.
Among others, the Commission directed the North American Electric Reliability Corporation (NERC) to “develop
modifications to the CIP Reliability Standards to require Responsible Entities 1 to implement controls to protect, at a
minimum, communication links and sensitive bulk electric system data communicated between bulk electric system
Control Centers in a manner that is appropriately tailored to address the risks posed to the bulk electric system by
the assets being protected (i.e., high, medium, or low impact).” (Order 822, Paragraph 53)
In response to the directive in Order No. 822, the Project 2016-02 standard drafting team (SDT) drafted Reliability
Standard CIP-012-1 to require Responsible Entities to implement controls to protect sensitive Bulk Electric System
(BES) data and communications links between BES Control Centers. Due to the sensitivity of the data being
communicated between Control Centers, as defined in the Glossary of Terms Used in NERC Reliability Standards, the
standard applies to all impact levels (i.e., high, medium, or low impact).
Although the Commission directed NERC to develop modifications to CIP-006, the SDT determined that modifications
to CIP-006 would not be appropriate. There are differences between the plan(s) required to be developed and
implemented for CIP-012-1 and the protection required in CIP-006-6 Requirement R1 Part 1.10. CIP-012-1
Requirements R1 and R2 protect the applicable data during transmission between two separate Control Centers. CIP006 Requirement R1 Part 1.10 protects nonprogrammable communication components within an Electronic Security
Perimeter (ESP) but outside of a Physical Security Perimeter (PSP). The transmission of applicable data between
Control Centers takes place outside of an ESP. Therefore, the protection contained in CIP-006-6 Requirement R1 Part
1.10 does not apply.
The SDT drafted requirements to provide Responsible Entities the latitude to protect the communication links, the
data, or both to satisfy the security objective consistent with the capabilities of the Responsible Entity’s operational
environment.

1

As used in the CIP Standards, a Responsible Entity refers to the registered entities subject to the CIP Standards.
NERC | Technical Rationale and Justification for Reliability Standard CIP-002-1| March 2018
iv

Requirement R1
R1.

The Responsible Entity shall implement one or more documented plan(s) to mitigate the risk of
unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring data while
being transmitted between any Control Centers. This requirement excludes oral communications. The
plan shall include: [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]
1.1 Identification of security protection used to mitigate the risk of unauthorized disclosure or
modification of Real-time Assessment and Real-time monitoring while being transmitted between
Control Centers;
1.2 Identification of where the Responsible Entity applied security protection for transmitting Real-time
Assessment and Real-time monitoring data between Control Centers; and
1.3 If the Control Centers are owned or operated by different Responsible Entities, identify the
responsibilities of each Responsible Entity for applying security protection to the transmission of
Real-time Assessment and Real-time monitoring data between those Control Centers.

General Considerations for Requirement R1
Requirement R1 focuses on implementing a document plan to protect information that is critical to the Real-time
operations of the Bulk Electric System while in transit between applicable Control Centers. The SDT does not intend
for the listed order of the three requirement parts to convey any sequence or significance.
Overview of confidentiality and integrity
The SDT drafted CIP-012-1 to address confidentiality and integrity of Real-time Assessment and Real-time monitoring
data. This is accomplished by drafting the requirement to mitigate the risk of unauthorized disclosure (confidentiality)
or modification (integrity). For this Standard, the SDT relied on the definitions of confidentiality and integrity as
defined by National Institute of Standards and Technology (NIST):
•

Confidentiality is defined as, “Preserving authorized restrictions on information access and disclosure,
including means for protecting personal privacy and proprietary information.” 2

•

Integrity is defined as, “Guarding against improper information modification or destruction, and includes
ensuring information non-repudiation and authenticity.” 3

The SDT asserts that the availability of this data is already required by the performance obligation of the Operating
and Planning Reliability Standards. The SDT drafted CIP-012 to address the data while being transmitted. The SDT
maintains that this data resides within BES Cyber Systems, and while at rest is protected by CIP-003 through CIP-011.
Alignment with IRO and TOP standards
The SDT recognized the FERC reference to additional Reliability Standards and the responsibilities to protect the
applicable data in accordance with NERC Reliability Standards TOP-003 and IRO-010. The SDT used these references
to drive the identification of sensitive BES data and chose to base the CIP-012 requirements on the Real-time data
specification elements in these standards. This approach provides consistent scoping of identified data, and does not
require each entity to devise its own list or inventory of this data. Many entities are required to provide this data
under agreements executed with their RC, BA or TOP. The SDT asserts that typically the RC, BA or TOP will identify
all data requiring protection for CIP-012-1 through the TOP-003 and IRO-010 Reliability Standards. However, the SDT
2
3

NIST Special Publication 800-53A, Revision 4, page B-3
NIST Special Publication 800-53A, Revision 4, page B-6
NERC | Technical Rationale and Justification for Reliability Standard CIP-002-1| March 2018
1

0 Requirement R1

noted that there may be special instances during which Real-time Assessment or Real-time Monitoring data is not
identified by the RC, BA, or TOP. This would include data that may be exchanged between a Responsible Entity’s
primary and backup Control Center.
Identification of Where Security Protection is Applied by the Responsible Entity
The SDT noted the need for a Responsible Entity to identify where it will apply protection for applicable data. The
SDT did not specify the location where CIP-012 security protection must be applied to provide latitude for Responsible
Entities to implement the security controls in a manner best fitting their individual circumstances. This latitude
ensures entities can still take advantage of security measures, such as deep packet inspection implemented at or near
the EAP when ESPs are present, while maintaining the capability to protect the applicable data being transmitted
between Control Centers.
The SDT also recognizes that CIP-012 security protection may be applied to a Cyber Asset that is not an identified BES
Cyber Asset or EACMS. The identification of the Cyber Asset as the location where security protection is applied does
not expand the scope of Cyber Assets identified as applicable under Cyber Security Standards CIP-002 through CIP011.
The SDT understands that in data exchanges between Control Centers, a single entity may not be responsible for both
ends of the communication link. The SDT intends for a Responsible Entity to identify only where it applied security
protection. The Responsible Entity should not be held accountable for identifying where a neighboring entity applied
security protection at the neighboring entity’s facility. A Responsible Entity, however, may decide to take
responsibility for both ends of a communication link. For example, it may place a router in a neighboring entity’s data
center. In a scenario like this, where a Responsible Entity has taken responsibility for applying security protection on
both ends of the communication link, the Responsible Entity should identify where it applied security protection at
both ends of the link. The SDT intends for there to be alignment between the identification of where security
protection is applied in CIP-012 R1, Part 1.2 and the identification of Responsible Entity responsibilities in CIP-012 R1,
Part 1.3.
Control Center Ownership
The requirements address protection for Real-time Assessment and Real-time monitoring data while being
transmitted between Control Centers owned by a single Responsible Entity. They also cover the applicable data
transmitted between Control Centers owned by two or more separate Responsible Entities. Unlike protection
between a single Responsible Entity’s Control Centers, applying protection between Control Centers owned by more
than one Responsible Entity requires additional coordination. The requirements do not explicitly require formal
agreements between Responsible Entities partnering for protection of applicable data. It is strongly recommended,
however, that these partnering entities develop agreements, or use existing ones, to define responsibilities to ensure
the security objective is met. An example noted in FERC Order No. 822 Paragraph 59 is, “if several registered entities
have joint responsibility for a cryptographic key management system used between their respective Control Centers,
they should have the prerogative to come to a consensus on which organization administers that particular key
management system."
As an example, the reference model below shows some of the data transmissions between Control Centers that a
Responsible Entity should consider to be in-scope. The example does not include all possible scenarios. The solid
green lines are in-scope communications. The dashed red lines are out-of-scope communications.

NERC | Technical Rationale and Justification for Reliability Standard CIP-002-1| March 2018
2

0 Requirement R1

This reference model is an example and does not include all possible scenarios.

NERC | Technical Rationale and Justification for Reliability Standard CIP-002-1| March 2018
3

References
Here are several references to assist entities in developing plan(s) for protection of communication links:
• NIST Special Publication 800-53A, Revision 4: Security and Privacy Controls for Federal Information Systems
and Organizations
• NIST Special Publication 800-82: Guide to Industrial Control Systems (ICS) Security
• NIST Special Publication 800-175B: Guideline for Using Cryptographic Standards in the Federal Government:
Cryptographic Mechanisms
• NIST Special Publication 800-47: Security Guide for Interconnecting Information Technology Systems

NERC | Technical Rationale and Justification for Reliability Standard CIP-002-1| March 2018
4

DRAFT

Cyber Security –
Communications between
Control Centers
Technical Rationale and Justification for
Reliability Standard CIP-012-1

November March 20187

NERC | Report Title | Report Date
I

Table of Contents
Preface ...................................................................................................................................................................... iii
Introduction .............................................................................................................................................................. iv
Requirement R1 ......................................................................................................................................................... 1
General Considerations for Requirement R1...................................................................................................... 1
Overview of confidentiality and integrity ........................................................................................................... 1
Alignment with IRO and TOP standards ............................................................................................................. 1
Identification of Where Security Protection is Applied by the Responsible Entity ............................................ 2
Control Center Ownership .................................................................................................................................. 3
References.................................................................................................................................................................. 4

NERC | Technical Rationale and Justification for Relaibility Standard CIP-002-1| November 2017March 2018
ii

Preface
The vision for the Electric Reliability Organization (ERO) Enterprise, which is comprised of the North American Electric
Reliability Corporation (NERC) and the eight Regional Entities (REs), is a highly reliable and secure North American
bulk power system (BPS). Our mission is to assure the effective and efficient reduction of risks to the reliability and
security of the grid.
The North American BPS is divided into eight RE boundaries as shown in the map and corresponding table below.

The North American BPS is divided into eight RE boundaries. The highlighted areas denote overlap as some load-serving entities
participate in one Region while associated Transmission Owners/Operators participate in another.

FRCC

Florida Reliability Coordinating Council

MRO

Midwest Reliability Organization

NPCC

Northeast Power Coordinating Council

RF

ReliabilityFirst

SERC

SERC Reliability Corporation

SPP RE

Southwest Power Pool Regional Entity

Texas RE

Texas Reliability Entity

WECC

Western Electricity Coordinating Council

NERC | Technical Rationale and Justification for Relaibility Standard CIP-002-1| November 2017March 2018
iii

Introduction
This document explains the technical rationale and justification for the proposed Reliability Standard CIP-012-1. It
will provide stakeholders and the ERO Enterprise with an understanding of the technology and technical
requirements in the Reliability Standard. It also contains information on the SDT’s intent in drafting the requirements.
This Technical Rationale and Justification for CIP-012-1 is not a Reliability Standard and should not be considered
mandatory and enforceable.
On January 21, 2016, the Federal Energy Regulatory Commission (FERC or Commission) issued Order No. 822,
approving seven Critical Infrastructure Protection (CIP) Reliability Standards and new or modified terms in the
Glossary of Terms Used in NERC Reliability Standards, and directing modifications to the CIP Reliability Standards.
Among others, the Commission directed the North American Electric Reliability Corporation (NERC) to “develop
modifications to the CIP Reliability Standards to require Responsible Entities 1 to implement controls to protect, at a
minimum, communication links and sensitive bulk electric system data communicated between bulk electric system
Control Centers in a manner that is appropriately tailored to address the risks posed to the bulk electric system by
the assets being protected (i.e., high, medium, or low impact).” (Order 822, Paragraph 53)
In response to the directive in Order No. 822, the Project 2016-02 standard drafting team (SDT) drafted Reliability
Standard CIP-012-1 to require Responsible Entities to implement controls to protect sensitive Bulk Electric System
(BES) data and communications links between BES Control Centers. Due to the sensitivity of the data being
communicated between Control Centers, as defined in the Glossary of Terms Used in NERC Reliability Standards, the
standard applies to all impact levels (i.e., high, medium, or low impact).
Although the Commission directed NERC to develop modifications to CIP-006, the SDT determined that modifications
to CIP-006 would not be appropriate. There are differences between the plan(s) required to be developed and
implemented for CIP-012-1 and the protection required in CIP-006-6 Requirement R1 Part 1.10. CIP-012-1
Requirements R1 and R2 protect the applicable data during transmission between two separate Control Centers. CIP006 Requirement R1 Part 1.10 protects nonprogrammable communication components within an Electronic Security
Perimeter (ESP) but outside of a Physical Security Perimeter (PSP). The transmission of applicable data between
Control Centers takes place outside of an ESP. Therefore, the protection contained in CIP-006-6 Requirement R1 Part
1.10 does not apply.
The SDT drafted requirements to provide Responsible Entities the latitude to protect the communication links, the
data, or both to satisfy the security objective consistent with the capabilities of the Responsible Entity’s operational
environment. Requirement R1 requires Responsible Entities to implement one or more documented plan(s) that
protect Real-time Assessment and Real-time monitoring data while being transmitted between Control Centers. The
plan(s) must address how the Responsible Entity will mitigate the risk of unauthorized disclosure or modification of
the applicable data.

1

As used in the CIP Standards, a Responsible Entity refers to the registered entities subject to the CIP Standards.
NERC | Technical Rationale and Justification for Relaibility Standard CIP-002-1| November 2017March 2018
iv

Requirement R1
R1.

The Responsible Entity shall develop implement one or more documented plan(s) to mitigate the risk
of unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring and
control data while being transmitted between any Control Centers. This requirement excludes oral
communications. The plan shall include: [Violation Risk Factor: Medium] [Time Horizon: Operations
Planning]
1.1 Identification of security protection used to mitigate the risk of unauthorized disclosure or
modification of Real-time Assessment and Real-time monitoring and control data while being
transmitted between Control Centers;
1.2 Identification of demarcation point(s) where the Responsible Entity applied security protection is
applied for transmitting Real-time Assessment and Real-time monitoring and control data between
Control Centers; and
1.3 If Identification of roles and responsibilities of each Responsbile Entity for applying security
protection to the transmission of Real-time Assessmsnet and Real-time monitoring and control data
between Control Centers, when the Control Centers are owned or operated by different Responsible
Entities,identify the responsibilities of each Responsible Entity for applying security protection to the
transmission of Real-time Assessment and Real-time monitoring data between those Control
Centers.

General Considerations for Requirement R1
Requirement R1 focuses on developing implementing a document plan to protect information that is critical to the
realReal-time operations of the Bulk Electric System while in transit between applicable Control Centers. The SDT
does not intend for the listed order of the three requirement parts to convey any sequence or significance.
Overview of confidentiality and integrity
The SDT drafted CIP-012-1 to address confidentiality and integrity of Real-time Assessment and Real-time monitoring
and Control data. This is accomplished by drafting the requirement to mitigate the risk of unauthorized disclosure
(confidentiality) or modification (integrity). For this Standard, the SDT relied on the definitions of confidentiality and
integrity as defined by National Institute of Standards and Technology (NIST):
•

Confidentiality is defined as, “Preserving authorized restrictions on information access and disclosure,
including means for protecting personal privacy and proprietary information.” 2

•

Integrity is defined as, “Guarding against improper information modification or destruction, and includes
ensuring information non-repudiation and authenticity.” 3

The SDT asserts that the availability of this data is already required by the performance obligation of the Operating
and Planning Reliability Standards. The SDT drafted CIP-012 to address the data while being transmitted. The SDT
maintains that this data resides within BES Cyber Systems, and while at rest is protected by CIP-003 through CIP-011.
Alignment with IRO and TOP standards
The SDT recognized the FERC reference to additional Reliability Standards and the responsibilities to protect the
applicable data in accordance with NERC Reliability Standards TOP-003 and IRO-010. The SDT used these references
2
3

NIST Special Publication 800-53A, Revision 4, page B-3
NIST Special Publication 800-53A, Revision 4, page B-6
NERC | Technical Rationale and Justification for Relaibility Standard CIP-002-1| November 2017March 2018
1

0 Requirement R1

to drive the identification of sensitive BES data and chose to base the CIP-012 requirements on the Real-time data
specification elements in these standards. This approach provides consistent scoping of identified data, and does not
require each entity to devise its own list or inventory of this data. Many entities are required to provide this data
under agreements executed with their RC, BA or TOP., often without benfit of knowing how those entities use that
data. The SDT notes that it expanded the phrase “Real-time monitoring” data from TOP-003 and IRO-010 to “Realtime monitoring and control” data. The SDT was concerned that data transmitted between Control Centers that
results in the physical operation of BES Elements was not explicitly included in Real-time monitoring data. The SDT
understands that in practice Real-time control data is not transmitted separately from Real-time monitoring data.
However, the SDT wanted to ensure that Real-time control data was included regardless of whether or not it is
transmitted along with Real-time monitoring data. If entities only transmit Real-time control data along with Realtime monitoring data, then the SDT does not intend for such entities to identify additional data beyond that Realtime monitoring data already included in the data specifications for TOP-003 and IRO-010. The SDT asserts that
typically the RC, BA or TOP will identify all data requiring protection for CIP-012-1 through the TOP-003 and IRO-010
Reliability Standards. However, the SDT noted that there may be special instances during which Real-time
Assessment or Real-time Monitoring data is not identified by the RC, BA, or TOP. This would include data that may
be exchanged between a Responsible Entity’s primary and backup Control Center.
Demarcation Points
The SDT noted the need for an entity to identify a demarcation point inside each Control Center where it will apply
protection for applicable data. The SDT used the demarcation point concept for implementing protection to ensure
entities could still take advantage of security measures, such as deep packet inspection, already implemented at or
near the EAP when ESPs are present, while maintaining the capability to protect the applicable data being transmitted
between Control Centers.
Identification of Where Security Protection is Applied by the Responsible Entity
The SDT noted the need for a Responsible Entity to identify where it will apply protection for applicable data. The
SDT did not specify the location where CIP-012 security protection must be applied to provide latitude for Responsible
Entities to implement the security controls in a manner best fitting their individual circumstances. This latitude
ensures entities can still take advantage of security measures, such as deep packet inspection implemented at or near
the EAP when ESPs are present, while maintaining the capability to protect the applicable data being transmitted
between Control Centers.
The SDT also recognizes that CIP-012 security protection may be applied to a Cyber Asset that is not an identified BES
Cyber Asset or EACMS. The identification of the Cyber Asset as the location where security protection is applied does
not expand the scope of Cyber Assets identified as applicable under the CIP Cyber Security Standards CIP-002 through
CIP-011.
The SDT understands that in data exchanges between Control Centers, a single entity may not be responsible for both
ends of the communication link. The SDT intends for a Responsible Entity to identify only where it applied security
protection. The Responsible Entity should not be held accountable for identifying where a neighboring entity applied
security protection at the neighboring entity’s facility. A Responsible Entity, however, may decide to take
responsibility for both ends of a communication link. For example, it may place a router in a neighboring entity’s data
center. In a scenario like this, where a Responsible Entity has taken responsibility for applying security protection on
both ends of the communication link, the Responsible Entity should identify where it applied security protection at
both ends of the link. The SDT intends for there to be alignment between the identification of where security
protection is applied in CIP-012 R1, Part 1.2 and the identification of Responsible Entity responsibilities in CIP-012 R1,
Part 1.3.

NERC | Technical Rationale and Justification for Relaibility Standard CIP-002-1| November 2017March 2018
2

0 Requirement R1

Control Center Ownership
The requirements address protection for Real-time Assessment and Real-time monitoring and control data while
being transmitted between Control Centers owned by a single Responsible Entity. They also cover the applicable data
transmitted between Control Centers owned by two or more separate Responsible Entities. Unlike protection
between a single Responsible Entity’s Control Centers, applying protection between Control Centers owned by more
than one Responsible Entity requires additional coordination. The requirements do not explicitly require formal
agreements between Responsible Entities partnering for protection of applicable data. It is strongly recommended,
however, that these partnering entities develop agreements, or use existing ones, to define responsibilities to ensure
adequate protection is applied the security objective is met. An example noted in FERC Order No. 822 Paragraph 59
is, “if several registered entities have joint responsibility for a cryptographic key management system used between
their respective Control Centers, they should have the prerogative to come to a consensus on which organization
administers that particular key management system."
As an example, the reference model below depicts shows some of the data transmissions between Control Centers
that a Responsible Entity should consider to be in-scope. The example does not include all possible scenarios. The
solid green lines are in-scope communications. The dashed red lines are out-of-scope communications.

This reference model is an example and does not include all possible scenarios.

NERC | Technical Rationale and Justification for Relaibility Standard CIP-002-1| November 2017March 2018
3

References
Here are several references to assist entities in developing plan(s) for protection of communication links:
• NIST Special Publication 800-53A, Revision 4: Security and Privacy Controls for Federal Information Systems
and Organizations
• NIST Special Publication 800-82: Guide to Industrial Control Systems (ICS) Security
• NIST Special Publication 800-175B: Guideline for Using Cryptographic Standards in the Federal Government:
Cryptographic Mechanisms
• NIST Special Publication 800-47: Security Guide for Interconnecting Information Technology Systems

NERC | Technical Rationale and Justification for Relaibility Standard CIP-002-1| November 2017March 2018
4

Reliability Standard Audit Worksheet1
CIP-012-1 – Cyber Security – Communications between Control Centers
This section to be completed by the Compliance Enforcement Authority.
Audit ID:
Registered Entity:
NCR Number:
Compliance Enforcement Authority:
Compliance Assessment Date(s) 2:
Compliance Monitoring Method:
Names of Auditors:

Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
Registered name of entity being audited
NCRnnnnn
Region or NERC performing audit
Month DD, YYYY, to Month DD, YYYY
[On-site Audit | Off-site Audit | Spot Check]
Supplied by CEA

Applicability of Requirements
R1

BA
X

DP

GO
X

GOP
X

PA/PC

RC
X

Legend:
Text with blue background:
Text entry area with Green background:
Text entry area with white background:

RP

RSG

TO
X

TOP
X

TP

TSP

Fixed text – do not edit
Entity-supplied information
Auditor-supplied information

1 NERC developed this Reliability Standard Audit Worksheet (RSAW) language in order to facilitate NERC’s and the Regional Entities’ assessment of a registered entity’s
compliance with this Reliability Standard. The NERC RSAW language is written to specific versions of each NERC Reliability Standard. Entities using this RSAW should
choose the version of the RSAW applicable to the Reliability Standard being assessed. While the information included in this RSAW provides some of the methodology
that NERC has elected to use to assess compliance with the requirements of the Reliability Standard, this document should not be treated as a substitute for the
Reliability Standard or viewed as additional Reliability Standard requirements. In all cases, the Regional Entity should rely on the language contained in the Reliability
Standard itself, and not on the language contained in this RSAW, to determine compliance with the Reliability Standard. NERC’s Reliability Standards can be found on
NERC’s website. Additionally, NERC Reliability Standards are updated frequently, and this RSAW may not necessarily be updated with the same frequency. Therefore,
it is imperative that entities treat this RSAW as a reference document only, and not as a substitute or replacement for the Reliability Standard. It is the responsibility
of the registered entity to verify its compliance with the latest approved version of the Reliability Standards, by the applicable governmental authority, relevant to its
registration status.

The RSAW may provide a non-exclusive list, for informational purposes only, of examples of the types of evidence a registered entity may produce or may be asked to
produce to demonstrate compliance with the Reliability Standard. A registered entity’s adherence to the examples contained within this RSAW does not necessarily
constitute compliance with the applicable Reliability Standard, and NERC and the Regional Entity using this RSAW reserve the right to request additional evidence from
the registered entity that is not included in this RSAW. This RSAW may include excerpts from FERC Orders and other regulatory references which are provided for ease
of reference only, and this document does not necessarily include all applicable Order provisions. In the event of a discrepancy between FERC Orders, and the language
included in this document, FERC Orders shall prevail.
2

Compliance Assessment Date(s): The date(s) the actual compliance assessment (on-site audit, off-site spot check, etc.) occurs.

DRAFT NERC Reliability Standard Audit Worksheet

Findings
(This section to be completed by the Compliance Enforcement Authority)
Req.
Finding
Summary and Documentation
R1

Req.

Areas of Concern

Req.

Recommendations

Req.

Positive Observations

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft3_v2Revision Date: April 25, 2018 RSAW Template: RSAW2017R3.0
2

Functions Monitored

DRAFT NERC Reliability Standard Audit Worksheet

Subject Matter Experts
Identify the Subject Matter Expert(s) responsible for this Reliability Standard.
Registered Entity Response (Required; Insert additional rows if needed):
SME Name
Title
Organization

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
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Requirement(s)

DRAFT NERC Reliability Standard Audit Worksheet

Registered Entity Response (Required):
Question 1: Does the Registered Entity own or operate a Control Center? ☐ Yes ☐ No
If no:
1. Provide evidence in the space that the Registered Entity does not own or operate one or more Control
Centers. This evidence may include, but is not limited to:
• Evidence that the Registered Entity does not own or operate a Control Center; or
• Evidence or a reference to evidence from the Registered Entity’s CIP-002 compliance program
that demonstrates the entity does not own or operate a Control Center.
2. The remainder of this RSAW may be left blank.
[Note: A separate spreadsheet or other document may be used. If so, provide the document reference
below.]

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft3_v2Revision Date: April 25, 2018 RSAW Template: RSAW2017R3.0
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DRAFT NERC Reliability Standard Audit Worksheet

R1 Supporting Evidence and Documentation
R1.

M1.

The Responsible Entity shall implement one or more documented plan(s) to mitigate the risk of unauthorized
disclosure or modification of Real-time Assessment and Real-time monitoring data while being transmitted
between any Control Centers. This requirement excludes oral communications. The plan shall include: [Violation
Risk Factor: Medium] [Time Horizon: Operations Planning]
1.1

Identification of security protection used to mitigate the risk of unauthorized disclosure or modification of
Real-time Assessment and Real-time monitoring data while being transmitted between Control Centers;

1.2

Identification of where the Responsible Entity applied security protection for transmitting Real-time
Assessment and Real-time monitoring data between Control Centers; and

1.3

If the Control Centers are owned or operated by different Responsible Entities, identify the responsibilities
of each Responsible Entity for applying security protection to the transmission of Real-time Assessment
and Real-time monitoring data between those Control Centers.

Evidence may include, but is not limited to, documented plan(s) that meet the security objective of Requirement
R1 and documentation demonstrating the implementation of the plan(s).

Registered Entity Response (Required):
Compliance Narrative:

Provide a brief explanation, in your own words, of how you comply with this Requirement. References to supplied
evidence, including links to the appropriate page, are recommended.

Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.
Relevant
Revision
Page(s)
or
Document
or
Description of Applicability
File Name
Document Title
Version
Date
Section(s)
of Document

Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft3_v2Revision Date: April 25, 2018 RSAW Template: RSAW2017R3.0
5

DRAFT NERC Reliability Standard Audit Worksheet

Compliance Assessment Approach Specific to CIP-012-1, R1
This section to be completed by the Compliance Enforcement Authority
If the Registered Entity has answered “No” to Question 1, verify the Registered Entity does not own or
operate a Control Center.
Note: If the Registered Entity does not own or operate a Control Center, the remainder of this RSAW is
not applicable.
Verify the entity has implemented one or more documented plan(s) to mitigate the risk of the
unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring data while
being transmitted between Control Centers.
Verify the documented plans collectively include identification of security protection used to mitigate
the risk of unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring
data while being transmitted between Control Centers.
Verify the documented plans collectively include identification of where the Responsible Entity applied
security protection for transmitting Real-time Assessment and Real-time monitoring data between
Control Centers.
Verify the documented plans collectively include identification of responsibilities of each Responsible
Entity for applying security protection to the transmission of Real-time Assessment and Real-time
monitoring data between Control Centers, when the Control Centers are owned or operated by
different Responsible Entities.
Verify the documented plans collectively achieve the security objective of mitigating the risk of the
unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring data while
being transmitted between Control Centers.
Note to Auditor:
1. Oral communications are not in scope for CIP-012-1.
Auditor Notes:

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
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DRAFT NERC Reliability Standard Audit Worksheet

Additional Information:
Reliability Standard
The full text of CIP-012-1 may be found on the NERC Web Site (www.nerc.com) under “Program Areas &
Departments”, “Standards,” “Reliability Standards.”
In addition to the Reliability Standard, there is an applicable Implementation Plan available on the NERC Web
Site.
In addition to the Reliability Standard, there is background information available on the NERC Web Site.
Capitalized terms in the Reliability Standard refer to terms in the NERC Glossary, which may be found on the
NERC Web Site.
Sampling Methodology
Sampling is essential for auditing compliance with NERC Reliability Standards since it is not always possible
or practical to test 100% of either the equipment, documentation, or both, associated with the full suite of
enforceable standards. The Sampling Guide contained in the Compliance Monitoring and Enforcement Manual
(see NERC website) provided by the Electric Reliability Organization help to establish a minimum sample set
for monitoring and enforcement uses in audits of NERC Reliability Standards.
Regulatory Language
FERC Order 822 P53-56, 58, and 62
Selected Glossary Terms
The following Glossary terms are provided for convenience only. Please refer to the NERC web site for the
current enforceable terms.
Control Center
One or more facilities, including their associated data centers, that monitor and control the Bulk Electric
System (BES) and also host operating personnel who:
1) perform the Real-time reliability-related tasks of a Reliability Coordinator; or
2) perform the Real-time reliability-related tasks of a Balancing Authority; or
3) perform the Real-time reliability-related tasks of a Transmission Operator for Transmission Facilities at
two or more locations; or
4) can act independently as the Generator Operator to develop specific dispatch instructions for
generation Facilities at two or more locations; or
5) can operate or direct the operation of a Transmission Owner’s BES Transmission Facilities in Real-time.
Operating personnel do not include:
1) plant operators located at a generator plant site or personnel at a centrally located dispatch center
who relay dispatch instructions without making any modifications; or
2) Transmission Owner or Transmission Operator field switching personnel.
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
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DRAFT NERC Reliability Standard Audit Worksheet

Real-time Assessment
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.)
Real-time
Present time as opposed to future time.

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
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DRAFT NERC Reliability Standard Audit Worksheet

Revision History for RSAW
Version
Draft1 v1
Draft1 v2
Draft1 v3

Date
07/28/2017
08/01/2017
08/02/2017

Reviewers
NERC Stds Group
RSAW Task Force
RSAW Task Force

Draft1 v4

08/07/2017

RSAW Task Force,
2016-02 SDT

Draft2 v1

10/27/2017

RSAW Task Force

Draft2 v2

11/27/2017

RSAW Task Force,
Standard Drafting
Team

Draft3 v0

03/20/2018

RSAW Task Force

Revision Description
New document
Modified Question to clarify applicability
Response to MRO comments. Moved Questions
1 and 2 above R1. Made text changes to Q1 and
to R2 Compliance Assessment Approach.
Response to TexasRE and SDT comments.
Clarified scope of Q1 to be data transmitted
between Control Centers. Removed extra space
from Auditor Notes.
Modified title.
Modified Q2 to conform with new language.
Modified R1 with new Requirement text and new
Compliance Assessment Approach.
Modified R2 with new Compliance Assessment
Approach.
Removed Operational Planning Analysis from the
Selected Glossary Terms.
Modified footer with revised version and date.
Response to comments:
• RF: Footnote 1 page 1 added space after
“references.”
• RF: Changed “Tasf” to “Task” in Revision
History.
• Response to SERC CIPC and Southern
Company comments to Draft 1.
• Modified Question 1 to include reference
to CIP-002.
• Added an item to the R1 Compliance
Assessment Approach to verify the
effectiveness of the process.
• Modified the R2 Compliance Assessment
Approaches to clarify that the review is
for implementation.
Modified for Draft 3 language:
• Removed Requirement R2
• Modified Requirement R1 language to
match the Standard
• Modified the R1 Compliannce Assessment
Approach

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
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DRAFT NERC Reliability Standard Audit Worksheet

•

Draft3 v1

04/03/2018

ERO Enterprise

Draft3 v2

4/25/2018

NERC Legal

Removed “CIP Exceptional Circumstance”
from the Selected Glossary Terms
• Revised the definition of “Control Center”
in Selected Glossary Terms to match the
definition posted alongside CIP-012-1
Draft 3
• Consideration of Comments from RF
o Changed Sampling Methodology
section to match current NERC
documents. Will also need to be
reflected in the RSAW Template.
Addressed comments. No text changes were
made.

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft3_v2Revision Date: April 25, 2018 RSAW Template: RSAW2017R3.0
10

Reliability Standard Audit Worksheet1
CIP-012-1 – Cyber Security – Communications between Control Centers
This section to be completed by the Compliance Enforcement Authority.
Audit ID:
Registered Entity:
NCR Number:
Compliance Enforcement Authority:
Compliance Assessment Date(s) 2:
Compliance Monitoring Method:
Names of Auditors:

Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
Registered name of entity being audited
NCRnnnnn
Region or NERC performing audit
Month DD, YYYY, to Month DD, YYYY
[On-site Audit | Off-site Audit | Spot Check]
Supplied by CEA

Applicability of Requirements
R1
R2

BA
X
X

DP

GO
X
X

GOP
X
X

PA/PC

RC
X
X

Legend:
Text with blue background:
Text entry area with Green background:
Text entry area with white background:

RP

RSG

TO
X
X

TOP
X
X

TP

TSP

Fixed text – do not edit
Entity-supplied information
Auditor-supplied information

1 NERC developed this Reliability Standard Audit Worksheet (RSAW) language in order to facilitate NERC’s and the Regional Entities’ assessment of a registered entity’s
compliance with this Reliability Standard. The NERC RSAW language is written to specific versions of each NERC Reliability Standard. Entities using this RSAW should
choose the version of the RSAW applicable to the Reliability Standard being assessed. While the information included in this RSAW provides some of the methodology
that NERC has elected to use to assess compliance with the requirements of the Reliability Standard, this document should not be treated as a substitute for the
Reliability Standard or viewed as additional Reliability Standard requirements. In all cases, the Regional Entity should rely on the language contained in the Reliability
Standard itself, and not on the language contained in this RSAW, to determine compliance with the Reliability Standard. NERC’s Reliability Standards can be found on
NERC’s website. Additionally, NERC Reliability Standards are updated frequently, and this RSAW may not necessarily be updated with the same frequency. Therefore,
it is imperative that entities treat this RSAW as a reference document only, and not as a substitute or replacement for the Reliability Standard. It is the responsibility
of the registered entity to verify its compliance with the latest approved version of the Reliability Standards, by the applicable governmental authority, relevant to its
registration status.

The RSAW may provide a non-exclusive list, for informational purposes only, of examples of the types of evidence a registered entity may produce or may be asked to
produce to demonstrate compliance with the Reliability Standard. A registered entity’s adherence to the examples contained within this RSAW does not necessarily
constitute compliance with the applicable Reliability Standard, and NERC and the Regional Entity using this RSAW reserve the right to request additional evidence from
the registered entity that is not included in this RSAW. This RSAW may include excerpts from FERC Orders and other regulatory references which are provided for ease
of reference only, and this document does not necessarily include all applicable Order provisions. In the event of a discrepancy between FERC Orders, and the language
included in this document, FERC Orders shall prevail.
2

Compliance Assessment Date(s): The date(s) the actual compliance assessment (on-site audit, off-site spot check, etc.) occurs.

DRAFT NERC Reliability Standard Audit Worksheet

Findings
(This section to be completed by the Compliance Enforcement Authority)
Req.
Finding
Summary and Documentation
R1
R2

Req.

Areas of Concern

Req.

Recommendations

Req.

Positive Observations

Functions Monitored

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft2_v2 3_v210Revision Date: November 27, 2017April 254March 20, 2018 RSAW Template: RSAW2017R3.0
2

DRAFT NERC Reliability Standard Audit Worksheet

Subject Matter Experts
Identify the Subject Matter Expert(s) responsible for this Reliability Standard.
Registered Entity Response (Required; Insert additional rows if needed):
SME Name
Title
Organization

Requirement(s)

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft2_v2 3_v210Revision Date: November 27, 2017April 254March 20, 2018 RSAW Template: RSAW2017R3.0
3

DRAFT NERC Reliability Standard Audit Worksheet

Registered Entity Response (Required):
Question 1: Does the Registered Entity own or operate a Control Center? ☐ Yes ☐ No
If no:
1. Provide evidence in the space that the Registered Entity does not own or operate one or more Control
Centers. This evidence may include, but is not limited to:
• Evidence that the Registered Entity does not own or operate a Control Center; or
• Evidence or a reference to evidence from the Registered Entity’s CIP-002 compliance program
that demonstrates the entity does not own or operate a Control Center.[A1][A2]
2. The remainder of this RSAW may be left blank.
[Note: A separate spreadsheet or other document may be used. If so, provide the document reference
below.]

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft2_v2 3_v210Revision Date: November 27, 2017April 254March 20, 2018 RSAW Template: RSAW2017R3.0
4

DRAFT NERC Reliability Standard Audit Worksheet

R1 Supporting Evidence and Documentation
R1.

M1.

The Responsible Entity shall develop implement one or more documented plan(s) to mitigate the risk of
unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring and control data
while being transmitted between any Control Centers. This requirement excludes oral communications. The plan
shall include: [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]
1.1

Identification of security protection used to mitigate the risk of unauthorized disclosure or modification of
Real-time Assessment and Real-time monitoring and control data while being transmitted between
Control Centers;

1.2

Identification of demarcation point(s) where the Responsible Entity applied security protection is applied
for transmitting Real-time Assessment and Real-time monitoring and control data between Control
Centers; and

1.3

If Identification of roles and responsibilities of each Responsible Entity for applying security protection to
the transmission of Real-time Assessment and Real-time monitoring and control data between Control
Centers, when the Control Centers are owned or operated by different Responsible Entities, identify the
responsibilities of each Responsible Entity for applying security protection to the transmission of Real-time
Assessment and Real-time monitoring data between those Control Centers.

Evidence may include, but is not limited to, documented plan(s) that meet the security objective of Requirement
R1 and documentation demonstrating the implementation of the plan(s).

Registered Entity Response (Required):
Compliance Narrative:

Provide a brief explanation, in your own words, of how you comply with this Requirement. References to supplied
evidence, including links to the appropriate page, are recommended.

Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.
Relevant
Revision
Page(s)
or
Document
or
Description of Applicability
File Name
Document Title
Version
Date
Section(s)
of Document

Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft2_v2 3_v210Revision Date: November 27, 2017April 254March 20, 2018 RSAW Template: RSAW2017R3.0
5

DRAFT NERC Reliability Standard Audit Worksheet

Compliance Assessment Approach Specific to CIP-012-1, R1
This section to be completed by the Compliance Enforcement Authority
If the Registered Entity has answered “No” to Question 1, verify the Registered Entity does not own or
operate a Control Center.
Note: If the Registered Entity does not own or operate a Control Center, the remainder of this RSAW is
not applicable.
Verify the entity has developed implemented one or more documented plan(s) to mitigate the risk of
the unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring and
control data while being transmitted between Control Centers.
Verify the documented plans collectively include identification of security protection used to mitigate
the risk of unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring
and control data while being transmitted between Control Centers.
Verify the documented plans collectively include identification of demarcation point(s) where the
Responsible Entity applied security protection is applied for transmitting Real-time Assessment and
Real-time monitoring and control data between Control Centers.
Verify the documented plans collectively include identification of roles and responsibilities of each
Responsible Entity for applying security protection to the transmission of Real-time Assessment and
Real-time monitoring and control data between Control Centers, when the Control Centers are owned
or operated by different Responsible Entities.
Verify the documented plans collectively achieve the security objective of mitigating the risk of the
unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring and control
data while being transmitted between Control Centers.[A3][A4]
Note to Auditor:
1. Oral communications are not in scope for CIP-012-1.
Auditor Notes:

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft2_v2 3_v210Revision Date: November 27, 2017April 254March 20, 2018 RSAW Template: RSAW2017R3.0
6

DRAFT NERC Reliability Standard Audit Worksheet

R2 Supporting Evidence and Documentation
R2.

The Responsible Entity shall implement the plan(s) specified in Requirement R1, except under CIP Exceptional
Circumstances.

M2.

Evidence may include, but is not limited to, documentation to demonstrate implementation of methods to
mitigate the risk of the unauthorized disclosure or modification of data in Requirement R1.

Registered Entity Response (Required):
Compliance Narrative:

Provide a brief explanation, in your own words, of how you comply with this Requirement. References to supplied
evidence, including links to the appropriate page, are recommended.

Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.
Relevant
Revision
Page(s)
or
Document
or
Description of Applicability
File Name
Document Title
Version
Date
Section(s)
of Document

Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft2_v2 3_v210Revision Date: November 27, 2017April 254March 20, 2018 RSAW Template: RSAW2017R3.0
7

DRAFT NERC Reliability Standard Audit Worksheet

Compliance Assessment Approach Specific to CIP-012-1, R2
This section to be completed by the Compliance Enforcement Authority
Verify the entity has implemented one or more documented plan(s) to mitigate the risk of the
unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring and control
data while being transmitted between Control Centers.
Verify the entity has implemented the identified security protection used to mitigate the risk of
unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring and control
data while being transmitted between Control Centers.
Verify the entity has implemented the identified security protection at the identified demarcation
point(s) where security protection is applied for transmitting Real-time Assessment and Real-time
monitoring and control data between Control Centers; and
If Control Centers are not owned and operated by the same Responsible Entity, verify the entity has
identified roles and responsibilities of each Responsible Entity for applying security protection to the
transmission of Real-time Assessment and Real-time monitoring and control data between Control
Centers.
If the Responsible Entity has declared and responded to CIP Exceptional Circumstances, verify the
Responsible Entity has adhered to the applicable cyber security policies.
Note to Auditor:
The Responsible Entity may reference a separate set of documents to demonstrate its response to any
requirements impacted by CIP Exceptional Circumstances.
Auditor Notes:

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft2_v2 3_v210Revision Date: November 27, 2017April 254March 20, 2018 RSAW Template: RSAW2017R3.0
8

DRAFT NERC Reliability Standard Audit Worksheet

Additional Information:
Reliability Standard
The full text of CIP-012-1 may be found on the NERC Web Site (www.nerc.com) under “Program Areas &
Departments”, “Standards,” “Reliability Standards.”
In addition to the Reliability Standard, there is an applicable Implementation Plan available on the NERC Web
Site.
In addition to the Reliability Standard, there is background information available on the NERC Web Site.
Capitalized terms in the Reliability Standard refer to terms in the NERC Glossary, which may be found on the
NERC Web Site.
Sampling Methodology
Sampling is essential for auditing compliance with NERC Reliability Standards since it is not always possible
or practical to test 100% of either the equipment, documentation, or both, associated with the full suite of
enforceable standards. The Sampling Guide contained in the Compliance Monitoring and Enforcement Manual
Methodology Guidelines and Criteria (see NERC website), or sample guidelines, provided by the Electric
Reliability Organization help to establish a minimum sample set for monitoring and enforcement uses in audits
of NERC Reliability Standards.
Regulatory Language
FERC Order 822 P53-56, 58, and 62
Selected Glossary Terms
The following Glossary terms are provided for convenience only. Please refer to the NERC web site for the
current enforceable terms.
CIP Exceptional Circumstance
A situation that involves or threatens to involve one or more of the following, or similar, conditions that
impact safety or BES reliability: a risk of injury or death; a natural disaster; civil unrest; an imminent or existing
hardware, software, or equipment failure; a Cyber Security Incident requiring emergency assistance; a
response by emergency services; the enactment of a mutual assistance agreement; or an impediment of large
scale workforce availability.
Control Center
One or more facilities hosting operating personnel that monitor and control the Bulk Electric System (BES) in
real-time to perform the reliability tasks, including their associated data centers, of: 1) a Reliability
Coordinator, 2) a Balancing Authority, 3) a Transmission Operator for transmission Facilities at two or more
locations, or 4) a Generator Operator for generation Facilities at two or more locations.
One or more facilities, including their associated data centers, that monitor and control the Bulk Electric
System (BES) and also host operating personnel who:
1) perform the Real-time reliability-related tasks of a Reliability Coordinator; or
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft2_v2 3_v210Revision Date: November 27, 2017April 254March 20, 2018 RSAW Template: RSAW2017R3.0
9

DRAFT NERC Reliability Standard Audit Worksheet

2) perform the Real-time reliability-related tasks of a Balancing Authority; or
3) perform the Real-time reliability-related tasks of a Transmission Operator for Transmission Facilities at
two or more locations; or
4) can act independently as the Generator Operator to develop specific dispatch instructions for
generation Facilities at two or more locations; or
5) can operate or direct the operation of a Transmission Owner’s BES Transmission Facilities in Real-time.
Operating personnel do not include:
1) plant operators located at a generator plant site or personnel at a centrally located dispatch center
who relay dispatch instructions without making any modifications; or
1) Transmission Owner or Transmission Operator field switching personnel.
2)
Real-time Assessment
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.)
Real-time
Present time as opposed to future time.

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft2_v2 3_v210Revision Date: November 27, 2017April 254March 20, 2018 RSAW Template: RSAW2017R3.0
10

DRAFT NERC Reliability Standard Audit Worksheet

Revision History for RSAW
Version
Draft1 v1
Draft1 v2
Draft1 v3

Date
07/28/2017
08/01/2017
08/02/2017

Reviewers
NERC Stds Group
RSAW Task Force
RSAW Task Force

Draft1 v4

08/07/2017

RSAW Task Force,
2016-02 SDT

Draft2 v1

10/27/2017

RSAW Task Force

Draft2 v2

11/27/2017

RSAW Task Force,
Standard Drafting
Team

Draft3 v0

03/20/2018

RSAW Task Force

Revision Description
New document
Modified Question to clarify applicability
Response to MRO comments. Moved Questions
1 and 2 above R1. Made text changes to Q1 and
to R2 Compliance Assessment Approach.
Response to TexasRE and SDT comments.
Clarified scope of Q1 to be data transmitted
between Control Centers. Removed extra space
from Auditor Notes.
Modified title.
Modified Q2 to conform with new language.
Modified R1 with new Requirement text and new
Compliance Assessment Approach.
Modified R2 with new Compliance Assessment
Approach.
Removed Operational Planning Analysis from the
Selected Glossary Terms.
Modified footer with revised version and date.
Response to comments:
• RF: Footnote 1 page 1 added space after
“references.”
• RF: Changed “Tasf” to “Task” in Revision
History.
• Response to SERC CIPC and Southern
Company comments to Draft 1.
• Modified Question 1 to include reference
to CIP-002.
• Added an item to the R1 Compliance
Assessment Approach to verify the
effectiveness of the process.
• Modified the R2 Compliance Assessment
Approaches to clarify that the review is
for implementation.
Modified for Draft 3 language:
• Removed Requirement R2
• Modified Requirement R1 language to
match the Standard
• Modified the R1 Complianaince
Assessment Approach

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft2_v2 3_v210Revision Date: November 27, 2017April 254March 20, 2018 RSAW Template: RSAW2017R3.0
11

DRAFT NERC Reliability Standard Audit Worksheet

•

Draft3 v1

04/03/2018

ERO Enterprise

Draft3 v2

4/25/2018

NERC Legal

Removed “CIP Exceptional Circumstance”
from the Selected Glossary Terms
• Revised the definition of “Control Center”
in Selected Glossary Terms to match the
definition posted alongside CIP-012-1
Draft 3
• Consideration of Comments from RF
o Changed Sampling Methodology
section to match current NERC
documents. Will also need to be
reflected in the RSAW Template.
Addressed comments. No text changes were
made.

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft2_v2 3_v210Revision Date: November 27, 2017April 254March 20, 2018 RSAW Template: RSAW2017R3.0
12

Standards Announcement
Reminder

Project 2016-02 Modifications to CIP Standards
Initial and Additional Ballots and Non-binding Polls Open through April 30, 2018
Now Available

Initial ballots for the Control Center Definition and its Implementation Plan, additional ballots for CIP002-6 and CIP-012-1 and the associated non-binding polls of the associated Violation Risk Factors and
Violation Severity Levels are open through 8 p.m. Eastern, Monday, April 30, 2018.
The standard drafting team’s considerations of the responses received from the last comment period
for CIP-002-6 and CIP-012-1 are reflected in these drafts of the standards.
Balloting

Members of the ballot pools associated with this project can log in and submit their votes by accessing
the Standards Balloting and Commenting System (SBS) here. If you experience any difficulties navigating
the SBS, contact Wendy Muller.
•

If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential
error messages, or system lock-out, contact NERC IT support directly at https://support.nerc.net/
(Monday – Friday, 8 a.m. - 5 p.m. Eastern).

•

Passwords expire every 6 months and must be reset.

•

The SBS is not supported for use on mobile devices.

•

Please be mindful of ballot and comment period closing dates. We ask to allow at least 48 hours
for NERC support staff to assist with inquiries. Therefore, it is recommended that users try logging
into their SBS accounts prior to the last day of a comment/ballot period.

Note: If a member cast a vote in the previous ballot, that vote will not carry over to the additional
ballot. It is the responsibility of the registered voter in the ballot pool to cast a vote again in the
additional ballot. To ensure a quorum is reached, if you do not want to vote affirmative or negative,
cast an abstention.
Next Steps

The ballot results will be announced and posted on the project page. The drafting team will review all
responses received during the comment period and determine the next steps of the project.

For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Mat Bunch at (404) 446-9785 or Jordan Mallory at (404) 4462589.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement | CIP-012-1 Ballot Open Reminder
Project 2016-02 Modifications to CIP Standards | December 1, 2017

2

Standards Announcement

Project 2016-02 Modifications to CIP Standards
Formal Comment Periods Open through April 30, 2018
Ballot Pools Forming through April 16, 2018
Now Available

Three formal comment periods are open through 8 p.m. Eastern, Monday, April 30, 2018 for:
1. CIP-002-6 – Cyber Security - BES Cyber System Categorization
2. CIP-012-1 – Cyber Security - Communications between Control Centers
3. Project 2016-02 Modifications to NERC Glossary of Terms Used in Reliability Standards – Control
Center
Commenting

Use the Standards Balloting and Commenting System (SBS) to submit comments. If you experience
difficulties navigating the SBS, contact Wendy Muller. Unofficial Word versions of the comment forms
are posted on the project page.
Ballot Pools

Ballot pools are being formed through 8 p.m. Eastern, Monday, April 16, 2018 for the Control Center
Definition and its Implementation Plan. Registered Ballot Body members can join the ballot pools
here.
•

If you are having difficulty accessing the SBS due to a forgotten password, incorrect
credential error messages, or system lock-out, contact NERC IT support directly at
https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5 p.m. Eastern).

•

Passwords expire every 6 months and must be reset.

•

The SBS is not supported for use on mobile devices.

•

Please be mindful of ballot and comment period closing dates. We ask to allow at least 48
hours for NERC support staff to assist with inquiries. Therefore, it is recommended that users try
logging into their SBS accounts prior to the last day of a comment/ballot period.

Next Steps

The initial ballots for the Control Center Definition and its Implementation Plan will be conducted
April 20-30, 2018. Additional ballots for CIP-002-6 and CIP-012-1 and the associated non-binding polls
of the associated Violation Risk Factors and Violation Severity Levels will be conducted April 20-30,
2018.
For information on the Standards Development Process, refer to the Standard Processes Manual.

For more information or assistance, contact Mat Bunch at (404) 446-9785 or Jordan Mallory at (404) 4462589.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | July-September, 2017

2

Index - NERC Balloting Tool

NERC Balloting Tool (/)

Page 1 of 18

Dashboard (/)

Users

Ballots

Comment Forms

Login (/Users/Login) / Register (/Users/Register)

BALLOT RESULTS
Comment: View Comment Results (/CommentResults/Index/130)
Ballot Name: 2016-02 Modifications to CIP Standards CIP-012-1 AB 3 ST
Voting Start Date: 4/20/2018 12:01:00 AM
Voting End Date: 4/30/2018 8:00:00 PM
Ballot Type: ST
Ballot Activity: AB
Ballot Series: 3
Total # Votes: 242
Total Ballot Pool: 309
Quorum: 78.32
Weighted Segment Value: 83.71

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Negative
Fraction
w/
Comment

Segment:
1

80

1

48

0.828

10

0.172

0

5

17

Segment:
2

7

0.6

5

0.5

1

0.1

0

0

1

Segment:
3

73

1

47

0.887

6

0.113

0

5

15

Segment:
4

17

1

12

0.857

2

0.143

0

1

2

Segment:
5

73

1

37

0.771

11

0.229

0

2

23

Segment:
6

46

1

27

0.75

9

0.25

0

2

8

Segment:
7

2

0.1

1

0.1

0

0

0

0

1

Segment:
8

3

0.3

3

0.3

0

0

0

0

0

Segment:
9

1

0.1

1

0.1

0

0

0

0

0

1

0.1

0

0

0

Segment

Segment: 7
0.7
6
0.6
© 2018
NERC
Ver
4.2.1.0
Machine
Name:
ERODVSBSWB01
10

https://sbs.nerc.net/BallotResults/Index/237

Negative
Votes
w/o
Comment

Abstain

No
Vote

9/10/2018

Index - NERC Balloting Tool

Page 2 of 18

Segment

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Totals:

309

6.8

187

5.692

40

Negative
Fraction
w/
Comment

Negative
Votes
w/o
Comment

Abstain

No
Vote

1.108

0

15

67

BALLOT POOL MEMBERS
Show All

Segment

 entries

Organization

Search: Search

Voter

Designated
Proxy

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Allete - Minnesota Power,
Inc.

Jamie Monette

Abstain

N/A

1

American Transmission
Company, LLC

Douglas Johnson

Affirmative

N/A

1

APS - Arizona Public Service
Co.

Michelle
Amarantos

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

John Shaver

Negative

Third-Party
Comments

1

Associated Electric
Cooperative, Inc.

Ryan Ziegler

Affirmative

N/A

1

Austin Energy

Thomas
Standifur

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Affirmative

N/A

1

Basin Electric Power
Cooperative

David Rudolph

None

N/A

1

BC Hydro and Power
Authority

Patricia
Robertson

Affirmative

N/A

Negative

Comments
Submitted

1
Berkshire Hathaway Energy
Terry Harbour
© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB01
- MidAmerican Energy Co.

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Joe Tarantino

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 3 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Bonneville Power
Administration

Kammy RogersHolliday

Affirmative

N/A

1

Brazos Electric Power
Cooperative, Inc.

Tony Kroskey

None

N/A

1

Cedar Falls Utilities

Adam Peterson

None

N/A

1

CenterPoint Energy Houston
Electric, LLC

Daniela
Hammons

Affirmative

N/A

1

Central Electric Power
Cooperative (Missouri)

Michael Bax

Affirmative

N/A

1

Central Hudson Gas &
Electric Corp.

Frank Pace

Negative

Third-Party
Comments

1

City Utilities of Springfield,
Missouri

Michael Buyce

Affirmative

N/A

1

CMS Energy - Consumers
Energy Company

James Anderson

Negative

Comments
Submitted

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Dominion - Dominion
Virginia Power

Larry Nash

Negative

Comments
Submitted

1

Duke Energy

Laura Lee

Negative

Comments
Submitted

1

Edison International Southern California Edison
Company

Steven Mavis

Affirmative

N/A

1

Entergy - Entergy Services,
Inc.

Oliver Burke

Negative

Comments
Submitted

1

Eversource Energy

Quintin Lee

Affirmative

N/A

1

Exelon

Chris Scanlon

Affirmative

N/A

1

FirstEnergy - FirstEnergy
Corporation

Karen Yoder

Affirmative

N/A

1

Great Plains Energy Kansas City Power and Light
Co.

James McBee

Affirmative

N/A

1

Great River Energy

Gordon Pietsch

None

N/A

Douglas Webb

© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB01

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 4 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Hydro One Networks, Inc.

Payam
Farahbakhsh

Affirmative

N/A

1

Hydro-Qu?bec TransEnergie

Nicolas Turcotte

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Laura Nelson

None

N/A

1

Imperial Irrigation District

Jesus Sammy
Alcaraz

None

N/A

1

International Transmission
Company Holdings
Corporation

Michael Moltane

Abstain

N/A

1

Lincoln Electric System

Danny Pudenz

Affirmative

N/A

1

Long Island Power Authority

Robert Ganley

None

N/A

1

Los Angeles Department of
Water and Power

faranak sarbaz

Affirmative

N/A

1

Lower Colorado River
Authority

Michael Shaw

Affirmative

N/A

1

M and A Electric Power
Cooperative

William Price

None

N/A

1

Manitoba Hydro

Mike Smith

Affirmative

N/A

1

MEAG Power

David Weekley

Abstain

N/A

1

Memphis Light, Gas and
Water Division

Allan Long

None

N/A

1

Minnkota Power Cooperative
Inc.

Theresa Allard

Affirmative

N/A

1

Muscatine Power and Water

Andy Kurriger

Affirmative

N/A

1

N.W. Electric Power
Cooperative, Inc.

Mark Ramsey

Affirmative

N/A

1

National Grid USA

Michael Jones

Affirmative

N/A

1

Nebraska Public Power
District

Jamison Cawley

Affirmative

N/A

1

New York Power Authority

Salvatore
Spagnolo

Affirmative

N/A

Affirmative

N/A

1

NextEra Energy - Florida
Mike ONeil
Power
and
Light
Co.
© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB01

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Stephanie Burns

Scott Miller

Andy Fuhrman

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 5 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

1

NiSource - Northern Indiana
Public Service Co.

Steve Toosevich

Affirmative

N/A

1

Northeast Missouri Electric
Power Cooperative

Kevin White

Affirmative

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Affirmative

N/A

1

Ohio Valley Electric
Corporation

Scott
Cunningham

Affirmative

N/A

1

Omaha Public Power District

Doug Peterchuck

None

N/A

1

Oncor Electric Delivery

Lee Maurer

Affirmative

N/A

1

OTP - Otter Tail Power
Company

Charles Wicklund

Affirmative

N/A

1

Peak Reliability

Scott Downey

None

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Laurie Williams

None

N/A

1

PPL Electric Utilities
Corporation

Brenda Truhe

Affirmative

N/A

1

PSEG - Public Service
Electric and Gas Co.

Joseph Smith

Affirmative

N/A

1

Public Utility District No. 1 of
Chelan County

Jeff Kimbell

Abstain

N/A

1

Public Utility District No. 1 of
Snohomish County

Long Duong

Affirmative

N/A

1

Puget Sound Energy, Inc.

Theresa
Rakowsky

None

N/A

1

Sacramento Municipal Utility
District

Arthur Starkovich

Affirmative

N/A

1

Salt River Project

Steven Cobb

None

N/A

1

Santee Cooper

Chris Wagner

None

N/A

1

SCANA - South Carolina
Electric and Gas Co.

Tom Hanzlik

None

N/A

1

Seattle City Light

Pawel Krupa

Affirmative

N/A

Tho Tran

Joe Tarantino

© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB01

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 6 of 18

Voter

1

Seminole Electric
Cooperative, Inc.

Mark Churilla

1

Sempra - San Diego Gas
and Electric

Mo Derbas

1

Sho-Me Power Electric
Cooperative

1

Designated
Proxy

Ballot

NERC
Memo

Abstain

N/A

None

N/A

Peter Dawson

Affirmative

N/A

Southern Company Southern Company
Services, Inc.

Katherine Prewitt

Affirmative

N/A

1

Southern Indiana Gas and
Electric Co.

Steve Rawlinson

Affirmative

N/A

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

Negative

Comments
Submitted

1

Tennessee Valley Authority

Howell Scott

Affirmative

N/A

1

Tri-State G and T
Association, Inc.

Tracy Sliman

Negative

Comments
Submitted

1

U.S. Bureau of Reclamation

Richard Jackson

Negative

Comments
Submitted

1

Westar Energy

Kevin Giles

Affirmative

N/A

1

Western Area Power
Administration

sean erickson

Affirmative

N/A

1

Xcel Energy, Inc.

Dean Schiro

Affirmative

N/A

2

California ISO

Richard Vine

Affirmative

N/A

2

Electric Reliability Council of
Texas, Inc.

Brandon Gleason

Affirmative

N/A

2

Independent Electricity
System Operator

Leonard Kula

Affirmative

N/A

2

ISO New England, Inc.

Michael Puscas

None

N/A

2

Midcontinent ISO, Inc.

Ellen Oswald

Negative

Comments
Submitted

2

New York Independent
System Operator

Gregory Campoli

Affirmative

N/A

2

PJM Interconnection, L.L.C.

Mark Holman

Affirmative

N/A

3 - NERC Ver 4.2.1.0
AEP Machine Name: ERODVSBSWB01
Aaron Austin
© 2018

Affirmative

N/A

https://sbs.nerc.net/BallotResults/Index/237

Jeff Johnson

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 7 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

3

AES - Indianapolis Power
and Light Co.

Bette White

Affirmative

N/A

3

APS - Arizona Public Service
Co.

Vivian Vo

Affirmative

N/A

3

Arkansas Electric
Cooperative Corporation

Philip Huff

Affirmative

N/A

3

Associated Electric
Cooperative, Inc.

Todd Bennett

Affirmative

N/A

3

Austin Energy

W. Dwayne
Preston

Affirmative

N/A

3

Basin Electric Power
Cooperative

Jeremy Voll

Affirmative

N/A

3

BC Hydro and Power
Authority

Hootan Jarollahi

Affirmative

N/A

3

Berkshire Hathaway Energy
- MidAmerican Energy Co.

Annette Johnston

Negative

Comments
Submitted

3

Bonneville Power
Administration

Rebecca Berdahl

Affirmative

N/A

3

Central Electric Power
Cooperative (Missouri)

Adam Weber

Affirmative

N/A

3

City of Farmington

Linda JacobsonQuinn

Abstain

N/A

3

City of Leesburg

Chris Adkins

None

N/A

3

City of Vero Beach

Ginny Beigel

Negative

Comments
Submitted

3

City Utilities of Springfield,
Missouri

Scott Williams

Affirmative

N/A

3

Cleco Corporation

Michelle Corley

Affirmative

N/A

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Affirmative

N/A

3

Cowlitz County PUD

Russell Noble

Negative

Comments
Submitted

3

Duke Energy

Lee Schuster

Negative

Comments
Submitted

Darnez
Gresham

Brandon
McCormick

Louis Guidry

© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB01

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 8 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Edison International Southern California Edison
Company

Romel Aquino

None

N/A

3

Empire District Electric Co.

Kalem Long

None

N/A

3

Eversource Energy

Mark Kenny

Affirmative

N/A

3

Exelon

John Bee

Affirmative

N/A

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

Affirmative

N/A

3

Georgia System Operations
Corporation

Scott McGough

Affirmative

N/A

3

Great Plains Energy Kansas City Power and Light
Co.

Jessica Tucker

Affirmative

N/A

3

Great River Energy

Brian Glover

Affirmative

N/A

3

Hydro One Networks, Inc.

Paul Malozewski

Affirmative

N/A

3

KAMO Electric Cooperative

Ted Hilmes

None

N/A

3

Lincoln Electric System

Jason Fortik

Affirmative

N/A

3

M and A Electric Power
Cooperative

Stephen Pogue

Affirmative

N/A

3

Manitoba Hydro

Karim AbdelHadi

Affirmative

N/A

3

MEAG Power

Roger Brand

Scott Miller

Abstain

N/A

3

Modesto Irrigation District

Jack Savage

Nick Braden

None

N/A

3

Muscatine Power and Water

Seth Shoemaker

Affirmative

N/A

3

National Grid USA

Brian Shanahan

Affirmative

N/A

3

Nebraska Public Power
District

Tony Eddleman

Affirmative

N/A

3

New York Power Authority

David Rivera

Affirmative

N/A

3

NiSource - Northern Indiana
Public Service Co.

Aimee Harris

Affirmative

N/A

3

North Carolina Electric
Membership Corporation

doug white

Affirmative

N/A

Douglas Webb

Scott Brame

© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB01

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 9 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Northeast Missouri Electric
Power Cooperative

Skyler
Wiegmann

Affirmative

N/A

3

NW Electric Power
Cooperative, Inc.

John Stickley

Affirmative

N/A

3

Ocala Utility Services

Neville Bowen

None

N/A

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Affirmative

N/A

3

OTP - Otter Tail Power
Company

Wendi Olson

Affirmative

N/A

3

Owensboro Municipal
Utilities

Thomas Lyons

None

N/A

3

Platte River Power Authority

Jeff Landis

Abstain

N/A

3

PNM Resources - Public
Service Company of New
Mexico

Lynn Goldstein

Affirmative

N/A

3

Portland General Electric
Co.

Angela Gaines

Affirmative

N/A

3

PPL - Louisville Gas and
Electric Co.

Charles Freibert

Affirmative

N/A

3

PSEG - Public Service
Electric and Gas Co.

Jeffrey Mueller

Affirmative

N/A

3

Public Utility District No. 1 of
Chelan County

Joyce Gundry

Abstain

N/A

3

Puget Sound Energy, Inc.

Tim Womack

None

N/A

3

Rutherford EMC

Tom Haire

None

N/A

3

Sacramento Municipal Utility
District

Nicole Looney

Affirmative

N/A

3

Salt River Project

Robert
Kondziolka

Negative

Comments
Submitted

3

Santee Cooper

James Poston

None

N/A

3

SCANA - South Carolina
Electric and Gas Co.

Scott Parker

None

N/A

3

Seattle City Light

Tuan Tran

Affirmative

N/A

Joe Tarantino

© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB01

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 10 of 18

Voter

3

Seminole Electric
Cooperative, Inc.

James Frauen

3

Sempra - San Diego Gas
and Electric

Bridget Silvia

3

Sho-Me Power Electric
Cooperative

3

Designated
Proxy

Ballot

NERC
Memo

Abstain

N/A

Affirmative

N/A

Jeff Neas

Affirmative

N/A

Silicon Valley Power - City of
Santa Clara

Val Ridad

None

N/A

3

Snohomish County PUD No.
1

Mark Oens

Affirmative

N/A

3

Southern Company Alabama Power Company

Joel Dembowski

Affirmative

N/A

3

Southern Indiana Gas and
Electric Co.

Fred Frederick

Affirmative

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

Marc Donaldson

Negative

Comments
Submitted

3

TECO - Tampa Electric Co.

Ronald Donahey

None

N/A

3

Tennessee Valley Authority

Ian Grant

None

N/A

3

Tri-State G and T
Association, Inc.

Janelle Marriott
Gill

None

N/A

3

WEC Energy Group, Inc.

Thomas Breene

Affirmative

N/A

3

Westar Energy

Bo Jones

Affirmative

N/A

3

Xcel Energy, Inc.

Michael Ibold

Affirmative

N/A

4

American Public Power
Association

Jack Cashin

None

N/A

4

Arkansas Electric
Cooperative Corporation

Alice Wright

Affirmative

N/A

4

Austin Energy

Esther Weekes

Affirmative

N/A

4

City of Clewiston

Lynne Mila

Negative

Comments
Submitted

4

City Utilities of Springfield,
Missouri

John Allen

Affirmative

N/A

Affirmative

N/A

4

FirstEnergy - FirstEnergy
Aubrey Short
Corporation
© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB01

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Harold Sherrill

Brandon
McCormick

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 11 of 18

Voter

4

Georgia System Operations
Corporation

Guy Andrews

4

Indiana Municipal Power
Agency

Jack Alvey

4

National Rural Electric
Cooperative Association

Barry Lawson

4

North Carolina Electric
Membership Corporation

John Lemire

4

Public Utility District No. 1 of
Snohomish County

John Martinsen

4

Sacramento Municipal Utility
District

Beth Tincher

4

Seattle City Light

4

Designated
Proxy

Ballot

NERC
Memo

Affirmative

N/A

Abstain

N/A

Affirmative

N/A

Affirmative

N/A

Affirmative

N/A

Affirmative

N/A

Hao Li

Affirmative

N/A

Seminole Electric
Cooperative, Inc.

Charles
Wubbena

None

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

Negative

Comments
Submitted

4

Utility Services, Inc.

Brian EvansMongeon

Affirmative

N/A

4

WEC Energy Group, Inc.

Anthony
Jankowski

Affirmative

N/A

5

Acciona Energy North
America

George Brown

Affirmative

N/A

5

AEP

Thomas Foltz

Affirmative

N/A

5

Ameren - Ameren Missouri

Sam Dwyer

Affirmative

N/A

5

APS - Arizona Public Service
Co.

Kelsi Rigby

Affirmative

N/A

5

Arkansas Electric
Cooperative Corporation

Moses Harris

Affirmative

N/A

5

Associated Electric
Cooperative, Inc.

Brad Haralson

None

N/A

5

Austin Energy

Shirley Mathew

None

N/A

5

Avista - Avista Corporation

Glen Farmer

Affirmative

N/A

Scott Berry

Scott Brame

Joe Tarantino

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 12 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Basin Electric Power
Cooperative

Mike Kraft

Affirmative

N/A

5

BC Hydro and Power
Authority

Helen Hamilton
Harding

None

N/A

5

Boise-Kuna Irrigation District
- Lucky Peak Power Plant
Project

Mike Kukla

Affirmative

N/A

5

Bonneville Power
Administration

Scott Winner

Affirmative

N/A

5

BP Wind Energy North
America Inc.

Carla Holly

None

N/A

5

Choctaw Generation Limited
Partnership, LLLP

Rob Watson

Affirmative

N/A

5

Cleco Corporation

Stephanie
Huffman

Affirmative

N/A

5

CMS Energy - Consumers
Energy Company

David
Greyerbiehl

Negative

Comments
Submitted

5

Colorado Springs Utilities

Jeff Icke

Negative

Comments
Submitted

5

Con Ed - Consolidated
Edison Co. of New York

William Winters

Affirmative

N/A

5

Dairyland Power
Cooperative

Tommy Drea

None

N/A

5

Dominion - Dominion
Resources, Inc.

Lou Oberski

Negative

Comments
Submitted

5

Duke Energy

Dale Goodwine

Negative

Comments
Submitted

5

Edison International Southern California Edison
Company

Selene Willis

None

N/A

5

EDP Renewables North
America LLC

Heather Morgan

Negative

Comments
Submitted

5

Entergy

Jamie Prater

Negative

Comments
Submitted

5

Exelon

Ruth Miller

Negative

Comments
Submitted

Louis Guidry

Alyson Slanover

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 13 of 18

Voter

5

FirstEnergy - FirstEnergy
Solutions

Robert Loy

5

Great Plains Energy Kansas City Power and Light
Co.

Harold Wyble

5

Great River Energy

5

Designated
Proxy

Ballot

NERC
Memo

Affirmative

N/A

Affirmative

N/A

Preston Walsh

Affirmative

N/A

Gridforce Energy
Management, LLC

David Blackshear

None

N/A

5

Hydro-Qu?bec Production

Junji Yamaguchi

None

N/A

5

JEA

John Babik

None

N/A

5

Kissimmee Utility Authority

Mike Blough

Negative

Comments
Submitted

5

Lakeland Electric

Jim Howard

None

N/A

5

Lincoln Electric System

Kayleigh
Wilkerson

Affirmative

N/A

5

Los Angeles Department of
Water and Power

Donald
Sievertson

Affirmative

N/A

5

Manitoba Hydro

Yuguang Xiao

Affirmative

N/A

5

Massachusetts Municipal
Wholesale Electric Company

David Gordon

Affirmative

N/A

5

MEAG Power

Steven Grego

Abstain

N/A

5

Muscatine Power and Water

Neal Nelson

Affirmative

N/A

5

NB Power Corporation

Laura McLeod

None

N/A

5

Nebraska Public Power
District

Don Schmit

Affirmative

N/A

5

New York Power Authority

Erick Barrios

Affirmative

N/A

5

NextEra Energy

Allen Schriver

None

N/A

5

NiSource - Northern Indiana
Public Service Co.

Dmitriy Bazylyuk

Affirmative

N/A

5

North Carolina Electric
Membership Corporation

Robert Beadle

Affirmative

N/A

Negative

Comments
Submitted

5

Northern California Power
Marty Hostler
Agency
© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB01

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Douglas Webb

Brandon
McCormick

Scott Miller

Scott Brame

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 14 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

5

OGE Energy - Oklahoma
Gas and Electric Co.

John Rhea

Affirmative

N/A

5

Omaha Public Power District

Mahmood Safi

Affirmative

N/A

5

Ontario Power Generation
Inc.

David
Ramkalawan

Affirmative

N/A

5

OTP - Otter Tail Power
Company

Cathy Fogale

Affirmative

N/A

5

Portland General Electric
Co.

Ryan Olson

Affirmative

N/A

5

PPL - Louisville Gas and
Electric Co.

JULIE
HOSTRANDER

Affirmative

N/A

5

PSEG - PSEG Fossil LLC

Tim Kucey

Affirmative

N/A

5

Public Utility District No. 1 of
Chelan County

Haley Sousa

Abstain

N/A

5

Public Utility District No. 1 of
Snohomish County

Sam Nietfeld

Affirmative

N/A

5

Puget Sound Energy, Inc.

Eleanor Ewry

None

N/A

5

Sacramento Municipal Utility
District

Susan Oto

Affirmative

N/A

5

Salt River Project

Kevin Nielsen

Negative

Comments
Submitted

5

Santee Cooper

Tommy Curtis

None

N/A

5

SCANA - South Carolina
Electric and Gas Co.

Alyssa Hubbard

None

N/A

5

Seattle City Light

Faz Kasraie

None

N/A

5

Seminole Electric
Cooperative, Inc.

Brenda Atkins

None

N/A

5

Sempra - San Diego Gas
and Electric

Daniel Frank

None

N/A

5

Silicon Valley Power - City of
Santa Clara

Sandra Pacheco

None

N/A

5

Southern Company Southern Company
Generation

William D. Shultz

Affirmative

N/A

Joe Tarantino

Andrey
Komissarov

© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB01

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 15 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

5

SunPower

Bradley Collard

None

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

None

N/A

5

Talen Generation, LLC

Matthew
McMillan

None

N/A

5

TECO - Tampa Electric Co.

Frank L Busot

None

N/A

5

Tennessee Valley Authority

M Lee Thomas

Affirmative

N/A

5

U.S. Bureau of Reclamation

Wendy Center

Negative

Comments
Submitted

5

WEC Energy Group, Inc.

Linda Horn

Affirmative

N/A

5

Xcel Energy, Inc.

Gerry Huitt

Affirmative

N/A

6

APS - Arizona Public Service
Co.

Jonathan Aragon

Affirmative

N/A

6

Arkansas Electric
Cooperative Corporation

Bruce Walkup

Affirmative

N/A

6

Austin Energy

Andrew Gallo

Affirmative

N/A

6

Basin Electric Power
Cooperative

Paul Huettl

Affirmative

N/A

6

Berkshire Hathaway PacifiCorp

Sandra Shaffer

Negative

Comments
Submitted

6

Bonneville Power
Administration

Andrew Meyers

Affirmative

N/A

6

Cleco Corporation

Robert Hirchak

Affirmative

N/A

6

Con Ed - Consolidated
Edison Co. of New York

Robert Winston

Affirmative

N/A

6

Dominion - Dominion
Resources, Inc.

Sean Bodkin

Negative

Comments
Submitted

6

Duke Energy

Greg Cecil

Negative

Comments
Submitted

6

Edison International Southern California Edison
Company

Kenya Streeter

Affirmative

N/A

6

Entergy

Julie Hall

Negative

Comments
Submitted

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Louis Guidry

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 16 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Exelon

Becky Webb

Negative

Comments
Submitted

6

FirstEnergy - FirstEnergy
Solutions

Ann Ivanc

Affirmative

N/A

6

Florida Municipal Power
Pool

Tom Reedy

Brandon
McCormick

Negative

Comments
Submitted

6

Great Plains Energy Kansas City Power and Light
Co.

Jim Flucke

Douglas Webb

Affirmative

N/A

6

Lincoln Electric System

Eric Ruskamp

Affirmative

N/A

6

Los Angeles Department of
Water and Power

Anton Vu

Affirmative

N/A

6

Luminant - Luminant Energy

Brenda Hampton

Affirmative

N/A

6

Manitoba Hydro

Blair Mukanik

None

N/A

6

Modesto Irrigation District

James McFall

Nick Braden

None

N/A

6

Muscatine Power and Water

Ryan Streck

Amie Shuger
McConnaha

Affirmative

N/A

6

NextEra Energy - Florida
Power and Light Co.

Silvia Mitchell

Affirmative

N/A

6

NiSource - Northern Indiana
Public Service Co.

Joe O'Brien

Affirmative

N/A

6

Northern California Power
Agency

Dennis Sismaet

Negative

Comments
Submitted

6

OGE Energy - Oklahoma
Gas and Electric Co.

Sing Tay

Affirmative

N/A

6

Omaha Public Power District

Joel Robles

None

N/A

6

Portland General Electric
Co.

Daniel Mason

Affirmative

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

Affirmative

N/A

6

Public Utility District No. 1 of
Chelan County

Davis Jelusich

Abstain

N/A

6

Public Utility District No. 2 of
Grant County, Washington

LeRoy Patterson

None

N/A

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Segment

Organization

Page 17 of 18

Voter

6

Sacramento Municipal Utility
District

Jamie Cutlip

6

Salt River Project

6

Designated
Proxy
Joe Tarantino

Ballot

NERC
Memo

Affirmative

N/A

Bobby Olsen

Negative

Comments
Submitted

Santee Cooper

Michael Brown

None

N/A

6

Seattle City Light

Charles Freeman

Affirmative

N/A

6

Seminole Electric
Cooperative, Inc.

Trudy Novak

Abstain

N/A

6

Snohomish County PUD No.
1

Franklin Lu

Affirmative

N/A

6

Southern Company Southern Company
Generation and Energy
Marketing

Jennifer Sykes

Affirmative

N/A

6

Southern Indiana Gas and
Electric Co.

Brad Lisembee

None

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Rick Applegate

Negative

Comments
Submitted

6

Talen Energy Marketing,
LLC

Jennifer
Hohenshilt

None

N/A

6

TECO - Tampa Electric Co.

Benjamin Smith

None

N/A

6

Tennessee Valley Authority

Marjorie Parsons

Affirmative

N/A

6

WEC Energy Group, Inc.

David Hathaway

Affirmative

N/A

6

Westar Energy

Megan Wagner

Affirmative

N/A

6

Xcel Energy, Inc.

Carrie Dixon

Affirmative

N/A

7

Exxon Mobil

Jay Barnett

None

N/A

7

Luminant Mining Company
LLC

Stewart Rake

Affirmative

N/A

8

David Kiguel

David Kiguel

Affirmative

N/A

8

Massachusetts Attorney
General

Frederick Plett

Affirmative

N/A

8

Roger Zaklukiewicz

Roger
Zaklukiewicz

Affirmative

N/A

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Segment

Organization

Page 18 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

9

Commonwealth of
Massachusetts Department
of Public Utilities

Donald Nelson

Affirmative

N/A

10

Midwest Reliability
Organization

Russel Mountjoy

Affirmative

N/A

10

New York State Reliability
Council

ALAN
ADAMSON

Affirmative

N/A

10

Northeast Power
Coordinating Council

Guy V. Zito

Affirmative

N/A

10

ReliabilityFirst

Anthony
Jablonski

Affirmative

N/A

10

SERC Reliability Corporation

Drew Slabaugh

Affirmative

N/A

10

Texas Reliability Entity, Inc.

Rachel Coyne

Negative

Comments
Submitted

10

Western Electricity
Coordinating Council

Steven Rueckert

Affirmative

N/A

Previous

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Showing 1 to 309 of 309 entries

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NERC Balloting Tool (/)

Dashboard (/)

Page 1 of 17

Users

Ballots

Comment Forms

Login (/Users/Login) / Register (/Users/Register)

BALLOT RESULTS
Ballot Name: 2016-02 Modifications to CIP Standards CIP-012-1 Non-binding Poll AB 3 NB
Voting Start Date: 4/20/2018 12:01:00 AM
Voting End Date: 4/30/2018 8:00:00 PM
Ballot Type: NB
Ballot Activity: AB
Ballot Series: 3
Total # Votes: 221
Total Ballot Pool: 290
Quorum: 76.21
Weighted Segment Value: 79.78
Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes

Negative
Fraction

Abstain

No
Vote

Segment:
1

75

1

36

0.837

7

0.163

14

18

Segment:
2

7

0.5

4

0.4

1

0.1

1

1

Segment:
3

70

1

36

0.837

7

0.163

10

17

Segment:
4

14

1

8

0.8

2

0.2

2

2

Segment:
5

69

1

28

0.737

10

0.263

9

22

Segment:
6

42

1

20

0.714

8

0.286

6

8

Segment:
7

2

0.1

1

0.1

0

0

0

1

Segment:
8

3

0.3

3

0.3

0

0

0

0

Segment:
9

1

0.1

1

0.1

0

0

0

0

Segment:
10

7

0.6

5

0.5

1

0.1

1

0

36

1.274

43

69

Segment

Totals:
290
6.6
142
5.326
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Page 2 of 17

BALLOT POOL MEMBERS
Show All

Segment

 entries

Organization

Search: Search

Voter

Designated
Proxy

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

American Transmission
Company, LLC

Douglas Johnson

Affirmative

N/A

1

APS - Arizona Public Service
Co.

Michelle
Amarantos

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

John Shaver

Negative

Comments
Submitted

1

Associated Electric
Cooperative, Inc.

Ryan Ziegler

Affirmative

N/A

1

Austin Energy

Thomas
Standifur

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Affirmative

N/A

1

Basin Electric Power
Cooperative

David Rudolph

None

N/A

1

BC Hydro and Power
Authority

Patricia
Robertson

Abstain

N/A

1

Berkshire Hathaway Energy
- MidAmerican Energy Co.

Terry Harbour

Negative

Comments
Submitted

1

Bonneville Power
Administration

Kammy RogersHolliday

Affirmative

N/A

1

Brazos Electric Power
Cooperative, Inc.

Tony Kroskey

None

N/A

1

Cedar Falls Utilities

Adam Peterson

None

N/A

Affirmative

N/A

1

CenterPoint Energy Houston
Daniela
Electric,
LLC
Hammons
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Joe Tarantino

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 3 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Central Electric Power
Cooperative (Missouri)

Michael Bax

Affirmative

N/A

1

Central Hudson Gas &
Electric Corp.

Frank Pace

Abstain

N/A

1

City Utilities of Springfield,
Missouri

Michael Buyce

Affirmative

N/A

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Dominion - Dominion Virginia
Power

Larry Nash

Abstain

N/A

1

Duke Energy

Laura Lee

Negative

Comments
Submitted

1

Edison International Southern California Edison
Company

Steven Mavis

Affirmative

N/A

1

Entergy - Entergy Services,
Inc.

Oliver Burke

Negative

Comments
Submitted

1

Eversource Energy

Quintin Lee

Affirmative

N/A

1

Exelon

Chris Scanlon

Abstain

N/A

1

FirstEnergy - FirstEnergy
Corporation

Karen Yoder

Affirmative

N/A

1

Great Plains Energy Kansas City Power and Light
Co.

James McBee

Affirmative

N/A

1

Great River Energy

Gordon Pietsch

None

N/A

1

Hydro One Networks, Inc.

Payam
Farahbakhsh

Affirmative

N/A

1

Hydro-Qu?bec TransEnergie

Nicolas Turcotte

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Laura Nelson

None

N/A

1

Imperial Irrigation District

Jesus Sammy
Alcaraz

None

N/A

Abstain

N/A

1

International Transmission
Michael Moltane
Company Holdings
Corporation
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Douglas Webb

Stephanie Burns

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 4 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Lincoln Electric System

Danny Pudenz

Affirmative

N/A

1

Long Island Power Authority

Robert Ganley

None

N/A

1

Los Angeles Department of
Water and Power

faranak sarbaz

None

N/A

1

Lower Colorado River
Authority

Michael Shaw

Affirmative

N/A

1

M and A Electric Power
Cooperative

William Price

None

N/A

1

Manitoba Hydro

Mike Smith

Affirmative

N/A

1

MEAG Power

David Weekley

Abstain

N/A

1

Memphis Light, Gas and
Water Division

Allan Long

None

N/A

1

Minnkota Power Cooperative
Inc.

Theresa Allard

Affirmative

N/A

1

Muscatine Power and Water

Andy Kurriger

Abstain

N/A

1

N.W. Electric Power
Cooperative, Inc.

Mark Ramsey

Affirmative

N/A

1

National Grid USA

Michael Jones

Affirmative

N/A

1

Nebraska Public Power
District

Jamison Cawley

Abstain

N/A

1

New York Power Authority

Salvatore
Spagnolo

Affirmative

N/A

1

NextEra Energy - Florida
Power and Light Co.

Mike ONeil

Affirmative

N/A

1

NiSource - Northern Indiana
Public Service Co.

Steve Toosevich

Affirmative

N/A

1

Northeast Missouri Electric
Power Cooperative

Kevin White

Affirmative

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Affirmative

N/A

1

Ohio Valley Electric
Corporation

Scott
Cunningham

Affirmative

N/A

1

Omaha Public Power District

Doug Peterchuck

None

N/A

Scott Miller

Andy Fuhrman

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Segment

Organization

Page 5 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

1

OTP - Otter Tail Power
Company

Charles Wicklund

Affirmative

N/A

1

Peak Reliability

Scott Downey

None

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Laurie Williams

Negative

Comments
Submitted

1

PPL Electric Utilities
Corporation

Brenda Truhe

Abstain

N/A

1

PSEG - Public Service
Electric and Gas Co.

Joseph Smith

Abstain

N/A

1

Public Utility District No. 1 of
Chelan County

Jeff Kimbell

None

N/A

1

Public Utility District No. 1 of
Snohomish County

Long Duong

Affirmative

N/A

1

Puget Sound Energy, Inc.

Theresa
Rakowsky

None

N/A

1

Sacramento Municipal Utility
District

Arthur Starkovich

Affirmative

N/A

1

Salt River Project

Steven Cobb

None

N/A

1

Santee Cooper

Chris Wagner

None

N/A

1

SCANA - South Carolina
Electric and Gas Co.

Tom Hanzlik

None

N/A

1

Seattle City Light

Pawel Krupa

Affirmative

N/A

1

Seminole Electric
Cooperative, Inc.

Mark Churilla

Abstain

N/A

1

Sempra - San Diego Gas
and Electric

Mo Derbas

None

N/A

1

Sho-Me Power Electric
Cooperative

Peter Dawson

Affirmative

N/A

1

Southern Company Southern Company
Services, Inc.

Katherine Prewitt

Affirmative

N/A

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

Negative

Comments
Submitted

Abstain

N/A

1 - NERC Ver 4.2.1.0
Tennessee
Valley
Authority
Howell Scott
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Joe Tarantino

Jeff Johnson

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 6 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Tri-State G and T
Association, Inc.

Tracy Sliman

Abstain

N/A

1

U.S. Bureau of Reclamation

Richard Jackson

Negative

Comments
Submitted

1

Westar Energy

Kevin Giles

Affirmative

N/A

1

Western Area Power
Administration

sean erickson

Abstain

N/A

2

California ISO

Richard Vine

Affirmative

N/A

2

Electric Reliability Council of
Texas, Inc.

Brandon Gleason

Affirmative

N/A

2

Independent Electricity
System Operator

Leonard Kula

Affirmative

N/A

2

ISO New England, Inc.

Michael Puscas

None

N/A

2

Midcontinent ISO, Inc.

Ellen Oswald

Negative

Comments
Submitted

2

New York Independent
System Operator

Gregory Campoli

Abstain

N/A

2

PJM Interconnection, L.L.C.

Mark Holman

Affirmative

N/A

3

AEP

Aaron Austin

Affirmative

N/A

3

AES - Indianapolis Power
and Light Co.

Bette White

Affirmative

N/A

3

APS - Arizona Public Service
Co.

Vivian Vo

Affirmative

N/A

3

Arkansas Electric
Cooperative Corporation

Philip Huff

Affirmative

N/A

3

Associated Electric
Cooperative, Inc.

Todd Bennett

Affirmative

N/A

3

Austin Energy

W. Dwayne
Preston

Affirmative

N/A

3

Basin Electric Power
Cooperative

Jeremy Voll

Affirmative

N/A

3

Berkshire Hathaway Energy
- MidAmerican Energy Co.

Annette Johnston

Negative

Comments
Submitted

Darnez
Gresham

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Segment

Organization

Page 7 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Bonneville Power
Administration

Rebecca Berdahl

Affirmative

N/A

3

Central Electric Power
Cooperative (Missouri)

Adam Weber

Affirmative

N/A

3

City of Farmington

Linda JacobsonQuinn

Abstain

N/A

3

City of Leesburg

Chris Adkins

None

N/A

3

City of Vero Beach

Ginny Beigel

Negative

Comments
Submitted

3

City Utilities of Springfield,
Missouri

Scott Williams

Affirmative

N/A

3

Cleco Corporation

Michelle Corley

Affirmative

N/A

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Affirmative

N/A

3

Cowlitz County PUD

Russell Noble

Negative

Comments
Submitted

3

Duke Energy

Lee Schuster

None

N/A

3

Edison International Southern California Edison
Company

Romel Aquino

None

N/A

3

Eversource Energy

Mark Kenny

Affirmative

N/A

3

Exelon

John Bee

Abstain

N/A

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

Negative

Comments
Submitted

3

Georgia System Operations
Corporation

Scott McGough

Affirmative

N/A

3

Great Plains Energy Kansas City Power and Light
Co.

Jessica Tucker

Affirmative

N/A

3

Great River Energy

Brian Glover

Affirmative

N/A

3

Hydro One Networks, Inc.

Paul Malozewski

Affirmative

N/A

3

KAMO Electric Cooperative

Ted Hilmes

None

N/A

3

Lincoln Electric System

Jason Fortik

Abstain

N/A

Brandon
McCormick

Louis Guidry

Douglas Webb

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Segment

Organization

Page 8 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

3

M and A Electric Power
Cooperative

Stephen Pogue

Affirmative

N/A

3

Manitoba Hydro

Karim AbdelHadi

Affirmative

N/A

3

MEAG Power

Roger Brand

Scott Miller

Abstain

N/A

3

Modesto Irrigation District

Jack Savage

Nick Braden

None

N/A

3

Muscatine Power and Water

Seth Shoemaker

Affirmative

N/A

3

National Grid USA

Brian Shanahan

Affirmative

N/A

3

Nebraska Public Power
District

Tony Eddleman

Abstain

N/A

3

New York Power Authority

David Rivera

Affirmative

N/A

3

NiSource - Northern Indiana
Public Service Co.

Aimee Harris

Negative

Comments
Submitted

3

North Carolina Electric
Membership Corporation

doug white

Affirmative

N/A

3

Northeast Missouri Electric
Power Cooperative

Skyler
Wiegmann

Affirmative

N/A

3

NW Electric Power
Cooperative, Inc.

John Stickley

Affirmative

N/A

3

Ocala Utility Services

Neville Bowen

None

N/A

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Affirmative

N/A

3

OTP - Otter Tail Power
Company

Wendi Olson

Affirmative

N/A

3

Owensboro Municipal
Utilities

Thomas Lyons

None

N/A

3

Platte River Power Authority

Jeff Landis

Abstain

N/A

3

PNM Resources - Public
Service Company of New
Mexico

Lynn Goldstein

Negative

Comments
Submitted

3

Portland General Electric Co.

Angela Gaines

Affirmative

N/A

3

PPL - Louisville Gas and
Electric Co.

Charles Freibert

None

N/A

Scott Brame

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Segment

Organization

Page 9 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

3

PSEG - Public Service
Electric and Gas Co.

Jeffrey Mueller

Abstain

N/A

3

Public Utility District No. 1 of
Chelan County

Joyce Gundry

Abstain

N/A

3

Puget Sound Energy, Inc.

Tim Womack

None

N/A

3

Rutherford EMC

Tom Haire

None

N/A

3

Sacramento Municipal Utility
District

Nicole Looney

Affirmative

N/A

3

Salt River Project

Robert
Kondziolka

Negative

Comments
Submitted

3

Santee Cooper

James Poston

None

N/A

3

SCANA - South Carolina
Electric and Gas Co.

Scott Parker

None

N/A

3

Seattle City Light

Tuan Tran

None

N/A

3

Seminole Electric
Cooperative, Inc.

James Frauen

Abstain

N/A

3

Sempra - San Diego Gas
and Electric

Bridget Silvia

Affirmative

N/A

3

Sho-Me Power Electric
Cooperative

Jeff Neas

Affirmative

N/A

3

Silicon Valley Power - City of
Santa Clara

Val Ridad

None

N/A

3

Snohomish County PUD No.
1

Mark Oens

Affirmative

N/A

3

Southern Company Alabama Power Company

Joel Dembowski

Affirmative

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

Marc Donaldson

Affirmative

N/A

3

TECO - Tampa Electric Co.

Ronald Donahey

None

N/A

3

Tennessee Valley Authority

Ian Grant

None

N/A

3

Tri-State G and T
Association, Inc.

Janelle Marriott
Gill

None

N/A

3

WEC Energy Group, Inc.

Thomas Breene

Affirmative

N/A

Joe Tarantino

Harold Sherrill

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Segment

Organization

Page 10 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Westar Energy

Bo Jones

Affirmative

N/A

3

Xcel Energy, Inc.

Michael Ibold

Abstain

N/A

4

American Public Power
Association

Jack Cashin

None

N/A

4

Austin Energy

Esther Weekes

Affirmative

N/A

4

City of Clewiston

Lynne Mila

Negative

Comments
Submitted

4

City Utilities of Springfield,
Missouri

John Allen

Affirmative

N/A

4

Georgia System Operations
Corporation

Guy Andrews

Affirmative

N/A

4

Indiana Municipal Power
Agency

Jack Alvey

Scott Berry

Abstain

N/A

4

North Carolina Electric
Membership Corporation

John Lemire

Scott Brame

Affirmative

N/A

4

Public Utility District No. 1 of
Snohomish County

John Martinsen

Affirmative

N/A

4

Sacramento Municipal Utility
District

Beth Tincher

Affirmative

N/A

4

Seattle City Light

Hao Li

Affirmative

N/A

4

Seminole Electric
Cooperative, Inc.

Charles
Wubbena

None

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

Negative

Comments
Submitted

4

Utility Services, Inc.

Brian EvansMongeon

Abstain

N/A

4

WEC Energy Group, Inc.

Anthony
Jankowski

Affirmative

N/A

5

Acciona Energy North
America

George Brown

Abstain

N/A

5

AEP

Thomas Foltz

Affirmative

N/A

5

Ameren - Ameren Missouri

Sam Dwyer

Abstain

N/A

Affirmative

N/A

5

APS - Arizona Public Service
Kelsi Rigby
Co.
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Brandon
McCormick

Joe Tarantino

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 11 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Associated Electric
Cooperative, Inc.

Brad Haralson

None

N/A

5

Austin Energy

Shirley Mathew

None

N/A

5

Avista - Avista Corporation

Glen Farmer

Affirmative

N/A

5

Basin Electric Power
Cooperative

Mike Kraft

Affirmative

N/A

5

BC Hydro and Power
Authority

Helen Hamilton
Harding

None

N/A

5

Boise-Kuna Irrigation District
- Lucky Peak Power Plant
Project

Mike Kukla

Affirmative

N/A

5

Bonneville Power
Administration

Scott Winner

Affirmative

N/A

5

BP Wind Energy North
America Inc.

Carla Holly

None

N/A

5

Choctaw Generation Limited
Partnership, LLLP

Rob Watson

Affirmative

N/A

5

Cleco Corporation

Stephanie
Huffman

Affirmative

N/A

5

CMS Energy - Consumers
Energy Company

David
Greyerbiehl

Negative

Comments
Submitted

5

Colorado Springs Utilities

Jeff Icke

Negative

Comments
Submitted

5

Con Ed - Consolidated
Edison Co. of New York

William Winters

Affirmative

N/A

5

Dairyland Power
Cooperative

Tommy Drea

None

N/A

5

Dominion - Dominion
Resources, Inc.

Lou Oberski

Negative

Comments
Submitted

5

Duke Energy

Dale Goodwine

Negative

Comments
Submitted

5

Edison International Southern California Edison
Company

Selene Willis

None

N/A

Negative

Comments
Submitted

5
EDP Renewables North
Heather Morgan
© 2018 - NERC Ver 4.2.1.0
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AmericaMachine
LLC

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Louis Guidry

Alyson Slanover

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 12 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Entergy

Jamie Prater

Negative

Comments
Submitted

5

Exelon

Ruth Miller

Abstain

N/A

5

FirstEnergy - FirstEnergy
Solutions

Robert Loy

Affirmative

N/A

5

Great Plains Energy Kansas City Power and Light
Co.

Harold Wyble

Affirmative

N/A

5

Great River Energy

Preston Walsh

Affirmative

N/A

5

Hydro-Qu?bec Production

Junji Yamaguchi

None

N/A

5

JEA

John Babik

None

N/A

5

Kissimmee Utility Authority

Mike Blough

Negative

Comments
Submitted

5

Lakeland Electric

Jim Howard

None

N/A

5

Lincoln Electric System

Kayleigh
Wilkerson

Abstain

N/A

5

Los Angeles Department of
Water and Power

Donald
Sievertson

Affirmative

N/A

5

Manitoba Hydro

Yuguang Xiao

Affirmative

N/A

5

Massachusetts Municipal
Wholesale Electric Company

David Gordon

Abstain

N/A

5

MEAG Power

Steven Grego

Abstain

N/A

5

Muscatine Power and Water

Neal Nelson

None

N/A

5

NB Power Corporation

Laura McLeod

Abstain

N/A

5

Nebraska Public Power
District

Don Schmit

Affirmative

N/A

5

New York Power Authority

Erick Barrios

Affirmative

N/A

5

NextEra Energy

Allen Schriver

None

N/A

5

NiSource - Northern Indiana
Public Service Co.

Dmitriy Bazylyuk

Affirmative

N/A

5

Northern California Power
Agency

Marty Hostler

Negative

Comments
Submitted

Douglas Webb

Brandon
McCormick

Scott Miller

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 13 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

5

OGE Energy - Oklahoma
Gas and Electric Co.

John Rhea

Affirmative

N/A

5

Omaha Public Power District

Mahmood Safi

Affirmative

N/A

5

Ontario Power Generation
Inc.

David
Ramkalawan

Affirmative

N/A

5

OTP - Otter Tail Power
Company

Cathy Fogale

Affirmative

N/A

5

Portland General Electric Co.

Ryan Olson

Affirmative

N/A

5

PPL - Louisville Gas and
Electric Co.

JULIE
HOSTRANDER

None

N/A

5

PSEG - PSEG Fossil LLC

Tim Kucey

Abstain

N/A

5

Public Utility District No. 1 of
Chelan County

Haley Sousa

Abstain

N/A

5

Public Utility District No. 1 of
Snohomish County

Sam Nietfeld

Affirmative

N/A

5

Puget Sound Energy, Inc.

Eleanor Ewry

None

N/A

5

Sacramento Municipal Utility
District

Susan Oto

Affirmative

N/A

5

Salt River Project

Kevin Nielsen

Negative

Comments
Submitted

5

Santee Cooper

Tommy Curtis

None

N/A

5

SCANA - South Carolina
Electric and Gas Co.

Alyssa Hubbard

None

N/A

5

Seattle City Light

Faz Kasraie

None

N/A

5

Seminole Electric
Cooperative, Inc.

Brenda Atkins

None

N/A

5

Sempra - San Diego Gas
and Electric

Jerome Gobby

Affirmative

N/A

5

Silicon Valley Power - City of
Santa Clara

Sandra Pacheco

None

N/A

5

Southern Company Southern Company
Generation

William D. Shultz

Affirmative

N/A

None

N/A

5 - NERC Ver 4.2.1.0
SunPower
Bradley Collard
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Machine Name: ERODVSBSWB02

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Joe Tarantino

Andrey
Komissarov

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 14 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

None

N/A

5

Talen Generation, LLC

Matthew
McMillan

Affirmative

N/A

5

TECO - Tampa Electric Co.

Frank L Busot

None

N/A

5

Tennessee Valley Authority

M Lee Thomas

None

N/A

5

U.S. Bureau of Reclamation

Wendy Center

Negative

Comments
Submitted

5

Westar Energy

Laura Cox

Affirmative

N/A

6

APS - Arizona Public Service
Co.

Jonathan Aragon

Affirmative

N/A

6

Arkansas Electric
Cooperative Corporation

Bruce Walkup

Affirmative

N/A

6

Austin Energy

Andrew Gallo

Affirmative

N/A

6

Basin Electric Power
Cooperative

Paul Huettl

Affirmative

N/A

6

Berkshire Hathaway PacifiCorp

Sandra Shaffer

Negative

Comments
Submitted

6

Cleco Corporation

Robert Hirchak

Affirmative

N/A

6

Con Ed - Consolidated
Edison Co. of New York

Robert Winston

Affirmative

N/A

6

Dominion - Dominion
Resources, Inc.

Sean Bodkin

Negative

Comments
Submitted

6

Duke Energy

Greg Cecil

Negative

Comments
Submitted

6

Edison International Southern California Edison
Company

Kenya Streeter

Affirmative

N/A

6

Entergy

Julie Hall

Negative

Comments
Submitted

6

Exelon

Becky Webb

Abstain

N/A

6

FirstEnergy - FirstEnergy
Solutions

Ann Ivanc

Affirmative

N/A

Louis Guidry

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 15 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Florida Municipal Power Pool

Tom Reedy

Brandon
McCormick

Negative

Comments
Submitted

6

Great Plains Energy Kansas City Power and Light
Co.

Jim Flucke

Douglas Webb

Affirmative

N/A

6

Lincoln Electric System

Eric Ruskamp

Abstain

N/A

6

Los Angeles Department of
Water and Power

Anton Vu

Affirmative

N/A

6

Luminant - Luminant Energy

Brenda Hampton

Affirmative

N/A

6

Manitoba Hydro

Blair Mukanik

None

N/A

6

Muscatine Power and Water

Ryan Streck

Affirmative

N/A

6

NextEra Energy - Florida
Power and Light Co.

Silvia Mitchell

Abstain

N/A

6

NiSource - Northern Indiana
Public Service Co.

Joe O'Brien

Affirmative

N/A

6

Northern California Power
Agency

Dennis Sismaet

Negative

Comments
Submitted

6

OGE Energy - Oklahoma
Gas and Electric Co.

Sing Tay

Affirmative

N/A

6

Omaha Public Power District

Joel Robles

None

N/A

6

Portland General Electric Co.

Daniel Mason

Affirmative

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

None

N/A

6

Public Utility District No. 1 of
Chelan County

Davis Jelusich

Abstain

N/A

6

Public Utility District No. 2 of
Grant County, Washington

LeRoy Patterson

None

N/A

6

Sacramento Municipal Utility
District

Jamie Cutlip

Affirmative

N/A

6

Salt River Project

Bobby Olsen

Negative

Comments
Submitted

6

Santee Cooper

Michael Brown

None

N/A

None

N/A

6 - NERC Ver 4.2.1.0
Seattle Machine
City LightName: ERODVSBSWB02
Charles Freeman
© 2018

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Amie Shuger
McConnaha

Joe Tarantino

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 16 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Seminole Electric
Cooperative, Inc.

Trudy Novak

Abstain

N/A

6

Snohomish County PUD No.
1

Franklin Lu

Affirmative

N/A

6

Southern Company Southern Company
Generation and Energy
Marketing

Jennifer Sykes

Affirmative

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Rick Applegate

Negative

Comments
Submitted

6

Talen Energy Marketing,
LLC

Jennifer
Hohenshilt

Affirmative

N/A

6

TECO - Tampa Electric Co.

Benjamin Smith

None

N/A

6

Tennessee Valley Authority

Marjorie Parsons

Abstain

N/A

6

WEC Energy Group, Inc.

David Hathaway

None

N/A

6

Westar Energy

Megan Wagner

Affirmative

N/A

7

Exxon Mobil

Jay Barnett

None

N/A

7

Luminant Mining Company
LLC

Stewart Rake

Affirmative

N/A

8

David Kiguel

David Kiguel

Affirmative

N/A

8

Massachusetts Attorney
General

Frederick Plett

Affirmative

N/A

8

Roger Zaklukiewicz

Roger
Zaklukiewicz

Affirmative

N/A

9

Commonwealth of
Massachusetts Department
of Public Utilities

Donald Nelson

Affirmative

N/A

10

Midwest Reliability
Organization

Russel Mountjoy

Affirmative

N/A

10

New York State Reliability
Council

ALAN
ADAMSON

Affirmative

N/A

10

Northeast Power
Coordinating Council

Guy V. Zito

Affirmative

N/A

10

ReliabilityFirst

Anthony

Affirmative

N/A

Jablonski
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Segment

Organization

Page 17 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

10

SERC Reliability Corporation

Drew Slabaugh

Affirmative

N/A

10

Texas Reliability Entity, Inc.

Rachel Coyne

Negative

Comments
Submitted

10

Western Electricity
Coordinating Council

Steven Rueckert

Abstain

N/A

Previous

1

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Showing 1 to 290 of 290 entries

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9/10/2018

Standards Announcement

Project 2016-02 Modifications to CIP Standards
Formal Comment Periods Open through April 30, 2018
Ballot Pools Forming through April 16, 2018
Now Available

Three formal comment periods are open through 8 p.m. Eastern, Monday, April 30, 2018 for:
1. CIP-002-6 – Cyber Security - BES Cyber System Categorization
2. CIP-012-1 – Cyber Security - Communications between Control Centers
3. Project 2016-02 Modifications to NERC Glossary of Terms Used in Reliability Standards – Control
Center
Commenting

Use the Standards Balloting and Commenting System (SBS) to submit comments. If you experience
difficulties navigating the SBS, contact Wendy Muller. Unofficial Word versions of the comment forms
are posted on the project page.
Ballot Pools

Ballot pools are being formed through 8 p.m. Eastern, Monday, April 16, 2018 for the Control Center
Definition and its Implementation Plan. Registered Ballot Body members can join the ballot pools
here.
•

If you are having difficulty accessing the SBS due to a forgotten password, incorrect
credential error messages, or system lock-out, contact NERC IT support directly at
https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5 p.m. Eastern).

•

Passwords expire every 6 months and must be reset.

•

The SBS is not supported for use on mobile devices.

•

Please be mindful of ballot and comment period closing dates. We ask to allow at least 48
hours for NERC support staff to assist with inquiries. Therefore, it is recommended that users try
logging into their SBS accounts prior to the last day of a comment/ballot period.

Next Steps

The initial ballots for the Control Center Definition and its Implementation Plan will be conducted
April 20-30, 2018. Additional ballots for CIP-002-6 and CIP-012-1 and the associated non-binding polls
of the associated Violation Risk Factors and Violation Severity Levels will be conducted April 20-30,
2018.
For information on the Standards Development Process, refer to the Standard Processes Manual.

For more information or assistance, contact Mat Bunch at (404) 446-9785 or Jordan Mallory at (404) 4462589.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | July-September, 2017

2

Comment Report
Project Name:

2016-02 Modifications to CIP Standards | CIP-012-1 Draft 3

Comment Period Start Date:

3/16/2018

Comment Period End Date:

4/30/2018

Associated Ballots:

2016-02 Modifications to CIP Standards CIP-012-1 AB 3 ST

There were 58 sets of responses, including comments from approximately 155 different people from approximately 108 companies
representing 10 of the Industry Segments as shown in the table on the following pages.

Questions
1. Requirement R1: The SDT drafted CIP-012-1 Requirement R1 for the Responsible Entity to implement one or more documented plan(s) to
mitigate the risk of the unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring data while being
transmitted between any Control Centers. Do you agree with this revision? If not, please provide the basis for your disagreement and an
alternate proposal.

2. Implementation Plan: The SDT established the Implementation Plan to make the standard effective the first day of the first calendar quarter
that is twenty-four (24) calendar months after the effective date of the applicable governmental authority’s order approving the standard, or
as otherwise provided for by the applicable governmental authority. Do you agree with this proposal? If you think an alternate
implementation time period is needed, please provide a detailed explanation of actions and time needed to meet the implementation deadline.

3. The SDT modified the draft Technical Rationale and Justification for CIP-012 to assist in understanding the technology and technical
requirements in the Reliability Standard. It also contains information on the SDT’s intent in drafting the requirements. Do you agree with the
technology and technical requirements in the draft Technical Rationale and Justification? If you do not agree, or if you agree but have
comments or suggestions for the draft Technical Rationale and Justification, please provide your recommendation and explanation.

4. The SDT modified the draft Implementation Guidance for CIP-012 to provide examples of how a Responsible Entity could comply with the
requirements. The draft Implementation Guidance does not prescribe the only approach to compliance. Rather, it describes what the SDT
believes would be effective ways to comply with the standard. See NERC’s Compliance Guidance policy for information on Implementation
Guidance. Do you agree with the draft Implementation Guidance? If you do not agree, or if you agree but have comments or suggestions for
the draft Implementation Guidance, please provide your recommendation and explanation.

5. The SDT believes proposed CIP-012-1 provides entities with flexibility to meet the reliability objectives in a cost effective manner. Do you
agree? If you do not agree, or if you agree but have suggestions for improvement to enable more cost effective approaches, please provide
your recommendation and, if appropriate, technical justification.

Organization
Name
FirstEnergy FirstEnergy
Corporation

Brandon
McCormick

Name

Aaron
Ghodooshim

Brandon
McCormick

Segment(s)

3

Region

RF

FRCC

Group Name Group Member
Name

Group
Member
Organization

FirstEnergy
Corporation

Aaron
Ghdooshim

FirstEnergy FirstEnergy
Corporation

4

RF

Aubrey Short

FirstEnergy FirstEnergy
Corporation

1

RF

Theresa Ciancio

FirstEnergy FirstEnergy
Corporation

3

RF

Robert Loy

FirstEnergy FirstEnergy
Solutions

5

RF

Ann Ivanc

FirstEnergy FirstEnergy
Solutions

6

RF

Tim Beyrle

City of New
4
Smyrna Beach
Utilities
Commission

FRCC

Jim Howard

Lakeland
Electric

5

FRCC

Lynne Mila

City of
Clewiston

4

FRCC

Javier Cisneros

Fort Pierce
Utilities
Authority

3

FRCC

Randy Hahn

Ocala Utility
Services

3

FRCC

Don Cuevas

Beaches
Energy
Services

1

FRCC

Jeffrey Partington Keys Energy
Services

4

FRCC

Tom Reedy

6

FRCC

3

FRCC

FMPA

Florida
Municipal
Power Pool

Steven Lancaster Beaches
Energy
Services

Group
Member
Segment(s)

Group Member
Region

Duke Energy

Seattle City
Light

Colby Bellville

Ginette
Lacasse

1,3,5,6

1,3,4,5,6

Southern
Pamela Hunter 1,3,5,6
Company Southern
Company
Services, Inc.

Mike Blough

Kissimmee
Utility
Authority

5

FRCC

Chris Adkins

City of
Leesburg

3

FRCC

Ginny Beigel

City of Vero
Beach

3

FRCC

Duke Energy

1

RF

Lee Schuster

Duke Energy

3

FRCC

Dale Goodwine

Duke Energy

5

SERC

Greg Cecil

Duke Energy

6

RF

Pawel Krupa

Seattle City
Light

1

WECC

Hao Li

Seattle City
Light

4

WECC

Bud (Charles)
Freeman

Seattle City
Light

6

WECC

Mike Haynes

Seattle City
Light

5

WECC

Michael Watkins

Seattle City
Light

1,4

WECC

Faz Kasraie

Seattle City
Light

5

WECC

John Clark

Seattle City
Light

6

WECC

Tuan Tran

Seattle City
Light

3

WECC

Laurrie
Hammack

Seattle City
Light

3

WECC

Katherine Prewitt Southern
1
Company
Services, Inc.

SERC

Joel Dembowski Southern
Company Alabama
Power
Company

3

SERC

William D. Shultz Southern
Company
Generation

5

SERC

Jennifer G.
Sykes

6

SERC

FRCC,RF,SERC Duke Energy Doug Hils

WECC

SERC

Seattle City
Light Ballot
Body

Southern
Company

Southern
Company
Generation

and Energy
Marketing
Northeast
Power
Coordinating
Council

Ruida Shu

1,2,3,4,5,6,7,8,9,10 NPCC

RSC no
Dominion,
NextEra and
HQ

Guy V. Zito

Northeast
Power
Coordinating
Council

10

NPCC

Randy
MacDonald

New
Brunswick
Power

2

NPCC

Wayne Sipperly

New York
Power
Authority

4

NPCC

Glen Smith

Entergy
Services

4

NPCC

Brian Robinson

Utility Services 5

NPCC

Alan Adamson

New York
State
Reliability
Council

7

NPCC

Edward Bedder

Orange &
Rockland
Utilities

1

NPCC

David Burke

Orange &
Rockland
Utilities

3

NPCC

Michele Tondalo UI

1

NPCC

Laura Mcleod

NB Power

1

NPCC

David
Ramkalawan

Ontario Power 5
Generation
Inc.

NPCC

Helen Lainis

IESO

2

NPCC

Michael
Schiavone

National Grid

1

NPCC

Michael Jones

National Grid

3

NPCC

Michael Forte

Con Ed Consolidated
Edison

1

NPCC

Peter Yost

Con Ed 3
Consolidated
Edison Co. of
New York

NPCC

Sean Cavote

PSEG

NPCC

4

Kathleen
Goodman

ISO-NE

2

NPCC

Paul Malozewski Hydro One
3
Networks, Inc.

NPCC

Quintin Lee

1

NPCC

2

NPCC

Eversource
Energy

Gregory Campoli New York
Independent
System
Operator

Midwest
Reliability
Organization

Russel
Mountjoy

10

MRO NSRF

Dermot Smyth

Con Ed 1,5
Consolidated
Edison Co. of
New York

NPCC

Dermot Smyth

Con Ed 1,5
Consolidated
Edison Co. of
New York

NPCC

Salvatore
Spagnolo

New York
Power
Authority

1

NPCC

Shivaz Chopra

New York
Power
Authority

6

NPCC

David Kiguel

Independent

NA - Not
Applicable

NPCC

Joseph
DePoorter

Madison Gas
& Electric

3,4,5,6

MRO

Larry Heckert

Alliant Energy 4

MRO

Amy Casucelli

Xcel Energy

1,3,5,6

MRO

Michael
Brytowski

Great River
Energy

1,3,5,6

MRO

Jodi Jensen

Western Area 1,6
Power
Administratino

MRO

Kayleigh
Wilkerson

Lincoln
Electric
System

1,3,5,6

MRO

Mahmood Safi

Omaha Public 1,3,5,6
Power District

MRO

Brad Parret

Minnesota
Power

1,5

MRO

Terry Harbour

MidAmerican
Energy
Company

1,3

MRO

Dominion Dominion
Resources,
Inc.

Colorado
Springs
Utilities

Southwest
Power Pool,
Inc. (RTO)

Sean Bodkin

Shannon Fair

Shannon
Mickens

6

Dominion

1,3,5,6

2

Colorado
Springs
Utilities

SPP RE

SPP
Standards
Review
Group

Tom Breene

Wisconsin
3,5,6
Public Service

MRO

Jeremy Volls

Basin Electric 1
Power Coop

MRO

Kevin Lyons

Central Iowa
Power
Cooperative

1

MRO

Mike Morrow

Midcontinent
Independent
System
Operator

2

MRO

Connie Lowe

Dominion Dominion
Resources,
Inc.

3

NA - Not
Applicable

Lou Oberski

Dominion Dominion
Resources,
Inc.

5

NA - Not
Applicable

Larry Nash

Dominion 1
Dominion
Virginia Power

NA - Not
Applicable

Jeff Icke

Colorado
Springs
Utilities

5

WECC

Hilary Dobson

Colorado
Springs
Utilities

3

WECC

Brandon Ware

Colorado
Springs
Utilities

1

WECC

Shannon Fair

Colorado
Springs
Utilities

6

WECC

Shannon
Mickens

Southwest
Power Pool
Inc.

2

SPP RE

Steve Keller

Soutwest
Power Pool
Inc

2

SPP RE

Sean Simpson

Board of
NA - Not
Public Utilities, Applicable
City of
Mcpherson,
Kansas

SPP RE

louis Guidry

Cleco

SPP RE

1,3,5,6

Associated
Electric
Cooperative,
Inc.

Todd Bennett

3

AECI

Michael Bax

Central
1
Electric Power
Cooperative
(Missouri)

SERC

Adam Weber

Central
3
Electric Power
Cooperative
(Missouri)

SERC

Stephen Pogue

M and A
3
Electric Power
Cooperative

SERC

William Price

M and A
1
Electric Power
Cooperative

SERC

Jeff Neas

Sho-Me
3
Power Electric
Cooperative

SERC

Peter Dawson

Sho-Me
1
Power Electric
Cooperative

SERC

Mark Ramsey

N.W. Electric
Power
Cooperative,
Inc.

1

NPCC

John Stickley

NW Electric
Power
Cooperative,
Inc.

3

SERC

Ted Hilmes

KAMO Electric 3
Cooperative

SERC

Walter Kenyon

KAMO Electric 1
Cooperative

SERC

Kevin White

Northeast
1
Missouri
Electric Power
Cooperative

SERC

Skyler Wiegmann Northeast
3
Missouri
Electric Power
Cooperative

SERC

Ryan Ziegler

1

SERC

6

SERC

Associated
Electric
Cooperative,
Inc.

Brian Ackermann Associated
Electric

Cooperative,
Inc.
Brad Haralson

Associated
Electric
Cooperative,
Inc.

5

SERC

1. Requirement R1: The SDT drafted CIP-012-1 Requirement R1 for the Responsible Entity to implement one or more documented plan(s) to
mitigate the risk of the unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring data while being
transmitted between any Control Centers. Do you agree with this revision? If not, please provide the basis for your disagreement and an
alternate proposal.
Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer

No

Document Name
Comment
R1.2 needs to be modified to reflect the comments in question 4 below.
“On page 5 under section “Identification of Where Security Protection is Applied by the Responsible Entity”, language should be added to address the
situation where a Responsible Entity does not manage either end of a communication link, indicating that this Responsible Entity does not have
compliance obligations to R1.2.”
Likes

0

Dislikes

0

Response

Jeanne Kurzynowski - CMS Energy - Consumers Energy Company - 1,3,4,5 - RF
Answer

No

Document Name
Comment
The requirement as written does not provide clear threshold on the type of Control Centers that should be in scope for this standard, i.e. does this
requirement apply to high/medium impact BES Cyber Systems, or it also applies to low impact BES Cyber System. Please clarify. Please also consider
how to incorporate the scoping criteria into CIP-002 standard.
Likes

0

Dislikes

0

Response

Marty Hostler - Northern California Power Agency - 5
Answer
Document Name
Comment

No

This standard is unnecessary IRO-010 and TOP-003 already require a mutually agreeable security protocol.
Likes

0

Dislikes

0

Response

Darnez Gresham - Darnez Gresham On Behalf of: Annette Johnston, Berkshire Hathaway Energy - MidAmerican Energy Co., 1, 3; - Darnez
Gresham
Answer

No

Document Name
Comment
We support the MRO NSRF comments and add these. One, until the definition of Control Center is set, we will vote no due to uncertain scope for this
requirement. Two, "security protection used to mitigate risk" is too ambiguous for an enforceable standard. We respect the SDT's challenge in writing
language that is not overly prescriptive but yet enforceable. However, we respectfully request SDT to consider including two concepts in R1. First
concept is to include clarity on currently in place ICCP. The Requirement states "while being transmitted between any Control Centers." The draft
Implementation Guidance has content talking about "both ends of the link" but doesn't enlighten on what the expectations are for the data while on the
link. We are concerned with latency (primarily for generation control) if secure encryption is expected over the ICCP. Also, it is our understanding the
secure ICCP may not be widely implemented. Second concept is to include examples that include but are not limiting for security protection.
Likes

1

Dislikes

Central Hudson Gas &amp; Electric Corp., 1, Pace Frank
0

Response

Kevin Salsbury - Berkshire Hathaway - NV Energy - 5
Answer

No

Document Name
Comment
Given this ballot is concurrently open with the Control Center definition revision, NV Energy cannot vote affirmative for this iteration of CIP-012-1, until
there is further clarity in the Control Center definition, or the definition is approved. Additionally, NV Energy has concerns with the implementation of
security protections associated with its multiple ICCP links. The reference documentation of the proposed Standard assumes an “ease” for installation of
“secure ICCP”, but previous regional studies of such protections have proven unfeasible and costly.
Likes

0

Dislikes
Response

0

James Anderson - CMS Energy - Consumers Energy Company - 1
Answer

No

Document Name
Comment
The requirement as written does not provide clear threshold on the type of Control Centers that should be in scope for this standard, i.e. does this
requirement apply to high/medium impact BES Cyber Systems, or it also applies to low impact BES Cyber System. Please clarify. Please also consider
how to incorporate the scoping criteria into CIP-002 standard.
Likes

0

Dislikes

0

Response

Ellen Oswald - Midcontinent ISO, Inc. - 2
Answer

No

Document Name
Comment
The statement for Real-time monitoring does not include control data here. Again for clarification and consistency is control going to be removed from
all the referencing within CIP-012 or added to all references of Real-time monitoring requirements.

Likes

0

Dislikes

0

Response

Brandon McCormick - Brandon McCormick On Behalf of: Ginny Beigel, City of Vero Beach, 3; Lynne Mila, City of Clewiston, 4; Mike Blough,
Kissimmee Utility Authority, 5, 3; Tom Reedy, Florida Municipal Power Pool, 6; - Brandon McCormick, Group Name FMPA
Answer

No

Document Name
Comment
FMPA agrees with the following comments from Lakeland Electric:
Real-time Assessments lists a number of specific inputs that should be considered for both “Real-time Assessment (RTA) and Real-time monitoring
(RTm) data.” There may be an overly stringent audit approach taken that would require consideration of both RTA AND RTm data for proof that an
entity provided adequate protections. If there is a distinction between data used for the RTA and data used for RTm, please provide clarification of the

expectation. We recommend consideration of the use of the inputs in the RTA NERC term with a caveat that Entities may choose to protect additional
data if they feel the need to expand the scope.
From the RTA definition: 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.
While we recognize that TOP/GOP are doing monitoring of their own systems, the Functional Model does not include the term monitoring in the list of
the functions they are performing in real-time. The TOP/GOP functions include “providing real time operational information” or “real time operating
information” to the BA/RC.

The term “any Control Centers” may be overly broad as it seems more reasonable for the standards to apply to High and Medium Impact Control
Centers. It seems more likely that the Control Centers that meet the low impact rating for CIP-002 Attachment 1 Criteria for Low Impact found in section
3 would be transmitting information via the ICCP network. The RC should be required to plan for the encryption of that data on behalf of the Entities
under their direction/control. I believe that some of the “Low Impact Control Centers” may not be required to have a backup control center, especially if
they are operating out of a control house at a substation or control room at a generating plant.

Also, the VRF/VSL still contains language related to CIP Exceptional Circumstances which was part of R2 which was struck from the standard.

Likes

0

Dislikes

0

Response

Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Answer

No

Document Name
Comment
While Tri-State agrees with the language of Requirement R1, we are concerned that there could be a possible violation if logical protections (encryption)
were to temporarily fail. Is that the intent of the SDT? The removal of the CIP Exceptional Circumstance that was in R2 no longer provides the exception
from potential noncompliance if either entity's protections fail due to catastrophic event. Tri-State would like for the CIP Exceptional Circumstance
exclusion to be added back to the standard.

Additionally, if we use encryption as our primary method to meet this requirement and it fails, can we rely solely on physical protections identified and
documented in our plans as a backup protection method to satisfy the intent of the standard?
Likes
Dislikes

0
0

Response

Dennis Sismaet - Northern California Power Agency - 6
Answer

No

Document Name
Comment
This standard is unnecessary. IRO-010 and TOP-003 already require a mutually agreeable security protocol.

Likes

0

Dislikes

0

Response

Eli Rivera - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment
CenterPoint Energy Houston Electric, LLC (“CenterPoint Energy”) does not agree with the revision and suggests adding the phrase “except under CIP
Exceptional Circumstances” to the first sentence to be consistent with the earlier version. CenterPoint Energy recommends changing the first sentence
to:
“The Responsible Entity shall implement one or more documented plan(s) to mitigate the risk of unauthorized disclosure or modification of Real-time
Assessment and Real-time monitoring data while being transmitted between any Control Centers, except under CIP Exceptional Circumstances.”
Likes

0

Dislikes

0

Response

Heather Morgan - EDP Renewables North America LLC - 5
Answer

No

Document Name
Comment
There is concern about the overlap between CIP-012 and TOP-003-3/IRO-010-2. These Standards dictate what generators must comply with from our
RC, BA, and TOP in the way of data communication. As a generator, we must comply with our TOP-003 and IRO-010 instructions for data

communication. Should these standards be combined? Will the RC, BA, and TOP take responsibility to ensure security of the data being transmitted on
their equipment that we are required to use? In the current language, there is a lack of ownership responsibility. For 1.3, the RC, BA, and TOP (as the
authorizing entities that own the equipment and instruct generators on how to comply for IRO-010 and TOP-003) should be responsible (for identifying
not only their RC, BA, and TOP) responsibilities, but the Generator Operator’s responsibilities as well.
Likes

0

Dislikes

0

Response

Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6
Answer

No

Document Name
Comment
PacifiCorp supports MEC’s comments and adds the following: In November 2005, it was decided that all Reliability Transmission Controllers (RTCs,
now called RCs) would need to have Secure ICCP implemented by October 2006, and that all connecting utilities would need to have Secure ICCP by
October 2008.

Encryption between routers was discussed, but some utilities managed their own edge routers and others were managed by AT&T therefore,
coordination between entities could not be secured. Eventually Secure ICCP was removed from the Data Exchange/EMS Work Group (DEMSWG)
agendas. There is no awareness of any WECC utilities which are making use of Secure ICCP today, and only a limited number utilities have the
capability.

The WECC Data Exchange/EMS Work Group (DEMSWG) worked with vendors to perform inter-operability testing and also train utilities in how to
obtain and install certificates. This effort is referenced in comments for item 3 below.

Please provide additional clarity where ICCP is used for Real-time Assessment and Real-time monitoring data being transmitted between any Control
Centers owned or operated by different Responsible Entities. (Please note the distinction between ICCP and Secure ICCP used above)

Likes

0

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0

Response

Terry Harbour - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1
Answer
Document Name

No

Comment
We support the MRO NSRF comments and add these. One, until the definition of Control Center is set, we will vote no due to uncertain scope for this
requirement. Two, "security protection used to mitigate risk" is too ambiguous for an enforceable standard. We respect the SDT's challenge in writing
language that is not overly prescriptive but yet enforceable. However, we respectfully request SDT to consider including two concepts in R1. First
concept is to include clarity on currently in place ICCP. The Requirement states "while being transmitted between any Control Centers." The draft
Implementation Guidance has content talking about "both ends of the link" but doesn't enlighten on what the expectations are for the data while on the
link. We are concerned with latency (primarily for generation control) if secure encryption is expected over the ICCP. Also, it is our understanding the
secure ICCP may not be widely implemented. Second concept is to include examples that include but are not limiting for security protection.
Likes

0

Dislikes

0

Response

Warren Cross - ACES Power Marketing - 1,3,4,5 - MRO,WECC,Texas RE,SERC,SPP RE,RF
Answer

No

Document Name
Comment
The SDT team has done a good job of responding to industry comments regarding CIP-012.

Does an entity need to draft a new plan to mitigate these areas of concerns:

- security protection used to mitigate the risk of unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring data while
being transmitted between Control Centers;
- where the Responsible Entity applied security protection for transmitting Real-time Assessment and Real-time monitoring data between Control
Centers;
- The responsibilities of each Responsible Entity for applying security protection to the transmission of Real-time Assessment and Real-time monitoring
data between Control Centers that are owned or operated by different Responsible Entities.

Does not the current set of standards address those additional vulnerabilities in the entity’s IT Security Plan? That current plan should be updated to
include these additional risks, threats and integrated solution(s) that are already by performed by the entity.
Likes

0

Dislikes
Response

0

Wendy Center - U.S. Bureau of Reclamation - 5
Answer

No

Document Name
Comment
Reclamation disagrees that having a plan adds to the reliability of protecting data used for Real-time Assessment and Real-time monitoring. A plan is an
unwarranted layer of compliance that is not needed. Reclamation recommends replacing the term “plan” with “process” and rewriting R1 and its parts as
follows:
•

R1. Each Responsible Entity shall implement one or more documented processes to mitigate the risk of unauthorized disclosure or modification
of BES Data being transmitted between any Control Centers. This requirement excludes oral and non-electronic communications.
o

R1.1. Identify the security protection used to mitigate the risk of unauthorized disclosure of BES Data being transmitted between Control
Centers;

o

R1.2. Identify where the Responsible Entity applied security protection for transmitting BES Data between Control Centers; and

o

R1.3. Identify the responsibilities of each Responsible Entity whose Control Center(s) are involved in the transmission of BES Data.

Reclamation also recommends adding the following definition to the NERC Glossary of Terms:
•

BES Data: BES reliability operating services information affecting Operational Planning Analysis, Real-time Assessments, and Real-time
monitoring.

Likes

0

Dislikes

0

Response

Jamie Prater - Entergy - 5
Answer

No

Document Name
Comment
Comments: The deletion of R2 removed the exemption for “except under CIP Exceptional Circumstances," however the CIP Exceptional Circumstances
language still exists in the VSL/VRF tables. The CIP Exceptional Circumstance language should be explicitly added to the R1 requirement to align with
the VSL/VRF, and clearly indicate the intent of the requirement.
Likes

0

Dislikes

0

Response

Lynn Goldstein - PNM Resources - Public Service Company of New Mexico - 3

Answer

No

Document Name
Comment
PNM agrees with FMPA's comment which stated “... the VRF/VSL still contains language related to CIP Exceptional Circumstances which was part of
R2 which was struck from the standard.”
Likes

0

Dislikes

0

Response

Laurie Williams - PNM Resources - Public Service Company of New Mexico - 1
Answer

No

Document Name
Comment
PNM agrees with FMPA's comment which stated “... the VRF/VSL still contains language related to CIP Exceptional Circumstances which was part of
R2 which was struck from the standard."
Likes

0

Dislikes

0

Response

Patricia Lynch - NRG - NRG Energy, Inc. - 5,6
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Joe Tarantino - Joe Tarantino On Behalf of: Arthur Starkovich, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Beth Tincher, Sacramento
Municipal Utility District, 4, 1, 5, 6, 3; Jamie Cutlip, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Kevin Smith, Balancing Authority of
Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Susan Oto, Sacramento Municipal Utility District, 4, 1,
5, 6, 3; - Joe Tarantino

Answer

Yes

Document Name
Comment

Real-time monitoring is not a defined term, the R in Real-time should not be capitalized. We are still concerned that coordination between
control centers may result in compromises that may not satisfy the needs of the entities involved.

Likes

0

Dislikes

0

Response

Russel Mountjoy - Midwest Reliability Organization - 10, Group Name MRO NSRF
Answer

Yes

Document Name
Comment
The drafting team has done a good job of responding to industry comments. The NSRF would like to offer the following two items:
1) The Standards Efficiency group within NERC is working towards actionable Standards and removing the layers of compliance that do not promote
reliability. The NSRF recommends for R1 that entities not be required to have a plan, but have an actionable Requirement to implement. NSRF
suggests the following R1 wording:
“The Responsible Entity shall mitigate the risk of unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring data while
being transmitted between any Control Centers. This requirement excludes oral communications. Responsible Entities shall document:
•

security protection used to mitigate the risk of unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring data
while being transmitted between Control Centers;

•

where the Responsible Entity applied security protection for transmitting Real-time Assessment and Real-time monitoring data between Control
Centers;

•

The responsibilities of each Responsible Entity for applying security protection to the transmission of Real-time Assessment and Real-time
monitoring data between Control Centers that are owned or operated by different Responsible Entities.

2) NERC has issued for comment the definition for Control Center during the third draft of CIP-012-1. The definition of terms late in the drafting/balloting
process of a Standard is not the right time to consider a definition change as this may impact the Standard being considered during the late rounds of
balloting. The NSRF recommends that defined terms be offered up in the early stages of drafting and balloting of Standards.
Likes
Dislikes

0
0

Response

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer

Yes

Document Name
Comment
City Light supports SRP comments
Likes

0

Dislikes

0

Response

Andy Fuhrman - Andy Fuhrman On Behalf of: Theresa Allard, Minnkota Power Cooperative Inc., 1; - Andy Fuhrman
Answer

Yes

Document Name
Comment
See MRO NSRF comments.
Likes

0

Dislikes

0

Response

Shannon Fair - Colorado Springs Utilities - 1,3,5,6, Group Name Colorado Springs Utilities
Answer

Yes

Document Name
Comment
CSU agrees the data should be protected. CSU also agrees the protections for the data in scope must ensure the data has not been modified, and that
FERC directed NERC to “specify how the confidentiality, integrity, and availability of each type of bulk electric system data should be protected while it
is being transmitted.” However, CSU takes exception to the extent the proposed standard requires the data in scope to be protected. FERC Order 822
states on page 36, “ we recognize that not all communication network components and data pose the same risk to bulk electric system reliability and
may not require the same level of protection.” However, the proposed standard applies the same criteria of protection against unauthorized disclosure
across all of the data within the defined scope. CSU does not agree viewing of the Real-time Assessment and Real-time monitoring and control data
without context will decrease the reliable operation of the BES and asserts confidentiality does not need to be protected for all data under this scope.
Along with this, CSU would like a clarification of how the SDT defines Real-Time Assessment Data.

Additionally, CSU recognizes the SDT is not specifying the controls used to protect confidentiality and integrity. However, the only method available to
achieve the proposed required objective is to implement encryption. FERC Order 822 states on page 39, “it is reasonable to conclude that any lag in
communication speed resulting from implementation of protections [encryption technologies] should only be measureable on the order of milliseconds
and, therefore, will not adversely impact Control Center communications,” but CSU asserts this statement only refers to a single data stream. It is
unknown what encryption will do when dealing with multiple data streams being transmitted at once, from one to many points, not only to the latency
added for the reliable operation of the BES, but also to the computing resources.
Likes

0

Dislikes

0

Response

Thomas Breene - WEC Energy Group, Inc. - 3
Answer

Yes

Document Name
Comment
While we support the changes to the standard, we are concerned that there may be unintended consequences if the Control Center definition is
approved as proposed and urge the SDT to proceed with caution.
Likes

0

Dislikes

0

Response

Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment
While Duke Energy has no immediate concerns regarding the scope of R1, we do have concerns regarding the proposed definition of Control Center
which is included in this project. We have submitted our comments on the proposed definition separately, and will not repeat them here. However, the
definition of Control Center is directly related to the overall scope of CIP-012, and if we have some clarifying concerns with the definition, those same
concerns are inherent to the proposed CIP-012. We suggest the drafting team consider the procedural effects of balloting these two related items
separately, when they are so directly related.
Likes

0

Dislikes

0

Response

Vivian Vo - APS - Arizona Public Service Co. - 3

Answer

Yes

Document Name

CIP-012-1_Draft 3_AZPS Comments-Question 1.docx

Comment
Please see the attached file for Arizona Public Service Co.'s comments to Question 1.
Likes

0

Dislikes

0

Response

John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1
Answer

Yes

Document Name
Comment
No Comment
Likes

0

Dislikes

0

Response

Jack Cashin - American Public Power Association - 4
Answer

Yes

Document Name
Comment
no comment
Likes

0

Dislikes

0

Response

Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Document Name

Yes

Comment
Yes, with comments. Some of Southern Company’s partner utilities do not currently use a VPN for their data connections – this will require Southern to
engage in discussions and potentially renegotiate contract terms regarding these connections. We recognize that other utilities will be held to the same
standard and, therefore, will be motivated to work toward maintaining compliance. We recognize this as something we will need to spend time to
address.
Likes

0

Dislikes

0

Response

Russell Martin II - Salt River Project - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
SRP agrees the data should be protected. SRP also agrees the protections for the data in scope must ensure the data has not been modified, and that
FERC directed NERC to “specify how the confidentiality, integrity, and availability of each type of bulk electric system data should be protected while it
is being transmitted.” However, SRP takes exception to the extent the proposed standard requires the data in scope to be protected. FERC Order 822
states on page 36, “…we recognize that not all communication network components and data pose the same risk to bulk electric system reliability and
may not require the same level of protection.” However, the proposed standard applies the same criteria of protection against unauthorized disclosure
across all of the data within the defined scope. SRP does not agree viewing of the Real-time Assessment and Real-time monitoring and control data
without context will decrease the reliable operation of the BES and asserts confidentiality does not need to be protected for all data under this scope.
Along with this, SRP would like a clarification of how the SDT defines Real-Time Assessment Data.

Additionally, SRP recognizes the SDT is not specifying the controls used to protect confidentiality and integrity. However, the only method available to
achieve the proposed required objective is to implement encryption. FERC Order 822 states on page 39, “it is reasonable to conclude that any lag in
communication speed resulting from implementation of protections [encryption technologies] should only be measureable on the order of milliseconds
and, therefore, will not adversely impact Control Center communications,” but SRP asserts this statement only refers to a single data stream. It is
unknown what encryption will do when dealing with multiple data streams being transmitted at once, from one to many points, not only to the latency
added for the reliable operation of the BES, but also to the computing resources.
Likes

0

Dislikes

0

Response

Kristine Ward - Seminole Electric Cooperative, Inc. - 1,3,4,5,6 - FRCC
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

Nicholas Lauriat - Network and Security Technologies - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Aaron Austin - AEP - 3
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Steven Rueckert - Western Electricity Coordinating Council - 10
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Faz Kasraie - Seattle City Light - 5 - WECC
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Glen Farmer - Avista - Avista Corporation - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

Tho Tran - Tho Tran On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; - Tho Tran
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Adrian Andreoiu - BC Hydro and Power Authority - 1,3,5 - WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Douglas Johnson - American Transmission Company, LLC - 1
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

David Gordon - Massachusetts Municipal Wholesale Electric Company - 5

Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 3, Group Name FirstEnergy Corporation
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Chris Scanlon - Exelon - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Nicolas Turcotte - Hydro-Qu?bec TransEnergie - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Andrey Komissarov - Andrey Komissarov On Behalf of: Jerome Gobby, Sempra - San Diego Gas and Electric, 3, 5, 1; - Andrey Komissarov
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Teresa Cantwell - Lower Colorado River Authority - 1,5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Russell Noble - Cowlitz County PUD - 3
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion, NextEra and HQ
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment

Likes
Dislikes

0
0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Brandon Gleason - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment

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0

Response

Todd Bennett - Associated Electric Cooperative, Inc. - 3, Group Name AECI
Answer
Document Name
Comment
AECI supports comments provided by NRECA
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Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

Document Name
Comment
Texas RE appreciates the SDT’s efforts to develop a workable data security standard. In particular, Texas RE believes that the SDT’s various revisions
have substantially improved the proposed CIP-012-1 Standard from the initial version. Despite these improvements, Texas RE remains concerned that
the proposed Standard, as currently drafted, is not sufficiently clear that in identifying both the security protections used to mitigate the risk of
unauthorized disclosures and the locations where the Responsible Entities applied such protections, Responsible Entities will need to protect both data
throughout the transmission process, as well as communications links. That is, Texas RE continues to believe that FERC Order No, 822 contemplated
both physical protection of communications links and additional protections for data to ensure there is adequate “security protection used to mitigate the
risk of unauthorized disclosure or modification” of data while being transmitted between Control Centers. As such, Texas RE recommends inserting the
phrase “including protections for communications links and data” into the proposed CIP-012-1 R1.1 so that it reads “[i]dentification of security protection,
including protections for communications links and data, used to mitigate the risk of unauthorized disclosure or modification of Real-time Assessment
and Real-time monitoring data while being transmitted between Control Centers.”

Texas RE continues to be concerned that Operations Planning Analysis (OPA) data is not included in CIP-012-1. Texas RE noticed the Violation Time
Horizon is for Operations Planning. Since the SDT has indicated reasons for excluding OPA data, should the relevant Violation Time Horizon be Realtime Operation?
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0

2. Implementation Plan: The SDT established the Implementation Plan to make the standard effective the first day of the first calendar quarter
that is twenty-four (24) calendar months after the effective date of the applicable governmental authority’s order approving the standard, or
as otherwise provided for by the applicable governmental authority. Do you agree with this proposal? If you think an alternate
implementation time period is needed, please provide a detailed explanation of actions and time needed to meet the implementation
deadline.
Russell Martin II - Salt River Project - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
Overall, SRP does not agree with twenty-four (24) calendar months for the implementation of Requirements R1, as R1 and R2 from the second draft
have been merged. Although SRP recognizes the SDT is not specifying the controls to be used to protect confidentiality and integrity, the only examples
provided in the implementation guidance includes encryption. If there are other methods available to achieve the security objective, SRP asks the SDT
to provide them. However, the only method available to achieve the proposed required objective, on the ICCP network, is to implement encryption. As
FERC order 822 states on page 37, “if several registered entities have joint responsibility for a cryptographic key management system used between
their respective Control Centers, they should have the prerogative to come to a consensus on which organization administers that particular key
management system.” Furthermore, the FERC order states on page 38, “While responsible entities are required to exchange real-time and operational
planning data necessary to operate the bulk electric system using mutually agreeable security protocols, there is no technical specification for how this
transfer of information should incorporate mandatory security controls.” These are activities and specifications that must be created and agreed upon by
all registered entities involved in the data transfer. As such the timeline is reliant on registered entities working together on a common solution and
would not be achievable within 24 calendar months.

Additionally, if encryption fails, SRP would lose Real-time Assessment and Real-time monitoring and control data. There are many opportunities for
encryption to fail that must be addressed. The implementation of encryption requires a pilot to truly understand and address the mechanisms of failure,
the impacts encryption would cause on the exchange of the data, and the computing resources required. A pilot also requires a great amount of
coordination to execute, not only within the industry, but may also include carriers, vendors, and possibly third-party encryption key program managers.

Because of the aforementioned reasons and concerns, SRP is recommending a phased implementation for CIP-012-1. A 24 month implementation is
appropriate, but only for Requirement R1. The 24 months for R1 would provide time to coordinate and create an industry-wide solution. SRP is
proposing the SDT include an additional 12 months for the plan implementation aspect of Requirement R1. The additional 12 months would be used for
a pilot and course correction if needed, in addition to understanding, formulating, and executing maintenance strategies.
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Terry Harbour - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1
Answer
Document Name

No

Comment
Until the security protections scope is clearer and the definition of Control Center is final, it is not possible to determine if 24 months is adequate.
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Response

Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6
Answer

No

Document Name
Comment
PacifiCorp support MEC’s comments and add the following: Until the definition of Control Center is final and clarity is added where ICCP is used for
Real-time Assessment and Real-time monitoring data being transmitted between any Control Centers owned or operated by different Responsible
Entities, it is not possible to determine if 24 months is adequate. (Please note the distinction between ICCP and Secure ICCP used in question 2
above)
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0

Response

Russell Noble - Cowlitz County PUD - 3
Answer

No

Document Name
Comment
Cowlitz PUD supports the comments submitted by the Bonneville Power Administration.
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0

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0

Response

Dennis Sismaet - Northern California Power Agency - 6
Answer
Document Name

No

Comment
See Response to Question 1.
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0

Response

Nicolas Turcotte - Hydro-Qu?bec TransEnergie - 1
Answer

No

Document Name
Comment
Recommend 36 months for 1) review and 2) develop new contract and 3) budgetary cycles 4) Implementation cycles (planned outages, etc.)
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0

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0

Response

Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Answer

No

Document Name
Comment
Tri-State anticipates implementation of CIP-012 could be extremely burdensome and would recommend increasing the implementation period to 36
months. Depending on the number of connections to other entities, the negotiation process could take some significant resources and time.
Tri-State suggests the SDT send a survey to industry requesting feedback to gauge the number of connections to other entities industry has and the
amount of time entities expect they will need to implement CIP-012.
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Ellen Oswald - Midcontinent ISO, Inc. - 2
Answer
Document Name

No

Comment
Concerns about the contracts with third parties for carriers used between applicable control centers. If they are dedicated or shared circuits based on
the implementation guidance document this should not be an issue until it is actually put into practical use.
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Kevin Salsbury - Berkshire Hathaway - NV Energy - 5
Answer

No

Document Name
Comment
Without further clarity involving security protections of the data (i.e. ICCP protections) NV Energy is unable to determine if the 24 calendar months is
sufficient.
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0

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Response

Darnez Gresham - Darnez Gresham On Behalf of: Annette Johnston, Berkshire Hathaway Energy - MidAmerican Energy Co., 1, 3; - Darnez
Gresham
Answer

No

Document Name
Comment
Until the security protections scope is clearer and the definition of Control Center is final, it is not possible to determine if 24 months is adequate.
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0

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Response

Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer
Document Name

No

Comment
Duke Energy suggests a staggered implementation plan for CIP-012 specifically concerning coordination with neighboring entities. We consider it
possible for an entity to gather necessary data, convening of internal work groups, and drafting of security protection plans in the proposed 24 month
Implementation Plan. However, we feel that the coordination with other entities that will be necessary for R1.3 will take longer than the proposed 24
months, especially with internal work already taking place. We recommend the drafting team consider a staggered implementation plan for internal work
(18 months) compared to external coordination work (36 months). We feel that this amount of time will is necessary to implement all aspects of the
proposed standard.
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0

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0

Response

Marty Hostler - Northern California Power Agency - 5
Answer

No

Document Name
Comment
See Response to Question 1.
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0

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0

Response

Shannon Fair - Colorado Springs Utilities - 1,3,5,6, Group Name Colorado Springs Utilities
Answer

No

Document Name
Comment
CSU does not agree with twenty-four (24) calendar months for the implementation of Requirements R1, as R1 and R2 from the second draft have been
merged. Although CU recognizes the SDT is not specifying the controls to be used to protect confidentiality and integrity, the only examples provided in
the implementation guidance includes encryption. If there are other methods available to achieve the security objective, SRP asks the SDT to provide
them. However, the only method available to achieve the proposed required objective, on the ICCP network, is to implement encryption. As FERC order
822 states on page 37, “if several registered entities have joint responsibility for a cryptographic key management system used between their respective
Control Centers, they should have the prerogative to come to a consensus on which organization administers that particular key management system.”
Furthermore, the FERC order states on page 38, “While responsible entities are required to exchange real-time and operational planning data
necessary to operate the bulk electric system using mutually agreeable security protocols, there is no technical specification for how this transfer of
information should incorporate mandatory security controls.” These are activities and specifications that must be created and agreed upon by all
registered entities involved in the data transfer. As such the timeline is reliant on registered entities working together on a common solution and would
not be achievable within 24 calendar months.

Additionally, if encryption fails, CSU would lose Real-time Assessment and Real-time monitoring and control data. There are many opportunities for
encryption to fail that must be addressed. The implementation of encryption requires a pilot to truly understand and address the mechanisms of failure,
the impacts encryption would cause on the exchange of the data, and the computing resources required. A pilot also requires a great amount of
coordination to execute, not only within the industry, but may also include carriers, vendors, and possibly third-party encryption key program managers.
Because of the aforementioned reasons and concerns, CSU is recommending a phased implementation for CIP-012-1. A 24 month implementation is
appropriate, but only for Requirement R1. The 24 months for R1 would provide time to coordinate and create an industry-wide solution. CSU is
proposing the SDT include an additional 12 months for the plan implementation aspect of Requirement R1. The additional 12 months would be used for
a pilot and course correction if needed, in addition to understanding, formulating, and executing maintenance strategies.
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0

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0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
BPA appreciates the increase to 24 months but recommends 36 months due to BPA’s large amount of applicable data, access to funds and budget
cycle, and resources to perform work required.
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Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer

No

Document Name
Comment
City Light supports SRP comments
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0

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0

Response

Patricia Lynch - NRG - NRG Energy, Inc. - 5,6

Answer

No

Document Name
Comment

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0

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0

Response

Brandon McCormick - Brandon McCormick On Behalf of: Ginny Beigel, City of Vero Beach, 3; Lynne Mila, City of Clewiston, 4; Mike Blough,
Kissimmee Utility Authority, 5, 3; Tom Reedy, Florida Municipal Power Pool, 6; - Brandon McCormick, Group Name FMPA
Answer

No

Document Name
Comment

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0

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0

Response

Wendy Center - U.S. Bureau of Reclamation - 5
Answer

Yes

Document Name
Comment
Reclamation supports a 24-month implementation period.
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0

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0

Response

Warren Cross - ACES Power Marketing - 1,3,4,5 - MRO,WECC,Texas RE,SERC,SPP RE,RF
Answer
Document Name
Comment

Yes

No comment.
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0

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0

Response

Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer

Yes

Document Name
Comment
Yes, without additional comment.
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0

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0

Response

Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer

Yes

Document Name
Comment
Due to the time and cost of acquiring and implementing needed technological solutions and the coordination that will be required between Responsible
Entities, a 24 month implementation period would be the minimal amount of time needed to properly implement the proposed Requirements.
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0

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0

Response

Chris Scanlon - Exelon - 1
Answer

Yes

Document Name
Comment
24 months should be the minimum implementation time used, no shorter.

Likes

0

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0

Response

Andy Fuhrman - Andy Fuhrman On Behalf of: Theresa Allard, Minnkota Power Cooperative Inc., 1; - Andy Fuhrman
Answer

Yes

Document Name
Comment
See MRO NSRF comments.
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0

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0

Response

Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer

Yes

Document Name
Comment
24 months allows the Responsible Entity sufficient time to both develop and successfully implement the plan. This would include coordination with
neighboring entities and potentially adding new controls to the communication links.
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0

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0

Response

Brandon Gleason - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment

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0
0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

Yes

Document Name
Comment

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0

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0

Response

David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment

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0

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0

Response

Jamie Prater - Entergy - 5
Answer

Yes

Document Name
Comment

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0

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0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion, NextEra and HQ
Answer
Document Name

Yes

Comment

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0

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0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

Yes

Document Name
Comment

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0

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0

Response

Heather Morgan - EDP Renewables North America LLC - 5
Answer

Yes

Document Name
Comment

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0

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0

Response

Eli Rivera - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

Yes

Document Name
Comment

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0

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Response

0

Teresa Cantwell - Lower Colorado River Authority - 1,5
Answer

Yes

Document Name
Comment

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0

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0

Response

Andrey Komissarov - Andrey Komissarov On Behalf of: Jerome Gobby, Sempra - San Diego Gas and Electric, 3, 5, 1; - Andrey Komissarov
Answer

Yes

Document Name
Comment

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0

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0

Response

James Anderson - CMS Energy - Consumers Energy Company - 1
Answer

Yes

Document Name
Comment

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0

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0

Response

Vivian Vo - APS - Arizona Public Service Co. - 3
Answer
Document Name
Comment

Yes

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0

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0

Response

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 3, Group Name FirstEnergy Corporation
Answer

Yes

Document Name
Comment

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0

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0

Response

David Gordon - Massachusetts Municipal Wholesale Electric Company - 5
Answer

Yes

Document Name
Comment

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0

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0

Response

Douglas Johnson - American Transmission Company, LLC - 1
Answer

Yes

Document Name
Comment

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0

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Response

0

Adrian Andreoiu - BC Hydro and Power Authority - 1,3,5 - WECC
Answer

Yes

Document Name
Comment

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0

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0

Response

Thomas Breene - WEC Energy Group, Inc. - 3
Answer

Yes

Document Name
Comment

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0

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0

Response

Tho Tran - Tho Tran On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; - Tho Tran
Answer

Yes

Document Name
Comment

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0

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0

Response

Glen Farmer - Avista - Avista Corporation - 5
Answer
Document Name
Comment

Yes

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0

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0

Response

Faz Kasraie - Seattle City Light - 5 - WECC
Answer

Yes

Document Name
Comment

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0

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0

Response

Jeanne Kurzynowski - CMS Energy - Consumers Energy Company - 1,3,4,5 - RF
Answer

Yes

Document Name
Comment

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0

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0

Response

Russel Mountjoy - Midwest Reliability Organization - 10, Group Name MRO NSRF
Answer

Yes

Document Name
Comment

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0

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0

Response

Aaron Austin - AEP - 3

Answer

Yes

Document Name
Comment

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0

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0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment

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0

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0

Response

Nicholas Lauriat - Network and Security Technologies - 1
Answer

Yes

Document Name
Comment

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0

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0

Response

Joe Tarantino - Joe Tarantino On Behalf of: Arthur Starkovich, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Beth Tincher, Sacramento
Municipal Utility District, 4, 1, 5, 6, 3; Jamie Cutlip, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Kevin Smith, Balancing Authority of
Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Susan Oto, Sacramento Municipal Utility District, 4, 1,
5, 6, 3; - Joe Tarantino
Answer
Document Name
Comment

Yes

Likes

0

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0

Response

Kristine Ward - Seminole Electric Cooperative, Inc. - 1,3,4,5,6 - FRCC
Answer

Yes

Document Name
Comment

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0

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0

Response

Jack Cashin - American Public Power Association - 4
Answer
Document Name
Comment
The proposed standard and implementation plan are silent on physical security for the equipment being used to provide the data protection. For
example, physical security protection for a router located in another Entity’s facility. Trouble shooting such issues could affect the implementation
schedule.
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0

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0

Response

John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1
Answer
Document Name
Comment
Tacoma Power supports comments provided by APPA.
Likes

0

Dislikes

0

Response

Todd Bennett - Associated Electric Cooperative, Inc. - 3, Group Name AECI
Answer
Document Name
Comment
AECI supports comments provided by NRECA
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0

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0

Response

Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer
Document Name
Comment
The proposed standard and implementation plan are silent on physical security for the equipment being used to provide the data protection. For
example, protection for a router that is located in an other Entities facility
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0

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Response

Steven Rueckert - Western Electricity Coordinating Council - 10
Answer
Document Name
Comment
WECC has heard concerns voiced that a 24 calendar month implementation plan is not enough time to implemnt the technical solution, however, a
alternative time frame has not been suggested.
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0

Response

3. The SDT modified the draft Technical Rationale and Justification for CIP-012 to assist in understanding the technology and technical
requirements in the Reliability Standard. It also contains information on the SDT’s intent in drafting the requirements. Do you agree with the
technology and technical requirements in the draft Technical Rationale and Justification? If you do not agree, or if you agree but have
comments or suggestions for the draft Technical Rationale and Justification, please provide your recommendation and explanation.
Jeanne Kurzynowski - CMS Energy - Consumers Energy Company - 1,3,4,5 - RF
Answer

No

Document Name
Comment
To be consistent with other CIP standards, please combine Technical Rational and Justification document with the Implementation Guidance document
and then incorporate the new document into the draft standard. Please clarify that CIP-012 is a standalone standard that is not associated with all the
other CIP standards.
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0

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0

Response

Marty Hostler - Northern California Power Agency - 5
Answer

No

Document Name
Comment
See Response to Question 1.
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0

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0

Response

Darnez Gresham - Darnez Gresham On Behalf of: Annette Johnston, Berkshire Hathaway Energy - MidAmerican Energy Co., 1, 3; - Darnez
Gresham
Answer

No

Document Name
Comment
We support MRO NSRF comments.
Likes

0

Dislikes

0

Response

James Anderson - CMS Energy - Consumers Energy Company - 1
Answer

No

Document Name
Comment
To be consistent with other CIP standards, please combine Technical Rational and Justification document with the Implementation Guidance document
and then incorporate the new document into the draft standard. Please clarify that CIP-012 is a standalone standard that is not associated with all the
other CIP standards.
Likes

0

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0

Response

Ellen Oswald - Midcontinent ISO, Inc. - 2
Answer

No

Document Name
Comment
By adding control to the statement "Real-time monitoring" from TOP-003 and IRO-010 won't this set an expectation that control data will be part of
those standards by default. The implementation guidance for CIP-012-1 in the identification of security protection section has taken out the wording of
control so just in the documents providing guidance has contradictions of the Real-time monitoring of data. Recommendation that if control is to be part
of "Real-time monitoring" then make the modifications across the board including in the Glossary. The way it is right now adds to the
misunderstanding and different interruption that and entity could have in trying to create an implementation plan.
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Response

Brandon McCormick - Brandon McCormick On Behalf of: Ginny Beigel, City of Vero Beach, 3; Lynne Mila, City of Clewiston, 4; Mike Blough,
Kissimmee Utility Authority, 5, 3; Tom Reedy, Florida Municipal Power Pool, 6; - Brandon McCormick, Group Name FMPA
Answer
Document Name
Comment

No

FMPA agrees with the following comments from Lakeland Electric:
NERC SDTs need to start revising language related to the number of regions with the removal of the SPP RE (p. 3).
General Considerations for Requirement R1: document should be documented plan
Alignment with IRO and TOP standards: last sentence “Real-time Monitoring “, the M should not be capitalized as it is not a NERC defined term.
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0

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0

Response

Dennis Sismaet - Northern California Power Agency - 6
Answer

No

Document Name
Comment
See Response to Question 1.
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0

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0

Response

Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6
Answer

No

Document Name
Comment
PacifiCorp supports MEC’s comments and adds the following: With reference to the Technical Rationale “Control Center Ownership”, the WECC Data
Exchange/EMS Work Group (DEMSWG) worked with vendors to perform inter-operability testing and also train utilities in how to obtain and install
certificates. Initially companies could not implement Secure ICCP on a UNIX server because the implementation required a SISCO stack and an Intel
windows based server. Obtaining a new certificate would require 10 days and would expire in 1 year. This certificate expiration presented a problem of
renewal in a timely manner and because of this many utilities were wanting expiration periods from 3 to 15 years. There was concern if a certificate
expired during the night or weekend as to what would happen to the data transfer. Eventually the inability to guarantee a valid certificate at all times
doomed the implementation of Secure ICCP.
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0

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0

Terry Harbour - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1
Answer

No

Document Name
Comment
We support MRO NSRF comments.
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0

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0

Response

Wendy Center - U.S. Bureau of Reclamation - 5
Answer

No

Document Name
Comment
Reclamation recommends the changes proposed in the response to Question 1 be implemented in the Technical Rationale for consistency.
Reclamation also recommends correcting the grammar in “General Considerations for Requirement R1
from: “Requirement R1 focuses on implemented a document plan…”
to: “Requirement R1 focuses on implementing a documented process…”
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0

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0

Response

Patricia Lynch - NRG - NRG Energy, Inc. - 5,6
Answer

No

Document Name
Comment

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0

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Response

0

Aaron Austin - AEP - 3
Answer

Yes

Document Name
Comment
AEP requests the SDT consider including some statements in Technical Rationale to address the possibility that data requests made related to TOP003 and/or IRO-010 include other data that is not Real-time Assessment data or Real-time monitoring data and how the Responsible Entity could
exclude this other data from the security requirements.
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0

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0

Response

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer

Yes

Document Name
Comment
City Light supports SRP comments
Likes

0

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0

Response

Andy Fuhrman - Andy Fuhrman On Behalf of: Theresa Allard, Minnkota Power Cooperative Inc., 1; - Andy Fuhrman
Answer

Yes

Document Name
Comment
See MRO NSRF comments.
Likes

0

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Response

0

Shannon Fair - Colorado Springs Utilities - 1,3,5,6, Group Name Colorado Springs Utilities
Answer

Yes

Document Name
Comment
CSU agrees with the Technical Rationale and Justification for CIP-012 provided by the SDT. However, CSU continues to maintain that an additional 12
months be considered for the plan implementation aspect of Requirement R1. PDF page 6, paragraph 3 of section title Identification of Where Security
Protection is Applied by the Responsible Entity states "The SDT understands that in data exchanges between Control Centers, a single entity may not
be responsible for both ends of the communication link." With the intent of the standard being to secure communications between Control Centers
(including communication between two separate entities Control Centers), this will call for inter-entity cooperation to ensure both sides of link are
secure. This is where the additional 12 months would be necessary, for coordination of efforts from both entities.
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0

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0

Response

Kevin Salsbury - Berkshire Hathaway - NV Energy - 5
Answer

Yes

Document Name
Comment
NV Energy does believe the need for this Standard is necessary, and the Rationale and Justification document provides a sufficient amount of
information for the need, and protections to consider. The documents focus is not to provide detailed implementation methods, but just provide the
“why” for the Standard and its Requirement.
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0

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0

Response

John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1
Answer

Yes

Document Name
Comment
No Comment
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0
0

Response

Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer

Yes

Document Name
Comment
Yes, without additional comment.
Likes

0

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0

Response

Warren Cross - ACES Power Marketing - 1,3,4,5 - MRO,WECC,Texas RE,SERC,SPP RE,RF
Answer

Yes

Document Name
Comment
No comment.
Likes

0

Dislikes

0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion, NextEra and HQ
Answer

Yes

Document Name
Comment
Recommend removing the diagram because it does not represent enough examples. We believe the scope is understandable without the diagram
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0

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0

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

Yes

Document Name
Comment
The SPP Standards Review Group suggests revising language in the General Considerations for Requirement R1 to read as follows:
Requirement R1 focuses on implementing a documented plan to protect information that is critical to the Real-time operations of the Bulk Electric
System while in transit between applicable Control Centers.
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Russell Martin II - Salt River Project - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
SRP agrees with the Technical Rationale and Justification for CIP-012 provided by the SDT. However, SRP continues to maintain that an additional 12
months be considered for the plan implementation aspect of Requirement R1. PDF page 6, paragraph 3 of section title Identification of Where Security
Protection is Applied by the Responsible Entity states "The SDT understands that in data exchanges between Control Centers, a single entity may not
be responsible for both ends of the communication link." With the intent of the standard being to secure communications between Control Centers
(including communication between two separate entities Control Centers), this will call for inter-entity cooperation to ensure both sides of link are
secure. This is where the additional 12 months would be necessary, for coordination of efforts from both entities.
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0

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Brandon Gleason - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment
When addressing the security protections, the rationale should include that logical and physical controls can be used. This should include the team’s
rationale for allowing these alternatives.
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0

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Kristine Ward - Seminole Electric Cooperative, Inc. - 1,3,4,5,6 - FRCC
Answer

Yes

Document Name
Comment

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0

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0

Response

Joe Tarantino - Joe Tarantino On Behalf of: Arthur Starkovich, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Beth Tincher, Sacramento
Municipal Utility District, 4, 1, 5, 6, 3; Jamie Cutlip, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Kevin Smith, Balancing Authority of
Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Susan Oto, Sacramento Municipal Utility District, 4, 1,
5, 6, 3; - Joe Tarantino
Answer

Yes

Document Name
Comment

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0

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0

Response

Nicholas Lauriat - Network and Security Technologies - 1
Answer

Yes

Document Name
Comment

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0

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Response

0

Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment

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0

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0

Response

Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer

Yes

Document Name
Comment

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0

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0

Response

Faz Kasraie - Seattle City Light - 5 - WECC
Answer

Yes

Document Name
Comment

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0

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0

Response

Glen Farmer - Avista - Avista Corporation - 5
Answer
Document Name
Comment

Yes

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0

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0

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Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment

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0

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0

Response

Tho Tran - Tho Tran On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; - Tho Tran
Answer

Yes

Document Name
Comment

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0

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0

Response

Thomas Breene - WEC Energy Group, Inc. - 3
Answer

Yes

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Comment

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0

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0

Response

Adrian Andreoiu - BC Hydro and Power Authority - 1,3,5 - WECC

Answer

Yes

Document Name
Comment

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0

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0

Response

Douglas Johnson - American Transmission Company, LLC - 1
Answer

Yes

Document Name
Comment

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0

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0

Response

David Gordon - Massachusetts Municipal Wholesale Electric Company - 5
Answer

Yes

Document Name
Comment

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0

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0

Response

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 3, Group Name FirstEnergy Corporation
Answer

Yes

Document Name
Comment

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0

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0

Response

Vivian Vo - APS - Arizona Public Service Co. - 3
Answer

Yes

Document Name
Comment

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0

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0

Response

Chris Scanlon - Exelon - 1
Answer

Yes

Document Name
Comment

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0

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0

Response

Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment

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0

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0

Response

Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer

Yes

Document Name
Comment

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0

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0

Response

Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Answer

Yes

Document Name
Comment

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0

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0

Response

Nicolas Turcotte - Hydro-Qu?bec TransEnergie - 1
Answer

Yes

Document Name
Comment

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0

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0

Response

Andrey Komissarov - Andrey Komissarov On Behalf of: Jerome Gobby, Sempra - San Diego Gas and Electric, 3, 5, 1; - Andrey Komissarov
Answer

Yes

Document Name
Comment

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0
0

Response

Teresa Cantwell - Lower Colorado River Authority - 1,5
Answer

Yes

Document Name
Comment

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0

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0

Response

Eli Rivera - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

Yes

Document Name
Comment

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0

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0

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Russell Noble - Cowlitz County PUD - 3
Answer

Yes

Document Name
Comment

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0

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0

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Heather Morgan - EDP Renewables North America LLC - 5
Answer
Document Name

Yes

Comment

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0

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0

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Jack Cashin - American Public Power Association - 4
Answer

Yes

Document Name
Comment

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0

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0

Response

Jamie Prater - Entergy - 5
Answer

Yes

Document Name
Comment

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0

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0

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David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment

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0

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0

Russel Mountjoy - Midwest Reliability Organization - 10, Group Name MRO NSRF
Answer
Document Name
Comment
See the NSRF comments provided in the Implementation Guidance section.
Likes

0

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0

Response

Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer
Document Name
Comment
Duke Energy suggests a clarifying addition to the diagram on page 3 (Control Centers in Scope) of the Technical Rationale and Justification document.
In order to make the diagram more closely align to the statement made on page 8 of the Implementation Guidance which states:
“Entity Alpha does not need to consider any communications to other non-Control Center facilities such as generating plants or substations. These
communications are out of scope for CIP-012-1.”
The statement above indicates that communications from a Control Center, to a non-Control Center (generation or sub) are out of scope. We suggest
that a dotted line be added to the diagram on page 3 (Control Centers in Scope) of the Technical Rational and Justification document to show that
communications from a GOP Control Center to a GOP Control Room should be considered out of scope. It is possible that a scenario could exist where
GOP Control Centers pass information through a GOP Control Room out to Field Assets.
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0

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0

Response

Todd Bennett - Associated Electric Cooperative, Inc. - 3, Group Name AECI
Answer
Document Name
Comment
AECI supports comments provided by NRECA

Likes

0

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0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE is concerned BCAs and EACMs used for CIP-012-1 may be considered out of scope for the rest of the CIP Reliability Standards based on a
statement on Page 6: “The SDT also recognizes that CIP-012 security protection may be applied to a Cyber Asset that is not an identified BES Cyber
Asset or EACMS. The identification of the Cyber Asset as the location where security protection is applied does not expand the scope of Cyber Assets
identified as applicable under the CIP Cyber Security Standards CIP-002 through CIP-011.”

There appears to be a typo in the footer as it shows Reliability Standard CIP-002-1, instead of CIP-012-1.
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0

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0

4. The SDT modified the draft Implementation Guidance for CIP-012 to provide examples of how a Responsible Entity could comply with the
requirements. The draft Implementation Guidance does not prescribe the only approach to compliance. Rather, it describes what the SDT
believes would be effective ways to comply with the standard. See NERC’s Compliance Guidance policy for information on Implementation
Guidance. Do you agree with the draft Implementation Guidance? If you do not agree, or if you agree but have comments or suggestions for
the draft Implementation Guidance, please provide your recommendation and explanation.
Russell Martin II - Salt River Project - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
Overall, SRP does not agree with twenty-four (24) calendar months for the implementation of Requirements R1, as R1 and R2 from the second draft
have been merged. Although SRP recognizes the SDT is not specifying the controls to be used to protect confidentiality and integrity, the only examples
provided in the implementation guidance includes encryption. If there are other methods available to achieve the security objective, SRP asks the SDT
to provide them. However, the only method available to achieve the proposed required objective, on the ICCP network, is to implement encryption. As
FERC order 822 states on page 37, “if several registered entities have joint responsibility for a cryptographic key management system used between
their respective Control Centers, they should have the prerogative to come to a consensus on which organization administers that particular key
management system.” Furthermore, the FERC order states on page 38, “While responsible entities are required to exchange real-time and operational
planning data necessary to operate the bulk electric system using mutually agreeable security protocols, there is no technical specification for how this
transfer of information should incorporate mandatory security controls.” These are activities and specifications that must be created and agreed upon by
all registered entities involved in the data
transfer. As such the timeline is reliant on registered entities working together on a common solution and would not be achievable within 24 calendar
months.

Additionally, if encryption fails, SRP would lose Real-time Assessment and Real-time monitoring and control data. There are many opportunities for
encryption to fail that must be addressed. The implementation of encryption requires a pilot to truly understand and address the mechanisms of failure,
the impacts encryption would cause on the exchange of the data, and the computing resources required. A pilot also requires a great amount of
coordination to execute, not only within the industry, but may also include carriers, vendors, and possibly third-party encryption key program managers.

Because of the aforementioned reasons and concerns, SRP is recommending a phased implementation for CIP-012-1. A 24 month implementation is
appropriate, but only for Requirement R1. The 24 months for R1 would provide time to coordinate and create an industry-wide solution. SRP is
proposing the SDT include an additional 12 months for the plan implementation aspect of Requirement R1. The additional 12 months would be used for
a pilot and course correction if needed, in addition to understanding, formulating, and executing maintenance strategies.
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Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion, NextEra and HQ
Answer

No

Document Name
Comment
Request a definition of “logical protection” or replace all instances of “logical protection” with “encryption”
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0

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0

Response

Wendy Center - U.S. Bureau of Reclamation - 5
Answer

No

Document Name
Comment
Reclamation recommends the term “plan” be replaced with the term “process” throughout the CIP-012-1 standard, Technical Rationale, Implementation
Guidance, and associated documents. A plan is an unwarranted layer of compliance that does not improve the reliability of the BES. The processes an
entity chooses to implement are what improve the reliability of the BES.
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0

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0

Response

Terry Harbour - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1
Answer

No

Document Name
Comment
We support MRO NSRF comments. Additionally, The Implementation Guidance doesn’t address our comments to question 1. And, the Implementation
Guidance starts with “as noted in the Technical Rationale.” Does this cross reference blur the lines between the two?
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0

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0

Response

Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6
Answer

No

Document Name
Comment
PacifiCorp supports MEC’s comments.
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0

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0

Response

John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1
Answer

No

Document Name
Comment
Implementation of R1.3 will require a standardized solution/technology between entities and a hierarchy of entity responsibilities. Recommend the SDT
add guidance and a requirement to identify the entity who is the controlling authority for the secure communications between two or more entities.
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0

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0

Response

Dennis Sismaet - Northern California Power Agency - 6
Answer

No

Document Name
Comment
See Response to Question 1.
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0

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0

Response

Brandon McCormick - Brandon McCormick On Behalf of: Ginny Beigel, City of Vero Beach, 3; Lynne Mila, City of Clewiston, 4; Mike Blough,
Kissimmee Utility Authority, 5, 3; Tom Reedy, Florida Municipal Power Pool, 6; - Brandon McCormick, Group Name FMPA
Answer
Document Name

No

Comment
FMPA agrees with the following comments from Lakeland Electric:
The draft Implementation Guidance document provides references to the TOP-003 and IRO-010 for the operating information/data that should be
protected. It appears that there may be opportunities for differences in interpretation depending on what specifications are requested by the RC or the
TOP per IRO-010 R1: “A list of data and information needed by the Reliability Coordinator to support its Operational Planning Analyses, Real-time
monitoring, and Real-time Assessments including non-BES data and external network data, as deemed necessary by the Reliability Coordinator. And,
TOP-003 R1 1.1. A list of data and information needed by the Transmission Operator to support its Operational Planning Analyses, Real-time
monitoring, and Real-time Assessments including non-BES data and external network data as deemed necessary by the Transmission Operator.” It
seems that the list of items enumerated in the NERC Glossary definition for Real-time Assessment: “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” should be the starting
point instead of the R1 requirements referenced in the CIP-012. If an entity needed to add more, there should be some way of incorporating more, but
the baseline should be the inputs listed in the RTA definition.
Does an entity that is only participating in sharing information via the ICCP network and that does not need to send data to a backup control center (ie, a
TOP operating out of a substation control house or a GOP that may operate two facilities) need to meet the same requirements as an entity with actual
Control Center/Backup Control Center NERC obligations? It seems to me that the scope for the low impact Control Centers might be limited and
reduced in scope.
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0

Response

James Anderson - CMS Energy - Consumers Energy Company - 1
Answer

No

Document Name
Comment
To be consistent with other CIP standards, please combine Technical Rational and Justification document with the Implementation Guidance document
and then incorporate the new document into the draft standard. Please clarify that CIP-012 is a standalone standard that is not associated with all the
other CIP standards.
Likes

0

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0

Response

Darnez Gresham - Darnez Gresham On Behalf of: Annette Johnston, Berkshire Hathaway Energy - MidAmerican Energy Co., 1, 3; - Darnez
Gresham
Answer
Document Name

No

Comment
We support MRO NSRF comments. Additionally, The Implementation Guidance doesn’t address our comments to question 1. And, the Implementation
Guidance starts with “as noted in the Technical Rationale.” Does this cross reference blur the lines between the two?
Likes

0

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0

Response

David Gordon - Massachusetts Municipal Wholesale Electric Company - 5
Answer

No

Document Name
Comment
MMWEC supports comments submitted by NPCC.
Likes

0

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0

Response

Marty Hostler - Northern California Power Agency - 5
Answer

No

Document Name
Comment
See Response to Question 1.
Likes

0

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0

Response

Shannon Fair - Colorado Springs Utilities - 1,3,5,6, Group Name Colorado Springs Utilities
Answer
Document Name
Comment

No

Overall, CSU does not agree with twenty-four (24) calendar months for the implementation of Requirements R1, as R1 and R2 from the second draft
have been merged. Although CSU recognizes the SDT is not specifying the controls to be used to protect confidentiality and integrity, the only examples
provided in the implementation guidance includes encryption. If there are other methods available to achieve the security objective, CSU asks the SDT
to provide them. However, the only method available to achieve the proposed required objective, on the ICCP network, is to implement encryption. As
FERC order 822 states on page 37, “if several registered entities have joint responsibility for a cryptographic key management system used between
their respective Control Centers, they should have the prerogative to come to a consensus on which organization administers that particular key
management system.” Furthermore, the FERC order states on page 38, “While responsible entities are required to exchange real-time and operational
planning data necessary to operate the bulk electric system using mutually agreeable security protocols, there is no technical specification for how this
transfer of information should incorporate mandatory security controls.” These are activities and specifications that must be created and agreed upon by
all registered entities involved in the data transfer. As such the timeline is reliant on registered entities working together on a common solution and
would not be achievable within 24 calendar months.
Additionally, if encryption fails, CSU would lose Real-time Assessment and Real-time monitoring and control data. There are many opportunities for
encryption to fail that must be addressed. The implementation of encryption requires a pilot to truly understand and address the mechanisms of failure,
the impacts encryption would cause on the exchange of the data, and the computing resources required. A pilot also requires a great amount of
coordination to execute, not only within the industry, but may also include carriers, vendors, and possibly third-party encryption key program managers.
Because of the aforementioned reasons and concerns, CSU is recommending a phased implementation for CIP-012-1. A 24 month implementation is
appropriate, but only for Requirement R1. The 24 months for R1 would provide time to coordinate and create an industry-wide solution. CSU is
proposing the SDT include an additional 12 months for the plan implementation aspect of Requirement R1. The additional 12 months would be used for
a pilot and course correction if needed, in addition to understanding, formulating, and executing maintenance strategies.
Likes

0

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0

Response

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer

No

Document Name
Comment
City Light supports SRP comments
Likes

0

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0

Response

Jeanne Kurzynowski - CMS Energy - Consumers Energy Company - 1,3,4,5 - RF
Answer
Document Name
Comment

No

To be consistent with other CIP standards, please combine Technical Rational and Justification document with the Implementation Guidance document
and then incorporate the new document into the draft standard. Please clarify that CIP-012 is a standalone standard that is not associated with all the
other CIP standards.
Likes

0

Dislikes

0

Response

Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer

No

Document Name
Comment
On page 5 under section “Identification of Where Security Protection is Applied by the Responsible Entity”, language should be added to address the
situation where a Responsible Entity does not manage either end of a communication link, indicating that this Responsible Entity does not have
compliance obligations to R1.2.
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0

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0

Response

Patricia Lynch - NRG - NRG Energy, Inc. - 5,6
Answer

No

Document Name
Comment

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0

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0

Response

Brandon Gleason - Electric Reliability Council of Texas, Inc. - 2
Answer
Document Name
Comment

Yes

When addressing the security protections that can be used in meeting CIP-012, examples of physical protection should be included in guidance. This
should include details on how they can be used to address various parts of the communication between Control Centers. {C}
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0

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0

Response

Warren Cross - ACES Power Marketing - 1,3,4,5 - MRO,WECC,Texas RE,SERC,SPP RE,RF
Answer

Yes

Document Name
Comment
Yes. For the requirement to be less prescriptive, additional technical and implementation guidance is needed to provide clarity on the SDT intent and
audited scope.
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0

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0

Response

Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer

Yes

Document Name
Comment
Yes, without additional comment.
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0

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0

Response

Jack Cashin - American Public Power Association - 4
Answer
Document Name
Comment

Yes

no comment
Likes

0

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0

Response

Ellen Oswald - Midcontinent ISO, Inc. - 2
Answer

Yes

Document Name
Comment
Currently it is good guidance document but until an entity does actual implementation and experiences any issues that arise from the implementation of
CIP-012 requirement one can only assume the outcome.
Likes

0

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0

Response

Kevin Salsbury - Berkshire Hathaway - NV Energy - 5
Answer

Yes

Document Name
Comment
NV Energy believes the document is necessary for CIP-012-1, due to its complexity. The document still requires additional clarity on protections
associated with data protection on ICCP communication. The document reflects a lack of research into current technology availability, feasibility, and
costs for this common type of Control Center communication.
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0

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0

Response

Chris Scanlon - Exelon - 1
Answer
Document Name
Comment

Yes

Suggestion for last paragraph under Identification of Where Security Protection is Applied by the Responsible Entity. Split into two separate
paragraphs. One describing how to handle “when exchanging data between two entities” and another focused on “when a Responsible Entity owns and
operates both Control Centers.”
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0

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0

Response

Andy Fuhrman - Andy Fuhrman On Behalf of: Theresa Allard, Minnkota Power Cooperative Inc., 1; - Andy Fuhrman
Answer

Yes

Document Name
Comment
See MRO NSRF comments.
Likes

0

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0

Response

Russel Mountjoy - Midwest Reliability Organization - 10, Group Name MRO NSRF
Answer

Yes

Document Name
Comment
The NSRF would like to thank the drafting team for their guidance and especially under the Reference Model and Reference Model discussion within
the Implementation Guidance document. Since the Requirement within this Standard is purposely non-prescriptive due to the various operating
conditions for which security can be applied it is important to have model applications for entities to apply the Standard to their particular operations and
in a consistent manner among the industry.

The NSRF notes that the drafting team stated in their previous draft response that they will submit the Implementation Guidance for ERO endorsement,
thank you. However, the NSRF notes that the current “Technical Rationale for Reliability Standards” initiative underway may alter how “Compliance
Guidance” during the drafting/balloting process is handled. The Reference Model section of CIP-012 is a good example of providing drafting team
application and intent that is essential to the understanding of a Standard. Although the preferred approach would be to have Implementation Guidance
issued prior to a Standards’ effective date, we would hope that when moving forward with the “Technical Rationale for Reliability Standards Initiative”
that in cases, such as mentioned with the CIP-012, that these types of sections would be included within the Technical Rationale section or by another
means for clarification of Standard application.
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0

Dislikes

0

Response

Aaron Austin - AEP - 3
Answer

Yes

Document Name
Comment
AEP requests the SDT consider including some statements in Implementation Guidance to address the possibility that data requests made related to
TOP-003 and/or IRO-010 include other data that is not Real-time Assessment data or Real-time monitoring data and how the Responsible Entity could
exclude this other data from the security requirements.
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0

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0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Jamie Prater - Entergy - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Heather Morgan - EDP Renewables North America LLC - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Russell Noble - Cowlitz County PUD - 3
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Eli Rivera - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

Teresa Cantwell - Lower Colorado River Authority - 1,5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Andrey Komissarov - Andrey Komissarov On Behalf of: Jerome Gobby, Sempra - San Diego Gas and Electric, 3, 5, 1; - Andrey Komissarov
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Nicolas Turcotte - Hydro-Qu?bec TransEnergie - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC

Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Vivian Vo - APS - Arizona Public Service Co. - 3
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 3, Group Name FirstEnergy Corporation
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Douglas Johnson - American Transmission Company, LLC - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Adrian Andreoiu - BC Hydro and Power Authority - 1,3,5 - WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Thomas Breene - WEC Energy Group, Inc. - 3
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Tho Tran - Tho Tran On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; - Tho Tran
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Glen Farmer - Avista - Avista Corporation - 5
Answer

Yes

Document Name
Comment

Likes
Dislikes

0
0

Response

Faz Kasraie - Seattle City Light - 5 - WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Nicholas Lauriat - Network and Security Technologies - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Joe Tarantino - Joe Tarantino On Behalf of: Arthur Starkovich, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Beth Tincher, Sacramento
Municipal Utility District, 4, 1, 5, 6, 3; Jamie Cutlip, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Kevin Smith, Balancing Authority of
Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Susan Oto, Sacramento Municipal Utility District, 4, 1,
5, 6, 3; - Joe Tarantino

Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Kristine Ward - Seminole Electric Cooperative, Inc. - 1,3,4,5,6 - FRCC
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE is not comfortable commenting on Implementation Guidance until the standard language is in its final form.
Likes

0

Dislikes

0

Response

Todd Bennett - Associated Electric Cooperative, Inc. - 3, Group Name AECI
Answer
Document Name
Comment

AECI supports comments provided by NRECA
Likes

0

Dislikes
Response

0

5. The SDT believes proposed CIP-012-1 provides entities with flexibility to meet the reliability objectives in a cost effective manner. Do you
agree? If you do not agree, or if you agree but have suggestions for improvement to enable more cost effective approaches, please provide
your recommendation and, if appropriate, technical justification.
Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer

No

Document Name
Comment
While the standard is flexible on methodology, the requirement to coordinate with the other Responsible Entity may limit the inherent flexibility by
requiring one Responsible Entity to make Capital Investments to meet the security requirements of the other Responsible Entity.
Likes

0

Dislikes

0

Response

Jeanne Kurzynowski - CMS Energy - Consumers Energy Company - 1,3,4,5 - RF
Answer

No

Document Name
Comment
More flexibility and less guidance could lead to inconsistency on requirement implementation among different entities.
Likes

0

Dislikes

0

Response

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer

No

Document Name
Comment
City Light supports SRP comments
Likes
Dislikes

0
0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
BPA believes that if the data must be protected throughout the transmission, it would seem that could only be accomplished with encryption. For cases
where the existing equipment is not capable of encryption, replacement will be costly and implementation lengthy.
Due to BPA’s large amount of applicable data, access to funds and budget cycle, and resources to perform work required, the solution will be costly.
Likes

0

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0

Response

Shannon Fair - Colorado Springs Utilities - 1,3,5,6, Group Name Colorado Springs Utilities
Answer

No

Document Name
Comment
CSU does not agree the current standard and implementation plan can be executed in a cost effective manner. Encryption has been the only presented
solution provided by auditors and SDT guidance to protect both confidentiality and integrity for the data within this scope. If the implementation
timeframe remains at 24 months, more resources and capital will be required versus a phased implementation. A phased implementation provides the
ability to not only ensure the most effective plan, but also provides the ability to plan more accurately within budget cycles. More importantly, if
encryption fails, CSU would lose Real-time Assessment and Real-time monitoring and control data. CSU is concerned a 24 month implementation
timeline would impact reliability as there are many opportunities for encryption to fail that must be addressed. This has a direct correlation on cost when
addressing those opportunities during this timeframe.
Additionally, CSU would like to see reference models of methods that do not require encryption as a method to protect communications between
Control Centers.
Likes

0

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0

Response

Marty Hostler - Northern California Power Agency - 5
Answer
Document Name

No

Comment
See Response to Question 1.
Likes

0

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0

Response

Darnez Gresham - Darnez Gresham On Behalf of: Annette Johnston, Berkshire Hathaway Energy - MidAmerican Energy Co., 1, 3; - Darnez
Gresham
Answer

No

Document Name
Comment
Without clarity on ICCP between Control Centers we cannot be certain of what is expected, the costs or flexibility.
Likes

0

Dislikes

0

Response

Kevin Salsbury - Berkshire Hathaway - NV Energy - 5
Answer

No

Document Name
Comment
Without additional expectations of ICCP communication protections, NV Energy is unable to determine the overall costs of CIP-012-1 implementation.
Likes

0

Dislikes

0

Response

James Anderson - CMS Energy - Consumers Energy Company - 1
Answer
Document Name
Comment

No

More flexibility and less guidance could lead to inconsistency on requirement implementation among different entities.
Likes

0

Dislikes

0

Response

Brandon McCormick - Brandon McCormick On Behalf of: Ginny Beigel, City of Vero Beach, 3; Lynne Mila, City of Clewiston, 4; Mike Blough,
Kissimmee Utility Authority, 5, 3; Tom Reedy, Florida Municipal Power Pool, 6; - Brandon McCormick, Group Name FMPA
Answer

No

Document Name
Comment
FMPA agrees with the following comments from Lakeland Electric:
Depending on the outcome of the new definition of Control Center, there may be unintended consequences on the implementation of CIP-012 for small
entities who only have BES Assets containing low impact BES Cyber Systems (i.e., Control Centers) --especially with the consideration of non-BES
data and external network data. Industry is strongly motivated to protect the “right things” and maintain the BES so that it can continue to operate
reliably, safely, and securely. Industry would be wise to carefully consider expansion of scope beyond what is truly required to protect the BES/critical
infrastructure.
Likes

0

Dislikes

0

Response

Dennis Sismaet - Northern California Power Agency - 6
Answer

No

Document Name
Comment
See Response to Question 1.
Likes

0

Dislikes

0

Response

Russell Noble - Cowlitz County PUD - 3
Answer

No

Document Name
Comment
Cowlitz PUD supports the comments submitted by the Bonneville Power Administration.
Likes

0

Dislikes

0

Response

Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6
Answer

No

Document Name
Comment
In the absence of clarity where ICCP is used for Real-time Assessment and Real-time monitoring data being transmitted between any Control Centers
owned or operated by different Responsible Entities PacifiCorp cannot be certain of what is expected, regarding the costs or flexibility.

Likes

0

Dislikes

0

Response

Terry Harbour - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1
Answer

No

Document Name
Comment
Without clarity on ICCP between Control Centers we cannot be certain of what is expected, the costs or flexibility.
Likes

0

Dislikes

0

Response

Warren Cross - ACES Power Marketing - 1,3,4,5 - MRO,WECC,Texas RE,SERC,SPP RE,RF
Answer

No

Document Name
Comment
Cost effective manner as compared to what? Additional resources will be required and those resources will be needed to monitored 24x7 for those
controls to be effective. I would think most entities would budget that as a considerable expense.
Likes

0

Dislikes

0

Response

Russell Martin II - Salt River Project - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
SRP does not agree the current standard and implementation plan can be executed in a cost effective manner. Encryption has been the only presented
solution provided by auditors and SDT guidance to protect both confidentiality and integrity for the data within this scope. If the implementation
timeframe remains at 24 months, more resources and capital will be required versus a phased implementation. A phased implementation provides the
ability to not only ensure the most effective plan, but also provides the ability to plan more accurately within budget cycles. More importantly, if
encryption fails, SRP would lose Real-time Assessment and Real-time monitoring and control data. SRP is concerned a 24 month implementation
timeline would impact reliability as there are many opportunities for encryption to fail that must be addressed. This has a direct correlation on cost when
addressing those opportunities during this timeframe.

Additionally, SRP would like to see reference models of methods that do not require encryption as a method to protect communications between Control
Centers
Likes

0

Dislikes

0

Response

Patricia Lynch - NRG - NRG Energy, Inc. - 5,6
Answer

No

Document Name
Comment

Likes
Dislikes

0
0

Response

Kristine Ward - Seminole Electric Cooperative, Inc. - 1,3,4,5,6 - FRCC
Answer

Yes

Document Name
Comment
what is cost effective to some, may not be cost effective to others. How do you define cost effective?
Additional Comments
If we identify multiple types of security protection for R1.1, and one of the forms of protection fails for whatever reason, however, Seminole believes we
are still “protecting” the data transmission to the intent of the Standard via our other form(s) of protection, how is the drafting team addressing this?
Likes

0

Dislikes

0

Response

Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer

Yes

Document Name
Comment
Yes, without additional comment.
Likes

0

Dislikes

0

Response

Joe Tarantino - Joe Tarantino On Behalf of: Arthur Starkovich, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Beth Tincher, Sacramento
Municipal Utility District, 4, 1, 5, 6, 3; Jamie Cutlip, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Kevin Smith, Balancing Authority of
Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Susan Oto, Sacramento Municipal Utility District, 4, 1,
5, 6, 3; - Joe Tarantino
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Nicholas Lauriat - Network and Security Technologies - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Faz Kasraie - Seattle City Light - 5 - WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Glen Farmer - Avista - Avista Corporation - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Thomas Breene - WEC Energy Group, Inc. - 3
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Adrian Andreoiu - BC Hydro and Power Authority - 1,3,5 - WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Douglas Johnson - American Transmission Company, LLC - 1
Answer

Yes

Document Name
Comment

Likes
Dislikes

0
0

Response

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 3, Group Name FirstEnergy Corporation
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Vivian Vo - APS - Arizona Public Service Co. - 3
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Chris Scanlon - Exelon - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer
Document Name

Yes

Comment

Likes

0

Dislikes

0

Response

Ellen Oswald - Midcontinent ISO, Inc. - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Nicolas Turcotte - Hydro-Qu?bec TransEnergie - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Andrey Komissarov - Andrey Komissarov On Behalf of: Jerome Gobby, Sempra - San Diego Gas and Electric, 3, 5, 1; - Andrey Komissarov
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Teresa Cantwell - Lower Colorado River Authority - 1,5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Eli Rivera - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Heather Morgan - EDP Renewables North America LLC - 5
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

Wendy Center - U.S. Bureau of Reclamation - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion, NextEra and HQ
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Jamie Prater - Entergy - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Aaron Austin - AEP - 3
Answer
Document Name
Comment
No Comment
Likes

0

Dislikes

0

Response

Todd Bennett - Associated Electric Cooperative, Inc. - 3, Group Name AECI
Answer
Document Name
Comment

AECI supports comments provided by NRECA
Likes

0

Dislikes

0

Response

John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1
Answer
Document Name
Comment
No Comment
Likes

0

Dislikes

0

Response

Jack Cashin - American Public Power Association - 4
Answer
Document Name
Comment
no comment
Likes

0

Dislikes

0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE does not have comments on this question.

Likes

0

Dislikes

0

Response

Brandon Gleason - Electric Reliability Council of Texas, Inc. - 2
Answer
Document Name
Comment
No answer or comments.
Likes

0

Dislikes

0

Response

Comments Received from Kara White at NRG Energy, Inc.
Questions

1. Requirement R1: The SDT drafted CIP-012-1 Requirement R1 for the Responsible Entity to implement one or more documented plan(s) to mitigate
the risk of the unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring data while being transmitted between any
Control Centers. Do you agree with this revision? If not, please provide the basis for your disagreement and an alternate proposal.
Yes
No
Comments:
NRG agrees with the revisions if they are a part of CIP-005, because: NRG thinks removing the term "control" could cause some misinterpretation
within the industry, this change could also broaden the scope of what protocols are included in standard. NRG recommends that the security
protections described in CIP-012 R1 go from EAP (Electronic Access Point) to EAP. This would eliminate the risk of a compromise of the data due to
an attack on a Responsible Entities’ corporate network (outside the ESP).
NRG recommends that the scope of R1 of CIP-012 be added instead directly into CIP-005 and CIP-003 as additional requirements (instead of a
separate requirement in a CIP-012 standard).
2. Implementation Plan: The SDT established the Implementation Plan to make the standard effective the first day of the first calendar quarter that is
twenty-four (24) calendar months after the effective date of the applicable governmental authority’s order approving the standard, or as otherwise

provided for by the applicable governmental authority. Do you agree with this proposal? If you think an alternate implementation time period is
needed, please provide a detailed explanation of actions and time needed to meet the implementation deadline.
Yes
No
Comments:
3. The SDT modified the draft Technical Rationale and Justification for CIP-012 to assist in understanding the technology and technical requirements in
the Reliability Standard. It also contains information on the SDT’s intent in drafting the requirements. Do you agree with the technology and technical
requirements in the draft Technical Rationale and Justification? If you do not agree, or if you agree but have comments or suggestions for the draft
Technical Rationale and Justification, please provide your recommendation and explanation.
Yes
No
Comments: NRG recommends that NERC SDT see NRG comments for CIP-012 R1 relating to inclusion of EAP to EAP for protections scope.
4. The SDT modified the draft Implementation Guidance for CIP-012 to provide examples of how a Responsible Entity could comply with the
requirements. The draft Implementation Guidance does not prescribe the only approach to compliance. Rather, it describes what the SDT believes
would be effective ways to comply with the standard. See NERC’s Compliance Guidance policy for information on Implementation Guidance. Do you
agree with the draft Implementation Guidance? If you do not agree, or if you agree but have comments or suggestions for the draft Implementation
Guidance, please provide your recommendation and explanation.
Yes
No
Comments: NRG requests that NERC SDT see comments above. There are more prescriptive inclusion of protocols in other requirements and
therefore, NRG thinks that this proposed standard as written may cause confusion within industry regarding implementation scope.
5. The SDT believes proposed CIP-012-1 provides entities with flexibility to meet the reliability objectives in a cost effective manner. Do you agree? If
you do not agree, or if you agree but have suggestions for improvement to enable more cost effective approaches, please provide your
recommendation and, if appropriate, technical justification.
Yes
No
Comments: NRG asserts that the vague nature of the requirement does not meet the reliability objective in a cost effective manner, because it does
not specify the protocols in the requirement; therefore, the industry could misinterperet the scope of the requirement
Comments received from Laura McLeod at NB Power Corporation

Questions

1. Requirement R1: The SDT drafted CIP-012-1 Requirement R1 for the Responsible Entity to implement one or more documented plan(s) to mitigate
the risk of the unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring data while being transmitted between any
Control Centers. Do you agree with this revision? If not, please provide the basis for your disagreement and an alternate proposal.

x

Yes
No

Comments: 1) The applicability of this requirement is uncertain given the proposed Control Center definition has not been approved. 2) R1 also
notes that oral communications is excluded. Why not clarify that email is also excluded given the last paragraph page 8 of the implementation
guidance.
2. Implementation Plan: The SDT established the Implementation Plan to make the standard effective the first day of the first calendar quarter that is
twenty-four (24) calendar months after the effective date of the applicable governmental authority’s order approving the standard, or as otherwise
provided for by the applicable governmental authority. Do you agree with this proposal? If you think an alternate implementation time period is
needed, please provide a detailed explanation of actions and time needed to meet the implementation deadline.
x

Yes
No

Comments:
3. The SDT modified the draft Technical Rationale and Justification for CIP-012 to assist in understanding the technology and technical requirements in
the Reliability Standard. It also contains information on the SDT’s intent in drafting the requirements. Do you agree with the technology and technical
requirements in the draft Technical Rationale and Justification? If you do not agree, or if you agree but have comments or suggestions for the draft
Technical Rationale and Justification, please provide your recommendation and explanation.
x

Yes
No

Comments: References to the specifications required under TOP-003 and IRO-010 should specifically state that data necessary to perform operational
planning analysis is not applicable if not used for real time assessments.
4. The SDT modified the draft Implementation Guidance for CIP-012 to provide examples of how a Responsible Entity could comply with the
requirements. The draft Implementation Guidance does not prescribe the only approach to compliance. Rather, it describes what the SDT believes
would be effective ways to comply with the standard. See NERC’s Compliance Guidance policy for information on Implementation Guidance. Do you
agree with the draft Implementation Guidance? If you do not agree, or if you agree but have comments or suggestions for the draft Implementation
Guidance, please provide your recommendation and explanation.

x

Yes
No

Comments:
5. The SDT believes proposed CIP-012-1 provides entities with flexibility to meet the reliability objectives in a cost effective manner. Do you agree? If
you do not agree, or if you agree but have suggestions for improvement to enable more cost effective approaches, please provide your
recommendation and, if appropriate, technical justification.

x

Yes
No

Comments: An entities State Estimator can identify (and ignore) off normal values. This inherent capability reduces the risk that flawed or incorrect
data will be utilized in real time assessments.

CIP-012-1
Project 2016-02 Modifications to the CIP
Standards: Consideration of Comments
May 2018

NERC | Report Title | Report Date
I

Table of Contents
Preface ...................................................................................................................................................................... iii
Introduction .............................................................................................................................................................. iv
Background............................................................................................................................................................ iv
CIP-012-1 Consideration of Comments...................................................................................................................... 5
Purpose................................................................................................................................................................... 5
Control Center Definition ....................................................................................................................................... 5
Requirement R1...................................................................................................................................................... 5
Implementation Plan .............................................................................................................................................. 7
Technical Rationale for CIP-012-1 .......................................................................................................................... 7
Implementation Guidance...................................................................................................................................... 9
Cost Effectiveness................................................................................................................................................. 10

NERC | CIP-012-1 Consideration of Comments Summary Report | May 2018
ii

Preface
The vision for the Electric Reliability Organization (ERO) Enterprise, which is comprised of the North American Electric
Reliability Corporation (NERC) and the eight Regional Entities (REs), is a highly reliable and secure North American
bulk power system (BPS). Our mission is to assure the effective and efficient reduction of risks to the reliability and
security of the grid.
The North American BPS is divided into eight RE boundaries as shown in the map and corresponding table below.

The North American BPS is divided into eight RE boundaries. The highlighted areas denote overlap as some load-serving entities
participate in one Region while associated Transmission Owners/Operators participate in another.

FRCC

Florida Reliability Coordinating Council

MRO

Midwest Reliability Organization

NPCC

Northeast Power Coordinating Council

RF

ReliabilityFirst

SERC

SERC Reliability Corporation

SPP RE

Southwest Power Pool Regional Entity

Texas RE

Texas Reliability Entity

WECC

Western Electricity Coordinating Council

NERC | CIP-012-1 Consideration of Comments Summary Report | May 2018
iii

Introduction
Background

The Project 2016-02 Modifications to CIP Standards Drafting Team thanks all commenters who submitted
comments on the draft CIP-012-1 standard. This standard was posted for a 45-day public comment period through
Friday, April 30, 2018. Stakeholders were asked to provide feedback on the standards and associated documents
through a special electronic comment form. There were 58 sets of responses, including comments from
approximately 155 different people from approximately 108 companies representing the 10 Industry Segments as
shown in the table on the following pages.
All comments submitted may be reviewed in their original format on the standard’s project page.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give every
comment serious consideration in this process. If you feel there has been an error or omission, you can contact the
NERC standards developer, Jordan Mallory, at 404-446-2589 or at [email protected].

NERC | CIP-012-1 Consideration of Comments Summary Report | May 2018
iv

CIP-012-1 Consideration of Comments
Purpose

The Modification to CIP Standards drafting team appreciates industry’s comments on the CIP-012-1 standard. The
CIP standards drafting team (SDT) thanks everyone for their comments. The SDT reviewed all comments carefully and
made changes to the standard accordingly. The following pages are a summary of the comments received and how
the CIP SDT addressed them. If a specific comment was not addressed in the summary of comments, please contact
the NERC standards developer.

Control Center Definition

Many commenters expressed concern with the proposed Control Center definition.
The SDT thanks everyone for their comments. The SDT decided to draft exemption language within the applicability
section of CIP-012 instead of revising the Control Center definition. Please see the Control Center definition
consideration of comments report for additional SDT responses on the new path taken by the SDT.

Requirement R1

A commenter expressed that Real-time Assessments list a number of specific inputs that should be considered for
both “Real-time Assessment (RTA) and Real-time monitoring (RTm) data.” The commenter suggested there may
be an audit approach taken that would require consideration of both RTA AND RTm data for proof that an entity
provided adequate protections. The commenter requested that the SDT provide clarification on whether there is
a distinction between data used for the RTA and data used for RTm. The commenter recommended consideration
of the use of the inputs in the RTA NERC term with a caveat that Entities may choose to protect additional data if
they feel the need to expand the scope.
The TOP-003-3 Requirement R1 already requires TOPs identify data used for RTA and RTm.
Some commenters questioned if CIP Exceptional Circumstance language needed to be added CIP-012-1.
The CIP Exceptional Circumstance language has been added to CIP-012.
A commenter expressed that "security protection used to mitigate risk" is too ambiguous. The commenter
requested the SDT consider including two concepts in Requirement R1. The first concept is to clarify whether
currently in place ICCP should be encrypted. The commenter noted that the requirement states "while being
transmitted between any Control Centers." The commenter further noted that the draft Implementation Guidance
has content talking about "both ends of the link" but did not include the expectations for the data while on the
link. The commenter was concerned with latency (primarily for generation control) if secure encryption is expected
over the ICCP. Second concept is to include examples that include but are not limiting for security protection.
The SDT asserts that defining a plan to mitigate the risk of modification and disclosure of applicable data allows the
Responsible Entity to document the processes that are supportable within its organization and offers flexibility in
methods to meet the security objective. The SDT notes that the Implementation Guidance document offers examples
of how to comply with the standard.
The SDT encourages Responsible Entities to submit additional scenarios as Implementation Guidance 1 through prequalified organizations for endorsement consideration.

1

NERC Compliance Guidance Policy: https://www.nerc.com/pa/comp/guidance/Documents/Pre-qualified_org_submittal_with_form.pdf
NERC | CIP-012-1 Consideration of Comments Summary Report | May 2018
5

CIP-012-1 Consideration of Comments

Some commenters expressed that CIP-012 is unnecessary and that IRO-010 and TOP-003 already require a mutually
agreeable security protocol. Additionally, another commenter expressed concern about the overlap between CIP012 and TOP-003-3/IRO-010-2. The commenter questioned whether these standards should be combined.
The SDT asserts that the standard is necessary to protect the confidentiality and integrity of applicable data
transmitted between Control Centers and is responsive to the directive in Order No. 822.
A commenter requested clarity on the Responsible Entity in charge of securing the data being transmitted from a
generator on RC, BA, and TOP equipment. The commenter suggested that the RC, BA, and TOP identify the GOP
responsibilities under Part 1.3.
If the Generator is not a Control Center then CIP-012 does not apply as it is only between Control Centers. However,
if the Generator is an applicable Control Center, then Requirement R1 Part 1.3 is intended to require the entities to
document their responsibilities.
A commenter requested the SDT clarify whether CIP-012-1 applies to low, medium, or high BES Cyber Systems. The
commenter requested the SDT also consider how to incorporate the scoping criteria into CIP-002.
The SDT asserts that the applicability is clear. It applies to in-scope data being transmitted between Control Centers
as defined in the NERC Glossary of Terms and is applicable to all impact levels.
Some commenters noted that Real-time monitoring is not a defined term and that the R in Real-time should not
be capitalized. In addition, the commenters expressed concern that coordination between Control Centers may
result in compromises that may not satisfy the needs of the entities involved.
The term "Monitor" has been lowercased. “Real-time" is defined in the NERC Glossary of Terms and correctly used.
A commenter expressed concern that Operations Planning Analysis (OPA) data is not included in CIP-012-1. In
addition, the commenter also noticed the Violation Time Horizon is for Operations Planning. Since the SDT has
indicated reasons for excluding OPA data, the commenter asked whether the relevant Violation Time Horizon
should be Real-time Operation.
Please see CIP-012-1 Consideration of Comments Summary Response for the OPA part. Due to the plan being drafted
ahead of time; it would not be considered a Real-time Horizon and should remain operations planning horizon.
A commenter disagreed that having a plan adds to the reliability of protecting data used for Real-time Assessment
and Real-time monitoring and commented that a plan is not needed. Some commenters recommended replacing
the term “plan” with “process” throughout CIP-012-1, the Technical Rationale, Implementation Guidance, and
other associated documents. Additionally, some commenters recommended that entities not be required to have
a plan in Requirement R1, but have an actionable Requirement to implement. A suggestion was provided.
Based on industry feedback from a prior comment period, the SDT chose a requirement structure that is consistent
with many other CIP standards to implement a documented plan. With regard to the use of the “process” instead of
"plan", the SDT notes that the term ‘documented process’ refers to a set of required instructions specific to the
Responsible Entity, designed to achieve a specific outcome. The plan to meet R1 may simply include documentation
of the required elements of the Parts of CIP-012-1 Requirement R1. The plan also allows for R1 Part 1.3 to document
the entities’ responsibilities.
A commenter asked whether the current set of standards address those additional vulnerabilities in the entity’s IT
Security Plan. The commenter suggested that the current plan should be updated to include these additional risks,
threats and integrated solution(s) that are already performed by the entity.
NERC | CIP-012-1 Consideration of Comments Summary Report | May 2018
6

CIP-012-1 Consideration of Comments

The documented plan(s) will need to address the security protection in place to mitigate the risk of unauthorized
disclosure or modification of applicable data transmitted between any Control Centers in accordance with the
specified attributes in the Requirement Parts.

Implementation Plan

Some commenters stated that the 24-month timeline is not enough and requested the implementation timeline
be increased to 36 months or a phased-in approach. Additionally, a commenter acknowledged that the standard
and implementation plan are silent on physical security for the equipment being used to provide the data
protection. The commenter provided an example of protection for a router that is located in another Entity’s
facility.
The SDT carefully considered all comments and concluded that many factors should be considered to determine an
implementation period. These factors include complexity of technology solutions, quantity of telecommunications
lines requiring controls and coordination with other Responsible Entities/solution providers, among others. The SDT
concluded that a twenty-four (24) month implementation period is appropriate.
Some commenters noted the difficulty on providing responses to the implementation timeline until the Control
Center definition is developed.
Please see the Consideration of Comments for the Control Center definition for additional information on the SDT’s
approach.

Technical Rationale for CIP-012-1

Some entities requested the SDT consider including some statements in Technical Rationale to address the
possibility that data requests made related to TOP-003 and/or IRO-010 include other data that is not Real-time
Assessment data or Real-time monitoring data and how the Responsible Entity could exclude this other data from
the security requirements.
The SDT asserts that it is up to the Responsible entity to ensure all RTA and RTm data that is transmitted between
Control Centers is protected regardless of whether additional data is also exchanged in regards to the Technical
Rationale and the Implementation Guidance Documents.
A commenter noted that when addressing the security protections, the rationale should include that logical and
physical controls can be used. The commenter suggested this should include the team’s rationale for allowing these
alternatives.
The SDT asserts that the Technical Rationale document already specifies that logical or physical controls can be used
to achieve the required security objective.
A commenter noted that the number of regions needs to be updated.
NERC will make appropriate revisions to various documents upon the effective date of the SPP RE dissolution.
Some commenters noted grammatical modifications:
•

In requirement R1 of the technical rationale document, the document should state document plan

•

The alignment with IRO and TOP standards: last sentence “Real-time Monitoring “, the M should not be
capitalized as it is not a NERC defined term.
NERC | CIP-012-1 Consideration of Comments Summary Report | May 2018
7

CIP-012-1 Consideration of Comments

•

There appears to be a typo in the footer as it shows Reliability Standard CIP-002-1, instead of CIP-012-1

The SDT agrees and will make the modification as noted.
A commenter suggested a clarifying addition to the diagram on page 3 (Control Centers in Scope) of the Technical
Rationale document: “In order to make the diagram more closely align to the statement made on page 8 of the
Implementation Guidance which states:
‘Entity Alpha does not need to consider any communications to other non-Control Center facilities such as
generating plants or substations. These communications are out of scope for CIP-012-1.’
The statement above indicates that communications from a Control Center, to a non-Control Center (generation
or sub) are out of scope. We suggest that a dotted line be added to the diagram on page 3 (Control Centers in
Scope) of the Technical Rational and Justification document to show that communications from a GOP Control
Center to a GOP Control Room should be considered out of scope. It is possible that a scenario could exist where
GOP Control Centers pass information through a GOP Control Room out to Field Assets.”
The SDT asserts that the diagram clearly shows the communications that are in and out of scope. Additionally, this
diagram is simply one example and is not inclusive of all possible communication scenarios.
A commenter noted that adding control to the statement "Real-time monitoring" from TOP-003 and IRO-010 may
set an expectation that control data will be part of those standards by default. The commenter noted that the
proposed CIP-012-1 Implementation Guidance does not use “and control.” The commenter recommended that if
control is to be part of "Real-time monitoring" then the SDT should make the modifications to all documents,
including the Glossary, to reduce misunderstanding.
Based on comments from the prior ballot and comment period, the SDT removed "and control" from the requirement
for this posting. The SDT notes that the systems that provide control are generally the same systems that provide
monitoring. The SDT removed "and control" to be consistent with the TOP-003 and IRO-010 standards.
A commenter requested that the SDT be consistent with other CIP standards and suggested the SDT combine the
Technical Rationale document with the Implementation Guidance document within the draft standard. The
commenter also requested the SDT clarify that CIP-012 is a standalone standard that is not associated with all the
other CIP standards.
The Technical Rationale document and Implementation Guidance document serve two different purposes. The
Technical Rationale document provides the SDT’s intent and technical basis for the language in the standard. In
addition, the Technical Rationale document provides examples and diagrams to assist entities in understanding the
language of the standard. Implementation Guidance is a means for registered entities to develop examples or
approaches for ERO Enterprise endorsement to illustrate how registered entities could comply with a standard 2.
There is a project underway reviewing all of the current Technical Rationale documents and removing compliance
examples from each document to submit for ERO Enterprise endorsement. Therefore, the Technical Rationale
document and Implementation Guidance document cannot be merged together. While the applicability is different
from other CIP standards, the CIP-012-1 is one standard within the CIP Standard family.
A commenter expressed concern regarding the BCAs and EACMS used for CIP-012-1 may be considered out of scope
for the rest of the CIP Reliability Standards based on a statement on Page 6: “The SDT also recognizes that CIP-012
security protection may be applied to a Cyber Asset that is not an identified BES Cyber Asset or EACMS. The
2

NERC Compliance Guidance Policy: https://www.nerc.com/pa/comp/guidance/Documents/Pre-qualified_org_submittal_with_form.pdf
NERC | CIP-012-1 Consideration of Comments Summary Report | May 2018
8

CIP-012-1 Consideration of Comments

identification of the Cyber Asset as the location where security protection is applied does not expand the scope of
Cyber Assets identified as applicable under the CIP Cyber Security Standards CIP-002 through CIP-011.”
The SDT notes that the assets where the security protection is applied under CIP-012 may not be part of an entity's
identified BCAs or EACMS. If the asset meets the definition of a BCA or EACMS, it should be categorized as such. CIP012-1 neither expands nor diminishes the scope of applicable Cyber Assets under CIP-002 through CIP-011.
Some commenters noted difficulty with implementing Secure ICCP in the past because of concerns over the
inability to guarantee a valid certificate at all times.
The SDT asserts that implementation is not limited to Secure ICCP. Entities are allowed the implementation of physical
or logical controls that best meet their operational and reliability needs as long as it meets the security objective
specified in CIP-012-1 Requirement R1. This includes the management of certificates.

Implementation Guidance

A commenter mentioned that when addressing the security protection that can be used in meeting CIP-012,
examples of physical protection should be included in guidance. This should include details on how they can be
used to address various parts of the communication between Control Centers.
The SDT has addressed an example within the implementation guidance document that includes physical protections.
A commenter suggested that the last paragraph under Identification of where security protection is applied by the
Responsible Entity be split into two separate paragraphs. The commenter suggested the first paragraph would
describe how to handle “when exchanging data between two entities” and the second paragraph would focus on
“when a Responsible Entity owns and operates both Control Centers.”
The SDT agrees with the comment and split the paragraph into two separate paragraphs.
A commenter mentioned that the guidance document is good but until an entity does actual implementation and
experiences any issues that arise from the implementation of CIP-012 requirement one can only assume the
outcome.
The SDT notes there are a number of ways to demonstrate compliance with the requirement and encourages entities
to develop and submit additional examples of Implementation Guidance through pre-qualified organizations for
endorsement consideration.
A commenter stated that the implementation of R1.3 will require a standardized solution/technology between
entities and a hierarchy of entity responsibilities. The commenter recommended the SDT add guidance and a
requirement to identify the entity who is the controlling authority for the secure communications between two or
more entities.
The SDT agrees that there will be coordination necessary to meet R1.3. The requirement has been written to allow
flexibility on how entities work together on this requirement. The SDT notes there are a number of ways to
demonstrate compliance with the requirement and encourages entities to develop and submit additional examples
of Implementation Guidance through a pre-qualified organization for endorsement consideration.
Some commenters requested that the SDT define “logical protection” or replace all instances of “logical
protection” with “encryption.”

NERC | CIP-012-1 Consideration of Comments Summary Report | May 2018
9

CIP-012-1 Consideration of Comments

The SDT contends that the standard is written to not specify a particular technology. This allows the requirement to
be flexible in encompassing future protection solutions.
Some commenters recognized the SDT is not specifying the controls to be used to protect confidentiality and
integrity and that the only examples provided in the implementation guidance include encryption. The
commenters requested that the SDT provide other methods available to achieve the security objective if they exist.
The commenters suggested the commenter cited activities and specifications in FERC Order No. 822, such as key
management between separate Responsible Entities, that must be created and agreed upon by all registered
entities involved in the data transfer. The commenter suggested such activities may not be achievable in the 24month implementation period.
The commenter also noted that a Responsible Entity would lose Real-time Assessment and Real-time monitoring
and control data if encryption failed. The commenter suggested a pilot to implement encryption.
The SDT agrees that there will be coordination necessary to meet R1.3. The requirement has been written to allow
flexibility on how entities work together on this requirement. The SDT notes there are a number of ways to
demonstrate compliance with the requirement and encourages entities to develop and submit additional examples
of Implementation Guidance through pre-qualified organizations for endorsement consideration.
A commenter identified that on page 5 under section “Identification of Where Security Protection is applied by the
Responsible Entity”, language should be added to address the situation where a Responsible Entity does not
manage either end of a communication link, indicating that this Responsible Entity does not have compliance
obligations to R1.2.
The SDT notes that the entities communicating the in-scope data are required to have a plan. The plan should specify
the responsibilities of the Responsible Entities in protecting the applicable data.
A couple of comments were received that the requirement should be less prescriptive, and additional technical
and implementation guidance is needed to provide clarity on the SDT intent and audited scope.
The SDT notes there are a number of ways to demonstrate compliance with the requirement and encourages entities
to develop and submit additional examples of Implementation Guidance through pre-qualified organizations for
endorsement consideration.

Cost Effectiveness

A commenter expressed concern that if the data must be protected throughout the transmission, it would seem
that could only be accomplished with encryption. The commenter noted that are cases where the existing
equipment is not capable of encryption, replacement will be costly and implementation lengthy. In addition, the
commenter stated that due to the large amount of applicable data, access to funds and budget cycle, and resources
to perform work required, the solution will be costly.
The 24-month implementation timeline is to allow for selection the most practical solution, as well as for budgeting
and acquisition and implementation.
Some commenters noted that without clarity on ICCP between Control Centers, the commenters cannot be certain
of what is expected, the costs or flexibility.
The SDT notes that data in scope may not be limited to ICCP. This is dependent on the specifics of each entity or
entities.
NERC | CIP-012-1 Consideration of Comments Summary Report | May 2018
10

CIP-012-1 Consideration of Comments

A commenter acknowledged that more flexibility and less guidance could lead to inconsistency on requirement
implementation among different entities.
CIP-012 is written to allow for selection of the most practical solution for the entity or entities.
A commenter expressed that what is cost effective to some, may not be cost effective to others and questioned
the definition of cost effectiveness.
CIP-012 is written to allow for selection of the most practical solution for the entity or entities.
A commenter questioned how the SDT is addressing the scenario where a Responsible Entity identifies multiple
types of security protection and one of the forms fails but the data transmission is still protected, meeting the
intent of the standard.
In the event of a failure of a protection method, it is the Entity’s responsibility to demonstrate how compliance was
maintained during the event.
A commenter does not agree the current standard and implementation plan can be executed in a cost effective
manner. The commenter noted that encryption has been the only presented solution provided by auditors and
SDT guidance to protect both confidentiality and integrity for the data within this scope. The commenter noted
that more resources and capital will be required for a 24-month implementation versus a phased-in
implementation. The commenter further noted that a phased implementation provides the ability to not only
ensure the most effective plan, but also provides the ability to plan more accurately within budget cycles. In
addition, the commenter noted that if encryption fails, an entity would lose Real-time Assessment and Real-time
monitoring and control data. The commenter expressed concern that a 24-month implementation timeline would
impact reliability as there are many opportunities for encryption to fail that must be addressed. The commenter
suggested that this has a direct correlation on cost when addressing those opportunities during this timeframe.
Additionally, the commenter requested the SDT draft reference models of methods that do not require encryption
as a method to protect communications between Control Centers.
CIP-012 is written in a non-prescriptive manner to allow entities to select the protection methods that most
appropriately fit their organization. This allows for logical or physical protection as appropriate. Regarding guidance,
the SDT encourages entities to draft and submit guidance on other implementation examples.

NERC | CIP-012-1 Consideration of Comments Summary Report | May 2018
11

Proposed Revision to the Control Center
Definition for the NERC Glossary of Terms
Project 2016-02 CIP MOD SDT

Current Control Center Definition

One or more facilities hosting operating personnel that monitor and control the Bulk Electric System (BES)
in real-time to perform the reliability tasks, including their associated data centers, of: 1) a Reliability
Coordinator, 2) a Balancing Authority, 3) a Transmission Operator for transmission Facilities at two or
more locations, or 4) a Generator Operator for generation Facilities at two or more locations.

Proposed Revision to the Control Center Definition (Clean)

One or more facilities, including their associated data centers, that monitor and control the Bulk Electric
System (BES) and also host operating personnel who:
1) perform the Real-time reliability-related tasks of a Reliability Coordinator; or
2) perform the Real-time reliability-related tasks of a Balancing Authority; or
3) perform the Real-time reliability-related tasks of a Transmission Operator for Transmission
Facilities at two or more locations; or
4) can act independently as the Generator Operator to develop specific dispatch instructions for
generation Facilities at two or more locations; or
5) can operate or direct the operation of a Transmission Owner’s BES Transmission Facilities in Realtime.
Operating personnel do not include:
1) plant operators located at a generator plant site or personnel at a centrally located dispatch center
who relay dispatch instructions without making any modifications; or
2) Transmission Owner or Transmission Operator field switching personnel.

Proposed Revision to the Control Center Definition (Redlined)

One or more facilities, including their associated data centers, hosting operating personnel that monitor
and control the Bulk Electric System (BES) and also host operating personnel who:in real-time to
1) perform the Real-time reliability tasks, of including their associated data centers, of: 1) a
Reliability Coordinator; or,
2) perform the Real-time reliability tasks of a Balancing Authority; or,
3) perform the Real-time reliability tasks of a Transmission Operator for Ttransmission Facilities at
two or more locations; or,

4) can act independently as athe Generator Operator to develop specific dispatch instructions for
generation Facilities at two or more locations; or,.
5) can operate or direct the operation of a Transmission Owner’s BES Transmission Facilities in Realtime.
Operating personnel do not include:
1) plant operators located at a generator plant site or personnel at a centrally located dispatch center
who relay dispatch instructions without making any modifications; or and;
2) Transmission Owner or Transmission Operator field switching personnel.

Proposed Revisions to the Control Center Definition
Project 2016-02 CIP MOD SDT

2

Implementation Plan
Control Center Definition
Effective Date

Where approval by an applicable governmental authority is required, the NERC Glossary term “Control Center”
shall become effective the first day of the first calendar quarter that is three (3) calendar months after the
effective date of the applicable governmental authority’s order approving the term, or as otherwise provided
for by the applicable governmental authority.
Where approval by an applicable governmental authority is not required, the NERC Glossary term “Control
Center” shall become effective on the first day of the first calendar quarter that is three (3) calendar months
after the date the term is adopted by the NERC Board of Trustees, or as otherwise provided for in that
jurisdiction.

Retirement Date

The existing NERC Glossary term “Control Center” shall be retired immediately prior to the effective date of
the proposed NERC Glossary term “Control Center” in the particular jurisdiction in which the term is becoming
effective.

Unofficial Comment Form

Project 2016-02 Modifications to CIP Standards
Glossary of Terms Used in NERC Reliability Standards – Control Center
Do not use this form for submitting comments. Use the Standards Balloting and Commenting System
(SBS) to submit comments on Project 2016-02 Modifications to NERC Glossary of Terms Used in
Reliability Standards – Control Center. Comments must be submitted by 8 p.m. Eastern, Monday, April
30, 2018.
m. Eastern, Thursday, August 20, 2015
Additional information is available on the project page. If you have questions, contact Jordan Mallory at
(404) 446-2589 or Mat Bunch at (404) 446-9785.
Background Information

On January 21, 2016, the Federal Energy Regulatory Commission (FERC) issued Order No. 822, which
approved revisions to the cybersecurity Critical Infrastructure Protection (CIP) standards and directed
NERC to develop certain modifications to requirements in the CIP standards. Specifically, FERC directed
NERC to “develop modifications to the CIP Reliability Standards to require responsible entities to
implement controls to protect, at a minimum, communication links and sensitive bulk electric system data
communicated between bulk electric system Control Centers in a manner that is appropriately tailored to
address the risks posed to the bulk electric system by the assets being protected (i.e., high, medium, or
low impact).”
The Project 2016-02 Standard Drafting Team (SDT) developed proposed Reliability Standard CIP-012-1 to
require Responsible Entities to implement controls to protect sensitive Bulk Electric System (BES) data or
communications links between BES Control Centers and made the standard applicable to all impact levels
due to the sensitivity of the data being communicated. As the FERC directive addressed the protection of
data communicated between Control Centers, the SDT evaluated the current Control Center definition
and identified the following opportunities for clarification:
•

The term, “operating personnel” is not a NERC Glossary defined term and may be misinterpreted;

•

The phrase, “two or more locations” may be overbroad;

•

The phrase, “monitor and control” may be misinterpreted;

•

The SDT members considered both the NERC Glossary defined term “Real-time” and undefined
term “real-time.”

To address the issues identified above, the SDT developed proposed modifications to the Control Center
definition to make specific inclusions and exclusions. This model was based on the approach of the BES
definition which also has specific inclusions and exclusions.

Current Control Center Definition:
One or more facilities hosting operating personnel that monitor and control the Bulk Electric System (BES)
in real-time to perform the reliability tasks, including their associated data centers, of: 1) a Reliability
Coordinator, 2) a Balancing Authority, 3) a Transmission Operator for transmission Facilities at two or
more locations, or 4) a Generator Operator for generation Facilities at two or more locations.
Proposed Revised Control Center Definition:
One or more facilities, including their associated data centers, that monitor and control the Bulk Electric
System (BES) and also host operating personnel who:
1) perform the Real-time reliability-related tasks of a Reliability Coordinator; or
2) perform the Real-time reliability-related tasks of a Balancing Authority; or
3) perform the Real-time reliability-related tasks of a Transmission Operator for Transmission
Facilities at two or more locations; or
4) can act independently as the Generator Operator to develop specific dispatch instructions for
generation Facilities at two or more locations; or
5) can operate or direct the operation of a Transmission Owner’s BES Transmission Facilities in Realtime.
Operating personnel do not include:
1) plant operators located at a generator plant site or personnel at a centrally located dispatch center
who relay dispatch instructions without making any modifications; or
2) Transmission Owner or Transmission Operator field switching personnel.
Proposed Revised Redline Control Center Definition:
One or more facilities, including their associated data centers, hosting operating personnel that monitor
and control the Bulk Electric System (BES) and also host operating personnel who:in real-time to
1) perform the Real-time reliability tasks of, including their associated data centers, of: 1) a Reliability
Coordinator,’ or
2) 2) perform the Real-time reliability tasks of a Balancing Authority;, or
3) 3) perform the Real-time reliability tasks of a Transmission Operator for Ttransmission Facilities at
two or more locations;, or
4) 4) can act independently as the a Generator Operator to develop specific dispatch instructions for
generation Facilities at two or more locations; or.
5) can operate or direct the operation of a Transmission Owner’s BES Transmission Facilities in Realtime.
Operating personnel do not include:
1) plant operators located at a generator plant site or personnel at a centrally located dispatch center
who relay dispatch instructions without making any modifications; or
2) Transmission Owner or Transmission Operator field switching personnel.

Unofficial Comment Form | Project 2016-02 Modifications to CIP Standards
Control Center Definition | March - April 2018

2

Questions
1. Control Center definition: Do you agree with the proposed revisions to the definition of Control
Center? If not, please provide rationale or propose an alternative definition.
Yes
No
Comments:
2. Control Center definition: Do the proposed revisions to the Control Center definition change the
scope or intent of any current or pending Reliability Standard(s) using the defined term (examples
include Reliability Standards: COM-001-3; TOP-001-4; and IRO-002-5)? If yes, provide details of the
affected Reliability Standard(s), requirements, and any anticipated impact.
Yes
No
Comments:
3. Control Center definition: The SDT contends that there will be no change in BES Cyber System
categorization by clarifying the definition of Control Center. This assertion is based on SDT review
of the CIP-002-5.1a criteria and its understanding of BES Cyber System categorization through
experience implementing CIP-002-5.1a. Do you agree with this assertion? If not, please provide
rationale and practical examples of where a change in categorization will occur as a result of this
modification.
Yes
No
Comments:
4. Control Center definition: Is there a scenario where a Control Center hosts both the inclusion
personnel and the exclusion personnel? If yes, please provide them here.
Yes
No
Comments:

Unofficial Comment Form | Project 2016-02 Modifications to CIP Standards
Control Center Definition | March - April 2018

3

5. Implementation Plan: The new Control Center definition will become effective on the first day of
the first calendar quarter that is three (3) calendar months after the effective date of the
applicable governmental authority’s order approving the term, or as otherwise provided for by the
applicable governmental authority. Do you agree that three calendar months is enough time to
update documentation? If you do not agree, please provide the amount of time needed and types
of actions that will need to be completed during this time.
Yes
No
Comments:

Unofficial Comment Form | Project 2016-02 Modifications to CIP Standards
Control Center Definition | March - April 2018

4

Standards Announcement
Reminder

Project 2016-02 Modifications to CIP Standards
Initial and Additional Ballots and Non-binding Polls Open through April 30, 2018
Now Available

Initial ballots for the Control Center Definition and its Implementation Plan, additional ballots for CIP002-6 and CIP-012-1 and the associated non-binding polls of the associated Violation Risk Factors and
Violation Severity Levels are open through 8 p.m. Eastern, Monday, April 30, 2018.
The standard drafting team’s considerations of the responses received from the last comment period
for CIP-002-6 and CIP-012-1 are reflected in these drafts of the standards.
Balloting

Members of the ballot pools associated with this project can log in and submit their votes by accessing
the Standards Balloting and Commenting System (SBS) here. If you experience any difficulties navigating
the SBS, contact Wendy Muller.
•

If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential
error messages, or system lock-out, contact NERC IT support directly at https://support.nerc.net/
(Monday – Friday, 8 a.m. - 5 p.m. Eastern).

•

Passwords expire every 6 months and must be reset.

•

The SBS is not supported for use on mobile devices.

•

Please be mindful of ballot and comment period closing dates. We ask to allow at least 48 hours
for NERC support staff to assist with inquiries. Therefore, it is recommended that users try logging
into their SBS accounts prior to the last day of a comment/ballot period.

Note: If a member cast a vote in the previous ballot, that vote will not carry over to the additional
ballot. It is the responsibility of the registered voter in the ballot pool to cast a vote again in the
additional ballot. To ensure a quorum is reached, if you do not want to vote affirmative or negative,
cast an abstention.
Next Steps

The ballot results will be announced and posted on the project page. The drafting team will review all
responses received during the comment period and determine the next steps of the project.

For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Mat Bunch at (404) 446-9785 or Jordan Mallory at (404) 4462589.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement | CIP-012-1 Ballot Open Reminder
Project 2016-02 Modifications to CIP Standards | December 1, 2017

2

Standards Announcement

Project 2016-02 Modifications to CIP Standards
Formal Comment Periods Open through April 30, 2018
Ballot Pools Forming through April 16, 2018
Now Available

Three formal comment periods are open through 8 p.m. Eastern, Monday, April 30, 2018 for:
1. CIP-002-6 – Cyber Security - BES Cyber System Categorization
2. CIP-012-1 – Cyber Security - Communications between Control Centers
3. Project 2016-02 Modifications to NERC Glossary of Terms Used in Reliability Standards – Control
Center
Commenting

Use the Standards Balloting and Commenting System (SBS) to submit comments. If you experience
difficulties navigating the SBS, contact Wendy Muller. Unofficial Word versions of the comment forms
are posted on the project page.
Ballot Pools

Ballot pools are being formed through 8 p.m. Eastern, Monday, April 16, 2018 for the Control Center
Definition and its Implementation Plan. Registered Ballot Body members can join the ballot pools
here.
•

If you are having difficulty accessing the SBS due to a forgotten password, incorrect
credential error messages, or system lock-out, contact NERC IT support directly at
https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5 p.m. Eastern).

•

Passwords expire every 6 months and must be reset.

•

The SBS is not supported for use on mobile devices.

•

Please be mindful of ballot and comment period closing dates. We ask to allow at least 48
hours for NERC support staff to assist with inquiries. Therefore, it is recommended that users try
logging into their SBS accounts prior to the last day of a comment/ballot period.

Next Steps

The initial ballots for the Control Center Definition and its Implementation Plan will be conducted
April 20-30, 2018. Additional ballots for CIP-002-6 and CIP-012-1 and the associated non-binding polls
of the associated Violation Risk Factors and Violation Severity Levels will be conducted April 20-30,
2018.
For information on the Standards Development Process, refer to the Standard Processes Manual.

For more information or assistance, contact Mat Bunch at (404) 446-9785 or Jordan Mallory at (404) 4462589.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | July-September, 2017

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Index - NERC Balloting Tool

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BALLOT RESULTS
Comment: View Comment Results (/CommentResults/Index/132)
Ballot Name: 2016-02 Modifications to CIP Standards Control Center Definiton Implementation Plan IN 1 OT
Voting Start Date: 4/20/2018 12:01:00 AM
Voting End Date: 4/30/2018 8:00:00 PM
Ballot Type: OT
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 243
Total Ballot Pool: 298
Quorum: 81.54
Weighted Segment Value: 37.98

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Negative
Fraction
w/
Comment

Segment:
1

74

1

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7

12

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14

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0.595

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10

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0

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0.3
1
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© 2018
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Negative
Votes
w/o
Comment

Abstain

No
Vote

9/10/2018

Index - NERC Balloting Tool

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Segment

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Totals:

298

5.9

93

2.241

128

Negative
Fraction
w/
Comment

Negative
Votes
w/o
Comment

Abstain

No
Vote

3.659

0

22

55

BALLOT POOL MEMBERS
Show All

Segment

 entries

Organization

Search: Search

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Allete - Minnesota Power,
Inc.

Jamie Monette

Abstain

N/A

1

Ameren - Ameren Services

Eric Scott

Negative

Comments
Submitted

1

American Transmission
Company, LLC

Douglas Johnson

Negative

Comments
Submitted

1

Austin Energy

Thomas
Standifur

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Affirmative

N/A

1

Basin Electric Power
Cooperative

David Rudolph

None

N/A

1

BC Hydro and Power
Authority

Patricia
Robertson

Affirmative

N/A

1

Berkshire Hathaway Energy
- MidAmerican Energy Co.

Terry Harbour

Negative

Comments
Submitted

1

Bonneville Power
Administration

Kammy RogersHolliday

Affirmative

N/A

1

Cedar Falls Utilities

Adam Peterson

Affirmative

N/A

Affirmative

N/A

1

CenterPoint Energy Houston
Daniela
Electric, LLC
Hammons
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Index - NERC Balloting Tool

Segment

Organization

Page 3 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Central Electric Power
Cooperative (Missouri)

Michael Bax

Negative

Third-Party
Comments

1

Central Hudson Gas &
Electric Corp.

Frank Pace

Negative

Third-Party
Comments

1

City Utilities of Springfield,
Missouri

Michael Buyce

Negative

Third-Party
Comments

1

CMS Energy - Consumers
Energy Company

James Anderson

Negative

Comments
Submitted

1

Colorado Springs Utilities

Devin Elverdi

Affirmative

N/A

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Negative

Comments
Submitted

1

CPS Energy

Gladys DeLaO

None

N/A

1

Duke Energy

Laura Lee

Negative

Comments
Submitted

1

East Kentucky Power
Cooperative

Amber Skillern

Affirmative

N/A

1

Edison International Southern California Edison
Company

Steven Mavis

Negative

Comments
Submitted

1

Entergy - Entergy Services,
Inc.

Oliver Burke

Negative

Comments
Submitted

1

Eversource Energy

Quintin Lee

Affirmative

N/A

1

Exelon

Chris Scanlon

Negative

Comments
Submitted

1

FirstEnergy - FirstEnergy
Corporation

Karen Yoder

Affirmative

N/A

1

Great Plains Energy Kansas City Power and Light
Co.

James McBee

Affirmative

N/A

1

Great River Energy

Gordon Pietsch

None

N/A

1

Hydro One Networks, Inc.

Payam
Farahbakhsh

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Laura Nelson

None

N/A

Douglas Webb

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Segment

Organization

Page 4 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

1

International Transmission
Company Holdings
Corporation

Michael Moltane

Stephanie Burns

Negative

Comments
Submitted

1

JEA

Ted Hobson

Joe McClung

Affirmative

N/A

1

KAMO Electric Cooperative

Walter Kenyon

None

N/A

1

Lakeland Electric

Larry Watt

Negative

Comments
Submitted

1

Long Island Power Authority

Robert Ganley

None

N/A

1

Los Angeles Department of
Water and Power

faranak sarbaz

Affirmative

N/A

1

Lower Colorado River
Authority

Michael Shaw

Abstain

N/A

1

Manitoba Hydro

Mike Smith

Affirmative

N/A

1

MEAG Power

David Weekley

Abstain

N/A

1

Minnkota Power Cooperative
Inc.

Theresa Allard

None

N/A

1

Muscatine Power and Water

Andy Kurriger

Negative

Third-Party
Comments

1

N.W. Electric Power
Cooperative, Inc.

Mark Ramsey

Negative

Third-Party
Comments

1

National Grid USA

Michael Jones

Affirmative

N/A

1

Network and Security
Technologies

Nicholas Lauriat

Affirmative

N/A

1

New York Power Authority

Salvatore
Spagnolo

Negative

Third-Party
Comments

1

NextEra Energy - Florida
Power and Light Co.

Mike ONeil

Affirmative

N/A

1

NiSource - Northern Indiana
Public Service Co.

Steve Toosevich

Negative

Comments
Submitted

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Negative

Comments
Submitted

1

Oncor Electric Delivery

Lee Maurer

Affirmative

N/A

Negative

Third-Party
Comments

1

OTP - Otter Tail Power
Charles Wicklund
Company
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Scott Miller

Tho Tran

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 5 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

1

PNM Resources - Public
Service Company of New
Mexico

Laurie Williams

Negative

Comments
Submitted

1

Portland General Electric
Co.

Nathaniel Clague

Abstain

N/A

1

PPL Electric Utilities
Corporation

Brenda Truhe

Affirmative

N/A

1

PSEG - Public Service
Electric and Gas Co.

Joseph Smith

Affirmative

N/A

1

Public Utility District No. 1 of
Pend Oreille County

Kevin Conway

None

N/A

1

Public Utility District No. 1 of
Snohomish County

Long Duong

Affirmative

N/A

1

Sacramento Municipal Utility
District

Arthur Starkovich

Affirmative

N/A

1

Salt River Project

Steven Cobb

None

N/A

1

Santee Cooper

Chris Wagner

None

N/A

1

SCANA - South Carolina
Electric and Gas Co.

Tom Hanzlik

None

N/A

1

Seattle City Light

Pawel Krupa

Negative

Comments
Submitted

1

Seminole Electric
Cooperative, Inc.

Mark Churilla

Abstain

N/A

1

Sho-Me Power Electric
Cooperative

Peter Dawson

Negative

Third-Party
Comments

1

Southern Company Southern Company
Services, Inc.

Katherine Prewitt

Negative

Comments
Submitted

1

Southern Indiana Gas and
Electric Co.

Steve Rawlinson

Affirmative

N/A

1

Sunflower Electric Power
Corporation

Paul Mehlhaff

Abstain

N/A

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

Affirmative

N/A

Abstain

N/A

1
Tallahassee Electric (City of
Scott Langston
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Index - NERC Balloting Tool

Segment

Organization

Page 6 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Tennessee Valley Authority

Howell Scott

Affirmative

N/A

1

Tri-State G and T
Association, Inc.

Tracy Sliman

Affirmative

N/A

1

U.S. Bureau of Reclamation

Richard Jackson

Negative

Comments
Submitted

1

Westar Energy

Kevin Giles

Affirmative

N/A

1

Western Area Power
Administration

sean erickson

Negative

Comments
Submitted

1

Wind Energy Transmission
Texas, LLC

Julius Horvath

None

N/A

1

Xcel Energy, Inc.

Dean Schiro

Affirmative

N/A

2

Electric Reliability Council of
Texas, Inc.

Brandon Gleason

Negative

Comments
Submitted

2

Independent Electricity
System Operator

Leonard Kula

Negative

Comments
Submitted

2

Midcontinent ISO, Inc.

Ellen Oswald

Negative

Comments
Submitted

2

New York Independent
System Operator

Gregory Campoli

Abstain

N/A

2

PJM Interconnection, L.L.C.

Mark Holman

Affirmative

N/A

3

Ameren - Ameren Services

David Jendras

Negative

Comments
Submitted

3

APS - Arizona Public Service
Co.

Vivian Vo

Affirmative

N/A

3

Arkansas Electric
Cooperative Corporation

Philip Huff

Negative

Third-Party
Comments

3

Associated Electric
Cooperative, Inc.

Todd Bennett

Negative

Comments
Submitted

3

Austin Energy

W. Dwayne
Preston

Affirmative

N/A

3

Avista - Avista Corporation

Scott Kinney

None

N/A

3

Basin Electric Power
Cooperative

Jeremy Voll

Negative

Third-Party
Comments

Brad Calbick

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Segment

Organization

Page 7 of 18

Voter

3

Berkshire Hathaway Energy
- MidAmerican Energy Co.

Annette Johnston

3

Black Hills Corporation

3

Designated
Proxy
Darnez
Gresham

Ballot

NERC
Memo

Negative

Comments
Submitted

Eric Egge

Affirmative

N/A

Bonneville Power
Administration

Rebecca Berdahl

Affirmative

N/A

3

Central Electric Power
Cooperative (Missouri)

Adam Weber

Negative

Third-Party
Comments

3

City of Farmington

Linda JacobsonQuinn

Affirmative

N/A

3

City of Independence, Power
and Light Department

Mike Lotz

None

N/A

3

City of Vero Beach

Ginny Beigel

Negative

Comments
Submitted

3

City Utilities of Springfield,
Missouri

Scott Williams

Negative

Third-Party
Comments

3

Cleco Corporation

Michelle Corley

None

N/A

3

CMS Energy - Consumers
Energy Company

Karl Blaszkowski

Negative

Comments
Submitted

3

Colorado Springs Utilities

Hillary Dobson

Affirmative

N/A

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Negative

Comments
Submitted

3

CPS Energy

James Grimshaw

None

N/A

3

DTE Energy - Detroit Edison
Company

Karie Barczak

None

N/A

3

Duke Energy

Lee Schuster

Negative

Comments
Submitted

3

East Kentucky Power
Cooperative

Patrick Woods

Affirmative

N/A

3

Edison International Southern California Edison
Company

Romel Aquino

Affirmative

N/A

3

Eversource Energy

Mark Kenny

Affirmative

N/A

3

Exelon

John Bee

Negative

Comments
Submitted

Brandon
McCormick

Louis Guidry

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Segment

Organization

Page 8 of 18

Voter

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

3

Florida Municipal Power
Agency

Joe McKinney

3

Georgia System Operations
Corporation

Scott McGough

3

Great Plains Energy Kansas City Power and Light
Co.

John Carlson

3

Great River Energy

3

Designated
Proxy

Ballot

NERC
Memo

None

N/A

Negative

Comments
Submitted

Negative

Third-Party
Comments

Affirmative

N/A

Brian Glover

Negative

Third-Party
Comments

KAMO Electric Cooperative

Ted Hilmes

None

N/A

3

Lincoln Electric System

Jason Fortik

Negative

Third-Party
Comments

3

Los Angeles Department of
Water and Power

Henry (Hank)
Williams

None

N/A

3

M and A Electric Power
Cooperative

Stephen Pogue

Negative

Third-Party
Comments

3

Manitoba Hydro

Karim AbdelHadi

Affirmative

N/A

3

MEAG Power

Roger Brand

Abstain

N/A

3

Muscatine Power and Water

Seth Shoemaker

Negative

Third-Party
Comments

3

National Grid USA

Brian Shanahan

Affirmative

N/A

3

Nebraska Public Power
District

Tony Eddleman

Negative

Comments
Submitted

3

New York Power Authority

David Rivera

Negative

Third-Party
Comments

3

NiSource - Northern Indiana
Public Service Co.

Aimee Harris

Negative

Comments
Submitted

3

North Carolina Electric
Membership Corporation

doug white

Negative

Third-Party
Comments

3

Northeast Missouri Electric
Power Cooperative

Skyler
Wiegmann

Negative

Third-Party
Comments

Brandon
McCormick

Douglas Webb

Scott Miller

Scott Brame

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Segment

Organization

Page 9 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

3

NW Electric Power
Cooperative, Inc.

John Stickley

Negative

Third-Party
Comments

3

Ocala Utility Services

Neville Bowen

None

N/A

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Negative

Third-Party
Comments

3

OTP - Otter Tail Power
Company

Wendi Olson

Negative

Third-Party
Comments

3

Owensboro Municipal
Utilities

Thomas Lyons

None

N/A

3

Platte River Power Authority

Jeff Landis

Abstain

N/A

3

PNM Resources - Public
Service Company of New
Mexico

Lynn Goldstein

Negative

Comments
Submitted

3

Portland General Electric
Co.

Angela Gaines

Abstain

N/A

3

PPL - Louisville Gas and
Electric Co.

Charles Freibert

Affirmative

N/A

3

Public Utility District No. 1 of
Chelan County

Joyce Gundry

Abstain

N/A

3

Public Utility District No. 1 of
Pend Oreille County

Amber Orr

None

N/A

3

Rutherford EMC

Tom Haire

None

N/A

3

Sacramento Municipal Utility
District

Nicole Looney

Affirmative

N/A

3

Salt River Project

Robert
Kondziolka

Negative

Third-Party
Comments

3

Santee Cooper

James Poston

None

N/A

3

SCANA - South Carolina
Electric and Gas Co.

Scott Parker

None

N/A

3

Seminole Electric
Cooperative, Inc.

James Frauen

Abstain

N/A

3

Sho-Me Power Electric
Cooperative

Jeff Neas

Negative

Third-Party
Comments

3

Snohomish County PUD No.

Mark Oens

Affirmative

N/A

Joe Tarantino

1
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Segment

Organization

Page 10 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Southern Company Alabama Power Company

Joel Dembowski

Negative

Comments
Submitted

3

Southern Indiana Gas and
Electric Co.

Fred Frederick

Affirmative

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

Marc Donaldson

Affirmative

N/A

3

Tennessee Valley Authority

Ian Grant

None

N/A

3

WEC Energy Group, Inc.

Thomas Breene

Negative

Comments
Submitted

3

Westar Energy

Bo Jones

Affirmative

N/A

3

Xcel Energy, Inc.

Michael Ibold

Affirmative

N/A

4

Alliant Energy Corporation
Services, Inc.

Larry Heckert

None

N/A

4

American Public Power
Association

Jack Cashin

None

N/A

4

Arkansas Electric
Cooperative Corporation

Alice Wright

Negative

Third-Party
Comments

4

Austin Energy

Esther Weekes

Affirmative

N/A

4

City of Poplar Bluff

Neal Williams

None

N/A

4

City Utilities of Springfield,
Missouri

John Allen

Negative

Third-Party
Comments

4

CMS Energy - Consumers
Energy Company

Theresa Martinez

Negative

Third-Party
Comments

4

FirstEnergy - FirstEnergy
Corporation

Aubrey Short

Affirmative

N/A

4

Florida Municipal Power
Agency

Carol Chinn

Negative

Comments
Submitted

4

Georgia System Operations
Corporation

Guy Andrews

Negative

Third-Party
Comments

4

Illinois Municipal Electric
Agency

Mary Ann Todd

None

N/A

4

Indiana Municipal Power
Agency

Jack Alvey

Negative

Third-Party
Comments

Brandon
McCormick

Scott Berry

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Segment

Organization

Page 11 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

4

LaGen

Richard
Comeaux

Negative

Third-Party
Comments

4

MGE Energy - Madison Gas
and Electric Co.

Joseph
DePoorter

Negative

Third-Party
Comments

4

National Rural Electric
Cooperative Association

Barry Lawson

Negative

Comments
Submitted

4

North Carolina Electric
Membership Corporation

John Lemire

Negative

Third-Party
Comments

4

Public Utility District No. 1 of
Snohomish County

John Martinsen

Affirmative

N/A

4

Sacramento Municipal Utility
District

Beth Tincher

Affirmative

N/A

4

Seattle City Light

Hao Li

Negative

Comments
Submitted

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

Affirmative

N/A

4

Utility Services, Inc.

Brian EvansMongeon

Abstain

N/A

4

WEC Energy Group, Inc.

Anthony
Jankowski

Negative

Comments
Submitted

5

Acciona Energy North
America

George Brown

Negative

Comments
Submitted

5

AEP

Thomas Foltz

Affirmative

N/A

5

Ameren - Ameren Missouri

Sam Dwyer

Negative

Comments
Submitted

5

APS - Arizona Public Service
Co.

Kelsi Rigby

Affirmative

N/A

5

Arkansas Electric
Cooperative Corporation

Moses Harris

Negative

Third-Party
Comments

5

Associated Electric
Cooperative, Inc.

Brad Haralson

None

N/A

5

Austin Energy

Shirley Mathew

None

N/A

5

Avista - Avista Corporation

Glen Farmer

Affirmative

N/A

5

Basin Electric Power

Mike Kraft

Negative

Third-Party
Comments

Cooperative
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Joe Tarantino

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 12 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

5

BC Hydro and Power
Authority

Helen Hamilton
Harding

None

N/A

5

Berkshire Hathaway - NV
Energy

Kevin Salsbury

Negative

Comments
Submitted

5

Black Hills Corporation

George Tatar

Affirmative

N/A

5

Boise-Kuna Irrigation District
- Lucky Peak Power Plant
Project

Mike Kukla

Negative

Third-Party
Comments

5

Bonneville Power
Administration

Scott Winner

Affirmative

N/A

5

Brazos Electric Power
Cooperative, Inc.

Shari Heino

Negative

Third-Party
Comments

5

California Department of
Water Resources

ASM Mostafa

None

N/A

5

Choctaw Generation Limited
Partnership, LLLP

Rob Watson

Negative

Third-Party
Comments

5

City Water, Light and Power
of Springfield, IL

Steve Rose

Affirmative

N/A

5

CMS Energy - Consumers
Energy Company

David
Greyerbiehl

Negative

Comments
Submitted

5

Colorado Springs Utilities

Jeff Icke

Affirmative

N/A

5

Dairyland Power
Cooperative

Tommy Drea

None

N/A

5

Dominion - Dominion
Resources, Inc.

Lou Oberski

Negative

Comments
Submitted

5

DTE Energy - Detroit Edison
Company

Jeffrey DePriest

Affirmative

N/A

5

Duke Energy

Dale Goodwine

Negative

Comments
Submitted

5

East Kentucky Power
Cooperative

Steve Ricker

Affirmative

N/A

5

Entergy

Jamie Prater

Negative

Comments
Submitted

5

Exelon

Ruth Miller

Negative

Comments
Submitted

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Segment

Organization

Page 13 of 18

Voter

5

FirstEnergy - FirstEnergy
Solutions

Robert Loy

5

Florida Municipal Power
Agency

Chris Gowder

5

Great Plains Energy Kansas City Power and Light
Co.

Harold Wyble

5

Great River Energy

5

Designated
Proxy

Ballot

NERC
Memo

Affirmative

N/A

Brandon
McCormick

Negative

Comments
Submitted

Douglas Webb

Affirmative

N/A

Preston Walsh

Negative

Third-Party
Comments

Herb Schrayshuen

Herb
Schrayshuen

Affirmative

N/A

5

JEA

John Babik

None

N/A

5

Kissimmee Utility Authority

Mike Blough

Negative

Comments
Submitted

5

Lakeland Electric

Jim Howard

None

N/A

5

Lincoln Electric System

Kayleigh
Wilkerson

Negative

Third-Party
Comments

5

Manitoba Hydro

Yuguang Xiao

Affirmative

N/A

5

Massachusetts Municipal
Wholesale Electric Company

David Gordon

Negative

Third-Party
Comments

5

MEAG Power

Steven Grego

Abstain

N/A

5

Muscatine Power and Water

Neal Nelson

Negative

Third-Party
Comments

5

NaturEner USA, LLC

Eric Smith

None

N/A

5

NB Power Corporation

Laura McLeod

Affirmative

N/A

5

Nebraska Public Power
District

Don Schmit

Negative

Third-Party
Comments

5

New York Power Authority

Erick Barrios

Negative

Third-Party
Comments

5

NiSource - Northern Indiana
Public Service Co.

Dmitriy Bazylyuk

Negative

Comments
Submitted

5

North Carolina Electric
Membership Corporation

Robert Beadle

Negative

Third-Party
Comments

Brandon
McCormick

Scott Miller

Scott Brame

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Segment

Organization

Page 14 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

5

OGE Energy - Oklahoma
Gas and Electric Co.

John Rhea

Negative

Comments
Submitted

5

Omaha Public Power District

Mahmood Safi

Negative

Third-Party
Comments

5

Orlando Utilities Commission

Richard Kinas

None

N/A

5

OTP - Otter Tail Power
Company

Cathy Fogale

Negative

Third-Party
Comments

5

Platte River Power Authority

Tyson Archie

Affirmative

N/A

5

Portland General Electric
Co.

Ryan Olson

Abstain

N/A

5

PPL - Louisville Gas and
Electric Co.

JULIE
HOSTRANDER

Affirmative

N/A

5

PSEG - PSEG Fossil LLC

Tim Kucey

Affirmative

N/A

5

Public Utility District No. 1 of
Chelan County

Haley Sousa

Abstain

N/A

5

Public Utility District No. 1 of
Pend Oreille County

Mark Cleveland

None

N/A

5

Public Utility District No. 1 of
Snohomish County

Sam Nietfeld

Affirmative

N/A

5

Sacramento Municipal Utility
District

Susan Oto

Affirmative

N/A

5

Salt River Project

Kevin Nielsen

Negative

Third-Party
Comments

5

Santee Cooper

Tommy Curtis

None

N/A

5

SCANA - South Carolina
Electric and Gas Co.

Alyssa Hubbard

None

N/A

5

Southern Company Southern Company
Generation

William D. Shultz

Negative

Comments
Submitted

5

Southern Indiana Gas and
Electric Co.

Mark McDonald

Affirmative

N/A

5

SunPower

Bradley Collard

None

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

None

N/A

Joe Tarantino

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Segment

Organization

Page 15 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Tennessee Valley Authority

M Lee Thomas

Affirmative

N/A

5

Tri-State G and T
Association, Inc.

Mark Stein

Affirmative

N/A

5

U.S. Bureau of Reclamation

Wendy Center

Negative

Comments
Submitted

5

WEC Energy Group, Inc.

Linda Horn

Negative

Comments
Submitted

5

Xcel Energy, Inc.

Gerry Huitt

Affirmative

N/A

6

Ameren - Ameren Services

Robert Quinlivan

Negative

Comments
Submitted

6

APS - Arizona Public Service
Co.

Jonathan Aragon

Affirmative

N/A

6

Arkansas Electric
Cooperative Corporation

Bruce Walkup

Negative

Third-Party
Comments

6

Associated Electric
Cooperative, Inc.

Brian Ackermann

Negative

Comments
Submitted

6

Basin Electric Power
Cooperative

Paul Huettl

Negative

Third-Party
Comments

6

Black Hills Corporation

Eric Scherr

None

N/A

6

Bonneville Power
Administration

Andrew Meyers

Affirmative

N/A

6

Cleco Corporation

Robert Hirchak

None

N/A

6

Colorado Springs Utilities

Shannon Fair

Affirmative

N/A

6

Con Ed - Consolidated
Edison Co. of New York

Robert Winston

Negative

Comments
Submitted

6

Dominion - Dominion
Resources, Inc.

Sean Bodkin

Negative

Comments
Submitted

6

Duke Energy

Greg Cecil

Negative

Comments
Submitted

6

Edison International Southern California Edison
Company

Kenya Streeter

Negative

Comments
Submitted

6

Entergy

Julie Hall

Negative

Comments
Submitted

Louis Guidry

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Segment

Organization

Page 16 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Exelon

Becky Webb

Negative

Comments
Submitted

6

FirstEnergy - FirstEnergy
Solutions

Ann Ivanc

Affirmative

N/A

6

Florida Municipal Power
Agency

Richard
Montgomery

Brandon
McCormick

Negative

Comments
Submitted

6

Florida Municipal Power
Pool

Tom Reedy

Brandon
McCormick

Negative

Comments
Submitted

6

Great Plains Energy Kansas City Power and Light
Co.

Jennifer
Flandermeyer

Douglas Webb

Affirmative

N/A

6

Great River Energy

Donna
Stephenson

Michael
Brytowski

Negative

Third-Party
Comments

6

Los Angeles Department of
Water and Power

Anton Vu

Affirmative

N/A

6

Manitoba Hydro

Blair Mukanik

None

N/A

6

Muscatine Power and Water

Ryan Streck

Amie Shuger
McConnaha

Negative

Third-Party
Comments

6

New York Power Authority

Shivaz Chopra

Shelly Dineen

Negative

Third-Party
Comments

6

NextEra Energy - Florida
Power and Light Co.

Silvia Mitchell

Affirmative

N/A

6

NiSource - Northern Indiana
Public Service Co.

Joe O'Brien

Affirmative

N/A

6

Northern California Power
Agency

Dennis Sismaet

Negative

Comments
Submitted

6

NRG - NRG Energy, Inc.

Martin Sidor

None

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Sing Tay

Negative

Third-Party
Comments

6

Portland General Electric
Co.

Daniel Mason

None

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

Affirmative

N/A

None

N/A

6

PSEG - PSEG Energy
Karla Barton
Resources and Trade LLC
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Segment

Organization

Page 17 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Public Utility District No. 1 of
Chelan County

Davis Jelusich

Abstain

N/A

6

Public Utility District No. 1 of
Pend Oreille County

Kimberly Gentle

None

N/A

6

Public Utility District No. 2 of
Grant County, Washington

LeRoy Patterson

None

N/A

6

Sacramento Municipal Utility
District

Jamie Cutlip

Affirmative

N/A

6

Salt River Project

Bobby Olsen

Negative

Third-Party
Comments

6

Santee Cooper

Michael Brown

None

N/A

6

SCANA - South Carolina
Electric and Gas Co.

John Folsom

None

N/A

6

Seattle City Light

Charles Freeman

Negative

Comments
Submitted

6

Seminole Electric
Cooperative, Inc.

Trudy Novak

Abstain

N/A

6

Snohomish County PUD No.
1

Franklin Lu

Affirmative

N/A

6

Southern Company Southern Company
Generation and Energy
Marketing

Jennifer Sykes

Negative

Comments
Submitted

6

Tacoma Public Utilities
(Tacoma, WA)

Rick Applegate

Affirmative

N/A

6

Tennessee Valley Authority

Marjorie Parsons

Affirmative

N/A

6

WEC Energy Group, Inc.

David Hathaway

Negative

Comments
Submitted

6

Westar Energy

Megan Wagner

Affirmative

N/A

6

Western Area Power
Administration

Charles Faust

Negative

Comments
Submitted

6

Xcel Energy, Inc.

Carrie Dixon

Affirmative

N/A

8

David Kiguel

David Kiguel

Negative

Third-Party
Comments

Joe Tarantino

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Segment

Organization

Page 18 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

9

Commonwealth of
Massachusetts Department
of Public Utilities

Donald Nelson

Negative

Third-Party
Comments

10

Midwest Reliability
Organization

Russel Mountjoy

Abstain

N/A

10

New York State Reliability
Council

ALAN
ADAMSON

Negative

Comments
Submitted

10

Northeast Power
Coordinating Council

Guy V. Zito

Negative

Comments
Submitted

10

ReliabilityFirst

Anthony
Jablonski

Affirmative

N/A

10

Texas Reliability Entity, Inc.

Rachel Coyne

Abstain

N/A

10

Western Electricity
Coordinating Council

Steven Rueckert

Abstain

N/A

Previous

1

Next

Showing 1 to 298 of 298 entries

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Standards Announcement

Project 2016-02 Modifications to CIP Standards
Formal Comment Periods Open through April 30, 2018
Ballot Pools Forming through April 16, 2018
Now Available

Three formal comment periods are open through 8 p.m. Eastern, Monday, April 30, 2018 for:
1. CIP-002-6 – Cyber Security - BES Cyber System Categorization
2. CIP-012-1 – Cyber Security - Communications between Control Centers
3. Project 2016-02 Modifications to NERC Glossary of Terms Used in Reliability Standards – Control
Center
Commenting

Use the Standards Balloting and Commenting System (SBS) to submit comments. If you experience
difficulties navigating the SBS, contact Wendy Muller. Unofficial Word versions of the comment forms
are posted on the project page.
Ballot Pools

Ballot pools are being formed through 8 p.m. Eastern, Monday, April 16, 2018 for the Control Center
Definition and its Implementation Plan. Registered Ballot Body members can join the ballot pools
here.
•

If you are having difficulty accessing the SBS due to a forgotten password, incorrect
credential error messages, or system lock-out, contact NERC IT support directly at
https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5 p.m. Eastern).

•

Passwords expire every 6 months and must be reset.

•

The SBS is not supported for use on mobile devices.

•

Please be mindful of ballot and comment period closing dates. We ask to allow at least 48
hours for NERC support staff to assist with inquiries. Therefore, it is recommended that users try
logging into their SBS accounts prior to the last day of a comment/ballot period.

Next Steps

The initial ballots for the Control Center Definition and its Implementation Plan will be conducted
April 20-30, 2018. Additional ballots for CIP-002-6 and CIP-012-1 and the associated non-binding polls
of the associated Violation Risk Factors and Violation Severity Levels will be conducted April 20-30,
2018.
For information on the Standards Development Process, refer to the Standard Processes Manual.

For more information or assistance, contact Mat Bunch at (404) 446-9785 or Jordan Mallory at (404) 4462589.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | July-September, 2017

2

Comment Report
Project Name:

2016-02 Modifications to CIP Standards | Control Center Definition and Implementation Plan

Comment Period Start Date:

3/16/2018

Comment Period End Date:

4/30/2018

Associated Ballots:

2016-02 Modifications to CIP Standards Control Center Definition Implementation Plan IN 1 OT
2016-02 Modifications to CIP Standards Control Center Definition IN 1 DEF

There were 74 sets of responses, including comments from approximately 177 different people from approximately 127 companies
representing 10 of the Industry Segments as shown in the table on the following pages.

Questions
1. Control Center definition: Do you agree with the proposed revisions to the definition of Control Center? If not, please provide rationale or
propose an alternative definition.

2. Control Center definition: Do the proposed revisions to the Control Center definition change the scope or intent of any current or pending
Reliability Standard(s) using the defined term (examples include Reliability Standards: COM-001-3; TOP-001-4; and IRO-002-5)? If yes,
provide details of the affected Reliability Standard(s), requirements, and any anticipated impact.

3. Control Center definition: The SDT contends that there will be no change in BES Cyber System categorization by clarifying the definition
of Control Center. This assertion is based on SDT review of the CIP-002-5.1a criteria and its understanding of BES Cyber System
categorization through experience implementing CIP-002-5.1a. Do you agree with this assertion? If not, please provide rationale and practical
examples of where a change in categorization will occur as a result of this modification.

4. Control Center definition: Is there a scenario where a Control Center hosts both the inclusion personnel and the exclusion personnel? If
yes, please provide them here.

5. Implementation Plan: The new Control Center definition will become effective on the first day of the first calendar quarter that is three (3)
calendar months after the effective date of the applicable governmental authority’s order approving the term, or as otherwise provided for by
the applicable governmental authority. Do you agree that three calendar months is enough time to update documentation? If you do not
agree, please provide the amount of time needed and types of actions that will need to be completed during this time.

Organization
Name
FirstEnergy FirstEnergy
Corporation

Brandon
McCormick

Name

Aaron
Ghodooshim

Brandon
McCormick

Segment(s)

3

Region

RF

FRCC

Group Name Group Member
Name

Group
Group
Member
Member
Organization Segment(s)

FirstEnergy
Corporation

Aaron
Ghdooshim

FirstEnergy FirstEnergy
Corporation

4

RF

Aubrey Short

FirstEnergy FirstEnergy
Corporation

1

RF

Theresa Ciancio FirstEnergy FirstEnergy
Corporation

3

RF

Robert Loy

FirstEnergy FirstEnergy
Solutions

5

RF

Ann Ivanc

FirstEnergy FirstEnergy
Solutions

6

RF

Tim Beyrle

City of New
4
Smyrna
Beach Utilities
Commission

FRCC

Jim Howard

Lakeland
Electric

5

FRCC

Lynne Mila

City of
Clewiston

4

FRCC

Javier Cisneros Fort Pierce
Utilities
Authority

3

FRCC

Randy Hahn

Ocala Utility
Services

3

FRCC

Don Cuevas

Beaches
Energy
Services

1

FRCC

Jeffrey
Partington

Keys Energy
Services

4

FRCC

Tom Reedy

Florida
Municipal
Power Pool

6

FRCC

Steven
Lancaster

Beaches
Energy
Services

3

FRCC

FMPA

Group
Member
Region

Duke Energy

Colby Bellville 1,3,5,6

FRCC,RF,SERC

Mike Blough

Kissimmee
Utility
Authority

5

FRCC

Chris Adkins

City of
Leesburg

3

FRCC

Ginny Beigel

City of Vero
Beach

3

FRCC

Duke Energy

1

RF

Duke Energy

3

FRCC

Dale Goodwine Duke Energy

5

SERC

Greg Cecil

Duke Energy

6

RF

Pawel Krupa

Seattle City
Light

1

WECC

Hao Li

Seattle City
Light

4

WECC

Bud (Charles)
Freeman

Seattle City
Light

6

WECC

Mike Haynes

Seattle City
Light

5

WECC

Michael Watkins Seattle City
Light

1,4

WECC

Faz Kasraie

Seattle City
Light

5

WECC

John Clark

Seattle City
Light

6

WECC

Tuan Tran

Seattle City
Light

3

WECC

Laurrie
Hammack

Seattle City
Light

3

WECC

Oliver Burke

Entergy 1
Entergy
Services, Inc.

SERC

Jamie Prater

Entergy

5

SERC

Katherine
Prewitt

Southern
1
Company
Services, Inc.

SERC

Duke Energy Doug Hils
Lee Schuster

Seattle City
Light

Entergy

Ginette
Lacasse

Julie Hall

Southern
Pamela
Company Hunter
Southern
Company
Services, Inc.

1,3,4,5,6

WECC

6

1,3,5,6

Seattle City
Light Ballot
Body

Entergy

SERC

Southern
Company

Joel Dembowski Southern
Company Alabama
Power
Company

3

SERC

Northeast
Power
Coordinating
Council

Ruida Shu

1,2,3,4,5,6,7,8,9,10 NPCC

RSC no
Dominion,
NextEra and
HQ

William D.
Shultz

Southern
Company
Generation

5

SERC

Jennifer G.
Sykes

Southern
Company
Generation
and Energy
Marketing

6

SERC

Guy V. Zito

Northeast
Power
Coordinating
Council

10

NPCC

Randy
MacDonald

New
Brunswick
Power

2

NPCC

Wayne Sipperly New York
Power
Authority

4

NPCC

Glen Smith

Entergy
Services

4

NPCC

Brian Robinson Utility
Services

5

NPCC

Alan Adamson

New York
State
Reliability
Council

7

NPCC

Edward Bedder Orange &
Rockland
Utilities

1

NPCC

David Burke

3

NPCC

Michele Tondalo UI

1

NPCC

Laura Mcleod

NB Power

1

NPCC

David
Ramkalawan

Ontario Power 5
Generation
Inc.

NPCC

Helen Lainis

IESO

2

NPCC

Michael
Schiavone

National Grid

1

NPCC

Michael Jones

National Grid

3

NPCC

Michael Forte

Con Ed Consolidated
Edison

1

NPCC

Orange &
Rockland
Utilities

Midwest
Reliability
Organization

Russel
Mountjoy

10

MRO NSRF

Peter Yost

Con Ed 3
Consolidated
Edison Co. of
New York

NPCC

Sean Cavote

PSEG

4

NPCC

Kathleen
Goodman

ISO-NE

2

NPCC

Paul
Malozewski

Hydro One
3
Networks, Inc.

NPCC

Quintin Lee

Eversource
Energy

1

NPCC

Gregory
Campoli

New York
Independent
System
Operator

2

NPCC

Dermot Smyth

Con Ed 1,5
Consolidated
Edison Co. of
New York

NPCC

Dermot Smyth

Con Ed 1,5
Consolidated
Edison Co. of
New York

NPCC

Salvatore
Spagnolo

New York
Power
Authority

1

NPCC

Shivaz Chopra

New York
Power
Authority

6

NPCC

David Kiguel

Independent

NA - Not
Applicable

NPCC

Joseph
DePoorter

Madison Gas
& Electric

3,4,5,6

MRO

Larry Heckert

Alliant Energy 4

MRO

Amy Casucelli

Xcel Energy

1,3,5,6

MRO

Michael
Brytowski

Great River
Energy

1,3,5,6

MRO

Jodi Jensen

Western Area 1,6
Power
Administratino

MRO

Kayleigh
Wilkerson

Lincoln
Electric
System

1,3,5,6

MRO

Mahmood Safi

Omaha Public 1,3,5,6
Power District

MRO

Dominion Dominion
Resources,
Inc.

Southwest
Power Pool,
Inc. (RTO)

Associated
Electric
Cooperative,
Inc.

Sean Bodkin

Shannon
Mickens

Todd Bennett

6

2

3

Dominion

SPP RE

Brad Parret

Minnesota
Power

1,5

MRO

Terry Harbour

MidAmerican
Energy
Company

1,3

MRO

Tom Breene

Wisconsin
3,5,6
Public Service

MRO

Jeremy Volls

Basin Electric 1
Power Coop

MRO

Kevin Lyons

Central Iowa
Power
Cooperative

1

MRO

Mike Morrow

Midcontinent
Independent
System
Operator

2

MRO

Connie Lowe

Dominion Dominion
Resources,
Inc.

3

NA - Not
Applicable

Lou Oberski

Dominion Dominion
Resources,
Inc.

5

NA - Not
Applicable

Larry Nash

Dominion 1
Dominion
Virginia Power

NA - Not
Applicable

Southwest
Power Pool
Inc.

2

SPP RE

Steve Keller

Soutwest
Power Pool
Inc

2

SPP RE

Sean Simpson

Board of
NA - Not
Public Utilities, Applicable
City of
Mcpherson,
Kansas

SPP RE

louis Guidry

Cleco

SPP RE

Michael Bax

Central
1
Electric Power
Cooperative
(Missouri)

SERC

Adam Weber

Central
3
Electric Power

SERC

SPP
Shannon
Standards
Mickens
Review Group

AECI

1,3,5,6

Cooperative
(Missouri)
Stephen Pogue M and A
3
Electric Power
Cooperative

SERC

William Price

M and A
1
Electric Power
Cooperative

SERC

Jeff Neas

Sho-Me
3
Power Electric
Cooperative

SERC

Peter Dawson

Sho-Me
1
Power Electric
Cooperative

SERC

Mark Ramsey

N.W. Electric
Power
Cooperative,
Inc.

1

NPCC

John Stickley

NW Electric
Power
Cooperative,
Inc.

3

SERC

Ted Hilmes

KAMO Electric 3
Cooperative

SERC

Walter Kenyon

KAMO Electric 1
Cooperative

SERC

Kevin White

Northeast
1
Missouri
Electric Power
Cooperative

SERC

Skyler
Wiegmann

Northeast
3
Missouri
Electric Power
Cooperative

SERC

Ryan Ziegler

Associated
Electric
Cooperative,
Inc.

1

SERC

Brian
Ackermann

Associated
Electric
Cooperative,
Inc.

6

SERC

Brad Haralson

Associated
Electric
Cooperative,
Inc.

5

SERC

ACES Power Warren Cross 1,3,4,5
Marketing

MRO,RF,SERC,SPP ACES
Arizona Electric AEPC
RE,Texas
Standards
Power
RE,WECC
Collaborators Cooperative,
Inc.

1

WECC

Hoosier Energy HE
Rural Electric
Cooperative,
Inc.

1

RF

Rayburn
RCEC
Country Electric
Cooperative

3

SPP RE

Southern
Maryland
Electric
Cooperative

SMECO

3

RF

North Carolina
Electric
Membership
Corporation

NCEMC

3,4,5

SERC

Central Iowa
Power
Cooperative

CIPCO

1

MRO

East Kentucky
Power
Cooperative

EKPC

1,3

SERC

Buckeye Power, BUCK
Inc.

4

RF

Prairie Power,
Inc.

1,3

SERC

PPI

1. Control Center definition: Do you agree with the proposed revisions to the definition of Control Center? If not, please provide rationale or
propose an alternative definition.
Tony Eddleman - Nebraska Public Power District - 3
Answer

No

Document Name
Comment
Trying to define a “control center” is difficult and can have unintended consequences. As you work your way through this definition, the boundary of a
control center should be discussed and considered. Where is the boundary of a control center?
Reliability standard requirements contain words such as “within” a control center (TOP-001-4 R20), so the importance of knowing the boundary is
important and in many cases, the boundary isn’t obvious. Control centers are typically located with other business functions and including a larger
boundary than necessary can apply regulatory requirements to business functions not intended to be included in the requirement and introduce
confusion. Possible boundaries may be defined by the following:
1. The property line or fence line of the facility. This broad brush of a definition will include functions not intended for applicability under Reliability
Standards and cause unneeded costs for customers. In many cases where a control center is located in a metro area collocated in a building
with other functions, a fence does not exist and the property line may be a public sidewalk. This definition is also problematic because cyber
access equipment is not typically located at this boundary and access control would be extremely difficult. With the exception of a fence, gate,
camera, etc., it is difficult to apply reliability controls to effectively control access with little ability to apply defense in-depth. Other concerns
identified below for using the exterior building walls may also apply to using the property line or fence line. This definition is not recommended
and should only be used in special cases.
2. The exterior building walls surrounding the control center. This definition is problematic due to other functions being collocated with the control
center. If a control center is located with other business functions, such as a corporate headquarters, the control center may be located on a
floor of a multiple floor building. In these situations, defining the exterior building walls is clearly an overextension of the regulatory
requirements and will cause undue costs for an entity. Control centers may be collocated with a substation or power plant. For these
situations, specific regulatory requirements may apply to the substation or power plant and simply designating the exterior building wall will
confuse how to apply regulatory requirements. In a situation where you have a control center isolated from other business functions in a
standalone facility, other support functions for the control center are needed. These support functions would not need the additional protections
and will cause additional costs without a benefit to the BES. This definition may be used in specific situations, but should not be a default by
everyone.
3. The Physical Security Perimeter (PSP) for the Control Center, or if a formal PSP is not required, the location where the PSP would be
implemented, if required. A PSP is already defined in the NERC Glossary of Terms and entities have implemented security measures around
these defined locations, where required. These are demarcations with clear boundaries and can be used to apply regulatory
requirements. But, it’s easy to identify situations where identifying the boundary of a control center as a PSP may have unintended
consequences. A PSP is defined for CIP requirements and trying to standardize by using a CIP term for an Operations & Planning requirement
will lead to unintended consequences. A PSP is designed to contain BES Cyber Systems. In situations where you have multiple PSPs in the
same building, you would need to address how the area between the PSPs is handled for the control center definition.
4. The boundary of a control center could be defined as the room(s) where NERC certified system operators perform real-time functions and the
associated data centers. This definition limits the scope of the control center to the core functions and should provide a basis for the intent of
the Reliability Standards. There may be exceptions, but this definition may cover a large percentage of registered entities that have a control
center and need to identify a boundary.
Recommend the following definition:

One or more rooms in a facility, including their associated data centers, that monitor and control the Bulk Electric System (BES) and also host
NERC certified operating personnel who:
Likes

2

Dislikes

Nebraska Public Power District, 5, Schmit Don; OGE Energy - Oklahoma Gas and Electric Co., 6, Tay Sing
0

Response

Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1
Answer

No

Document Name
Comment
POPUD is concerned that the proposed definition of Control Center may include Dispatching Centers (Distribution), Back-Up Centers and Power Plant
Control Rooms in small utilities which have SCADA controls that control a very limited group of BES transmission assets. In our case, we provide
SCADA to the various areas because of the multiple roles our staff has due to staffing constraints. We believe that the unintended consequences of the
proposed change will impact us by confusing the auditing staff with the roles of Transmission Operators or Balancing Authorities; and, who must be
NERC Certified. We own approximately 58 miles of transmission which is operated and monitored by another entity.
Likes

0

Dislikes

0

Response

Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer

No

Document Name
Comment
Dominion Energy disagrees with the proposed definition for the following reasons:

1. The term ‘real time reliability tasks’ is undefined and ambiguous. This term is critical to compliance and needs some additional context to allow
entities to reliability operate. As such, there should be no obligations included in the task list for other Entities to perform. For example, one
would not expect a TOP’s task list to require that a TO perform a task. Rather, the TOP may require that the TO identify a Real-time reliability
task (in the TOs list under R2.1) to cover a situation. In this case, the real-time reliability-related task belongs to the TO and not the
TOP. Consequently, one would never expect that a task be classified as real-time reliability-related for one Entity just because it has been
designated as such by another Entity. For example, an RC may include running State Estimator and Contingency Analysis programs on its list
of real-time reliability-related tasks. Just because a TO happens to run a State Estimator does not make running the State Estimator a real-time
reliability-related task for the TO unless the TO has so designated it in the TO list, nor does the TO running the State Estimator satisfy the RC’s
obligation to run the State Estimator.

2. If the context for ‘real time reliability tasks’ is PER-005, the task lists are entity specific and not necessarily shared with the entity responsible for
determining if it’s a control center.
If PER-005 is the basis for these tasks, than the proposed Control Center definition should have the same language and limitations contained in PER005.
1. Just because an entity performs a task on any RC, BA, TOP BES company-specific Real-time reliability-related task list, the proposed definition
appears to automatically make that performance a reliability task that qualifies you as a Control Center.
If this is accurate, the responsible entity may not know what is on these lists as the entities that develop the lists are not required and, in most cases, do
not share these with other entities.
1. As currently written, the proposed definition excludes the reliability related tasks developed by a TO and could make the TO fall under the
definition of a Control Center unknowingly based on #3.
2. Based on ‘real time reliability tasks’ being defined in the context of PER-005, Dominion Energy proposes the following alternative language for a
Control Center definition.

“One or more facilities, including their associated data centers, of an RC, BA, TOP, TO that monitor and control the Bulk Electric System (BES) and host
operating personnel who can act independently to operate or direct in Real-time the operation of Bulk Electric System Transmission Facilities; or a
centrally located GOP dispatch center hosting dispatch personnel at who receive direction from their RC, BA, TOP or TO and may develop specific
dispatch instructions for plant operators or plant control systems under their control.

Operating and dispatch personnel do not include:
1. Transmission Owner or Transmission Operator field switching personnel; or
2. Plant operators located at a generator plant site or personnel at a centrally located dispatch center who relay dispatch instructions without
making any modifications.
The intent of the change to the definition is not clear in regards to TOs. Item 5 in the proposed definition of Control Center indicates that having
the ability to operate a TO’s BES Transmission Facilities or merely having the ability to dispatch someone to operate the Facility creates a
Control Center. Is the desired intent that any TO with SCADA control OR field switching personnel have a Control Center? Field switching
personnel are excluded from the definition of “operating personnel”, but there is no definition of who is included in this definition. Is someone
who answers the phone (e.g., from a TOP) and passes the instructions to field switching personnel considered to be “operating
personnel”? Consider the example of a Storm Center (e.g., conference room) where personnel gather to monitor storm damage and direct field
personnel for Real-time operation of the TO’s BES Transmission Facilities. Does the conference room become a Control Center under this
definition, or is it excluded because those gathered in it are not considered operating personnel? This ambiguity should be resolved.
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Response

Russel Mountjoy - Midwest Reliability Organization - 10, Group Name MRO NSRF
Answer

No

Document Name
Comment
Use of the term; “One or more facilities…” should be defined further as the NSRF believes the SDT’s intent and offer that a “facility” may be looked at as
an entire building that houses RCs, BAs, and TOPs. Recommend that the first part of the definition read “One or more rooms in a facility…”. This
clearly points to a prescribed area within a facility and not the entire facility.

Without understanding what “Real-time reliability-related tasks” are (see next paragraph), we cannot support this definition. There could be an entity
that has personnel who work outside the “Control Center” walls that have Real-time tasks that support the RC, BA and TOP. Or is the SDT referring to
NERC Certified System Operators only? Many entities require NERC Certifications for non-System Operators as part of the positions that they
fulfill. Please clarify.

It is unclear to what the SDT believe the definition of “…reliability-related tasks…” refers to within is part 1, 2, and 3 of the proposed Control Center
definition. Is this the “reliability-related tasks” associated with the tasks identified by each RC, TOP and BA per PER-005-2? Or is it the “reliabilityrelated tasks” noted in some other NERC document? Note that “reliability-related tasks” is not used within the NERC Functional Model. The Functional
Model uses “related reliability tasks”, only within the introduction sections and not under any specific Function. The term “Tasks” is used under each
Function. Is the SDT referring to “Tasks” within the Functional Model to mean the same as “…reliability related tasks…” within the proposed Control
Center definition? The NSRF is against using the Functional Model as a reference document as the current version is from 2010 and can be changed
by NERC at any time. The NSRF recommends that an asterisk (*) [or foot note] be placed next to “reliability-related tasks*” and refer to reliabilityrelated tasks identified by PER-005-2. This provides clarity the each applicable RC, TOP and BA.

Part 4 uses the word “can act” to describe the action that a GOP could accomplish in developing dispatch instructions. A GOP “can” do something but
may not have the authority to accomplish the dispatch instruction. Recommend that part 4 use the word “perform” in place of “can act”, this is also in
line with parts 1, 2, and 3.

Part 5 also uses the word “Can act”. Recommend this be replaced with “perform” with the same justification in part 4.

The NSRF would like to point out that the term "data center" is not defined in any NERC standard or NERC documentation. The issue is how far into
the SCADA acquisition process does the data center definition penetrate. Does the data center definition penetrate into data aggregators used to
reduce communication costs that represent loss of several RTU if compromised? The main impact area of this definition is in the new TOP-001-4
standard R20 that becomes enforceable 7-1-18. If the data center definition is beyond the bricks and mortar used for the Control Room and SCADA,
then redundant
and diversely routed data exchange infrastructure may be needed outside of the traditional primary Control Center facility. Please clarify.

R20. Each Transmission Operator shall have data exchange capabilities, with redundant and diversely routed data exchange infrastructure within the
Transmission Operator's primary Control Center, for the exchange of Real-time data with its Reliability Coordinator, Balancing Authority, and the entities
it has identified it needs data from in order for it to perform its Real-time monitoring and Real-time
Assessments.
Likes

2

OGE Energy - Oklahoma Gas and Electric Co., 6, Tay Sing; OGE Energy - Oklahoma Gas and Electric
Co., 3, Hargrove Donald

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Steven Rueckert - Western Electricity Coordinating Council - 10
Answer

No

Document Name

2016-02_Control_Center_Modified_Definition_03162018-WECC comments.docx

Comment
Thank you for the opportunity to comment on the proposed revisions to the definition of Control Center. WECC agrees with and supports the purpose
and intent of the proposed revisions to the Control Center Definition. WECC supports the revisions to the first five elements, and the concept behind the
last two elements identifying what is not a control center. However, WECC believes that the definition of a Control Center should not include identifying
what operating personnel are not, but rather, should include a definition of what a Control Center is not.
WECC believes that including language defining what Operating personnel are not will conflict with the purpose of COM-002-4 – Operating Personnel
Communications Protocols. There is evidence that a significant number of Misoperations are a result of poor communication between System Operators
at control centers and the entity’s operating personnel in the field.
The attached file contains WECC's proposed revisions to the defintion.
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Jonathan Aragon - APS - Arizona Public Service Co. - 6
Answer

No

Document Name
Comment
a) For the purpose of clarity, AZPS recommends that the first sentence of the proposed definition be changed to:
One or more facilities, including their associated data centers, hosting operating personnel that monitor and control the Bulk Electric System (BES) to:

b) AZPS is concerned that the new definition sets up the potential for inconsistency due to the use of the term “reliability tasks” in the definition for items
1 and 3, but the term “functional obligations” in sections 1.1 and 1.3 of the CIP-002 attachment 1.

c) AZPS is concerned that item (5), which appears to be the equivalent of Transmission Operator Control Centers, presents a lower criteria for control
centers than is applicable under item (3). Specifically, item 3, which is applicable to Transmission Operators, applies only when there are “facilities at
two or more locations;” however, item 5, which could be construed as describing a Transmission Operator does not have the same qualifier. For this

reason, AZPS requests clarification of the use of “can operate” as stated in item 5 of the definition as well as what the intended differentiation between
items 3 and 5 is.
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Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer

No

Document Name
Comment
City Light supports APPA comments
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ALAN ADAMSON - New York State Reliability Council - 10
Answer

No

Document Name
Comment
BES substation control rooms may be identified as “Control Centers” under the proposed definition; among other concerns, this could result in a
substation being classified as High-Impact.
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Peter Yost - Con Ed - Consolidated Edison Co. of New York - 3
Answer
Document Name
Comment
supporting comments from NPCC

No

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Central Hudson Gas &amp; Electric Corp., 1, Pace Frank
0

Response

Joel Charlebois - AESI - Acumen Engineered Solutions International Inc. - 5
Answer

No

Document Name
Comment
With respect to Generator Operators and Generator Owners;
There are existing generation Facility control rooms, and perhaps other centralized control or data centers, who have the capability to operate or direct
the operation of generation Facilities at two or more locations, but who do not develop specific dispatch instructions, but simply implement or relay
(electronically in some cases) operating and dispatch instructions from their RC/BA/TOP, or from their GOP if the existing generation Facility control
room implements or relays operating and dispatch instructions from a second larger GOP Control Center. These existing generation Facility control
rooms meet the existing Control Center definition, but would be excluded from the proposed definition.
Some of these existing generation Facility control rooms can operate or direct the operation of Generator Owner Facilities at two or more locations
(thereby meeting the existing Control Center definition) with an aggregate of 1500MW or more in a single Interconnection (e.g. 1000MW at one Facility,
500MW at another Facility), but simply implement or relay (electronically in some cases) operating and dispatch instructions from their
RC/BA/TOP/GOP in doing so. The proposed definition will lower the impact rating of the BCS located at these exiting generation Facility control rooms
from Medium under the CIP-002-5.1a impact rating criterion 2.11 down to Low under criterion 3.3, as these control rooms would no longer meet the
proposed Control Center definition. The proposed Control Center definition adds new applicability criteria to CIP-002-5.1a impact rating criterion 2.11
by reference, thereby reducing the scope of applicability of CIP-002-5.1a impact rating criterion 2.11.
Since the intent of the CIP standards is to protect Cyber Assets and systems that “if rendered unavailable, degraded, or misused, would adversely
impact the reliable operation of the BES within 15 minutes of the activation or exercise of the compromise”, the fact that a GOP (or GO) Facility’s control
room operating personnel do or do not develop specific dispatch instructions for generation Facilities at two or more locations or simply implement or
relay such instructions should be immaterial to the CIP-002-5.1a impact rating of the BCS located at those Facility control rooms.
As the 1500MW threshold is an important one and used in several CIP-002-5.1a Medium impact rating criteria, and the proposed definition will lower the
impact rating of some BCS under CIP-002-5.1a impact rating criterion 2.11, we do not agree with the proposed definition.
We propose the following modifications:
1- Modify the sentence:
“4) can act independently as the Generator Operator to develop specific dispatch instructions for generation Facilities at two or more locations;”
To:
“4) act as the Generator Operator for generation Facilities at two or more locations;” which is similar to the existing definition, or perhaps to more
accurately capture the intent of the CIP standards and to capture Facilities and control rooms performing GOP functions,
To:
“4) can operate or direct the operation of a Generator Owner’s BES generation Facilities at two or more locations in Real-time”, similar to the language
of “5)”, which would capture all control rooms performing GOP functions for BES generation Facilities at two or more locations.

2- Remove exclusion “1) plant operators located at a generator plant site or personnel …”
Otherwise, CIP-002-5.1a impact rating criterion 2.11 should be modified to recapture Medium BCS at control centers or control rooms that would now
be excluded from this criterion by the proposed definition.

With respect to Transmission Owner Control Centres (TOCCs);
The language in item “5)” should likely align with the concept in item “3)” with respect to operating or directing the operation of “Transmission Facilities
at two or more locations;”
We propose the following modifications:
1- Modify the sentence:
“5) can operate or direct the operation of a Transmission Owner’s BES Transmission Facilities in Real-time.”
To:
“5) can operate or direct the operation of a Transmission Owner’s BES Transmission Facilities at two or more locations in Real-time.”

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Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
BPA believes the majority of this definition isn’t needed. The only difference from existing System Operator definition being incorporated is the inclusion
of GOP. BPA suggests using the defined term System Operator in the existing definition of Control Center and specifically including operating personnel
at GOPs rather than listing all functions already covered in the current System Operator definition. The exclusions would also be covered in this manner
since the System Operator definition only applies to people “at a Control Center.”
BPA proposes the following:
One or more facilities where the Bulk Electric System (BES) is monitored and controlled, including its associated data centers and communications
infrastructure, and hosting operating personnel who:
1)

perform the Real-time reliability-related tasks of a Reliability Coordinator; or

2)

perform the Real-time reliability-related tasks of a Balancing Authority; or

3)

perform the Real-time reliability-related tasks of a Transmission Operator for Transmission Facilities at two or more locations; or

4)

can act independently as the Generator Operator to develop specific dispatch instructions for generation Facilities at two or more locations.

The exclusions aren’t clear enough to know whether No. 1 only applies to personnel located at generating plants or includes personnel at other centrally
located dispatch centers as well.
Operating personnel do not include:
1)
Plant operators located at a generator plant site who relay or implement dispatch instructions from a Generator Operator without making any
modifications; or
2)

Personnel at a centrally located dispatch center who relay or implement dispatch instructions without making any modifications; or

3)

Transmission Owner or Transmission Operator field switching personnel.

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Thomas Breene - WEC Energy Group, Inc. - 3
Answer

No

Document Name
Comment
We support the MRO NSRF comments. The proposed definition of Control Center is fatally flawed in that it would allow for the exclusion of any data
center which does not host operating personnel. This would introduce unacceptable security risks to the Bulk Electric System.
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Marty Hostler - Northern California Power Agency - 5,6
Answer

No

Document Name
Comment
Agree with WECC's comments regarding specifying what a Control Center is not.
Also Attachment No. 1 item four is too ambiguous. "can act independently as the Generator Operator to develop specific dispatch instructions for
generation Facilities at two or more locations". How does a GOP prove that they can not develop specific dispatch instructions?
I suggest the following: "Generator Operators that develop specific written dispatch instructions for generation Facilities, at two or more locations in realtime (at the same time), that deviate from their Balancing Authority's dispatch instructions".

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Response

Kenya Streeter - Edison International - Southern California Edison Company - 6
Answer

No

Document Name
Comment
Please refer to comments submitted by Robert Blackney on behalf of Southern California Edison
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sean erickson - Western Area Power Administration - 1
Answer

No

Document Name
Comment
WAPA desires clarification on the definition of “associated data centers”. As written, it could bring data centers into scope that have nothing to do with
power systems operations, but are “associated” in some other way. The qualifiers regarding “monitor and control the BES” and “host operating
personnel” apply to the “One or more facilities” and not necessarily to “associated data centers”. As one example, there might be a business office data
center that is associated with the facilities that monitor and host operating personnel. Another example might be that a scheduling vendor’s data center
(which provides Net Scheduled Interchange data) is associated with the facilities that operate a Balancing Authority. More clarity is needed as to the
intent in bringing “associated data centers” into this definition.
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Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer
Document Name
Comment

No

Duke Energy disagrees with the proposed revisions to the definition of Control Center based on the existence of some ambiguities. Regarding
“operating personnel”, is it the drafting team’s intent that to be considered as operating personnel, does the personnel need to be able to control
equipment such as opening a breaker? While we appreciate the drafting team’s effort to provide more detail to explain who “operating personnel”
actually applies to in the definition of Control Center, perhaps it may be more beneficial for operating personnel to have its own definition.
Also, the phrase “associated data centers”, while already in use today, would benefit industry if a more common understanding was created. For
example, is it the drafting team’s intent that a facility would need to be manned to be considered applicable to this definition? Industry could benefit from
having a common definition for “data center” as well.
Duke Energy offers the following suggested definition of Control Center for the drafting team’s consideration:
One or more facilities, including their associated data centers for the acquisition, aggregation, processing, or inter-utility exchange of Bulk Electric
System (BES) data that is used to support Real-time operations to make operational decisions regarding reliability and operability of the BES, and also
host operating personnel, who monitor and control the BES and
1. perform the Real-time reliability-related tasks of a Reliability Coordinator; or Balancing Authority; or Transmission Operator for Transmission
Facilities at two or more locations; or
2. can act independently as the Generator Operator to develop specific dispatch instructions for generation Facilities at two or more locations; or
3. can operate or direct the operation of a Transmission Owner’s BES Transmission Facilities in Real-time.
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Response

Douglas Johnson - American Transmission Company, LLC - 1
Answer

No

Document Name
Comment
Operating personnel is vague and broad. American Transmission Company LLC (ATC) proposes replacing operating personnel with the NERC
Glossary of Terms defined term System Operator. As a result, ATC requests consideration of rephrasing the first sentence as follows “One or more
facilities, including their associated data centers, that monitor and control the Bulk Electric System (BES) and also host System Operators who:”
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Steven Mavis - Edison International - Southern California Edison Company - 1
Answer
Document Name

No

Comment
Please refer to comments submitted by Robert Blackney on behalf of Southern California Edison
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Larry Watt - Lakeland Electric - 1
Answer

No

Document Name
Comment
1. The use of “host” in the first sentence is not understood.
2. The use of “including their associated data centers” in the proposed definition is a concern. Moving the “including their associated data centers”
phrase as proposed, could suggest, to some, that the data center must host operating personnel.
3. The use of “perform the Real-time reliability related tasks of a” in Numbers 1-3 in the proposed definition is a concern. The additions of, “Real-time”
and “related” to the existing “reliability tasks” does not provide additional clarity. These wording choices appear to be a reference to the NERC
Functional Model, since the current Introduction to the Function Model (V5) includes subsections labeled “Tasks” and “Real Time.” An entity that
performs the reliability tasks listed in the Functional Model should have the appropriate Functional Registration. For purposes of the Control Center
definition, the three criteria should be limited to entities with the RC, BA and TOP registrations. Adding this phrase to points 1 -3 of the proposed
definition does not address the issue of “capability or authority” as it relates to “perform.” Therefore, Lakeland Electric recommends striking this phrase
in all locations.
4. Using “can” in point number 4 of the definition is a concern. Using “can” does not address the issue of “capability or authority.” Therefore, it is
unclear how “can act” differs from the “perform” used in points 1-3. For example, if a VP of Operations for a GO (and not GOP) entity “can” order a unit
shut to be shut down, would that entity’s facilities fit under the definition? Lakeland Electric recommends removing the word “can.”
5. Using “specific dispatch instructions” in definition point 4 is a concern. It is unclear how the addition of the word “specific” differentiates between
different dispatch instructions. Therefore, Lakeland Electric recommends deleting the word “specific” and replacing the undefined “dispatch instructions”
with the NERC defined term “Operating Instruction.”
6. The term “locations” used in point 4 is open to many interpretations and therefore causes concern. It is unclear how “locations” is applied to
dispersed generation, adjoining or nested substations and switchyards. “Locations” may need to be defined in the NERC Glossary.
7. Use of “can” in the proposed definition point 5 causes concern. The word “can” does not address the issue of “capability or authority.” It is unclear
how “can act” differs from the “perform” used in definition points 1-3. As written, this qualifier seems to go against the CIP-002-5.1 GTB (page 24) which
states, “A TO BES Cyber System in a TO facility that does not perform or does not have an agreement with a TOP to perform any of these functional
tasks does not meet the definition of a Control Center.” Therefore, Lakeland Electric recommends language that limits the scope to entities that have
the capability. In addition, to ensure clarity, the GTB would need to be updated to agree with this change.
8. Use of, “Real-time” in point 5 without a pertinent understanding of how it will be specifically understood, causes concerns. The determination of how
“Real-time” is applied was made by the SDT for the BES Cyber Asset definition developed under project 2014-02 Critical Infrastructure Protection
Standards Version 5 Revisions - CIP-003, CIP-004, to mean “within 15 minutes of a required operation”. Lakeland Electric recommends that this 15minute phrase be used in place of the “Real-time” term to ensure clarity.

9. Lakeland Electric believes the point 5 qualifier should use, “two or more locations,” to provide clarity to the proposed definition. Without this qualifying
phrase, a facility at a TO with a single BES substation could be identified as a Control Center when “operating personnel” are present. Depending on
how “host(ing)” is defined, all control buildings at a TO substation could be Control Centers under the proposed definition. APPA recommends adding
the “two or more locations” phrase to this qualifying point 5.
10. Regarding exclusions with respect to operating personnel, point 1 states, “plant operators located at a generator plant site, or personnel at a
centrally located dispatch center who….” It is unclear if both parts (plant operators~personnel) of this exclusion point, apply to only generation? The
phrase, “generator plant site” can include both BES and non-BES generation and presents a lack of clarity. Public power recommends replacing
“dispatch center” with “personnel who.” It is also possible for an operating instruction to be relayed for Transmission and not just
Generation. Therefore, Lakeland Electric recommends removing the specific language limiting this exclusion to generation.
11. Exclusion point 1 includes, “dispatch instructions,” which is not a defined term. Lakeland Electic recommends replacing it with the NERC defined
term “Operating Instruction.”
The suggestions above could result in the following definition:

One or more facilities that monitor and control the Bulk Electric System (BES) and host operating personnel during normal operations, including the
facilities’ associated data centers, of a:
1) Reliability Coordinator; or
2) Balancing Authority; or
3) Transmission Operator for Transmission Facilities at two or more locations; or
4) Generator Operator that act independently to develop Operating Instructions for generation Facilities at two or more locations;
5) Generation Owner or Generation Operator that have generation Facilities that;
i) must operate, within 15 minutes of a required operation and
ii) are at two or more locations or
6) Transmission Owner that have the Transmission Facilities that:
i) must operate, within 15 minutes of a required operation and
ii) are at two or more locations or

Operating personnel do not include:
1) plant operators located at a generator plant site or personnel at a centrally located dispatch center who relay Operating Instructions without making
any modifications; or
2) field switching personnel.

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Response

Julie Hall - Entergy - 6, Group Name Entergy
Answer

No

Document Name
Comment
The NERC Rules of Procedure Section 500 and Appendix 5A require an entity which registers as a Balancing Authority (BA), Reliability Coordinator
(RC), and Transmission Operator (TOP) to undergo Certification which requires an audit and readiness review of the registering entity to perform the
functions of a BA, RC, or TOP. The control centers would have been identified under the program with exclusion to a GOP dispatcher for generation
Facilities at two or more locations.
The current Control Center definition introduces the concept of a GOP Control Center and uses the undefined term “operating personnel.” The
proposed Control Center definition creates potential conflict by overstating a control center function, attempting to define operating personnel, and uses
the undefined term “plant operator.”
Recommend the following changes to the proposed Control Center definition and creation of an Operations Personnel definition.
Control Center - One or more facilities, including associated data centers, that hosts Operations Personnel who monitor, operate, or direct the operation
of the Bulk Electric System (BES) in Real-time of: 1) a Reliability Coordinator, 2) a Balancing Authority, 3) a Transmission Operator for transmission
Facilities at two or more locations, or 4) a Generator Operator’s generation Facilities at two or more locations.
Operations Personnel - Includes System Operators, Transmission Owner personnel, and centrally located dispatch personnel who develop specific
dispatch instructions for Generator Operators under their control. The Transmission Owner or Transmission Operator personnel exclude field switching
personnel. The dispatch personnel exclude Generator Operators who relay dispatch instructions without making any modifications.
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Barry Lawson - National Rural Electric Cooperative Association - 4
Answer

No

Document Name
Comment
NRECA strongly disagrees with the wording in item 5) of the proposed revised Control Center definition. As we have stated numerous times, a TO
should not be considered to own/operate a Control Center unless they have the capability AND independent authority to operate BES Transmission
Facilities in Real-time. NRECA recommends that item 5) be redrafted as follows: 5) can act with independent authority and capability to operate or
direct the operation of a Transmission Owner’s BES Transmission Facilities in Real-time.
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Response

Chris Scanlon - Exelon - 1
Answer

No

Document Name
Comment
Comment 1 - Exelon would like to see the following modification made to 5. :
5. can operate or direct the operation of a Transmission Owner’s BES Transmission Facilities in Real-time, at two or more locations.
Without this additional language, Exelon is concerned that the current language in 5. may bring some currently out-of-scope relay houses into scope as
Medium Control Centers.
Comment 2 - Exelon questions the wording of the first item under “Operating personnel do not include:” Exelon suggests the following wording change:
1. plant operators located at a generator plant site or personnel at a centrally located dispatch center who can only relay dispatch instructions and
cannot make any modifications; or
This covers the situation where the normal process is for dispatch instructions to be relayed without modification, however, the system would allow the
operating personnel to make modifications to the dispatch instructions.
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0

Response

Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer

No

Document Name
Comment
The proposed changes to the definition do not address all of the “opportunities for clarification” and may add additional areas of uncertainty. Some of
these issues are:
1) “host”: Does this mean that a facility is a Control Center only when operating personnel are in the room? Example: A DP/TO with a two 115KV BES
Substations staffs their emergency operations room during weather related emergency conditions. The facility can control the BES breakers at the BES
substations. The facility is not staffed at most other times. Does this facility “host” operating personnel? Does this mean that a facility is a Control
Center only when operating personnel are in the room? Adding the phrase “during normal operations” is meant to exclude locations like those
mentioned in the example. We feel that this better defines a control center but may require that the list of assets in CIP-002 R1 be modified to include
other assets. “Host” may need to be defined in the NERC Glossary.

2) “including their associated data centers”: Moving the “including their associated data centers” phrase, as proposed, could allow the interpretation that
the data center must host operating personnel. Suggest restructuring this sentence. A suggested version of this language is included in the proposed
definition included at the end of these comments.
3) Inclusion lines 1-3, “perform the Real-time reliability related tasks of a”: It is unclear how adding “Real-time” and “related” to the existing “reliability
tasks” provides any clarity. This seems to be a direct reference to the NERC Functional Model. The Introduction to the Function Model (V5) as it
includes subsections labeled “Tasks” and “Real Time.” An entity that performs the reliability tasks listed in the Functional Model should have the
appropriate Functional Registration. These three criteria should be limited to entities with the RC, BA and TOP registrations. Adding this phrase to the
inclusion lines 1 -3 does not address the issue of “capability or authority” as it relates to “perform”. Suggest striking this phrase in all locations.
4) Inclusion line 4, “can”: The word “can” phrase does not address the issue of “capability or authority”. It is unclear how “can act” differs from the
“perform” used in lines 1-3. Does and entity meet this qualifier if a VP of Operations for a GO (and not GOP) entity can order that a unit shut
down? Suggest removing the word “can”.
5) Inclusion line 4, “specific dispatch instructions”. It is unclear how the addition of the word “specific” differentiates between different dispatch
instructions. Suggest deleting the word specific and replacing the undefined “dispatch instructions” with the NERC defined term “Operating Instruction”.
6) Inclusion line 4. This proposed definition does not include Generation that responds to Operating instructions for generation at two or more
locations. Propose adding an inclusion that is similar to the inclusion criteria for Transmission Owners with Transmission Facilities at two or more
locations.
7) Inclusion line 4, “locations”. The term “locations” is open to many interpretations. It is unclear how “locations” is applied to dispersed generation or
adjoining or nested substations or switchyards. “Locations” may need to be defined in the NERC Glossary.
8) Inclusion line 5, “can”: The word “can” does not address the issue of “capability or authority”. It is unclear how “can act” differs from the “perform”
used in lines 1-3. As written, this qualifier seems to go against the CIP-002-5.1 GTB (page 24) which states “A TO BES Cyber System in a TO facility
that does not perform or does not have an agreement with a TOP to perform any of these functional tasks does not meet the definition of a Control
Center.” Suggest replacing with language that limits the scope to entities that have the capability. The GTB would need to be updated to agree with
this change.
9) Inclusion line 5, “Real-time”: The determination of how “Real-time” is applied was made by previous SDT to mean “within 15 minutes of a required
operation”. Suggest that this 15-minute phrase be used in place of the “Real-time” term.
10) Inclusion line 5, “two or more locations”: This qualifier does not include the “two or more locations” phrase. Without this phrase, a facility at a TO
with a single BES substation could be identified as a Control Center when “operating personnel” are present. Depending on how “hosting” is defined, all
control buildings at a TO substation could be Control Centers. Suggest adding the “two or more locations” phrase to this qualifier.
11) Exclusions line 1, “plant operators located at a generator plant site or personnel at a centrally located dispatch center who”: It is unclear if both parts
of this exclusion line applies to only generation. “generator plant site” would apply to both BES and non-BES generation. “Dispatch center” is undefined
an could include the offices that dispatches service personnel. Suggest replacing the term with “personnel who”. It is also possible for an operating
instruction to be relayed for Transmission and not just Generation. Suggest removing the specific language limiting this exclusion to generation.
12) Exclusion line 1, “dispatch instructions”. This term is undefined. Suggest replacing it with the NERC defined term “Operating Instruction”.
13) Change “Transmission Owner or Transmission Operator field switching personnel” to just “Field switching personnel” so that all field switching
personnel are excluded.
The suggestions above could result in the following definition:
One or more facilities that monitor and control the Bulk Electric System (BES) and host operating personnel during normal operations, including the
facilities’ associated data centers, of a:
1) Reliability Coordinator; or

2) Balancing Authority; or
3) Transmission Operator for Transmission Facilities at two or more locations; or
4) Generator Operator that act independently to develop Operating Instructions for generation Facilities at two or more locations;
5) Generation Owner or Generation Operator that monitor and control generation Facilities that;
i) must operate, within 15 minutes of an operation required by an Operating Instruction and
ii) are at two or more locations or
6) Transmission Owner that monitor and control Transmission Facilities that:
i) must operate, within 15 minutes of an operation required by an Operating Instruction and
ii) are at two or more locations or

Operating personnel do not include:
1) personnel who relay Operating Instructions without making modifications; or
2) field switching personnel.
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David Jendras - Ameren - Ameren Services - 3
Answer

No

Document Name
Comment
•

The term "operating personnel" should be changed to NERC defined term "System Operator".

•

We believe the definition is overly complicated. Please consider the following wording to replace items 1-5:

A facility, including its associated data center(s), that houses equipment for the monitoring and control of the Bulk Electric System (BES) and also
System Operators who must be trained in accordance with NERC Standard PER-005-2.

Rationale: FERC challenged NERC to identify those personnel whose job duties that have real-time reliability implications for BES reliability. As a
response to the FERC directive, NERC established PER-005 to identify and govern those individuals who are RC, TOP, BA, TO, or GOP who have the
real-time reliability tasks. On its face then, PER-005-2 identifies everyone whose work assets should be protected and also by exclusion those whose
assets do not need to be protected since their work product does not affect real-time reliability (I.e. or else they should be trained.)
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Brandon McCormick - Brandon McCormick On Behalf of: Carol Chinn, Florida Municipal Power Agency, 6, 4, 3, 5; Chris Gowder, Florida
Municipal Power Agency, 6, 4, 3, 5; David Owens, Gainesville Regional Utilities, 3, 1, 5; Ginny Beigel, City of Vero Beach, 3; Joe McKinney,
Florida Municipal Power Agency, 6, 4, 3, 5; Mike Blough, Kissimmee Utility Authority, 5, 3; Richard Montgomery, Florida Municipal Power
Agency, 6, 4, 3, 5; Tom Reedy, Florida Municipal Power Pool, 6; - Brandon McCormick, Group Name FMPA
Answer

No

Document Name
Comment
FMPA agrees with the following comments from APPA:
APPA believes that the proposed Control Center definition needs to identify and address additional “opportunities for clarification.” Currently, the lack of
clarity on these additional items increases uncertainty associated with the implementation of the proposed Control Center definition. “opportunities for
clarification” include:
1. The use of “host” in the first sentence is not understood. Does this mean that a facility is a Control Center only when operating personnel are in the
room? As an example:
a. An entity registered as a DP/TO with a two 115KV BES Substations staffs their emergency operations room during weather-related emergency
conditions. Otherwise, the facility is not staffed. The facility can control the BES breakers at the BES substations.
Does the above scenario represent an instance that the facility is “host(ing)” operating personnel at the facility during emergencies? The proposed
definition implies that a facility is a Control Center when operating personnel are (ever) in the room. APPA believes that adding the phrase, “host during
normal operations” would provide the needed clarity. We believe that this change would improve the proposed Control Center definition. Public power
recognizes that this change may require that the list of assets in CIP-002 R1 be modified to include other assets. Moreover, “host” may need to be
defined in the NERC Glossary.
2. The use of “including their associated data centers” in the proposed definition is a concern. Moving the “including their associated data centers”
phrase as proposed, could suggest, to some, that the data center must host operating personnel. Public power suggests restructuring this sentence. A
suggested version of this language is included in the proposed definition provided at the end of these comments.
3. The use of “perform the Real-time reliability related tasks of a” in Numbers 1-3 in the proposed definition is a concern. The additions of, “Real-time”
and “related” to the existing “reliability tasks” does not provide additional clarity. These wording choices appear to be a reference to the NERC
Functional Model, since the current Introduction to the Function Model (V5) includes subsections labeled “Tasks” and “Real Time.” An entity that
performs the reliability tasks listed in the Functional Model should have the appropriate Functional Registration. For purposes of the Control Center
definition, the three criteria should be limited to entities with the RC, BA and TOP registrations. Adding this phrase to points 1 -3 of the proposed
definition does not address the issue of “capability or authority” as it relates to “perform.” Therefore, APPA recommends striking this phrase in all
locations.

4. Using “can” in point number 4 of the definition is a concern. Using “can” does not address the issue of “capability or authority.” Therefore, it is
unclear how “can act” differs from the “perform” used in points 1-3. For example, if a VP of Operations for a GO (and not GOP) entity “can” order a unit
shut to be shut down, would that entity’s facilities fit under the definition? APPA recommends removing the word “can.”
5. Using “specific dispatch instructions” in definition point 4 is a concern. It is unclear how the addition of the word “specific” differentiates between
different dispatch instructions. Therefore, APPA recommends deleting the word “specific” and replacing the undefined “dispatch instructions” with the
NERC defined term “Operating Instruction.”
6. The proposed definition’s point 4 does not include Generation that responds to operating instructions for generation at two or more locations. APPA
proposes adding inclusion criteria for Generation, similar to the inclusion criteria for Transmission Owners with Transmission Facilities at two or more
locations
7. The term “locations” used in point 4 is open to many interpretations and therefore causes concern. It is unclear how “locations” is applied to
dispersed generation, adjoining or nested substations and switchyards. “Locations” may need to be defined in the NERC Glossary.
8. Use of “can” in the proposed definition point 5 causes concern. The word “can” does not address the issue of “capability or authority.” It is unclear
how “can act” differs from the “perform” used in definition points 1-3. As written, this qualifier seems to go against the CIP-002-5.1 GTB (page 24) which
states, “A TO BES Cyber System in a TO facility that does not perform or does not have an agreement with a TOP to perform any of these functional
tasks does not meet the definition of a Control Center.” Therefore, APPA recommends language that limits the scope to entities that have the
capability. In addition, to ensure clarity, the GTB would need to be updated to agree with this change.
9. Use of, “Real-time” in point 5 without a pertinent understanding of how it will be specifically understood, causes concerns. The determination of how
“Real-time” is applied was made by the SDT for the BES Cyber Asset definition developed under project 2014-02 Critical Infrastructure Protection
Standards Version 5 Revisions - CIP-003, CIP-004, to mean “within 15 minutes of a required operation”. APPA recommends that this 15-minute phrase
be used in place of the “Real-time” term to ensure clarity.
10. APPA believes the point 5 qualifier should use, “two or more locations,” to provide clarity to the proposed definition. Without this qualifying phrase, a
facility at a TO with a single BES substation could be identified as a Control Center when “operating personnel” are present. Depending on how
“host(ing)” is defined, all control buildings at a TO substation could be Control Centers under the proposed definition. APPA recommends adding the
“two or more locations” phrase to this qualifying point 5.
11. Regarding exclusions with respect to operating personnel, point 1 states, “plant operators located at a generator plant site, or personnel at a
centrally located dispatch center who….” It is unclear if both parts (plant operators~personnel) of this exclusion point, apply to only generation? The
phrase, “generator plant site” can include both BES and non-BES generation and presents a lack of clarity. Public power recommends replacing
“dispatch center” with “personnel who.” It is also possible for an {C}1)
operating instruction to be relayed for Transmission and not just
Generation. Therefore, APPA recommends removing the specific language limiting this exclusion to generation.
12. Exclusion point 1 includes, “dispatch instructions,” which is not a defined term. Public power recommends replacing it with the NERC defined term
“Operating Instruction.”
The suggestions above could result in the following definition:
One or more facilities that monitor and control the Bulk Electric System (BES) and host operating personnel during normal operations, including the
facilities’ associated data centers, of a:
1) Reliability Coordinator; or
2) Balancing Authority; or
3) Transmission Operator for Transmission Facilities at two or more locations; or
4) Generator Operator that act independently to develop Operating Instructions for generation Facilities at two or more locations;

5) Generation Owner or Generation Operator that have generation Facilities that;
i) must operate, within 15 minutes of a required operation and
ii) are at two or more locations or
6) Transmission Owner that have the Transmission Facilities that:
i) must operate, within 15 minutes of a required operation and
ii) are at two or more locations or
Operating personnel do not include:
1) personnel who relay Operating Instructions without making modifications; or
2) field switching personnel.
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Dennis Sismaet - Northern California Power Agency - 6
Answer

No

Document Name
Comment
Agree with WECC's comments regarding specifying what a Control Center is not.
Also Attachment No. 1 item four is too ambiguous. "can act independently as the Generator Operator to develop specific dispatch instructions for
generation Facilities at two or more locations". How does a GOP prove that they can not develop specific dispatch instructions?
I suggest the following: "Generator Operators that develop specific written dispatch instructions for generation Facilities, at two or more locations in realtime (at the same time), that deviate from their Balancing Authority's dispatch instructions".
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Russell Noble - Cowlitz County PUD - 3,5
Answer
Document Name
Comment

No

Cowlitz PUD supports the comments submitted by Brian Evans-Mongeon, Utility Services Inc.
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Nicolas Turcotte - Hydro-Qu?bec TransEnergie - 1
Answer

No

Document Name
Comment
We support the following RSC comments :
•
•

recommend changing "dispatching instructions" with the defined term "Operating instructions".
Inclusion line 5 : "can" : The word “can” phrase does not address the issue of “capability or authority”. It is unclear how “can act” differs from the
“perform” used in lines 1-3. As written, this qualifier seems to go against the CIP-002-5.1 GTB (page 24) which states “A TO BES Cyber System
in a TO facility that does not perform or does not have an agreement with a TOP to perform any of these functional tasks does not meet the
definition of a Control Center.” Recommend 1) replacing with language that limits the scope to entities that have the capability; 2) updating the
GTB language to the new definition

•

Inclusion line 5, “two or more locations”: This qualifier does not include the “two or more locations” phrase. Without this phrase, a facility at a
TO with a single BES substation could be identified as a Control Center when “operating personnel” are present. Depending on how “hosting”
is defined, all control buildings at a TO substation could be Control Centers. Recommend adding the “two or more locations” phrase to this
qualifier.

•

Exclusions line 1, “plant operators located at a generator plant site or personnel at a centrally located dispatch center who”: It is unclear if both
parts of this exclusion line applies to only generation. “generator plant site” would apply to both BES and non-BES generation. “Dispatch center”
is undefined and could include the offices that dispatches service personnel. Recommend replacing the “plant operators located at a generator
plant site or personnel at a centrally located dispatch center who” with “personnel who”.

•

Exclusion line 1, “dispatch instructions”. This term is undefined. Recommend replacing it with the NERC defined term “Operating Instruction”.

•

Recommend removing Transmission Operator and Transmission Owner from the second exclusion, because Generator personnel can also
perform field switching.

Our recommendations above could result in the following proposed definition:
One or more facilities, including their associated data centers, that monitor and control the Bulk Electric System (BES) and also host operating
personnel who:
1. perform the Real-time reliability tasks of a Reliability Coordinator, or
2. perform the Real-time reliability tasks of a Balancing Authority; or

3. perform the Real-time reliability tasks of a Transmission Operator for Ttransmission Facilities at two or more locations;, or
4. has the capacity to act independently as the a Generator Operator to develop Operating instructions for generation Facilities at two or more
locations; or.
5. has the capability to operate or direct the operation of a Transmission Owner’s BES Transmission Facilities in Real-time at two or more
locations.
Operating personnel do not include:
1) personnel who relay Operating Instructions without making modifications; or
2) field switching personnel.
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George Brown - Acciona Energy North America - 5
Answer

No

Document Name
Comment
Supporting the MRO NSRF's comments.
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Heather Morgan - EDP Renewables North America LLC - 5
Answer

No

Document Name
Comment
What does “Can act independently as the GOP” mean? Does “develop specific dispatch instructions” mean “develop specific dispatch instructions after
receiving direction from the GOP’s RC, BA, TOP, or TO”? There has been confusion within the generation industry on this meaning as evident in
comments, questions, and concerns raised during the PER-005-2 project.

The current interpretation of the proposed definition as it relates to Generator Operators will impact not only NERC CIP Standards, but Operations and
Planning Standards as well. With respect to CIP Standards, there are numerous generation control centers that do not develop specific dispatch
instructions. Due to this, the proposed definition would impact the classification of BES Cyber Systems as required in CIP-002. Furthermore, generation

control centers with more than 1,500 MW in one or more Interconnection(s) would be able to easily revise operating protocols to ensure the entity never
reaches the criteria to be classified as a Medium Impact BES Cyber Systems as defined with CIP-002. This loophole would not support the reliability of
the Bulk Electric System.

EDPR NA advises the SDT to reconsider revising the definition of Control Center, which will have a significant impact on all NERC Standards, and
include applicability segments to the desired standard similar to PER-005-2 rather than revising the definition of Control Center.
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Kevin Salsbury - Berkshire Hathaway - NV Energy - 5
Answer

No

Document Name
Comment
NV Energy believes that it is time to address the term “data centers” within the definition. If there is no defined NERC Glossary Term for a “data center”,
the term becomes ambiguous, and interpretation is too subjective. NV Energy believes that NERC should address defining this term at this time.
NERC should provide further clarity within the revised definition, by adding the term “System Operator”, as the individuals perform the RT reliability
tasks. This would better align with the expectation of the applicable parties/facilities that the NV Energy believes the definition is looking to address.
NV Energy identifies concerns with the Control Center definition and PER-005-2. The inclusion of “Real-Time reliability tasks” to the definition creates
confusion between the standards. PER-005-2 identifies that Entities define their BES-company-specific RT reliability tasks, but the revised definition
does not recognize that RT reliability tasks are Entity-specific. The definition should address that the RT reliability tasks performed at these locations,
are defined by the Entity themselves, in order to better align with the existing PER-005-2 Standard.
NV Energy believes the use of passive action language as “…can act” is an issue. The inclusion of this language creates more questions than answers
for defining Control Centers.
The exclusions section of the definition should also include a reference to Operations Support Personnel (i.e. IT and/or OT personnel), especially with
inclusion of the PER-005-2 term, Real-time reliability tasks.
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Darnez Gresham - Darnez Gresham On Behalf of: Annette Johnston, Berkshire Hathaway Energy - MidAmerican Energy Co., 1, 3; - Darnez
Gresham
Answer
Document Name

No

Comment
We recommend the SDT consider approaches that correspond the scope of RC, TOP and BA Control Centers to the scope of EOP-008 and incorporate
System Operator. We recommend considering qualifying draft criteria 1 (RC), 2 (BA) and 3 (TOP) with the concept of “System Operator.” This aligns
with the BES risk intended. We are concerned that EOP-008 appears absent in consideration of solutions for the definition with respect to RCs, TOPs
and BAs. Yet, all EOP-008 versions since June 2007 have the stated purpose to continue reliable operations “in the event its control center becomes
inoperable” and don’t appear to have problems identifying the primary and backup control centers (Note: EOP-008 does not use the Glossary Control
Center term). The Control Center definition has problematically created ambiguity since its origination, especially with the concept of “two or more
locations.” We also agree with MRO NSRF comments that “One or more facilities” should be reconsidered as well as “reliability related tasks.”
In the GOP criteria (inclusion 4 and exclusion 1), following PER’s words exactly is not working. For inclusion 4, “can act” and having the authority to act
are not the same thing. See MRO NSRF comments. For exclusion 2, we reiterate comments from prior drafts that the PER concept of “plant operators
located at a generator plant site” is antiquated and does not comprehend dispersed generation, including combustion turbines, wind and solar. Consider
for exclusion 2, “personnel who do not independently make modifications to dispatch instructions for generation Facilities.”
Inclusion 5 “can operate” is problematic. If a Transmission Owner can operate their Facilities at a substation (under the direction of a TOP) and not for
switching, does inclusion 5 now make the substation a Control Center.
Additional exclusions are recommended to make it crystal clear that IT (information technology) and Operations Support Personnel are excluded.
We share concerns of other commenters on “data center” ambiguity. This includes other commenters concerns about how “and also host operating
personnel” does or doesn’t apply to data centers as currently drafted grammatically.
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Terry Harbour - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1
Answer

No

Document Name
Comment
We recommend the SDT consider approaches that correspond the scope of RC, TOP and BA Control Centers to the scope of EOP-008 and incorporate
System Operator. We recommend considering qualifying draft criteria 1 (RC), 2 (BA) and 3 (TOP) with the concept of “System Operator.” This aligns
with the BES risk intended. We are concerned that EOP-008 appears absent in consideration of solutions for the definition with respect to RCs, TOPs
and BAs. Yet, all EOP-008 versions since June 2007 have the stated purpose to continue reliable operations “in the event its control center becomes
inoperable” and don’t appear to have problems identifying the primary and backup control centers (Note: EOP-008 does not use the Glossary Control
Center term). The Control Center definition has problematically created ambiguity since its origination, especially with the concept of “two or more
locations.” We also agree with MRO NSRF comments that “One or more facilities” should be reconsidered as well as “reliability related tasks.”

In the GOP criteria (inclusion 4 and exclusion 1), following PER’s words exactly is not working. For inclusion 4, “can act” and having the authority to act
are not the same thing. See MRO NSRF comments. For exclusion 2, we reiterate comments from prior drafts that the PER concept of “plant operators
located at a generator plant site” is antiquated and does not comprehend dispersed generation, including combustion turbines, wind and solar. Consider
for exclusion 2, “personnel who do not independently make modifications to dispatch instructions for generation Facilities.”

Inclusion 5 “can operate” is problematic. If a Transmission Owner can operate their Facilities at a substation (under the direction of a TOP) and not for
switching, does inclusion 5 now make the substation a Control Center.

Additional exclusions are recommended to make it crystal clear that IT (information technology) and Operations Support Personnel are excluded.

We share concerns of other commenters on “data center” ambiguity. This includes other commenters concerns about how “and also host operating
personnel” does or doesn’t apply to data centers as currently drafted grammatically.
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Jack Cashin - American Public Power Association - 4
Answer

No

Document Name
Comment
APPA believes that the proposed Control Center definition needs to identify and address additional “opportunities for clarification.” Currently, the lack of
clarity on these additional items increases uncertainty associated with the implementation of the proposed Control Center definition. “opportunities for
clarification” include:

1) The use of “host” in the first sentence is not understood. Does this mean that a facility is a Control Center only when operating personnel are in the
room? As an example:

a.
An entity registered as a DP/TO with a two 115KV BES Substations staffs their emergency operations room during weather-related emergency
conditions. Otherwise, the facility is not staffed. The facility can control the BES breakers at the BES substations.

Does the above scenario represent an instance that the facility is “host(ing)” operating personnel at the facility during emergencies? The proposed
definition implies that a facility is a Control Center when operating personnel are (ever) in the room. APPA believes that adding the phrase, “host during
normal operations” would provide the needed clarity. We believe that this change would improve the proposed Control Center definition. Public power
recognizes that this change may require that the list of assets in CIP-002 R1 be modified to include other assets. Moreover, “host” may need to be
defined in the NERC Glossary.

2) The use of “including their associated data centers” in the proposed definition is a concern. Using the “including their associated data centers”
phrase as proposed, could suggest, to some, that the data center must host operating personnel. Public power suggests restructuring this sentence. A
suggested version of this language is included in the proposed definition provided at the end of these comments.

3) The use of “perform the Real-time reliability related tasks of a” in Numbers 1-3 in the proposed definition is a concern. The additions of, “Real-time”
and “related” to the existing “reliability tasks” does not provide additional clarity. These wording choices appear to be a reference to the NERC
Functional Model, since the current Introduction to the Function Model (V5) includes subsections labeled “Tasks” and “Real Time.” An entity that
performs the reliability tasks listed in the Functional Model should have the appropriate Functional Registration. For purposes of the Control Center
definition, the three criteria should be limited to entities with the RC, BA and TOP registrations. Adding this phrase to points 1 -3 of the proposed
definition does not address the issue of “capability or authority” as it relates to “perform.” Therefore, APPA recommends striking this phrase.

4) Using “can” in point number 4 of the definition is a concern. Using “can” does not address the issue of “capability or authority.” Therefore, it is
unclear how “can act” differs from the “perform” used in points 1-3. For example, if a VP of Operations for a GO (and not GOP) entity “can” order a unit
shut to be shut down, would that entity’s facilities fit under the definition? APPA recommends removing the word “can.”

5) Using “specific dispatch instructions” in definition point 4 is a concern. It is unclear how the addition of the word “specific” differentiates between
different dispatch instructions. Therefore, APPA recommends deleting the word “specific” and replacing the undefined “dispatch instructions” with the
NERC defined term “Operating Instruction.”

6) The proposed definition’s point 4 does not include Generation that responds to operating instructions for generation at two or more
locations. APPA proposes adding inclusion criteria for Generation, similar to the inclusion criteria for Transmission Owners with Transmission Facilities
at two or more locations.

7) The term “locations” used in point 4 is open to many interpretations and therefore causes concern. It is unclear how “locations” is applied to
dispersed generation, adjoining or nested substations and switchyards. “Locations” may need to be defined in the NERC Glossary.

8) Use of “can” in the proposed definition point 5 causes concern. The word “can” does not address the issue of “capability or authority.” It is unclear
how “can act” differs from the “perform” used in definition points 1-3. As written, this qualifier seems to go against the CIP-002-5.1 GTB (page 24) which
states, “A TO BES Cyber System in a TO facility that does not perform or does not have an agreement with a TOP to perform any of these functional
tasks does not meet the definition of a Control Center.” Therefore, APPA recommends language that limits the scope to entities that specifically have
the capability. In addition, to ensure clarity, the GTB would need to be updated to agree with this change.

9) Use of, “Real-time” in point 5 without a pertinent understanding of how it will be specifically understood, causes concerns. The determination of
how “Real-time” is applied was made by the SDT for the BES Cyber Asset definition developed under project 2014-02 Critical Infrastructure Protection
Standards Version 5 Revisions - CIP-003, CIP-004, to mean “within 15 minutes of a required operation”. APPA recommends that this 15-minute phrase
be used in place of the “Real-time” term to ensure clarity.

10) APPA believes the point 5 qualifier should use, “two or more locations,” to provide clarity to the proposed definition. Without this qualifying phrase, a
facility at a TO with a single BES substation could be identified as a Control Center when “operating personnel” are present. Depending on how
“host(ing)” is defined, all control buildings at a TO substation could be Control Centers under the proposed definition. APPA recommends adding the
“two or more locations” phrase to this qualifying point 5.

11) Regarding exclusions with respect to operating personnel, point 1 states, “plant operators located at a generator plant site, or personnel at a
centrally located dispatch center who….” It is unclear if both parts (plant operators~personnel) of this exclusion point, apply to only generation? The
phrase, “generator plant site” can include both BES and non-BES generation and presents a lack of clarity. Public power recommends replacing
“dispatch center” with “personnel who.” It is also possible for an operating instruction to be relayed for Transmission and not just
Generation. Therefore, APPA recommends removing the specific language limiting this exclusion to generation.

12) Exclusion point 1 includes, “dispatch instructions,” which is not a defined term. Public power recommends replacing it with the NERC defined term
“Operating Instruction.”

The suggestions above could result in the following definition:

One or more facilities that monitor and control the Bulk Electric System (BES) and host operating personnel during normal operations, including the
facilities’ associated data centers, of a:

1) Reliability Coordinator; or
2) Balancing Authority; or
3) Transmission Operator for Transmission Facilities at two or more locations; or
4) Generator Operator that act independently to develop Operating Instructions for generation Facilities at two or more locations;
5) Generation Owner or Generation Operator that monitor and control generation Facilities that;
i) must operate, within 15 minutes of an operation required by an Operating Instruction and
ii) are at two or more locations or
6) Transmission Owner that monitor and control the Transmission Facilities that:
i) must operate, within 15 minutes of an operation required by an Operating Instruction and
ii) are at two or more locations or

Operating personnel do not include:
1) personnel who relay Operating Instructions without making modifications; or

2) field switching personnel.
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Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

No

Document Name
Comment
Texas RE appreciates the opportunity to comment on the proposed revisions to the definition of a Control Center. While Texas RE appreciates the
Standard Drafting Team’s (SDT) efforts to develop a workable definition, Texas RE remains troubled regarding two aspects of the proposed
revisions. First, Texas RE believes that the proposed revisions to the Generator Operator (GOP) Control Center definition are problematic and will lead
to reliability gaps. Second, Texas RE contends that the use of the phrase “host operating personnel” could result in confusion among Registered
Entities regarding the scope of their compliance obligations. Texas RE respectfully requests that the SDT remove these changes from the proposed
definition. Alternatively, as detailed more fully below, the SDT must engage in a comprehensive review of the impact of these changes on all affective
Reliability Standards and not simply focus on the proposed CIP-012 data exchange requirements.

As an initial matter, Texas RE is concerned that the proposed GOP Control Center definition improperly narrows the Control Center scope solely to
GOP facilities that “can act independently . . . to develop specific dispatch instructions.” In Texas RE’s experience, a significant number of GOP entities
have asserted that PER-005-2 is not applicable to their Control Centers due to language in that requirement limiting training obligations to
circumstances in which GOP Control Center personnel act independently to develop specific dispatch instructions. Given this experience, Texas RE is
concerned that the use of similar concepts of “independent operations” and “developing dispatch instructions” will result in a number of GOPs believing
that their Control Centers are now largely excluded from the scope of the NERC CIP Cyber Security standards altogether. That is, the proposed
definition implies that BES Cyber Systems located at significant centralized GOP control locations would longer meet the Medium or High Impact criteria
in CIP-002-5.1a. As such, these BES Cyber Systems, despite potentially controlling thousands of MWs of generation resources potentially would not be
required to possess the full range of physical and electronic protections specified throughout the NERC CIP Standards applicable to Medium and High
Impact BES Cyber Systems.

Consider the following result. Under the current Control Center definition, BES Cyber Systems located at a “Control Center” performing the functional
obligations of a GOP for generating units at a single plant location with an aggregate net Real Power capability equal to or exceeding 1500 MW in a
single interconnection are current considered to be a High Impact BES Cyber Systems. Under the proposed Control Center definition, a GOP could
reasonably conclude that because it only dispatches this 1500 MW Facility pursuant to the instructions from its Reliability Coordinator or Transmission
Operator, it does not “independently” develop dispatch instructions. As such, the associated facility would no longer be a Control Center under the
definition. Although the BES Cyber Systems at this facility are responsible for the control of a 1500 MW facility – identified by the Federal Energy
Regulatory Commission (FERC) as the line at which the generation resource itself represents a heightened risk to reliability – the BES Cyber Systems
at the facility actually controlling it would not need apply robust cyber security controls. This is wholly contrary to the intent underpinning the
development of the CIP-002-5.1 impact rating criteria to provide clear “bright-line” criteria that is rooted in the actual impact an associated facility can
have on the BES.

The SDT should decline to follow this approach. At a minimum, the Texas RE recommends the SDT fully evaluate this issue, develop a record, and
provide FERC with information regarding the rationale for fundamentally redefining the CIP Standards in this manner.

In addition to these concerns, Texas RE also asserts that the proposed definition’s use of the phrase “hosts operating personnel” is problematic. Texas
RE asserts that the Control Center definitions above apply equally to primary and backup Control Centers. In Texas RE’s reading, both types of
facilities are capable of hosting operating personnel and, therefore, properly fall within the Control Center definition and all associated
requirements. This reading makes sense from a reliability perspective, particularly given the expectation in EOP-008 that a backup Control Center will
be capable of performing the same operating tasks as the primary Control Center for the duration of an issue at the primary facility. The proposed
definition, however, potentially clouds this clear reliability picture. Specifically, entities could argue that only “hot” facilities actually “host operating
personnel,” and exclude backup Control Centers from the definition. This would be an erroneous reading of the definition. However, Texas RE
suggests that the SDT add additional clarification by inserting the phrase “are capable of” so that the proposed definition reads “also are capable of
hosting operating personnel” to clarify this issue.

Lastly, Texas RE is concerned that “Real-time reliability related tasks” is not defined. This will lead to each registered entity having its own criteria and
not being consistent with the other entities performing the same function. It also may not include Operations Planning Analysis, which is just as
important for reliable operations as Real-time analysis.
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Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6
Answer

No

Document Name
Comment
Please see PacifiCorp’s suggested edits to the definition below:
One or more facilities, including their associated data centers, that monitor and control the Bulk Electric System (BES) and also host operating
personnel who:
1)

are System Operators that perform the Real-time reliability-related tasks of a Reliability Coordinator; or

2)

are System Operators that perform the Real-time reliability-related tasks of a Balancing Authority; or

3)
are System Operators that perform the Real-time reliability-related tasks of a Transmission Operator for Transmission Facilities at two or more
locations; or
4)
are Generator Operator dispatch personnel at a centrally located dispatch center who receive direction from the Generator Operator’s Reliability
Coordinator, Balancing Authority, Transmission Operator, or Transmission Owner, and may develop specific dispatch instructions for plant operators
under their control for generation Facilities at two or more locations; or

The current phrase " can act indepently as the Generator Operator to develop specific dispatch instructions" has been deleted from the proposed text
above.
5)
are Transmission Owner personnel who can act independently to operate or direct the operation of a Transmission Owner’s BES Transmission
Facilities in Real-time.
Operating personnel do not include:
1)
are Generator Operator plant operators located at a generator plant site or personnel at a centrally located dispatch center who relay dispatch
instructions without making any modifications; or
2)

Transmission Owner or Transmission Operator field switching personnel.

3)

Information Technology and Operational Technology personnel that perform task related to maintenance and security on BES Cyber Systems.

Adding System Operators to the scope of items 1, 2, & 3 narrows the scope sufficiently to include only the personnel trained and certified to operate the
BES. The edits to item 4, along with exclusion 1, reflect the applicability from PER-005-2 for Generator Operators. However, we would like the
Standards Drafting Team to address comments from prior drafts that the PER concept of “plant operators located at a generator plant site” is antiquated
and does not comprehend dispersed generation, including combustion turbines, wind and solar, by making further changes to the exclusion or adding
one for dispersed generation. The edits to item 5 reflect the applicability from PER-005-2 for Transmission Owner personnel. Adding an exclusion for
Information Technology and Operational Technology personnel allows for them to perform their tasks related to their job descriptions without limiting the
number of locations that they can be connected and communicating to at any given time, or inadvertently including them as operating personnel should
they occupy a desk in a Control Center or associated data center. We share concerns of other commenters on “data center” ambiguity. This includes
other commenters concerns about how “and also host operating personnel” does or doesn’t apply to data centers as currently drafted grammatically.
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Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer

No

Document Name
Comment
Southern Company would like to see clarification regarding the inclusion and exclusion statements where there are instances that a Generator Operator
may partially meet an inclusion and exclusion at the same time. For example, a Generator Operator that does not “act independently” outside of its
BA/RC, but that does develop specific dispatch instructions for non-reliability related functions may or may not be interpreted to be scoped in under this
proposed definition. A Generator Operator may act independently to develop specific dispatch instructions that are relayed from a centrally located
dispatch center to plant personnel (i.e., the GOP can monitor only – not monitor AND control), and may or may not be interpreted to be scoped in under
this proposed definition. Additionally, if there is a facility that houses field switching personnel exclusively, and field switching is identified by a RC, BA
and/or TOP as a “Real-time reliability-related task” in their PER-005-2 training programs, and the entity for which the field switching personnel are
associated is registered as a RC, BA and/or TOP, then there is a conflict between the inclusions and exclusions.

Southern questions the use of “Real-time reliability tasks” in the scope of inclusions 1 through 3, but not in the scope of inclusions 4 and 5, and feels the
term should be further defined. If the intent is an indirect reference to PER-005
‑2 that uses
“Real-time
reliability-related
the term
tasks”, where
applicability is to a Balancing Authority, Transmission Operator, Reliability Coordinator and Transmission Owner (even though the PER-005

applies to GOPs), this indirectly implies that the Generator Operator typically does not perform “Real
‑timtasks”,
ed
e reliabi
and
lity‑
therefore
relat a
specific exclusion to this effect is not warranted. This also appears to manifest itself in a change in wording for Inclusion Item 4 to “can act
independently” in reference to the Generator Operator. The ability to act (i.e., “can”) is not equivalent to the authority to act. If the word “independently”
included here is intended to suggest authority, then this remains ambiguous, at best. Southern feels that the definition of Control Center can be more
clearly stated if more clarity is provided around what constitutes “Real-time reliability tasks”. For example, Southern suggests that to provide clarity the
wording should be changed to: “GOPs that have been granted the authority by a BA, TOP or RC to make reliability decisions and incorporate these into
their dispatch instructions.”
Southern also requests additional clarity be provided on the intent of the term “dispatch instructions” versus the NERC defined term “Operating
Instructions.” We are not comfortable proceeding in support of this change without clarity on these terms and their use or omission from the proposed
definition.
Additionally, Southern provides the following proposed definition of Control Center:
One or more facilities, including their associated data centers, that monitor and control the Bulk Electric System (BES) in Real-time and also hosts
operating personnel that perform Real-time reliability-related tasks as defined and identified by the applicable Reliability Coordinator(s), Balancing
Authority(ies), or Transmission Operator(s). Note: Real-time reliability-related tasks do not include the execution of Operating Instructions by Generator
Operators as issued by applicable Reliability Coordinator(s), Balancing Authority(ies), or Transmission Operator(s).
Note that the above definition does not require inclusions or exclusions. If there is a facility housing operating personnel under a Generator Operator
registration and those operators monitor and control BES assets in real-time and perform Real-time reliability-related tasks defined and identified by
their RC, BA or TOP, then the facility is a Control Center. If there is a facility that houses field switching personnel that monitor and control BES assets
in real-time and perform Real-time reliability-related tasks defined and identified by their RC, BA or TOP, then the facility is a Control Center. If there is
a facility that houses field switching personnel, but the facility does not allow for monitoring and control of BES assets in real-time, or does not perform
Real-time reliability-related tasks defined and identified by their RC, BA or TOP, then the facility is not a Control Center.

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Wendy Center - U.S. Bureau of Reclamation - 5
Answer

No

Document Name
Comment
For all occurrences of the following terms, Reclamation recommends changing “Facilities” to “BES Facilities,” “Transmission Facilities” to “BES
Transmission Facilities,” and “generation Facilities” to “BES generation Facilities” to reduce confusion. Therefore, first paragraph of the proposed
definition should be revised to state:
“One or more BES facilities, including their associated Data Centers, that monitor and control the BES and also host System Operators who...”
and items 3 and 4 of the proposed definition should be revised as follows:
•

perform the Real-time reliability-related tasks of a Transmission Operator for any BES Transmission Facilities; or

•

can act independently as the Generator Operator to develop specific dispatch instructions for any BES generation Facilities.

Reclamation also recommends adding the following definitions to the NERC Glossary of Terms:
•

Data Center: A location used to interchange BES Data.

•

BES Data: BES reliability operating services information affecting Operational Planning Analysis, Real-time Assessments, and Real-time
monitoring.

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Warren Cross - ACES Power Marketing - 1,3,4,5 - MRO,Texas RE,SERC,SPP RE,RF, Group Name ACES Standards Collaborators
Answer

No

Document Name
Comment
1.
ACES supports the standard drafting team (SDT) and NERC efforts to clarify the definition of a Control Center. However, ACES suggests the SDT
use NERC-defined terms that have been industry vetted and/or defined in the NERC Glossary of Terms, and those terms used consistently. Examples
of terms that are vague, overly broad, and/or not NERC-defined include “operating personnel”, “Real-time reliability tasks”, “monitor and control” (does
the ability to “monitor” belong in the definition at all?), and “2 or more locations.”

2.
ACES requests further clarification regarding Line (5) regarding operation of a Transmission Owner’s BES Transmission Facilities in Real-time to
eliminate any confusion by small entities operating under a TOP’s jurisdictional control. ACES suggests the following alternative language:

5) “acts independently to operate or direct the operation of a Transmission Owner’s BES Transmission Facilities in Real-time.”

3.
As proposed, the Control Center definition seems to be encompassing all entities with BES Facilities, regardless of size or impact to the
BES. From a cyber-security standpoint, we understand that a cyber attacker is not going to ask permission from a TOP before performing actions on
the BES, and that NERC is trying to address that risk. However, aren’t those risks and mitigations addressed in the Low Impact CIP Requirements? Is
it NERC’s intent to pull virtually every control center and associated data center into scope? Many small entities (with no material impact to the BES)
would be brought in under the proposed definition.
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Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion, NextEra and HQ
Answer

No

Document Name
Comment
The proposed changes to the definition do not address all of the “opportunities for clarification” and may add additional areas of uncertainty. Some of
these issues are:

1) Inclusion lines 1-3, Recommend striking “perform the Real-time reliability related tasks of a:” this phrase in all locations. It is unclear how adding
“Real-time” and “related” to the existing “reliability tasks” provides any clarity. This seems to be a direct reference to the NERC Functional Model. The
Introduction to the Function Model (V5) as it includes subsections labeled “Tasks” and “Real Time”. An entity that performs the reliability tasks listed in
the Functional Model should have the appropriate Functional Registration. Adding this phrase to the inclusion lines 1 -3 does not address the issue of
“capability or authority” as it relates to “perform”. Inclusions line 1-3 should only apply to Entity with those Functional Registrations

2) Inclusion line 4, “can act independently”: The word “can” phrase does not address the issue of “capability or authority”. It is unclear how “can act”
differs from the “perform” used in lines 1-3. Does an entity meet this qualifier if a VP of Operations for a GO (and not GOP) entity can order that a unit
shut down? Recommend removing the word “can”.

3) Inclusion line 4, “specific dispatch instructions”. It is unclear how the addition of the word “specific” differentiates between different dispatch
instructions. Recommend replacing the undefined “dispatch instructions” with the NERC defined term “Operating Instruction”.

4) Inclusion line 5, “can”: The word “can” phrase does not address the issue of “capability or authority”. It is unclear how “can act” differs from the
“perform” used in lines 1-3. As written, this qualifier seems to go against the CIP-002-5.1 GTB (page 24) which states “A TO BES Cyber System in a TO
facility that does not perform or does not have an agreement with a TOP to perform any of these functional tasks does not meet the definition of a
Control Center.” Recommend 1) replacing with language that limits the scope to entities that have the capability; 2) updating the GTB language to the
new definition

5) Inclusion line 5, “two or more locations”: This qualifier does not include the “two or more locations” phrase. Without this phrase, a facility at a TO
with a single BES substation could be identified as a Control Center when “operating personnel” are present. Depending on how “hosting” is defined, all
control buildings at a TO substation could be Control Centers. Recommend adding the “two or more locations” phrase to this qualifier.

6) Exclusions line 1, “plant operators located at a generator plant site or personnel at a centrally located dispatch center who”: It is unclear if both parts
of this exclusion line applies to only generation. “generator plant site” would apply to both BES and non-BES generation. “Dispatch center” is undefined
and could include the offices that dispatches service personnel. Recommend replacing the “plant operators located at a generator plant site or
personnel at a centrally located dispatch center who” with “personnel who”.

7) Exclusion line 1, “dispatch instructions”. This term is undefined. Recommend replacing it with the NERC defined term “Operating Instruction”.

8) Recommend removing Transmission Operator and Transmission Owner from the second exclusion, because Generator personnel can also perform
field switching.

The recommendations above could result in the following definition:

One or more facilities that monitor and control the Bulk Electric System (BES) and host operating personnel, including the facilities’ associated data
centers, of a:

1) Reliability Coordinator; or
2) Balancing Authority; or
3) Transmission Operator for Transmission Facilities at two or more locations; or
4) Generator Operator that act independently to develop Operating Instructions for generation Facilities at two or more locations; or
5) Transmission Owner that have the capability to operate, in Real-time, the Transmission Owner’s Transmission Facilities, at two or more locations.

Operating personnel do not include:
1) personnel who relay Operating Instructions without making modifications; or
2) field switching personnel.
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David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

No

Document Name
Comment
Line 4, by adding the requirement that it must have the capability “to develop specific dispatch instructions”, excludes facilities that are currently
included and traditionally considered to be control centers. In the case where dispatches are received and modified or developed at a central “control
center” facility and sent to regional control centers who act on but do not modify those dispatches, those regional control centers would seem to no
longer be control centers by the proposed definition when, in fact, that is where the most sensitive, directly controlling systems (such as SCADA) reside.
These regional control centers often directly control remote, unstaffed generation Facilities directly through their BCS. A viable GOP control center
definition must consider the differences between control centers that merely co-ordinate and issue instructions (dispatches) and control centers that

directly control generating resources, such as those that have BCS that remotely control normally unstaffed generation Facilities. If both types are
intended to be included, the defining criteria must be common to both or distinguish between and specifically apply to each type.

Proposal for Line 4: a) who develop or modify dispatch instructions that are sent to either another control center or 2 or more generation facilities or b)
who have the potential to supply the final authoritative human supplied control inputs at least some of the time for 2 or more generation facilities.

Note that the suggested Line 4 above eliminates the need for Exclusion Line 1. The wording of b) would likely need to be refined, but the idea is to
capture the people who have the ability to input control inputs to operate generating resources without the need for other people’s involvement. For
example, a remote operator at a “control center” that can control the remote resource without the need for local personnel at the remote generation
resource to intercede. The existence of local operators or local control capability does not interfere with criteria b).

Line 4 - Dispatch instruction is not a defined term – suggest using the term operational instruction.
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Lynn Goldstein - PNM Resources - Public Service Company of New Mexico - 3
Answer

No

Document Name
Comment
PNM disagrees with the proposed revision to the definition of Control Center. We agree with concerns about the use of “real-time reliability tasks” as
raised by Dominion Energy, EEI, and Texas RE. We also share WECC’s concern that “including language defining what Operating personnel are not
will conflict with the purpose of COM-002-4 – Operating Personnel Communications Protocols.” We also share Texas RE’s concern that “that BES
Cyber Systems located at significant centralized GOP control locations would longer meet the Medium or High Impact criteria.”
Thus we recommend to either 1) change the criteria in CIP-002 Attachment 1 Impact Rating Criteria to achieve the desired outcome of scoping out
smaller facilities, or 2) consider Entergy’s recommended definition of Control Center and proposed term Operations Personnel.
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Laurie Williams - PNM Resources - Public Service Company of New Mexico - 1
Answer
Document Name

No

Comment
Concur with PNM-Lynn Goldstein Comments
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Kara White - NRG - NRG Energy, Inc. - 3,4,5,6 - FRCC,MRO,WECC,Texas RE,NPCC,SERC,SPP RE,RF
Answer

No

Document Name
Comment
The phrase “act independently” could be interpreted to exclude current Control Centers that act solely on direction of the ISO. NRG believes the intent
to be has the ability to control rather than act independently. NRG recommends that the verbiage be clarified.
The first exception lists plant operators at a generating plant site. This implies that plant control rooms that have the ability to start or monitor units at
other plant locations would not be considered Control Centers. NRG recommends that this should be clarified.
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Faz Kasraie - Seattle City Light - 5 - WECC
Answer

No

Document Name
Comment

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Patricia Lynch - NRG - NRG Energy, Inc. - 5,6
Answer
Document Name
Comment

No

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Joe Tarantino - Joe Tarantino On Behalf of: Arthur Starkovich, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Beth Tincher, Sacramento
Municipal Utility District, 4, 1, 5, 6, 3; Jamie Cutlip, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Kevin Smith, Balancing Authority of
Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Susan Oto, Sacramento Municipal Utility District, 4, 1,
5, 6, 3; - Joe Tarantino
Answer

Yes

Document Name
Comment

References to Real – time should be consistent with the NERC Glossary.
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Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer

Yes

Document Name
Comment
While Xcel Energy generally agrees with the proposed revisions, there is some concern with the lack of clarity in the verbiage in items #4 and #5. We
note the exception of operating personnel identified in #1 and #2 of the "Operating personnel do not include" section. However, additional clarity
provided would resolve cencerns. Xcel Energy suggests editing the language to read:
4) Has the authority to act independently as the Generator Operator to develop specific dispatch instructions for generation Facilities at two or more
locations; or
5) Has the authority to operate or direct the operation of a Transmission Owner's BES Transmission Facilities in Real-time.
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Teresa Cantwell - Lower Colorado River Authority - 1,5

Answer

Yes

Document Name
Comment
No comments.
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Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

Yes

Document Name
Comment
The SPP Standards Review Team suggests that the drafting team takes into consideration, providing some clarification for the lower case term facilities.
The defined term of Facility in the Glossary of terms focuses on electrical equipment serving as a single BES Element. However, there is some
confusion on what the lower case term facilities are applicable to. During our discussions, there were questions of could the term be referring to a
specific room in a building or is it an entire building? From our perspective, this clarity is needed to help the industry get a better understanding to meet
the expectations of the definition which helps ensure the reliability of the grid.
Additionally, we would suggest revising to #4 and #5 in the definition to read as follows:
4. Can have the authority to act independently as the Generator Operator to develop specific dispatch instructions for generation Facilities at two or
more locations; or
5. Has the authority act independently to operate or direct the operation of a Transmission Owner’s BES Transmission Facilities in Real-time.
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Brandon Gleason - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment
Consider the following revision: “(4) can act independently as the Generator Operator to develop specific dispatch instructions for generation Facilities
at two or more locations that have the ability to impact the BES;”

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Linda Jacobson-Quinn - City of Farmington - 3
Answer

Yes

Document Name
Comment

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0

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Sandra Pacheco - Silicon Valley Power - City of Santa Clara - 5
Answer

Yes

Document Name
Comment

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0

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0

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Val Ridad - Silicon Valley Power - City of Santa Clara - 3,4,5
Answer

Yes

Document Name
Comment

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0

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0

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Jeff Ipsaro - Silicon Valley Power - City of Santa Clara - 3,4,5

Answer

Yes

Document Name
Comment

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0

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0

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David Maier - Intermountain REA - 3
Answer

Yes

Document Name
Comment

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0

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0

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Kristine Ward - Seminole Electric Cooperative, Inc. - 1,3,4,5,6 - FRCC
Answer

Yes

Document Name
Comment

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0

Response

Nicholas Lauriat - Network and Security Technologies - 1
Answer

Yes

Document Name
Comment

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0

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Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment

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Aaron Austin - AEP - 3,5
Answer

Yes

Document Name
Comment

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Jeanne Kurzynowski - CMS Energy - Consumers Energy Company - 1,3,4,5 - RF
Answer

Yes

Document Name
Comment

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1

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CMS Energy - Consumers Energy Company, 4, Martinez Theresa
0

Response

Jeff Johnson - Sempra - San Diego Gas and Electric - 1,2,3,4,5,6,7,8,9 - WECC
Answer

Yes

Document Name
Comment

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Glen Farmer - Avista - Avista Corporation - 5
Answer

Yes

Document Name
Comment

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0

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Tho Tran - Tho Tran On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; - Tho Tran
Answer

Yes

Document Name
Comment

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Adrian Andreoiu - BC Hydro and Power Authority - 1,3,5 - WECC
Answer

Yes

Document Name
Comment

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0
0

Response

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 3, Group Name FirstEnergy Corporation
Answer

Yes

Document Name
Comment

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0

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0

Response

Stephanie Burns - Stephanie Burns On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Stephanie
Burns
Answer

Yes

Document Name
Comment

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0

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0

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Ellen Oswald - Midcontinent ISO, Inc. - 2
Answer

Yes

Document Name
Comment

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0

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James Anderson - CMS Energy - Consumers Energy Company - 1
Answer

Yes

Document Name
Comment

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Andrey Komissarov - Sempra - San Diego Gas and Electric - 7 - WECC
Answer

Yes

Document Name
Comment

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Eli Rivera - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

Yes

Document Name
Comment

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0

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Dmitriy Bazylyuk - NiSource - Northern Indiana Public Service Co. - 5
Answer

Yes

Document Name
Comment

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0
0

Response

John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1
Answer

Yes

Document Name
Comment

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Todd Bennett - Associated Electric Cooperative, Inc. - 3, Group Name AECI
Answer
Document Name
Comment
AECI supports comments provided by NRECA
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0

2. Control Center definition: Do the proposed revisions to the Control Center definition change the scope or intent of any current or pending
Reliability Standard(s) using the defined term (examples include Reliability Standards: COM-001-3; TOP-001-4; and IRO-002-5)? If yes,
provide details of the affected Reliability Standard(s), requirements, and any anticipated impact.
Warren Cross - ACES Power Marketing - 1,3,4,5 - MRO,Texas RE,SERC,SPP RE,RF, Group Name ACES Standards Collaborators
Answer

No

Document Name
Comment
No comments.
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Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer

No

Document Name
Comment
The term “control center” is used in other Standards as an undefined term (lower case “c”s). Specifically, in COM
‑001‑ 3,
referenced in Requirements R12 and R13, which apply to the GOP and DP functions, respectively. Both requirements specify that Interpersonal
Communication capability is required “between control centers within the same functional entity, and/or between a control center and field personnel.”
[Note that “control center” is lower case (i.e., an undefined term)]. Southern does not believe that the proposed Control Center definition change is in
controlcente
conflict with the Requirements of COM
‑001‑ 3, but the term “
In TOP
‑001‑
In the4,
context
R equirem
of these
ents Rreferences,
20, R 21, and
theRproposed
24 reference “
C
definition of Control Center does not create any concerns or conflicts provided that applicability for these Requirements is not expanded to other
functions such as GOPs because they are explicitly included in the new definition of Control Center.
In IRO
‑002‑
In the5,
context
R equirem
of these
ents Rreferences,
2 and R 3 ref
the
erence
proposed
“
C ont
definition
rolC enter”
of as
Control Center does not create any concerns or conflicts provided that the applicability for these Requirements is not expanded to other functions such
as GOPs because they are explicitly included in the new definition of Control Center.
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Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

No

Document Name
Comment
The definition of Control Center has changed substantively. Texas RE has identified 40 standard requirements that contain the term control center
(upper and lowercase). Texas RE inquires as to whether the SDT analyzed all of these requirements in order to determine the implications of the
revised definition of Control Center on other standards.
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Jack Cashin - American Public Power Association - 4
Answer

No

Document Name
Comment
COM-001-3 requires internal Interpersonal Communication capabilities between Control Centers and field personnel. It is unclear if the proposed
Control Center definition revision could be interpreted to also require these capabilities to and from the “associated data center” (the phrase used in the
current definition of Control Center. While this concern does not seem to be caused by changes in the proposed definition, clarity is needed. Possibly
this could be clarified in COM-001 guidance.
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Russell Noble - Cowlitz County PUD - 3,5
Answer

No

Document Name
Comment
Cowlitz PUD supports the comments submitted by Brian Evans-Mongeon, Utility Services Inc.
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Response

Brandon McCormick - Brandon McCormick On Behalf of: Carol Chinn, Florida Municipal Power Agency, 6, 4, 3, 5; Chris Gowder, Florida
Municipal Power Agency, 6, 4, 3, 5; David Owens, Gainesville Regional Utilities, 3, 1, 5; Ginny Beigel, City of Vero Beach, 3; Joe McKinney,

Florida Municipal Power Agency, 6, 4, 3, 5; Mike Blough, Kissimmee Utility Authority, 5, 3; Richard Montgomery, Florida Municipal Power
Agency, 6, 4, 3, 5; Tom Reedy, Florida Municipal Power Pool, 6; - Brandon McCormick, Group Name FMPA
Answer

No

Document Name
Comment
FMPA agrees with the following comments from APPA:
COM-001-3 requires internal Interpersonal Communication capabilities between Control Centers and field personnel. It is unclear if the proposed
Control Center definition revision could be interpreted to also require these capabilities to and from the “associated data center” (the phrase used in the
current definition of Control Center. While this concern does not seem to be caused by changes in the proposed definition, clarity is needed. Possibly
this could be clarified in COM-001 guidance.
Likes

0

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0

Response

Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer

No

Document Name
Comment
COM-001-3 requires internal Interpersonal Communication capabilities between Control Centers and field personnel. It is unclear if this revision could
be interpreted to require these capabilities to and from the associated data center. (The “associated data center” phrase is in the existing definition of
Control Center. This concern does not seem to be caused by changes in the proposed definition.) This may need to be clarified in guidance to COM001.
Likes

0

Dislikes

0

Response

Larry Watt - Lakeland Electric - 1
Answer

No

Document Name
Comment
COM-001-3 requires internal Interpersonal Communication capabilities between Control Centers and field personnel. It is unclear if the proposed
Control Center definition revision could be interpreted to also require these capabilities to and from the “associated data center” (the phrase used in the

current definition of Control Center. While this concern does not seem to be caused by changes in the proposed definition, clarity is needed. Possibly
this could be clarified in COM-001 guidance.
Likes

0

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0

Response

Kenya Streeter - Edison International - Southern California Edison Company - 6
Answer

No

Document Name
Comment
Please refer to comments submitted by Robert Blackney on behalf of Southern California Edison
Likes

0

Dislikes

0

Response

Thomas Breene - WEC Energy Group, Inc. - 3
Answer

No

Document Name
Comment
We support the MRO NSRF comments.
Likes

0

Dislikes

0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name
Comment
None

No

Likes

0

Dislikes

0

Response

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer

No

Document Name
Comment
City Light supports SRP comments
Likes

0

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0

Response

Kara White - NRG - NRG Energy, Inc. - 3,4,5,6 - FRCC,MRO,WECC,Texas RE,NPCC,SERC,SPP RE,RF
Answer

No

Document Name
Comment

Likes

0

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0

Response

Brandon Gleason - Electric Reliability Council of Texas, Inc. - 2
Answer

No

Document Name
Comment

Likes

0

Dislikes
Response

0

Patricia Lynch - NRG - NRG Energy, Inc. - 5,6
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Eli Rivera - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer
Document Name
Comment

No

Likes

0

Dislikes

0

Response

Nicolas Turcotte - Hydro-Qu?bec TransEnergie - 1
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Ellen Oswald - Midcontinent ISO, Inc. - 2
Answer

No

Document Name
Comment

Likes

0

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0

Response

Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer

No

Document Name
Comment

Likes

0

Dislikes
Response

0

Stephanie Burns - Stephanie Burns On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Stephanie
Burns
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Douglas Johnson - American Transmission Company, LLC - 1
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Adrian Andreoiu - BC Hydro and Power Authority - 1,3,5 - WECC
Answer
Document Name
Comment

No

Likes

0

Dislikes

0

Response

Tho Tran - Tho Tran On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; - Tho Tran
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Glen Farmer - Avista - Avista Corporation - 5
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Faz Kasraie - Seattle City Light - 5 - WECC
Answer

No

Document Name
Comment

Likes

0

Dislikes
Response

0

Jonathan Aragon - APS - Arizona Public Service Co. - 6
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Aaron Austin - AEP - 3,5
Answer

No

Document Name
Comment

Likes

0

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0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Nicholas Lauriat - Network and Security Technologies - 1
Answer
Document Name
Comment

No

Likes

0

Dislikes

0

Response

Kristine Ward - Seminole Electric Cooperative, Inc. - 1,3,4,5,6 - FRCC
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

David Maier - Intermountain REA - 3
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Jeff Ipsaro - Silicon Valley Power - City of Santa Clara - 3,4,5
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Val Ridad - Silicon Valley Power - City of Santa Clara - 3,4,5

Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Sandra Pacheco - Silicon Valley Power - City of Santa Clara - 5
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Lynn Goldstein - PNM Resources - Public Service Company of New Mexico - 3
Answer

Yes

Document Name
Comment
PNM believes that COM-001-3 is the one most likely to be affected since it is the only one with Generation Operator Control Centers in scope and that
is what the definition is trying to change.
Likes

0

Dislikes

0

Response

David Ramkalawan - Ontario Power Generation Inc. - 5
Answer
Document Name
Comment

Yes

CIP-012 and CIP-002. Facilities that are considered GOP control centers would no longer be if they do not host people who originate or modify dispatch
instructions.
Likes

0

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0

Response

Wendy Center - U.S. Bureau of Reclamation - 5
Answer

Yes

Document Name
Comment
If Reclamation’s proposed revisions are adopted, changes to the scope of COM-001-3 could be interpreted. To avoid changing the scope of COM-0013, Reclamation recommends modifying COM-001-3 to replace “Control Center” with “primary Control Center” throughout the Reliability Standard to align
COM-001-3 with TOP-001-4 and IRO-002-5.
Likes

0

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0

Response

Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6
Answer

Yes

Document Name
Comment
PacifiCorp supports MEC’s comments regarding TOP-001-4: The main impact area of this definition is in the new TOP-001-4 standard R20 that
becomes enforceable 7-1-18. If the data center definition is beyond the bricks and mortar used for the Control Room and SCADA, then redundant and
diversely routed data exchange infrastructure may be needed outside of the traditional primary Control Center facility. R.20. says: “R20. Each
Transmission Operator shall have data exchange capabilities, with redundant and diversely routed data exchange infrastructure within the Transmission
Operator's primary Control Center, for the exchange of Real-time data with its Reliability Coordinator, Balancing Authority, and the entities it has
identified it needs data from in order for it to perform its Real-time monitoring and Real-time Assessments.” Please provide additional clarity.
Likes

0

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0

Response

Terry Harbour - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1

Answer

Yes

Document Name
Comment
We support that EOP-008-2 (future enforceable) and prior versions do NOT (and should not) use the Control Center definition, but rather apply to
“control centers” for RCs, TOPs and BAs. We are not aware of plans to change that. However, Control Center first only existed in CIP standards and
has since crept into non-CIP standards. It is important that the definition revision consider what would happen to other standards, such as EOP-008, if
future revisions of EOP-008 considered adopting “Control Center” to replace “control center.”

The main impact area of this definition is in the new TOP-001-4 standard R20 that becomes enforceable 7-1-18. If the data center definition is beyond
the bricks and mortar used for the Control Room and SCADA, then redundant and diversely routed data exchange infrastructure may be needed
outside of the traditional primary Control Center facility. R.20. says: “R20. Each Transmission Operator shall have data exchange capabilities, with
redundant and diversely routed data exchange infrastructure within the Transmission Operator's primary Control Center, for the exchange of Real-time
data with its Reliability Coordinator, Balancing Authority, and the entities it has identified it needs data from in order for it to perform its Real-time
monitoring and Real-time Assessments.” Please clarify.

Likes

0

Dislikes

0

Response

Darnez Gresham - Darnez Gresham On Behalf of: Annette Johnston, Berkshire Hathaway Energy - MidAmerican Energy Co., 1, 3; - Darnez
Gresham
Answer

Yes

Document Name
Comment
We support that EOP-008-2 (future enforceable) and prior versions do NOT (and should not) use the Control Center definition, but rather apply to
“control centers” for RCs, TOPs and BAs. We are not aware of plans to change that. However, Control Center first only existed in CIP standards and
has since crept into non-CIP standards. It is important that the definition revision consider what would happen to other standards, such as EOP-008, if
future revisions of EOP-008 considered adopting “Control Center” to replace “control center.”
The main impact area of this definition is in the new TOP-001-4 standard R20 that becomes enforceable 7-1-18. If the data center definition is beyond
the bricks and mortar used for the Control Room and SCADA, then redundant and diversely routed data exchange infrastructure may be needed
outside of the traditional primary Control Center facility. R.20. says: “R20. Each Transmission Operator shall have data exchange capabilities, with
redundant and diversely routed data exchange infrastructure within the Transmission Operator's primary Control Center, for the exchange of Real-time
data with its Reliability Coordinator, Balancing Authority, and the entities it has identified it needs data from in order for it to perform its Real-time
monitoring and Real-time Assessments.” Please clarify.

Likes
Dislikes

0
0

Response

Kevin Salsbury - Berkshire Hathaway - NV Energy - 5
Answer

Yes

Document Name
Comment
The current and revised Control Center definition is actually presently impacting interpretation for TOP-001-4, Requirement 20. Without an official
definition for a data center, interpretation of the Control Center perimeter (per this Standard), may require redundant and diversely routed data
exchange infrastructure to be required outside of the traditional primary Control Center facility.
Likes

0

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0

Response

Teresa Cantwell - Lower Colorado River Authority - 1,5
Answer

Yes

Document Name
Comment
No comments.
Likes

0

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0

Response

Heather Morgan - EDP Renewables North America LLC - 5
Answer

Yes

Document Name
Comment
The NERC SDT should consider the impact on COM-001-3. With the proposed definition, many generation Control Centers (as currently defined within
the NERC Glossary) would no longer be a Control Center (with the proposed definition). With the proposed definition, many current Generator Operator
Control Centers would not have to have Interpersonal Communication “between Control Centers within the same functional entity, and/or between a
Control Center and field personnel” since they do not develop specific dispatch instructions as proposed.

Likes

0

Dislikes

0

Response

George Brown - Acciona Energy North America - 5
Answer

Yes

Document Name
Comment
Supporting the MRO NSRF's comments.
Likes

0

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0

Response

Dmitriy Bazylyuk - NiSource - Northern Indiana Public Service Co. - 5
Answer

Yes

Document Name
Comment
Within this proposed definition it appears that the SDT is interpreting who should not be included as “operating personnel”. Is this just in the
context of the Control Center definition or throughout the NERC Standards? For example would this apply to COM-002-4 Operating
Personnel Communication Protocols R1 R2 R3 R4? Maybe “operating personnel” should be defined separately.
Also, in addition to standards mentioned in this question, this proposed definition is tied to other definitions such as “Operating Instruction”
and “System Operator”. This may change the “scope or intent” of Reliability Standards which would require further review.
Likes

0

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0

Response

David Jendras - Ameren - Ameren Services - 3
Answer
Document Name
Comment

Yes

(Ditto EEI Comments):
•

COM-001-3; One scenario may be a GO could direct (verbally or through automatic schemes) a TO Facility to operate in support of a RAS.

•

COM-001-3: The proposed Control Center definition excludes field switching personnel. COM-001-3 R12 uses the Control Center definition and
includes communications between Control Centers and field personnel. Do the words of the Standard over-ride the proposed definition? The
proposed Control Center definition is in conflict with COM-001-3, R12 and will lead to uncertainty with CEAs and Applicable Entities.

•

IRO-002-5 uses the phrase “…and other entities deemed necessary…” which allows the RC to be added any entity to the RC’s Monitoring and
Analysis capabilities. No issue.

•

TOP-001-4 (effective 7/1/2018); This Standard’s Applicability section may need to be expanded if there are entities identified per the proposed
Control Center definition, such as a GO who can direct a Transmission Facility to do something to save their generator (RAS).

•

IRO-002 and TOP-001 both use the terms “primary” Control Centers in each of their applicable Requirement language. COM-001-3 uses the
term Control Center. Does the proposed definition include both primary and secondary Control Centers? If so, request that the SDT make this
statement for all Applicable Entities to understand.

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0

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0

Response

Chris Scanlon - Exelon - 1
Answer

Yes

Document Name
Comment
Yes the definition may change scope or intent of these standards, unless the added phrase “at two or more locations” is added to 5.
Likes

0

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0

Response

Barry Lawson - National Rural Electric Cooperative Association - 4
Answer
Document Name
Comment

Yes

Additional impacted standards include EOP-004-4 and EOP-008-1. To the extent the Control Center definition is revised and moves forward, it is
possible that new Control Centers will be identified or a Control Center impact rating could increase. Because of this, the proposed Implementation
Plan should be revised to provide additional time for non-CIP standard compliance impacted by the revised Control Center definition.
Likes

0

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0

Response

Julie Hall - Entergy - 6, Group Name Entergy
Answer

Yes

Document Name
Comment
Please see comments for Question 4.
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0

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0

Response

sean erickson - Western Area Power Administration - 1
Answer

Yes

Document Name
Comment
WAPA is in agreement with the comment that the term "data center" is not defined in any NERC standard or NERC documentation. The issue is how
far into the SCADA acquisition process does the data center definition penetrate. Does the data center definition penetrate into data aggregators used
to reduce communication costs that represent loss of several RTU if compromised? The main impact area of this definition is in the new TOP-001-4
standard R20 that becomes enforceable 7-1-18. If the data center definition is beyond the bricks and mortar used for the Control Room and SCADA,
then redundant and diversely routed data exchange infrastructure may be needed outside of the traditional primary Control Center facility. Please
clarify.
Likes

0

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0

Response

Steven Rueckert - Western Electricity Coordinating Council - 10
Answer

Yes

Document Name
Comment
COM-002-4
Concern that proposed definition would cause uncertainty in whether or not personnel at control centers must use three part communications. There is
evidence that a significant number of Misoperations are a result of poor communication between System Operators at control centers and the entity’s
operating personnel in the field.
Likes

0

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0

Response

Russel Mountjoy - Midwest Reliability Organization - 10, Group Name MRO NSRF
Answer

Yes

Document Name
Comment
COM-001-3; One scenario may be a GO could direct (verbally or through automatic schemes) a TO Facility to operate in support of a RAS.
COM-001-3: The proposed Control Center definition excludes field switching personnel. COM-001-3 R12 uses the Control Center definition and
includes communications between Control Centers and field personnel. Do the words of the Standard over-ride the proposed definition? The proposed
Control Center definition is in conflict with COM-001-3, R12 and will lead to uncertainty with CEAs and Applicable Entities.
IRO-002-5 uses the phrase “…and other entities deemed necessary…” which allows the RC to added any entity to the RC’s Monitoring and Analysis
capabilities. No issue.
TOP-001-4 (effective 7/1/2018); This Standard’s Applicability section may need to be expanded if there are entities identified per the proposed Control
Center definition, such as a GO who can direct a Transmission Facility to do something to save their generator (RAS).
IRO-002 and TOP-001 both use the terms “primary” Control Centers in each of their applicable Requirement language. COM-001-3 uses the term
Control Center. Does the proposed definition include both primary and secondary Control Centers? If so, request that the SDT make this statement for
all Applicable Entities to understand.
Likes

1

Dislikes

OGE Energy - Oklahoma Gas and Electric Co., 3, Hargrove Donald
0

Response

Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer
Document Name
Comment

Yes

The impacts to the non CIP Standards have not been examined at length due to the abbreviated amount of time available, but many non-CIP standards
rely on the definition of Control Center.
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0

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0

Response

Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1
Answer

Yes

Document Name
Comment
There is no choice for potentially. The unintended consequences will not be known until the auditing of standards has begun after the definition
change. The auditors, who are responsible to measure compliance performance, can have a subjective change in interpretation for applicability of
many standards. It is the duty of the Drafting Team to make a complete analysis of the existing standards to assure there is not misapplication due to
the change in definition.
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0

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0

Response

Dennis Sismaet - Northern California Power Agency - 6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Andrey Komissarov - Sempra - San Diego Gas and Electric - 7 - WECC
Answer
Document Name
Comment

Yes

Likes

0

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0

Response

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 3, Group Name FirstEnergy Corporation
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Marty Hostler - Northern California Power Agency - 5,6
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Jeff Johnson - Sempra - San Diego Gas and Electric - 1,2,3,4,5,6,7,8,9 - WECC
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Linda Jacobson-Quinn - City of Farmington - 3

Answer

Yes

Document Name
Comment

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0

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0

Response

Todd Bennett - Associated Electric Cooperative, Inc. - 3, Group Name AECI
Answer
Document Name
Comment
AECI supports comments provided by NRECA
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0

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0

Response

Joel Charlebois - AESI - Acumen Engineered Solutions International Inc. - 5
Answer
Document Name
Comment
Yes. CIP-002-5.1a impact rating criterion 2.11. See response to question #1.
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0

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0

Response

Tony Eddleman - Nebraska Public Power District - 3
Answer
Document Name
Comment

COM-001-3: The proposed Control Center definition excludes field switching personnel. COM-001-3 R12 uses the Control Center definition and
includes communications between Control Centers and field personnel. This is a Conflict with the proposed definition of Control Center.
IRO-002 and TOP-001 both use the terms “primary” Control Centers in each of their applicable Requirement language. COM-001-3 uses the term
Control Center. When one looks at proposed CIP-012-1 it is apparent in the rationale section of the Implementation Guide that Backup Control Centers
are included. Can one assume that “Control Center” used in Reliability Standards includes the Backup Control Center? Will this result in consistent
appication?
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1

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Response

Nebraska Public Power District, 5, Schmit Don
0

3. Control Center definition: The SDT contends that there will be no change in BES Cyber System categorization by clarifying the definition
of Control Center. This assertion is based on SDT review of the CIP-002-5.1a criteria and its understanding of BES Cyber System
categorization through experience implementing CIP-002-5.1a. Do you agree with this assertion? If not, please provide rationale and practical
examples of where a change in categorization will occur as a result of this modification.
Tony Eddleman - Nebraska Public Power District - 3
Answer

No

Document Name
Comment
Without knowing the boundary of a control center as discussed above in question one, it is not possible to answer this question. Will the new definition
of a control center, without a boundary as currently written, produce unintended consequences of bringing new cyber assets into CIP compliance? At a
minimum, a larger than required control center will require CIP-002 screening for BES Cyber Systems to include countless systems not intended to be
screened for entities collocated with other business functions.
Likes

1

Dislikes

Nebraska Public Power District, 5, Schmit Don
0

Response

Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1
Answer

No

Document Name
Comment
Dispatch centers of small utilities that are not categorized as Control Centers will now fall under that category. They will be categorized as low impact
facilities. It is possible that some plant control rooms will also be considered as Control Centers now because they may be responsible for local and
remote generation, or generation that is within the same campus, but not the same facility. Some large industrial sites, with their own generation, fall
under this category.
Likes

0

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0

Response

Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer
Document Name
Comment

No

It is unclear if entities with facilities not previously defined as a Control Center will now be considered a Control Center, resulting in newly categorized
BES Cyber Systems.
Likes

0

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0

Response

Kenya Streeter - Edison International - Southern California Edison Company - 6
Answer

No

Document Name
Comment
Please refer to comments submitted by Robert Blackney on behalf of Southern California Edison
Likes

0

Dislikes

0

Response

sean erickson - Western Area Power Administration - 1
Answer

No

Document Name
Comment
It is possible that the ambiguity of the language “associated data center” could result in an unintended consequence within BES Cyber System
categorization.
Likes

0

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0

Response

Stephanie Burns - Stephanie Burns On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Stephanie
Burns
Answer
Document Name
Comment

No

Language on inclusion 5 includes “direct operations” which is too vague for clear interpretation.
Likes

0

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0

Response

Barry Lawson - National Rural Electric Cooperative Association - 4
Answer

No

Document Name
Comment
There are an unknown number of scenarios where the BES Cyber System impact rating/categorization could be impacted. Because of the potential
impacts to non-CIP standards, the proposed Implementation Plan should be revised to provide additional time for non-CIP standard compliance
impacted by the revised Control Center definition.
Likes

0

Dislikes

0

Response

David Jendras - Ameren - Ameren Services - 3
Answer

No

Document Name
Comment
Clarification needs to be added around "associated data center" and whether it is included due to its relationship in support the Control Center or
because it contains operating personnel/System Operators (obviously, the former).
Likes

0

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0

Response

George Brown - Acciona Energy North America - 5
Answer
Document Name
Comment

No

From a Generator Operator perspective the proposed definition of Control Center does not.
Likes

0

Dislikes

0

Response

Heather Morgan - EDP Renewables North America LLC - 5
Answer

No

Document Name
Comment
The current interpretation of the proposed definition as it relates to Generator Operators will impact not only NERC CIP Standards, but Operations and
Planning Standards as well. With respect to CIP Standards, there are numerous generation control centers that do not develop specific dispatch
instructions. Due to this, the proposed definition would impact the classification of BES Cyber Systems as required in CIP-002. Furthermore, generation
control centers with more than 1,500 MW in one or more Interconnection(s) would be able to easily revise operating protocols to ensure the entity never
reaches the criteria to be classified as a Medium Impact BES Cyber Systems as defined with CIP-002. This loophole would not support the reliability of
the Bulk Electric System.
Furthermore, current Low Impact BES Cyber System Control Centers that do not “develop specific dispatch instructions,” will no longer have a Low
Impact BES Cyber System Control Center with the proposed changes.
Likes

0

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0

Response

Kevin Salsbury - Berkshire Hathaway - NV Energy - 5
Answer

No

Document Name
Comment
NV Energy does not recognize an impact for its facilities, but the fact that additional criteria have been added to define a Control Center, there is an
opportunity than an Entity will now have facilities that were not previously identified as a Control Center, now in scope of the Impact Criterion.
Likes

0

Dislikes
Response

0

Darnez Gresham - Darnez Gresham On Behalf of: Annette Johnston, Berkshire Hathaway Energy - MidAmerican Energy Co., 1, 3; - Darnez
Gresham
Answer

No

Document Name
Comment
We have had confidence on what in version 5 are our high and medium impact Control Centers. Depending on the revised Control Center definition, low
impact Control Centers could be in doubt. Refer to concerns with the definition.
Likes

0

Dislikes

0

Response

Terry Harbour - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1
Answer

No

Document Name
Comment
We have had confidence on what in version 5 are our high and medium impact Control Centers. Depending on the revised Control Center definition, low
impact Control Centers could be in doubt. Refer to concerns with the definition.
Likes

0

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0

Response

Warren Cross - ACES Power Marketing - 1,3,4,5 - MRO,Texas RE,SERC,SPP RE,RF, Group Name ACES Standards Collaborators
Answer

No

Document Name
Comment
It does not change the criteria used in CIP-00205.1a but it does influence the entity if they are now ruled a Control Center. If so, then that new Control
Center should have time to reevaluate their BES Cyber System categorization process and update their documentation.
Likes

0

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Response

0

Kara White - NRG - NRG Energy, Inc. - 3,4,5,6 - FRCC,MRO,WECC,Texas RE,NPCC,SERC,SPP RE,RF
Answer

No

Document Name
Comment
Please see NRG comment to Question number 1.
Likes

0

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0

Response

Faz Kasraie - Seattle City Light - 5 - WECC
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Patricia Lynch - NRG - NRG Energy, Inc. - 5,6
Answer
Document Name
Comment

No

Likes

0

Dislikes

0

Response

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer

Yes

Document Name
Comment
City Light supports SRP comments
Likes

0

Dislikes

0

Response

Peter Yost - Con Ed - Consolidated Edison Co. of New York - 3
Answer

Yes

Document Name
Comment
Supporting comments from NPCC
Likes

0

Dislikes

0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
None
Likes

0

Dislikes

0

Response

Julie Hall - Entergy - 6, Group Name Entergy
Answer

Yes

Document Name
Comment
Please see comments for Question 4.
Likes

0

Dislikes

0

Response

Brandon McCormick - Brandon McCormick On Behalf of: Carol Chinn, Florida Municipal Power Agency, 6, 4, 3, 5; Chris Gowder, Florida
Municipal Power Agency, 6, 4, 3, 5; David Owens, Gainesville Regional Utilities, 3, 1, 5; Ginny Beigel, City of Vero Beach, 3; Joe McKinney,
Florida Municipal Power Agency, 6, 4, 3, 5; Mike Blough, Kissimmee Utility Authority, 5, 3; Richard Montgomery, Florida Municipal Power
Agency, 6, 4, 3, 5; Tom Reedy, Florida Municipal Power Pool, 6; - Brandon McCormick, Group Name FMPA
Answer

Yes

Document Name
Comment
No comment
Likes

0

Dislikes

0

Response

Russell Noble - Cowlitz County PUD - 3,5
Answer

Yes

Document Name
Comment
Cowlitz PUD supports the comments submitted by Brian Evans-Mongeon, Utility Services Inc.
Likes

0

Dislikes

0

Response

Teresa Cantwell - Lower Colorado River Authority - 1,5
Answer

Yes

Document Name
Comment
No comments.
Likes

0

Dislikes

0

Response

Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer

Yes

Document Name
Comment
Southern does not foresee this change altering our categorization of existing BES Cyber Assets.
Likes

0

Dislikes

0

Response

Linda Jacobson-Quinn - City of Farmington - 3
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Sandra Pacheco - Silicon Valley Power - City of Santa Clara - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Val Ridad - Silicon Valley Power - City of Santa Clara - 3,4,5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Jeff Ipsaro - Silicon Valley Power - City of Santa Clara - 3,4,5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

David Maier - Intermountain REA - 3
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

Kristine Ward - Seminole Electric Cooperative, Inc. - 1,3,4,5,6 - FRCC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Nicholas Lauriat - Network and Security Technologies - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Aaron Austin - AEP - 3,5

Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Steven Rueckert - Western Electricity Coordinating Council - 10
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Jonathan Aragon - APS - Arizona Public Service Co. - 6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Jeanne Kurzynowski - CMS Energy - Consumers Energy Company - 1,3,4,5 - RF
Answer

Yes

Document Name
Comment

Likes

1

CMS Energy - Consumers Energy Company, 4, Martinez Theresa

Dislikes

0

Response

Jeff Johnson - Sempra - San Diego Gas and Electric - 1,2,3,4,5,6,7,8,9 - WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Glen Farmer - Avista - Avista Corporation - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Tho Tran - Tho Tran On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; - Tho Tran
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Adrian Andreoiu - BC Hydro and Power Authority - 1,3,5 - WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Marty Hostler - Northern California Power Agency - 5,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Douglas Johnson - American Transmission Company, LLC - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 3, Group Name FirstEnergy Corporation
Answer

Yes

Document Name
Comment

Likes
Dislikes

0
0

Response

Larry Watt - Lakeland Electric - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Chris Scanlon - Exelon - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer
Document Name

Yes

Comment

Likes

0

Dislikes

0

Response

Ellen Oswald - Midcontinent ISO, Inc. - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

James Anderson - CMS Energy - Consumers Energy Company - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Andrey Komissarov - Sempra - San Diego Gas and Electric - 7 - WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Dennis Sismaet - Northern California Power Agency - 6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Nicolas Turcotte - Hydro-Qu?bec TransEnergie - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Eli Rivera - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Dmitriy Bazylyuk - NiSource - Northern Indiana Public Service Co. - 5
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Jack Cashin - American Public Power Association - 4
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Wendy Center - U.S. Bureau of Reclamation - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion, NextEra and HQ
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

Brandon Gleason - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Russel Mountjoy - Midwest Reliability Organization - 10, Group Name MRO NSRF
Answer
Document Name
Comment
The NSRF cannot answer this question as we do not know the configuration within every member of NERC. Please see the second paragraph to
question 1.
Likes

1

Dislikes

OGE Energy - Oklahoma Gas and Electric Co., 3, Hargrove Donald
0

Response

Joel Charlebois - AESI - Acumen Engineered Solutions International Inc. - 5
Answer
Document Name
Comment
No. CIP-002-5.1a impact rating criterion 2.11. See response to question #1.
Likes
Dislikes

0
0

Response

Thomas Breene - WEC Energy Group, Inc. - 3
Answer
Document Name
Comment
We support the MRO NSRF comments.
Likes

0

Dislikes

0

Response

Todd Bennett - Associated Electric Cooperative, Inc. - 3, Group Name AECI
Answer
Document Name
Comment
AECI supports comments provided by NRECA
Likes

0

Dislikes

0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Please see Texas RE’s response to #1.
Likes

0

Dislikes
Response

0

4. Control Center definition: Is there a scenario where a Control Center hosts both the inclusion personnel and the exclusion personnel? If
yes, please provide them here.
Heather Morgan - EDP Renewables North America LLC - 5
Answer

No

Document Name
Comment
EDPR NA is not aware of the scenario ocnsisting of both inclusion and exclusion personnel.
Likes

0

Dislikes

0

Response

George Brown - Acciona Energy North America - 5
Answer

No

Document Name
Comment
Supporting the MRO NSRF's comments.
Likes

0

Dislikes

0

Response

Kenya Streeter - Edison International - Southern California Edison Company - 6
Answer

No

Document Name
Comment
Please refer to comments submitted by Robert Blackney on behalf of Southern California Edison
Likes

0

Dislikes
Response

0

Kara White - NRG - NRG Energy, Inc. - 3,4,5,6 - FRCC,MRO,WECC,Texas RE,NPCC,SERC,SPP RE,RF
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Brandon Gleason - Electric Reliability Council of Texas, Inc. - 2
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Patricia Lynch - NRG - NRG Energy, Inc. - 5,6
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer
Document Name
Comment

No

Likes

0

Dislikes

0

Response

David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Wendy Center - U.S. Bureau of Reclamation - 5
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Kevin Salsbury - Berkshire Hathaway - NV Energy - 5

Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Eli Rivera - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Dennis Sismaet - Northern California Power Agency - 6
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

David Jendras - Ameren - Ameren Services - 3
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Ellen Oswald - Midcontinent ISO, Inc. - 2
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Chris Scanlon - Exelon - 1
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Stephanie Burns - Stephanie Burns On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Stephanie
Burns

Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Douglas Johnson - American Transmission Company, LLC - 1
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

sean erickson - Western Area Power Administration - 1
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Marty Hostler - Northern California Power Agency - 5,6
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Adrian Andreoiu - BC Hydro and Power Authority - 1,3,5 - WECC
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Tho Tran - Tho Tran On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; - Tho Tran
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Glen Farmer - Avista - Avista Corporation - 5
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Faz Kasraie - Seattle City Light - 5 - WECC
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Jeff Johnson - Sempra - San Diego Gas and Electric - 1,2,3,4,5,6,7,8,9 - WECC
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Jonathan Aragon - APS - Arizona Public Service Co. - 6
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer

No

Document Name
Comment

Likes
Dislikes

0
0

Response

Joe Tarantino - Joe Tarantino On Behalf of: Arthur Starkovich, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Beth Tincher, Sacramento
Municipal Utility District, 4, 1, 5, 6, 3; Jamie Cutlip, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Kevin Smith, Balancing Authority of
Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Susan Oto, Sacramento Municipal Utility District, 4, 1,
5, 6, 3; - Joe Tarantino
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

David Maier - Intermountain REA - 3
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Jeff Ipsaro - Silicon Valley Power - City of Santa Clara - 3,4,5
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Val Ridad - Silicon Valley Power - City of Santa Clara - 3,4,5

Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion, NextEra and HQ
Answer

Yes

Document Name
Comment
Unless modified to limit to two or more locations, the inclusion qualifier 5 could include control building within a substation.

For small locations, one person may fulfill both roles (at different times)
Likes

0

Dislikes

0

Response

Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer

Yes

Document Name
Comment
Please see the comments provided under question 1 for examples of possible inclusion/exclusion conflicts. Southern Company believes there are
situations that exist where there is the potential to have an inclusion / exclusion conflict for business units that may partially meet an inclusion and
exclusion at the same time.
For example, Southern Company has a centrally located dispatch center that develops specific dispatch instructions for economics under the
constraints of reliability as determined by the BA and RC, and reliability dispatch instructions from the BA and RC are relayed through the dispatch
center without making modifications. The use of “develop dispatch instructions” versus using the NERC defined term “Operating Instruction” may create
confusion and ambiguity regarding applicability.

Likes

0

Dislikes

0

Response

Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6
Answer

Yes

Document Name
Comment
One example as suggested above, without adding an exclusion for Information Technology and Operational Technology personnel allows for them to
perform their tasks related to their job descriptions without limiting the number of locations that they can be connected and communicating to at any
given time, or inadvertently including them as operating personnel should they occupy a desk in a Control Center or associated data center.
Likes

0

Dislikes

0

Response

Jack Cashin - American Public Power Association - 4
Answer

Yes

Document Name
Comment
It may be possible for a single person to fit both operating personnel revised definition, as well as the definition of excluded personnel, but at different
times. This can happen at smaller organizations where individuals perform multiple roles.

It is also possible for management or engineering staff to be identified as operating personnel due to their qualifications, while not actually performing
the operator function.

Likes

0

Dislikes

0

Response

Terry Harbour - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1
Answer

Yes

Document Name
Comment
One example could be GOP inclusion personnel located at a plant site where there are also excluded unit operators.
Likes

0

Dislikes

0

Response

Darnez Gresham - Darnez Gresham On Behalf of: Annette Johnston, Berkshire Hathaway Energy - MidAmerican Energy Co., 1, 3; - Darnez
Gresham
Answer

Yes

Document Name
Comment
One example could be GOP inclusion personnel located at a plant site where there are also excluded unit operators.
Likes

0

Dislikes

0

Response

Teresa Cantwell - Lower Colorado River Authority - 1,5
Answer

Yes

Document Name
Comment
No comments.
Likes

0

Dislikes

0

Response

Dmitriy Bazylyuk - NiSource - Northern Indiana Public Service Co. - 5
Answer
Document Name
Comment

Yes

During the Loss of Primary Control Center Event (Real or Test), Dispatch Operator (TO) at Back Up Control Center (BUCC) may act as a TOP
while Transmission System Supervisors (TOP) are in transit to the BUCC.
Likes

0

Dislikes

0

Response

Nicolas Turcotte - Hydro-Qu?bec TransEnergie - 1
Answer

Yes

Document Name
Comment
We support the following RSC comment : Unless modified to limit to two or more locations, the inclusion qualifier 5 could include control building within
a substation.
For small locations, one person may fulfill both roles (at different times)
Likes

0

Dislikes

0

Response

Russell Noble - Cowlitz County PUD - 3,5
Answer

Yes

Document Name
Comment
Cowlitz PUD supports the comments submitted by Brian Evans-Mongeon, Utility Services Inc.
Likes

0

Dislikes

0

Response

Brandon McCormick - Brandon McCormick On Behalf of: Carol Chinn, Florida Municipal Power Agency, 6, 4, 3, 5; Chris Gowder, Florida
Municipal Power Agency, 6, 4, 3, 5; David Owens, Gainesville Regional Utilities, 3, 1, 5; Ginny Beigel, City of Vero Beach, 3; Joe McKinney,
Florida Municipal Power Agency, 6, 4, 3, 5; Mike Blough, Kissimmee Utility Authority, 5, 3; Richard Montgomery, Florida Municipal Power
Agency, 6, 4, 3, 5; Tom Reedy, Florida Municipal Power Pool, 6; - Brandon McCormick, Group Name FMPA
Answer

Yes

Document Name
Comment
FMPA agrees with the following comments from APPA:
It may be possible for a single person to fit both operating personnel revised definition, as well as the definition of excluded personnel, but at different
times. This can happen at smaller organizations where individuals perform multiple roles.
It is also possible for management or engineering staff to be identified as operating personnel due to their qualifications, while not actually performing
the operator function.
Likes

0

Dislikes

0

Response

Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment
It may be possible for a single person to fulfil both roles, maybe at different times. This may be more likely to occur in smaller organizations where
individuals perform multiple roles.
Management or engineering staff may also be identified as operating personnel when qualified to, but not performing the operator function.
Likes

0

Dislikes

0

Response

Julie Hall - Entergy - 6, Group Name Entergy
Answer

Yes

Document Name
Comment
The operation of a Transmission Owner breaker may be shared between the Transmission Operator and Generator Operator not centrally
dispatched. In such a case, the shared breaker(s) may exist on a ring bus where there is no separate breaker to isolate the generator Facility from the
ring bus, or a similar scenario involving a breaker and a half scheme. The use of the undefined term “plant operator” does not exclude the Generator
Operator from operating a Transmission Owner breaker. The same situation may occur with distribution customers, retail or commercial, which may
have the ability to operate a Transmission Owner breaker due to not having separate isolation equipment.

NOTE: Typically a Generator Operator which has a need to operate the shared Transmission Owner breaker will submit an outage request to the
Balancing Authority, Reliability Coordinator, and/or Transmission Operator. Unsure about distribution customer outages.
Likes

0

Dislikes

0

Response

Larry Watt - Lakeland Electric - 1
Answer

Yes

Document Name
Comment
It may be possible for a single person to fit both operating personnel revised definition, as well as the definition of excluded personnel, but at different
times. This can happen at smaller organizations where individuals perform multiple roles.
It is also possible for management or engineering staff to be identified as operating personnel due to their qualifications, while not actually performing
the operator function.
Likes

0

Dislikes

0

Response

Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment
Has the drafting team considered a scenario in which there could be two separate facilities that could both potentially fall under the proposed definition,
that are housed inside the same Physical Security Perimeter (PSP)? With both facilities being inside the same PSP, would this be considered to be one
Control Center or two separate Control Centers?
Likes

0

Dislikes

0

Response

Thomas Breene - WEC Energy Group, Inc. - 3
Answer
Document Name

Yes

Comment
We support the MRO NSRF comments.
Likes

0

Dislikes

0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
BPA believes the current language in the exclusion section isn’t clear enough to determine whether personnel can fall within both inclusion and
exclusion. Based on current language, it is unclear whether personnel at a centrally located dispatch center could fall within both inclusion and
exclusion.
Likes

0

Dislikes

0

Response

Peter Yost - Con Ed - Consolidated Edison Co. of New York - 3
Answer

Yes

Document Name
Comment
Supporting comments from NPCC
Likes

0

Dislikes

0

Response

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer
Document Name
Comment

Yes

City Light supports SRP comments
Likes

0

Dislikes

0

Response

Russel Mountjoy - Midwest Reliability Organization - 10, Group Name MRO NSRF
Answer

Yes

Document Name
Comment
There may be an Entity who is vertically integrated and host those Functions in separate locations due to their apparent size.
Likes

0

Dislikes

0

Response

Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer

Yes

Document Name
Comment
Yes, but it appears that even if there are any inclusion personnel it doesn’t matter if there are any exclusion personnel because by definition it’s a
Control Center.
Likes

0

Dislikes

0

Response

Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1
Answer

Yes

Document Name
Comment
By Agreement with our TOP, during emergency conditions we have staff that potentially can meet the included staff for "...operat[ing] or direct[ing] the
operation of a Transmission Owner’s BES Transmission Facilities in Realtime." Under Normal conditions we have "...plant operators located at a

generator plant site or personnel at a centrally located dispatch center who relay dispatch instructions without making any modifications."

Likes

0

Dislikes

0

Response

Aaron Austin - AEP - 3,5
Answer

Yes

Document Name
Comment
Potentially yes, but AEP is not aware of any specific instances. The words of the definition could be changed to only exclude if there are no inclusions
to get ahead of any possible issues. AEP suggests the SDT change the definition as follows: “Operating personnel do not include if they are the only
operating personnel located at the asset:”
Likes

0

Dislikes

0

Response

Sandra Pacheco - Silicon Valley Power - City of Santa Clara - 5
Answer

Yes

Document Name
Comment
Erroneous Response: I would like to change my answer from Yes to No.
Likes

0

Dislikes

0

Response

Andrey Komissarov - Sempra - San Diego Gas and Electric - 7 - WECC
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 3, Group Name FirstEnergy Corporation
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Linda Jacobson-Quinn - City of Farmington - 3
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Warren Cross - ACES Power Marketing - 1,3,4,5 - MRO,Texas RE,SERC,SPP RE,RF, Group Name ACES Standards Collaborators
Answer
Document Name
Comment
No comment.
Likes

0

Dislikes
Response

0

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Please see Texas RE’s response to #1.
Likes

0

Dislikes

0

Response

Todd Bennett - Associated Electric Cooperative, Inc. - 3, Group Name AECI
Answer
Document Name
Comment
AECI supports comments provided by NRECA
Likes

0

Dislikes

0

Response

Joel Charlebois - AESI - Acumen Engineered Solutions International Inc. - 5
Answer
Document Name
Comment
Yes.
For GOP Control Centers, there may be operating personnel who can develop specific dispatch instructions for generation Facilities at two or more
locations as part of their job function, and other operating personnel who simply operate (start/stop/etc) or relay the developed dispatch instructions.
Likes

0

Dislikes
Response

0

5. Implementation Plan: The new Control Center definition will become effective on the first day of the first calendar quarter that is three (3)
calendar months after the effective date of the applicable governmental authority’s order approving the term, or as otherwise provided for by
the applicable governmental authority. Do you agree that three calendar months is enough time to update documentation? If you do not
agree, please provide the amount of time needed and types of actions that will need to be completed during this time.
Leonard Kula - Independent Electricity System Operator - 2
Answer

No

Document Name
Comment
The IESO submits that the implimentation plan should allow an RE to update its documentation during its regular review cycle. This will help avoid
duplication of effort. It should also consider any potentially significant changes required for Control Center physical and logical changes to occur within
budget cycles.
Likes

0

Dislikes

0

Response

Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1
Answer

No

Document Name
Comment
In some cases there may be a need to implement security measures not considered prior to the reclassification. Depending on the budget period and
cycle, these would be unbudgeted and may take up to a year to complete.
Likes

0

Dislikes

0

Response

Russel Mountjoy - Midwest Reliability Organization - 10, Group Name MRO NSRF
Answer

No

Document Name
Comment
For those entities that may need to start some programs from scratch, they will need more time. Recommend that the Implementation time line be
pushed to 12 months.

Likes

0

Dislikes

0

Response

Jeanne Kurzynowski - CMS Energy - Consumers Energy Company - 1,3,4,5 - RF
Answer

No

Document Name
Comment
If the definition is a defined term being used by multiple reliability standards, 18 calendar months will be more appropriate to implement the revised
definition.
Likes

1

Dislikes

CMS Energy - Consumers Energy Company, 4, Martinez Theresa
0

Response

ALAN ADAMSON - New York State Reliability Council - 10
Answer

No

Document Name
Comment
The Implementation Plan does not allow enough time to bring newly-identified Control Centers into compliance.
Likes

0

Dislikes

0

Response

Peter Yost - Con Ed - Consolidated Edison Co. of New York - 3
Answer

No

Document Name
Comment
Supporting comments from NPCC.
Likes
Dislikes

0
0

Response

Thomas Breene - WEC Energy Group, Inc. - 3
Answer

No

Document Name
Comment
We do not believe the definition can be implemented as proposed and hesitate to suggest an alternative timeframe until we see a revised definition
however 12 months may be more appropriate than 3 months.
Likes

0

Dislikes

0

Response

Kenya Streeter - Edison International - Southern California Edison Company - 6
Answer

No

Document Name
Comment
Please refer to comments submitted by Robert Blackney on behalf of Southern California Edison
Likes

0

Dislikes

0

Response

sean erickson - Western Area Power Administration - 1
Answer

No

Document Name
Comment
WAPA agrees with the NSRF comment that for those entities that may need to start some programs from scratch, they will need more
time. Recommend that the Implementation time line be pushed to 12 months.
Likes

0

Dislikes
Response

0

Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

No

Document Name
Comment
Duke Energy disagrees with the proposed Implementation Plan of three (3) calendar months. The change to the definition of Control Center would
necessitate a review of all internal procedures in which it is referenced to determine if said procedure would need to be updated. The review and
analysis, coupled with the training that would be necessary if changes to a procedure were implemented would take much longer than three months.
Duke Energy recommends an Implementation Plan of twelve (12) months. This would give industry enough time to do internal reviews, make changes
where necessary, and train on said changes prior to the new definition going into effect.
Likes

0

Dislikes

0

Response

Stephanie Burns - Stephanie Burns On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Stephanie
Burns
Answer

No

Document Name
Comment
See EEI Comments.
Likes

0

Dislikes

0

Response

Larry Watt - Lakeland Electric - 1
Answer

No

Document Name
Comment
Three months should be acceptable if implementation of the revised definition does not result in the identification of a new Control Center. It should be
made clear that identification of a new Control Center would be an “unplanned change” and therefore provide an additional one or two years to meet the
requirements.
Likes

0

Dislikes

0

Response

Julie Hall - Entergy - 6, Group Name Entergy
Answer

No

Document Name
Comment
The three (3) calendar months would not allow enough time to make the needed procedure updates. Recommend six (6) calendar months.

Likes

0

Dislikes

0

Response

Barry Lawson - National Rural Electric Cooperative Association - 4
Answer

No

Document Name
Comment
While the Implementation Plan for CIP standard compliance, coupled with the proposed Planned and Unplanned Changes language in the proposed
CIP-002-6, is adequate, the Implementation Plan needs to be changed for non-CIP standard compliance. NRECA strongly recommends that language
and timeframes similar to the Planned and Unplanned Changes language should be added to the Implementation Plan for non-CIP standards
compliance. Without this change, registered entities will only have a little more than three months to be in compliance with non-CIP standards that
include the defined term Control Center in the standard/requirement language.
Likes

0

Dislikes

0

Response

David Jendras - Ameren - Ameren Services - 3
Answer

No

Document Name
Comment
If the changes needed to demonstrate compliance with this change amounts to more than a simple document change then there needs to be additional
time to accommodate the changes. We would suggest 12 months for implementation.

Likes

0

Dislikes

0

Response

James Anderson - CMS Energy - Consumers Energy Company - 1
Answer

No

Document Name
Comment
If the definition is a defined term being used by multiple reliability standards, 18 calendar months will be more appropriate to implement the revised
definition.
Likes

0

Dislikes

0

Response

Nicolas Turcotte - Hydro-Qu?bec TransEnergie - 1
Answer

No

Document Name
Comment
We support the following RSC comment : It should be made clear that this new identification would be an “unplanned change” and allow for the
additional one or two years for implementation as proposed in the CIP-002 revisions.
The Implementation Plan should state that any facilities that are newly identified as Control Centers as a result of the revised definition will have 24
months to meet newly applicable compliance requirements that apply to those Control Centers.The Implementation plan should allow an RE to update
its documentation during its regular review cycle. This will help avoid duplication of effort. It should also consider any potentially significant changes
required for Control Center physical and logical changes to occur within budget cycles.
Likes

0

Dislikes

0

Response

Dmitriy Bazylyuk - NiSource - Northern Indiana Public Service Co. - 5
Answer
Document Name
Comment

No

The changes would likely take more time than 3 months to implement. 12 calendar months would be reasonable to make sure the processes
and documentation are ready.

Likes

0

Dislikes

0

Response

George Brown - Acciona Energy North America - 5
Answer

No

Document Name
Comment
Supporting the MRO NSRF's comments.
Likes

0

Dislikes

0

Response

Heather Morgan - EDP Renewables North America LLC - 5
Answer

No

Document Name
Comment
Due to the proposed definition of “Control Center” and its impact to numerous NERC Standards, longer time should be given to allow Registered
Entities appropriate time to reevaluate CIP-002 as well as several other NERC Standards.

Likes

0

Dislikes

0

Response

Kevin Salsbury - Berkshire Hathaway - NV Energy - 5
Answer
Document Name

No

Comment
The questions relies on the revision of the definition only required administrative work associated with documentation. There is a concern that the
revised definition will place equipment and/or facilities within scope of Standards that were previously not addressing the equipment and/or facility.
Likes

0

Dislikes

0

Response

Darnez Gresham - Darnez Gresham On Behalf of: Annette Johnston, Berkshire Hathaway Energy - MidAmerican Energy Co., 1, 3; - Darnez
Gresham
Answer

No

Document Name
Comment
Until the scope of the revised definition is concrete, there isn’t certainty in how long it could take to implement changes, if there are any.
Likes

0

Dislikes

0

Response

Terry Harbour - Berkshire Hathaway Energy - MidAmerican Energy Co. - 1
Answer

No

Document Name
Comment
Until the scope of the revised definition is concrete, there isn’t certainty in how long it could take to implement changes, if there are any.

Likes

0

Dislikes

0

Response

Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6
Answer
Document Name

No

Comment
Until the scope of the revised definition is concrete, there isn’t certainty in how long it could take to implement changes, if there are any.
Likes

0

Dislikes

0

Response

Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer

No

Document Name
Comment
Southern Company feels that 12 months is a more reasonable timeframe for implementation if Order 693 facilities are impacted by this change or if an
entity is required to start a program from the ground up.

Likes

0

Dislikes

0

Response

Wendy Center - U.S. Bureau of Reclamation - 5
Answer

No

Document Name
Comment
Reclamation recommends the new Control Center definition become effective on the first day of the first calendar quarter that is eighteen (18) calendar
months after the effective date of the applicable governmental authority’s order approving the definition to allow entities time to evaluate the impact of
the changes effected by the new definition and implement an appropriate response. This will allow registered entities time to evaluate the impact of the
new definition on their facilities and determine any necessary changes.

Likes

0

Dislikes
Response

0

Warren Cross - ACES Power Marketing - 1,3,4,5 - MRO,Texas RE,SERC,SPP RE,RF, Group Name ACES Standards Collaborators
Answer

No

Document Name
Comment
For those entities now considered a Control Center and not a Control Room, we recommend that the Implementation time line be 18 months.
Likes

0

Dislikes

0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion, NextEra and HQ
Answer

No

Document Name
Comment
It should be made clear that this new identification would be an “unplanned change” and allow for the additional one or two years for implementation as
proposed in the CIP-002 revisions.

The Implementation Plan should state that any facilities that are newly identified as Control Centers as a result of the revised definition will have 24
months to meet newly applicable compliance requirements that apply to those Control Centers.

The Implementation plan should allow an RE to update its documentation during its regular review cycle. This will help avoid duplication of effort. It
should also consider any potentially significant changes required for Control Center physical and logical changes to occur within budget cycles.
Likes

0

Dislikes

0

Response

David Ramkalawan - Ontario Power Generation Inc. - 5
Answer
Document Name
Comment

No

If the new definition will bring new Control Centers into the scope of CIP Compliance then the three calendar months are not enough to complete all the
activities required for compliance.
Likes

0

Dislikes

0

Response

Lynn Goldstein - PNM Resources - Public Service Company of New Mexico - 3
Answer

No

Document Name
Comment
PNM agrees with EEI’s 12 month proposal/comments.
Likes

0

Dislikes

0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

No

Document Name
Comment
The SPP Standards Review Group feels that this isn’t enough time to get everything implemented. We suggest one year (1) in the event that an entity
needs to get an unidentified Control Center into compliance.
Likes

0

Dislikes

0

Response

Brandon Gleason - Electric Reliability Council of Texas, Inc. - 2
Answer
Document Name
Comment

No

Based on significance of possibly changing the impact rating of a BES asset, this should take place on an implementation timeline that allows sufficient
time for entities to verify their compliance with the operations and planning standards noted. The implementation and enforcement timelines for CIP-002
have been addressed, but the timeline for the other non-CIP standards has not been addressed.
Likes

0

Dislikes

0

Response

Faz Kasraie - Seattle City Light - 5 - WECC
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Patricia Lynch - NRG - NRG Energy, Inc. - 5,6
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Kara White - NRG - NRG Energy, Inc. - 3,4,5,6 - FRCC,MRO,WECC,Texas RE,NPCC,SERC,SPP RE,RF
Answer

No

Document Name
Comment

Likes
Dislikes

0
0

Response

Aaron Austin - AEP - 3,5
Answer

Yes

Document Name
Comment
Knowing that the FERC will determine the effective dates, AEP believes the Implementation Plans for the revised Control Center definition and
proposed CIP-002-6 should be synchronized so the transition is less impactful.

Likes

0

Dislikes

0

Response

Jonathan Aragon - APS - Arizona Public Service Co. - 6
Answer

Yes

Document Name
Comment
AZPS agrees with the exception to the initial implementation of CIP-002-6 as set forth in “Implementation Plan”.
Likes

0

Dislikes

0

Response

Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer

Yes

Document Name
Comment
City Light supports SRP comments
Likes
Dislikes

0
0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
None
Likes

0

Dislikes

0

Response

Chris Scanlon - Exelon - 1
Answer

Yes

Document Name
Comment
Yes, if the language is adjusted in 5. to add “at two or more locations.”
Likes

0

Dislikes

0

Response

Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment
Three months would be acceptable if the definition does not result in the new identification of a Control Center. It should be made clear that this new
identification would be an “unplanned change” and allow for the additional one or two years for implementation.
Likes

0

Dislikes
Response

0

Brandon McCormick - Brandon McCormick On Behalf of: Carol Chinn, Florida Municipal Power Agency, 6, 4, 3, 5; Chris Gowder, Florida
Municipal Power Agency, 6, 4, 3, 5; David Owens, Gainesville Regional Utilities, 3, 1, 5; Ginny Beigel, City of Vero Beach, 3; Joe McKinney,
Florida Municipal Power Agency, 6, 4, 3, 5; Mike Blough, Kissimmee Utility Authority, 5, 3; Richard Montgomery, Florida Municipal Power
Agency, 6, 4, 3, 5; Tom Reedy, Florida Municipal Power Pool, 6; - Brandon McCormick, Group Name FMPA
Answer

Yes

Document Name
Comment
FMPA agrees with the following comments from APPA:
Three months should be acceptable if implementation of the revised definition does not result in the identification of a new Control Center. It should be
made clear that identification of a new Control Center would be an “unplanned change” and therefore provide an additional one or two years to meet the
requirements
Likes

0

Dislikes

0

Response

Russell Noble - Cowlitz County PUD - 3,5
Answer

Yes

Document Name
Comment
Cowlitz PUD supports the comments submitted by Brian Evans-Mongeon, Utility Services Inc.
Likes

0

Dislikes

0

Response

Teresa Cantwell - Lower Colorado River Authority - 1,5
Answer

Yes

Document Name
Comment
No comments.
Likes
Dislikes

0
0

Response

Jack Cashin - American Public Power Association - 4
Answer

Yes

Document Name
Comment
Three months should be acceptable if implementation of the revised definition does not result in the identification of a new Control Center. It should be
made clear that identification of a new Control Center would be an “unplanned change” and therefore provide an additional one or two years to meet the
requirements.
Likes

0

Dislikes

0

Response

Linda Jacobson-Quinn - City of Farmington - 3
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Sandra Pacheco - Silicon Valley Power - City of Santa Clara - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Val Ridad - Silicon Valley Power - City of Santa Clara - 3,4,5

Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Jeff Ipsaro - Silicon Valley Power - City of Santa Clara - 3,4,5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

David Maier - Intermountain REA - 3
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Kristine Ward - Seminole Electric Cooperative, Inc. - 1,3,4,5,6 - FRCC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Joe Tarantino - Joe Tarantino On Behalf of: Arthur Starkovich, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Beth Tincher, Sacramento
Municipal Utility District, 4, 1, 5, 6, 3; Jamie Cutlip, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Kevin Smith, Balancing Authority of
Northern California, 1; Nicole Looney, Sacramento Municipal Utility District, 4, 1, 5, 6, 3; Susan Oto, Sacramento Municipal Utility District, 4, 1,
5, 6, 3; - Joe Tarantino
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Nicholas Lauriat - Network and Security Technologies - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Steven Rueckert - Western Electricity Coordinating Council - 10
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Jeff Johnson - Sempra - San Diego Gas and Electric - 1,2,3,4,5,6,7,8,9 - WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Glen Farmer - Avista - Avista Corporation - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Tho Tran - Tho Tran On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; - Tho Tran
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

Adrian Andreoiu - BC Hydro and Power Authority - 1,3,5 - WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Marty Hostler - Northern California Power Agency - 5,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Douglas Johnson - American Transmission Company, LLC - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 3, Group Name FirstEnergy Corporation

Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Ellen Oswald - Midcontinent ISO, Inc. - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Andrey Komissarov - Sempra - San Diego Gas and Electric - 7 - WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Dennis Sismaet - Northern California Power Agency - 6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Eli Rivera - CenterPoint Energy Houston Electric, LLC - 1 - Texas RE
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Joel Charlebois - AESI - Acumen Engineered Solutions International Inc. - 5
Answer

Document Name
Comment
Yes we agree, assuming there are appropriate implementation plans in place for all affected standards and requirements that allow newly identified
Control Centers brought into scope by the proposed definition sufficient time to come into compliance with such standards and requirements.
If such implementation plans for all affected standards and requirements do not currently exist or do not currently address newly identified Control
Centers, then we suggest that the SDT review all affected standards and requirements to develop an appropriate implementation plan for each of those,
or otherwise lengthen the effective date of the proposed definition to an appropriate duration to allow newly identified Control Centers sufficient time to
come into compliance with all applicable standards and requirements.
Likes

0

Dislikes

0

Response

Todd Bennett - Associated Electric Cooperative, Inc. - 3, Group Name AECI
Answer
Document Name
Comment
AECI supports comments provided by NRECA
Likes

0

Dislikes

0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE does not have comments on this question.
Likes

0

Dislikes
Response

0

Control Center Definition

Consideration of Comments | May 2018
Background

The Project 2016-02 Modifications to Critical Infrastructure Protection (CIP) Standard Drafting Team (SDT)
thanks all commenters who submitted comments on the draft Control Center definition. This definition
was posted for a 45-day public comment period through Friday, April 30, 2018. Stakeholders were asked
to provide feedback on the definition and implementation document through a special electronic
comment form. There were 74 sets of responses, including comments from approximately 177 different
people from approximately 127 companies representing the 10 Industry Segments as shown in the table
on the following pages.
All comments submitted can be reviewed in their original format on the project page.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process. If you feel there has been an error or omission, you
can contact the Standards Developer Jordan Mallory (via email) or at (404) 446‐2589.
Control Center Definition

The CIP Modifications SDT has been responding to a Federal Energy Regulatory Commission (FERC)
directive in Order No. 822 concerning protecting the communications between Control Centers,
culminating in a proposed CIP-012 standard. During our discussions, we discovered that CIP-012
highlighted some issues primarily with certain substation or generating plant locations that may also
relate to the current definition of Control Center.
An example of one issue is field assets such as substation control houses or plant control rooms that may
host operating personnel and have communications from their remote terminal units (RTUs) to a Control
Center. If these locations currently have or add a remote human-machine interface, or have some other
way to affect a unit or breaker at another “geographic location,” then the location could possibly be
classified as both a generating resource or substation and a Control Center. In that case, the RTU
communication would fall within the scope of CIP-012. The scope of CIP-012 is not intended to include
this communication, and implementing the required protection may not be feasible.
The SDT proposed a revised Control Center definition to resolve the issue of Control Center
misclassification and adopted language from PER-005-2 to clarify the term “operating personnel” by
excluding plant operators and substation field switching personnel with the goal of preventing field assets
from being identified as Control Centers when a location does not meet the SDTs understanding of the
intent of the Control Center definition. However, based on industry feedback, there are several
unintended consequences to this approach. The SDT has decided to address this specific issue by
excluding Control Centers that only communicate Real-time Assessment and Real-time monitoring data
about the single facility where the Control Center is located from CIP-012.

Other issues were pointed out by entities concerning elements of the currently approved definition,
including ambiguity around terms such as “hosting”, “operating personnel”, and “associated data centers”
and concerns around authority to operate versus a system’s capability to operate. The core issue is that
this facility-based Control Center definition is being used to handle different scenarios for different
purposes. One concerns many other non-CIP NERC standards that apply to traditional Control Centers for
Balancing Authorities, Reliability Coordinators, and Transmission Operators that have been certified by
the Electric Reliability Organization Enterprise and are under the direction of NERC certified System
Operators. The intent of the CIP Reliability Standards is for control systems to be identified and
categorized based more on their span of control rather than the building or room they are located in or
the role of the person using them. However, our inherited constructs that date back to 2003 in the CIP
standards have us looking for these systems in Control Centers. This is causing the definition of Control
Center to be stretched from a CIP perspective to entities that are not Control Centers from other
perspectives so that we can ensure the protection of these control systems. The SDT recognizes that these
matters are outside of our Standards Authorization Request (SAR).

Control Center Definition Consideration of Comments | May 2018

2

Unofficial Nomination Form

Project Number 2016-02 Modifications to CIP Standards
Do not use this form for submitting nominations. Use the electronic form to submit nominations by 8
p.m. Eastern, Wednesday, May 23, 2018. This unofficial version is provided to assist nominees in
compiling the information necessary to submit the electronic form.
Additional information can be found on the Project 2016-02 Modifications to the CIP Standards page. If
you have questions, contact Standards Developer, Jordan Mallory (via email), or at 404-446-2589.
By submitting a nomination form, you are indicating your willingness and agreement to actively
participate in face-to-face meetings and conference calls.
Previous drafting or review team experience is beneficial, but not required. A brief description of the
desired qualifications, expected commitment, and other pertinent information is included below.
Project 2016-02 Modifications to CIP Standards

This solicitation for nominations is to augment the existing Project 2016-02 Modifications to CIP Standards
drafting team that is continuing to address the Standards Authorization Request. NERC is seeking
individuals from the United States and Canada who possess experience in one or more of the following
areas, but are not limited to:
•

Virtualization;

•

Cyber Asset and BES Cyber Asset Definitions; and

•

Network and Externally Accessible Devices.

Standards Affected

CIP-002-5.1, CIP-003-6, CIP-004-6, CIP-005-5, CIP-006-6, CIP-007-6, CIP-008-5, CIP-009-6, CIP-010-2, CIP011-2, and CIP-012-1.
The time commitment for this project is expected to be up to two face-to-face meetings per quarter
(on average two full working days each meeting) with conference calls scheduled as needed to meet
the agreed-upon timeline the review or drafting team sets forth. Team members may also have side
projects, either individually or by subgroup, to present to the larger team for discussion and review.
Lastly, an important component of the review and drafting team effort is outreach. Members of the
team will be expected to conduct industry outreach during the development process to support a
successful project outcome.

Name:
Organization:
Address:

Telephone:
E-mail:
Please briefly describe your experience and qualifications to serve on the requested Standard
Drafting Team (Bio):

If you are currently a member of any NERC drafting team(s), please list each one here:
Not currently on any active SAR or standard drafting team.
Currently a member of the following SAR or standard drafting team(s):
If you previously worked on any NERC drafting team(s), please identify each one here:
No prior NERC SAR or standard drafting team.
Prior experience on the following team(s):
Select each NERC Region in which you have experience relevant to the Project for which you are
volunteering:
Texas RE
FRCC
MRO

NPCC
RF
SERC

SPP RE
WECC
NA – Not Applicable

Unofficial Nomination Form
Project 2016-02 Modifications to CIP Standards | April –May, 2018

2

Select each Industry Segment that you represent:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, and Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations and Regional Entities
NA – Not Applicable
Select each Function 1 in which you have current or prior expertise:
Balancing Authority
Compliance Enforcement Authority
Distribution Provider
Generator Operator
Generator Owner
Interchange Authority
Load-serving Entity
Market Operator
Planning Coordinator

1

Transmission Operator
Transmission Owner
Transmission Planner
Transmission Service Provider
Purchasing-selling Entity
Reliability Coordinator
Reliability Assurer
Resource Planner

These functions are defined in the NERC Functional Model, which is available on the NERC web site.

Unofficial Nomination Form
Project 2016-02 Modifications to CIP Standards | April –May, 2018

3

Provide the names and contact information of two references who could attest to your technical
qualifications and your ability to work well in a group:
Name:

Telephone:

Organization:

E-mail:

Name:

Telephone:

Organization:

E-mail:

Provide the name and contact information of your immediate supervisor or a member of your
management who can confirm your organization’s willingness to support your active participation.
Name:

Telephone:

Title:

Email:

Unofficial Nomination Form
Project 2016-02 Modifications to CIP Standards | April –May, 2018

4

Standards Announcement

Project 2016-02 Modifications to CIP Standards

Nomination Period Open through May 23, 2018
Now Available

Nominations are being sought for additional standard drafting team members through 8 p.m.
Eastern, Wednesday, May 23, 2018.
Use the electronic form to submit a nomination. If you experience difficulties using the electronic
form, contact Wendy Muller. An unofficial Word version of the nomination form is posted on the
Standard Drafting Team Vacancies and the project page.
By submitting a nomination form, you are indicating your willingness and agreement to actively
participate in face-to-face meetings and conference calls.
The time commitment for this project is expected to be up to two face-to-face meetings per quarter
(on average two full working days each meeting) with conference calls scheduled as needed to meet
the agreed-upon timeline the review or drafting team sets forth. Team members may also have side
projects, either individually or by subgroup, to present to the larger team for discussion and review.
Lastly, an important component of the review and drafting team effort is outreach. Members of the
team will be expected to conduct industry outreach during the development process to support a
successful project outcome.
Previous drafting or review team experience is beneficial, but not required.
Project 2016-02 Modifications to CIP Standards

This solicitation for nominations is to augment the existing Project 2016-02 Modifications to CIP
Standards drafting team that is continuing to address the Standards Authorization Request. NERC is
seeking individuals from the United States and Canada who possess experience in one or more of the
following areas, but are not limited to:
•

Virtualization;

•

Cyber Asset and BES Cyber Asset Definitions; and

•

Network and Externally Accessible Devices.

Standards Affected

CIP-002-5.1, CIP-003-6, CIP-004-6, CIP-005-5, CIP-006-6, CIP-007-6, CIP-008-5, CIP-009-6, CIP-010-2,
CIP-011-2, and CIP-012-1.

Next Steps

The Standards Committee is expected to appoint members to the team in June 2018. Nominees will
be notified shortly after they have been appointed.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Mat Bunch at (404) 446-9785 or Jordan Mallory at (404) 4462589.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement | Project 2016-02 Modifications to CIP Standards
Solicitation of Drafting Team Nominations | April – May, 2018

2

CIP-012-1 – Cyber Security – Communications between Control Centers

Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).

Description of Current Draft

This is the fourth draft of the proposed standard.
Completed Actions

Date

Standards Committee approved Standard Authorization Request
(SAR) for posting

March 9, 2016

SAR posted for comment

March 23 - April 21,
2016

SAR posted for comment

June 1 – June 30,
2016

Informal comment period

February 10- March
13, 2017

45-day formal comment period with initial ballot

July 27 – September
11, 2017

45-day formal comment period with additional ballot

October 27 –
December 11, 2017

45-day formal comment period with additional ballot

March 16 – April 30,
2018

45-day formal comment period with additional ballot

May 18 – July 2,
2018

Anticipated Actions

10-day final ballot
NERC Board

Draft 4 of CIP-012-1
May 2018 Page 1 of 6

Date

July 30 – August 8,
2018
August 16, 2018

CIP-012-1 – Cyber Security – Communications between Control Centers

A. Introduction
1.

Title: Cyber Security – Communications between Control Centers

2.

Number: CIP-012-1

3.

Purpose: To protect the confidentiality and integrity of Real-time Assessment and
Real-time monitoring data transmitted between Control Centers.

4.

Applicability:
4.1. Functional Entities: The requirements in this standard apply to the following
functional entities, referred to as “Responsible Entities,” that own or operate a
Control Center.
4.1.1. Balancing Authority
4.1.2. Generator Operator
4.1.3. Generator Owner
4.1.4. Reliability Coordinator
4.1.5. Transmission Operator
4.1.6. Transmission Owner
4.2. Exemptions: The following are exempt from Reliability Standard CIP-012-1:
4.2.1. Cyber Assets at Facilities regulated by the Canadian Nuclear Safety
Commission.
4.2.2. The systems, structures, and components that are regulated by the
Nuclear Regulatory Commission under a cyber security plan pursuant
to 10 C.F.R. Section 73.54.
4.2.3. A Control Center at a generation resource or Transmission station or
substation that transmits to another Control Center Real-time
Assessment or Real-time monitoring data pertaining only to the
generation resource or Transmission station or substation at which the
transmitting Control Center is located.

5.

Effective Date: See Implementation Plan for CIP-012-1.

B. Requirements and Measures
R1.

The Responsible Entity shall implement, except under CIP Exceptional Circumstances,
one or more documented plan(s) to mitigate the risk of unauthorized disclosure or
modification of Real-time Assessment and Real-time monitoring data while being
transmitted between any applicable Control Centers. The Responsible Entity is not
required to include oral communications in its plan. The plan shall include: [Violation
Risk Factor: Medium] [Time Horizon: Operations Planning]

Draft 4 of CIP-012-1
May 2018 Page 2 of 6

CIP-012-1 – Cyber Security – Communications between Control Centers

1.1. Identification of security protection used to mitigate the risk of unauthorized
disclosure or modification of Real-time Assessment and Real-time monitoring
data while being transmitted between Control Centers;
1.2. Identification of where the Responsible Entity applied security protection for
transmitting Real-time Assessment and Real-time monitoring data between
Control Centers; and
1.3. If the Control Centers are owned or operated by different Responsible Entities,
identify the responsibilities of each Responsible Entity for applying security
protection to the transmission of Real-time Assessment and Real-time
monitoring data between those Control Centers.
M1. Evidence may include, but is not limited to, documented plan(s) that meet the
security objective of Requirement R1 and documentation demonstrating the
implementation of the plan(s).

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority” (CEA)
means NERC, the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below
is shorter than the time since the last audit, the CEA may ask an entity to provide
other evidence to show that it was compliant for the full-time period since the
last audit.
The Responsible Entity shall keep data or evidence to show compliance as
identified below unless directed by its CEA to retain specific evidence for a
longer period of time as part of an investigation.
•

The Responsible Entities shall keep data or evidence of each Requirement in
this Reliability Standard for three calendar years.

•

If a Responsible Entity is found non-compliant, it shall keep information
related to the non-compliance until mitigation is complete and approved or for
the time specified above, whichever is longer.

•

The CEA shall keep the last audit records and all requested and submitted
subsequent audit records.

Draft 4 of CIP-012-1
May 2018 Page 3 of 6

CIP-012-1 – Cyber Security – Communications between Control Centers

1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers
to the identification of the processes that will be used to evaluate data or
information for the purpose of assessing performance or outcomes with the
associated Reliability Standard.

Draft 4 of CIP-012-1
May 2018 Page 4 of 6

CIP-012-1 – Cyber Security – Communications between Control Centers

Violation Severity Levels
Violation Severity Levels

R#

R1.

Lower VSL

N/A

Moderate VSL

The Responsible Entity
documented its plan(s) but
failed to include one of the
applicable Parts of the plan
as specified in Requirement
R1.

High VSL

The Responsible Entity
documented its plan(s) but
failed to include two of the
applicable Parts of the plan
as specified in Requirement
R1.

Severe VSL

The Responsible Entity failed
to document plan(s) for
Requirement R1;
Or
The Responsible Entity failed
to implement any Part of its
plan(s) for Requirement R1,
except under CIP Exceptional
Circumstances.

D. Regional Variances
None.

E. Associated Documents
Implementation Plan.

Technical Rationale for CIP-012-1.
Implementation Guidance.

Draft 4 of CIP-012-1
May 2018

Page 5 of 6

CIP-012-1 Version History

Version History
Version

Date

1

TBD

Draft 4 of CIP-012-1
May 2018

Action

Respond to FERC Order No. 822

Change
Tracking

N/A

Page 6 of 6

CIP-012-1 – Cyber Security – Communications between Control Centers

Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).

Description of Current Draft

This is the third fourth draft of the proposed standard.
Completed Actions

Date

Standards Committee approved Standard Authorization Request
(SAR) for posting

March 9, 2016

SAR posted for comment

March 23 - April 21,
2016

SAR posted for comment

June 1 – June 30,
2016

Informal comment period

February 10- March
13, 2017

45-day formal comment period with initial ballot

July 27 – September
11, 2017

45-day formal comment period with additional ballot

October 27 –
December 11, 2017

45-day formal comment period with additional ballot

March 16 – April 30,
2018

45-day formal comment period with additional ballot

May 18 – July 2,
2018

Anticipated Actions

45-day formal comment period with additional ballot
10-day final ballot
NERC Board

Draft 3 4 of CIP-012-1
March May 2018

Date

May 18 – July 2,
2018
July 30 – August 8,
2018
August 16, 2018

Page 1 of 6

CIP-012-1 – Cyber Security – Communications between Control Centers

A. Introduction
1.

Title: Cyber Security – Communications between Control Centers

2.

Number: CIP-012-1

3.

Purpose: To protect the confidentiality and integrity of Real-time Assessment and
Real-time monitoring data transmitted between Control Centers.

4.

Applicability:
4.1. Functional Entities: The requirements in this standard apply to the following
functional entities, referred to as “Responsible Entities,” that own or operate a
Control Center.
4.1.1. Balancing Authority
4.1.2. Generator Operator
4.1.3. Generator Owner
4.1.4. Reliability Coordinator
4.1.5. Transmission Operator
4.1.6. Transmission Owner
4.2. Exemptions: The following are exempt from Reliability Standard CIP-012-1:
4.2.1. Cyber Assets at Facilities regulated by the Canadian Nuclear Safety
Commission.
4.2.2. The systems, structures, and components that are regulated by the
Nuclear Regulatory Commission under a cyber security plan pursuant
to 10 C.F.R. Section 73.54.
4.2.3. A Control Center at a generation resource or Transmission station or
substation that transmits to another Control Center Real-time
Assessment or Real-time monitoring data pertaining only to the
generation resource or Transmission station or substation at which the
transmitting Control Center is located.

5.

Effective Date: See Implementation Plan for CIP-012-1.

B. Requirements and Measures
R1.

The Responsible Entity shall implement, except under CIP Exceptional Circumstances,
one or more documented plan(s) to mitigate the risk of unauthorized disclosure or
modification of Real-time Assessment and Real-time monitoring data while being
transmitted between any applicable Control Centers. Theis Responsible Entity is not
required to include requirement excludes oral communications in its plan. The plan
shall include: [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]

Draft 3 4 of CIP-012-1
March May 2018

Page 2 of 6

CIP-012-1 – Cyber Security – Communications between Control Centers

1.1. Identification of security protection used to mitigate the risk of unauthorized
disclosure or modification of Real-time Assessment and Real-time monitoring
data while being transmitted between Control Centers;
1.2. Identification of where the Responsible Entity applied security protection for
transmitting Real-time Assessment and Real-time monitoring data between
Control Centers; and
1.3. If the Control Centers are owned or operated by different Responsible Entities,
identify the responsibilities of each Responsible Entity for applying security
protection to the transmission of Real-time Assessment and Real-time
monitoring data between those Control Centers.
M1. Evidence may include, but is not limited to, documented plan(s) that meet the
security objective of Requirement R1 and documentation demonstrating the
implementation of the plan(s).

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority” (CEA)
means NERC, the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below
is shorter than the time since the last audit, the Compliance Enforcement
AuthorityCEA may ask an entity to provide other evidence to show that it was
compliant for the full-time period since the last audit.
The Responsible Entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement AuthorityCEA to
retain specific evidence for a longer period of time as part of an investigation.
•

The Responsible Entities shall keep data or evidence of each Requirement in
this Reliability Standard for three calendar years.

•

If a Responsible Entity is found non-compliant, it shall keep information
related to the non-compliance until mitigation is complete and approved or for
the time specified above, whichever is longer.

•

The Compliance Enforcement AuthorityCEA shall keep the last audit records
and all requested and submitted subsequent audit records.

Draft 3 4 of CIP-012-1
March May 2018

Page 3 of 6

CIP-012-1 – Cyber Security – Communications between Control Centers

1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers
to the identification of the processes that will be used to evaluate data or
information for the purpose of assessing performance or outcomes with the
associated Reliability Standard.

Draft 3 4 of CIP-012-1
March May 2018

Page 4 of 6

CIP-012-1 – Cyber Security – Communications between Control Centers

Violation Severity Levels
Violation Severity Levels

R#

R1.

Lower VSL

N/A

Moderate VSL

High VSL

Severe VSL

The Responsible Entity
documented its plan(s) but
failed to include one of the
applicable Pparts of the plan
as specified in Requirement
R1.

The Responsible Entity
documented its plan(s) but
failed to include two of the
applicable Pparts of the plan
as specified in Requirement
R1.

The Responsible Entity failed
to document plan(s) for
Requirement R1;
Or
The Responsible Entity failed
to implement any Part of its
plan(s) for Requirement R1,
except under CIP Exceptional
Circumstances.

D. Regional Variances
None.

E. Associated Documents
Implementation Plan.

Technical Rationale for CIP-012-1.
Implementation Guidance.

Draft 3 4 of CIP-012-1
March May 2018

Page 5 of 6

CIP-012-1 Version History

Version History
Version

Date

1

TBD

Draft 3 4 of CIP-012-1
March May 2018

Action

Respond to FERC Order No. 822

Change
Tracking

N/A

Page 6 of 6

Implementation Plan

Project 2016-02 Modifications to CIP Standards
Reliability Standard CIP-012-1
Applicable Standard
•

Reliability Standard CIP-012-1 - Cyber Security – Communications between Control Centers

Requested Retirements
•

None

Prerequisite Standard

These standard(s) or definitions must be approved before the Applicable Standard becomes
effective:
•

None

Applicable Entities
•

Balancing Authority

•

Generator Operator

•

Generator Owner

•

Reliability Coordinator

•

Transmission Operator

•

Transmission Owner

Effective Date

Reliability Standard CIP-012-1 - Cyber Security – Communications between Control Centers
Where approval by an applicable governmental authority is required, Reliability Standard CIP-012-1
shall become effective on the first day of the first calendar quarter that is twenty-four (24) calendar
months after the effective date of the applicable governmental authority’s order approving the
standard, or as otherwise provided for by the applicable governmental authority.
Where approval by an applicable governmental authority is not required, Reliability Standard CIP012-1 shall become effective on the first day of the first calendar quarter that is twenty-four (24)
calendar months after the date the standard is adopted by the NERC Board of Trustees, or as
otherwise provided for in that jurisdiction.

Unofficial Comment Form

Project 2016-02 Modifications to CIP Standards
CIP-012-1
Do not use this form for submitting comments. Use the Standards Balloting and Commenting System to
submit comments on CIP-012-1 – Cyber Security – Communications between Control Centers. Comments
must be submitted by 8 p.m. Eastern, Monday, July 2, 2018.
m. Eastern, Thursday, August 20, 2015
Additional information is available on the project page. If you have questions, contact Jordan Mallory at
(404) 446-2589.
Background

On January 21, 2016, the Commission issued Order No. 822, approving seven CIP Reliability Standards and
new or modified definitions, and directing modifications to the CIP Reliability Standards. Among others,
the Commission directed NERC to “develop modifications to the CIP Reliability Standards to require
responsible entities to implement controls to protect, at a minimum, communication links and sensitive
bulk electric system data communicated between bulk electric system Control Centers in a manner that is
appropriately tailored to address the risks posed to the bulk electric system by the assets being protected
(i.e., high, medium, or low impact).” (Order 822, Paragraph 53)
The Project 2016-02 Standard Drafting Team (SDT) drafted Reliability Standard CIP-012-1 to require
Responsible Entities to implement controls to protect sensitive Bulk Electric System (BES) data while being
transmitted over communications links between BES Control Centers. Due to the sensitivity of the data
being communicated between the Control Centers, the standard applies to all impact levels (i.e., high,
medium, or low impact).
The SDT drafted CIP-012-1 allowing Responsible Entities to apply protection to the links, the data, or both,
in order to satisfy the security objective consistent with the capabilities of the Responsible Entity’s
operational environment. Requirement R1 requires Responsible Entities to implement, except under CIP
Exceptional Circumstances, one or more documented plans that protect Real-time Assessment and Realtime monitoring data while being transmitted between Control Centers. The plan(s) must address how
the Responsible Entity will mitigate the risk of unauthorized disclosure or modification of the applicable
data.

Questions

1. Control Center Exemption Language: The SDT drafted Exemption language in the Applicability
section specifically for CIP-012-1 to exempt Control Centers that only transmit data pertaining to a
single co-located substation or generating plant. Do you agree with this revision? If not, please
provide the basis for your disagreement and an alternate proposal.
Yes
No
Comments:
2. Requirement R1: The SDT modified Requirement R1 to state: “The Responsible Entity shall
implement, except under CIP Exceptional Circumstances, one or more documented plan(s) to
mitigate the risk of unauthorized disclosure or modification of Real-time Assessment and Realtime monitoring data while being transmitted between any applicable Control Centers. The
Responsible Entity is not required to include oral communications in its plan.” Do you agree with
this revision? If not, please provide the basis for your disagreement and an alternate proposal.
Yes
No
Comments:
3. Implementation Plan: The SDT established the Implementation Plan to make the standard
effective the first day of the first calendar quarter that is twenty-four (24) calendar months after
the effective date of the applicable governmental authority’s order approving the standard, or as
otherwise provided for by the applicable governmental authority. Do you agree with this
proposal? If you think an alternate implementation time period is needed, please provide a
detailed explanation of actions and time needed to meet the implementation deadline.
Yes
No
Comments:
4. Technical Rationale: The SDT modified the draft Technical Rationale for CIP-012 to further explain
the need for the exemption for certain Control Centers. Do you agree with the explanations and
included diagrams in the draft Technical Rationale? If you do not agree, or if you agree but have
comments or suggestions for the draft Technical Rationale, please provide your recommendation
and explanation.
Yes
No
Comments:
Unofficial Comment Form | Project 2016-02 Modifications to CIP Standards
CIP-012-1 Draft 4 | May-July 2018

2

5. The SDT modified the draft Implementation Guidance for CIP-012 to provide examples of how a
Responsible Entity could comply with the requirements. The draft Implementation Guidance does
not prescribe the only approaches to compliance. Rather, it describes what the SDT believes would
be effective ways to comply with the standard. See NERC’s Compliance Guidance policy for
information on Implementation Guidance. Do you agree with the draft Implementation Guidance?
If you do not agree, or if you agree but have comments or suggestions for the draft
Implementation Guidance, please provide your recommendation and explanation.
Yes
No
Comments:
6. The SDT believes proposed CIP-012-1 provides entities with flexibility to meet the reliability
objectives in a cost effective manner. Do you agree? If you do not agree, or if you agree but have
suggestions for improvement to enable more cost effective approaches, please provide your
recommendation and, if appropriate, technical justification.
Yes
No
Comments:

Unofficial Comment Form | Project 2016-02 Modifications to CIP Standards
CIP-012-1 Draft 4 | May-July 2018

3

Violation Risk Factor and Violation Severity Level
Justifications
Project 2016-02 Modifications to CIP Standards

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in CIP-012-1. Each requirement is assigned a VRF and a VSL. These elements support the determination of
an initial value range for the Base Penalty Amount regarding violations of requirements in FERC-approved Reliability Standards, as defined in
the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT applied the following NERC criteria and FERC Guidelines when
developing the VRFs and VSLs for the requirements.

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•

Emergency operations

•

Vegetation management

•

Operator personnel training

•

Protection systems and their coordination

•

Operating tools and backup facilities

•

Reactive power and voltage control

•

System modeling and data exchange

•

Communication protocol and facilities

•

Requirements to determine equipment ratings

•

Synchronized data recorders

•

Clearer criteria for operationally critical facilities

•

Appropriate use of transmission loading relief.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | May 2018

2

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | May 2018

3

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL

Moderate VSL

The performance or product
measured almost meets the full
intent of the requirement.

The performance or product
measured meets the majority of
the intent of the requirement.

High VSL

The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet
some of the intent.

Severe VSL

The performance or product
measured does not
substantively meet the intent of
the requirement.

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | May 2018

4

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justifications for CIP-012-1, Requirement R1

Proposed VRF

Medium

NERC VRF Discussion

A VRF of Medium was assigned to this requirement. Cyber security plans enable effective implementation
of the CIP standard’s requirements to mitigate the risk of the unauthorized disclosure or modification of
data used for Real-time Assessments and Real-time monitoring while being transmitted between Control
Centers.

FERC VRF G1 Discussion

N/A

Guideline 1- Consistency
with Blackout Report
FERC VRF G2 Discussion

N/A

Guideline 2- Consistency
within a Reliability Standard
FERC VRF G3 Discussion
Guideline 3- Consistency
among Reliability Standards
FERC VRF G4 Discussion
Guideline 4- Consistency
with NERC Definitions of
VRFs
FERC VRF G5 Discussion

The requirement complements CIP-005-1, Requirement R1, CIP-006-6, Requirement R1, and CIP-007-6,
Requirement R1 which are related to security of networks and communications components. The
proposed VRF is consistent with these related requirements.
Failure to have a cyber security plan would not, under Emergency, abnormal, or restorative conditions
anticipated by the preparations, be expected to adversely affect the electrical state or capability of the
Bulk Electric System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

N/A

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | May 2018

5

VRF Justifications for CIP-012-1, Requirement R1

Proposed VRF

Medium

Guideline 5- Treatment of
Requirements that Comingle More than One
Obligation
VSLs for CIP-012-1, Requirement R1

Lower
N/A

Moderate
The Responsible Entity
documented its plan(s) but
failed to include one of the
applicable Parts of the plan as
specified in Requirement R1.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | May 2018

High
The Responsible Entity
documented its plan(s) but
failed to include two of the
applicable Parts of the plan as
specified in Requirement R1.

Severe
The Responsible Entity failed to
document plan(s) for
Requirement R1;
Or
The Responsible Entity failed to
implement any Part of its plan(s)
for Requirement R1, except
under CIP Exceptional
Circumstances.

6

VSL Justifications for CIP-012-1 Requirements R1

FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency
in the Determination of
Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent

The requirement is new. Therefore, the proposed VSL does not have the unintended consequence of
lowering the level of compliance.

The requirement is for the Responsible Entity to implement one or more documented plan(s) as specified
in Requirement R1.
The moderate VSL addresses where the Responsible Entity documented its plan(s) but failed to include
one of the applicable parts of the plan as specified in Requirement R1.
The high VSL addresses where the Responsible Entity documented its plan(s) but failed to include two of
the applicable parts of the plan as specified in Requirement R1.
The severe VSL addresses where the Responsible Entity failed to document plan(s) for Requirement R1, or
where the Responsible Entity failed to implement plan(s) for Requirement R1.

Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement

The proposed VSL uses the same terminology as used in the associated requirement and is, therefore,
consistent with the requirement.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | May 2018

7

FERC VSL G4

Each VSL is based on a single violation and not cumulative violations.

Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | May 2018

8

Violation Risk Factor and Violation Severity Level
Justifications
Project 2016-02 Modifications to CIP Standards

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in CIP-012-1. Each requirement is assigned a VRF and a VSL. These elements support the determination of
an initial value range for the Base Penalty Amount regarding violations of requirements in FERC-approved Reliability Standards, as defined in
the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT applied the following NERC criteria and FERC Guidelines when
developing the VRFs and VSLs for the requirements.

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•

Emergency operations

•

Vegetation management

•

Operator personnel training

•

Protection systems and their coordination

•

Operating tools and backup facilities

•

Reactive power and voltage control

•

System modeling and data exchange

•

Communication protocol and facilities

•

Requirements to determine equipment ratings

•

Synchronized data recorders

•

Clearer criteria for operationally critical facilities

•

Appropriate use of transmission loading relief.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | March May 2018

2

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | March May 2018

3

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL

Moderate VSL

The performance or product
measured almost meets the full
intent of the requirement.

The performance or product
measured meets the majority of
the intent of the requirement.

High VSL

The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet
some of the intent.

Severe VSL

The performance or product
measured does not
substantively meet the intent of
the requirement.

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | March May 2018

4

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justifications for CIP-012-1, Requirement R1

Proposed VRF

Medium

NERC VRF Discussion

A VRF of Medium was assigned to this requirement. Cyber security plans enable effective implementation
of the CIP standard’s requirements to mitigate the risk of the unauthorized disclosure or modification of
data used for Real-time Assessments and Real-time monitoring while being transmitted between Control
Centers.

FERC VRF G1 Discussion

N/A

Guideline 1- Consistency
with Blackout Report
FERC VRF G2 Discussion

N/A

Guideline 2- Consistency
within a Reliability Standard
FERC VRF G3 Discussion
Guideline 3- Consistency
among Reliability Standards
FERC VRF G4 Discussion
Guideline 4- Consistency
with NERC Definitions of
VRFs
FERC VRF G5 Discussion

The requirement complements CIP-005-1, Requirement R1, CIP-006-6, Requirement R1, and CIP-007-6,
Requirement R1 which are related to security of networks and communications components. The
proposed VRF is consistent with these related requirements.
Failure to have a cyber security plan would not, under Emergency, abnormal, or restorative conditions
anticipated by the preparations, be expected to adversely affect the electrical state or capability of the
Bulk Electric System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

N/A

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | March May 2018

5

VRF Justifications for CIP-012-1, Requirement R1

Proposed VRF

Medium

Guideline 5- Treatment of
Requirements that Comingle More than One
Obligation
VSLs for CIP-012-1, Requirement R1

Lower
N/A

Moderate
The Responsible Entity
documented its plan(s) but
failed to include one of the
applicable pParts of the plan as
specified in Requirement R1.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | March May 2018

High
The Responsible Entity
documented its plan(s) but
failed to include two of the
applicable pParts of the plan as
specified in Requirement R1.

Severe
The Responsible Entity failed to
document plan(s) for
Requirement R1;
Or
The Responsible Entity failed to
implement any Part of its plan(s)
for Requirement R1, except
under CIP Exceptional
Circumstances.

6

VSL Justifications for CIP-012-1 Requirements R1

FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency
in the Determination of
Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent

The requirement is new. Therefore, the proposed VSL does not have the unintended consequence of
lowering the level of compliance.

The requirement is for the Responsible Entity to implement one or more documented plan(s) as specified
in Requirement R1.
The moderate VSL addresses where the Responsible Entity documented its plan(s) but failed to include
one of the applicable parts of the plan as specified in Requirement R1.
The high VSL addresses where the Responsible Entity documented its plan(s) but failed to include two of
the applicable parts of the plan as specified in Requirement R1.
The severe VSL addresses where the Responsible Entity failed to document plan(s) for Requirement R1, or
where the Responsible Entity failed to implement plan(s) for Requirement R1.

Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement

The proposed VSL uses the same terminology as used in the associated requirement and is, therefore,
consistent with the requirement.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | March May 2018

7

FERC VSL G4

Each VSL is based on a single violation and not cumulative violations.

Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | March May 2018

8

DRAFT

Cyber Security –
Communications between
Control Centers
Technical Rationale and Justification for
Reliability Standard CIP-012-1

May 2018

NERC | Report Title | Report Date
I

Table of Contents
Preface ...................................................................................................................................................................... iii
Introduction .............................................................................................................................................................. iv
Requirement R1 ......................................................................................................................................................... 1
General Considerations for Requirement R1...................................................................................................... 1
Overview of confidentiality and integrity ........................................................................................................... 1
Alignment with IRO and TOP standards ............................................................................................................. 1
Identification of Where Security Protection is Applied by the Responsible Entity ............................................ 2
Control Center Ownership .................................................................................................................................. 2
References.................................................................................................................................................................. 4

NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1| May 2018
ii

Preface
The vision for the Electric Reliability Organization (ERO) Enterprise, which is comprised of the North American Electric
Reliability Corporation (NERC) and the eight Regional Entities (REs), is a highly reliable and secure North American
bulk power system (BPS). Our mission is to assure the effective and efficient reduction of risks to the reliability and
security of the grid.
The North American BPS is divided into eight RE boundaries as shown in the map and corresponding table below.

The North American BPS is divided into eight RE boundaries. The highlighted areas denote overlap as some load-serving entities
participate in one Region while associated Transmission Owners/Operators participate in another.

FRCC

Florida Reliability Coordinating Council

MRO

Midwest Reliability Organization

NPCC

Northeast Power Coordinating Council

RF

ReliabilityFirst

SERC

SERC Reliability Corporation

SPP RE

Southwest Power Pool Regional Entity

Texas RE

Texas Reliability Entity

WECC

Western Electricity Coordinating Council

NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1| May 2018
iii

Introduction
This document explains the technical rationale and justification for the proposed Reliability Standard CIP-012-1. It
will provide stakeholders and the ERO Enterprise with an understanding of the technology and technical
requirements in the Reliability Standard. It also contains information on the SDT’s intent in drafting the requirements.
This Technical Rationale and Justification for CIP-012-1 is not a Reliability Standard and should not be considered
mandatory and enforceable.
On January 21, 2016, the Federal Energy Regulatory Commission (FERC or Commission) issued Order No. 822,
approving seven Critical Infrastructure Protection (CIP) Reliability Standards and new or modified terms in the
Glossary of Terms Used in NERC Reliability Standards, and directing modifications to the CIP Reliability Standards.
Among others, the Commission directed the North American Electric Reliability Corporation (NERC) to “develop
modifications to the CIP Reliability Standards to require Responsible Entities 1 to implement controls to protect, at a
minimum, communication links and sensitive bulk electric system data communicated between bulk electric system
Control Centers in a manner that is appropriately tailored to address the risks posed to the bulk electric system by
the assets being protected (i.e., high, medium, or low impact).” (Order 822, Paragraph 53)
In response to the directive in Order No. 822, the Project 2016-02 standard drafting team (SDT) drafted Reliability
Standard CIP-012-1 to require Responsible Entities to implement controls to protect sensitive Bulk Electric System
(BES) data and communications links between BES Control Centers. Due to the sensitivity of the data being
communicated between Control Centers, as defined in the Glossary of Terms Used in NERC Reliability Standards, the
standard applies to all impact levels (i.e., high, medium, or low impact).
Although the Commission directed NERC to develop modifications to CIP-006, the SDT determined that modifications
to CIP-006 would not be appropriate. There are differences between the plan(s) required to be developed and
implemented for CIP-012-1 and the protection required in CIP-006-6 Requirement R1 Part 1.10. CIP-012-1
Requirements R1 and R2 protect the applicable data during transmission between two separate Control Centers. CIP006 Requirement R1 Part 1.10 protects nonprogrammable communication components within an Electronic Security
Perimeter (ESP) but outside of a Physical Security Perimeter (PSP). The transmission of applicable data between
Control Centers takes place outside of an ESP. Therefore, the protection contained in CIP-006-6 Requirement R1 Part
1.10 does not apply.
The SDT drafted requirements to provide Responsible Entities the latitude to protect the communication links, the
data, or both to satisfy the security objective consistent with the capabilities of the Responsible Entity’s operational
environment.
CIP-012 Exemption (4.2.3) for certain Control Centers
As the SDT drafted CIP-012, it became aware of certain generating plant or Transmission substation situations where
such field assets could be dual-classified as Control Centers based on the current Control Center definition. However,
their communications to their normal BA or TOP Control Center are not the type of communications that are the
intended scope of CIP-012 as they do not differ from any other generating plant or substation. The SDT wrote an
exemption (Section 4.2.3 within CIP-012) for this particular scenario which is described in further detail below.

1

As used in the CIP Standards, a Responsible Entity refers to the registered entities subject to the CIP Standards.
NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1| May 2018
iv

Introduction

Figure 1
Figure 1 above pictures a typical scenario with two Control Centers communicating (in this instance Entity C’s RC
Control Center and Entity A’s TOP Control Center). The communication between them is the intended scope of CIP012’s requirements if it meets the types of data inclusions and exclusions within the standard. The TOP Control Center
is communicating with an RTU at two of Entity B’s generating plants (Stations Alpha and Beta) and those RTU’s are
gathering information from each generating unit’s control system. Each generating unit at each plant has an HMI
(Human/Machine Interface; an operator workstation) that the local personnel use to operate their respective units.
Entity B decides that the generating unit at Station Beta, a small peaking facility, will only have an operator on site
during the day and the operator at Station Alpha should be able to remotely start the unit at Station Beta if necessary.

NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1| May 2018
v

Introduction

Figure 2
In Figure 2, Entity B installs a dedicated communications circuit from the control system on Station Beta’s control
system and puts a dedicated HMI at Station Alpha the operator can use. Station Alpha is now “one or more facilities
hosting operating personnel that monitor and control the BES in real time to perform the reliability tasks of…a
Generator Operator for generation Facilities at two or more locations.” It can now be dual-classified not only as a
generation resource but also as a Control Center.
The communications to the TOP and RC Control Centers from Figure 1 have not changed at all. No new cyber systems
are in place that can impact multiple units. No cyber systems have been added performing Control Center functions.
No additional risk from cyber systems has been added. The only thing that has changed is an HMI for Station Beta has
been moved within close physical proximity to an HMI for Station Alpha.

NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1| May 2018
vi

Introduction

Figure 3
The SDT realized how this suddenly makes the communication noted in Figure 3 between Station Alpha and Entity
A’s TOP Control Center subject to CIP-012 although nothing has changed between them. There is no new risk involved.
Two HMI’s have been moved into the same room and suddenly a new NERC CIP standard applies to two entities.
This is an anamoly of the current Control Center definition defining a facility, room, or building from which something
can be done without regard to how its done or with what systems. This is a generation specific example, but the SDT
can envision substations with an HMI or protective relay that “operating personnel” within the substation could use
to impact an adjacent substation. The SDT realizes that in the criteria for TO’s and GOP’s the “two or more geographic
locations” is not a precise enough filter for capturing what a Control Center truly is. The SDT’s attempts to address
this issue by clarifying the definition of Control Center pointed out larger issues that are not within the SDT’s SAR to
address at this time. Therefore the SDT is handling the issue this creates for CIP-012 by the 4.2.3 exemption within
the CIP-012 standard which reads:
4.2.3. A Control Center at a generation resource or Transmission station or substation that transmits to
another Control Center Real-time Assessment or Real-time monitoring data pertaining only to the generation
resource or Transmission station or substation at which the transmitting Control Center is located.
The intent of this exemption is to exclude the normal RTU-style communication from a field asset about that field
asset’s status from CIP-012. Throughout this scenario or others like it, that communication has not changed and is
still the same data pertaining only to the single location. The SDT recognizes that this communication is not the
intent of the standard for protecting communications between Control Centers and this type of communications
can be using older legacy communication technology and protocols.

NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1| May 2018
vii

Requirement R1
R1. The Responsible Entity shall implement, except under CIP Exceptional Circumstances, one or more

documented plan(s) to mitigate the risk of unauthorized disclosure or modification of Real-time
Assessment and Real-time monitoring data while being transmitted between any applicable Control
Centers. The Responsible Entity is not required to include oral communications in its plan. The plan
shall include: [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]
1.1

Identification of security protection used to mitigate the risk of unauthorized disclosure or
modification of Real-time Assessment and Real-time monitoring while being transmitted
between Control Centers;

1.2

Identification of where the Responsible Entity applied security protection for transmitting Realtime Assessment and Real-time monitoring data between Control Centers; and

1.3

If he Control Centers are owned or operated by different Responsible Entities,identify the
responsibilities of each Responsible Entity for applying security protection to the transmission of
Real-time Assessment and Real-time monitoring data between those Control Centers.

General Considerations for Requirement R1
Requirement R1 focuses on implementing a documented plan to protect information that is critical to the Real-time
operations of the Bulk Electric System while in transit between applicable Control Centers. The SDT does not intend
for the listed order of the three requirement parts to convey any sequence or significance.
Overview of confidentiality and integrity
The SDT drafted CIP-012-1 to address confidentiality and integrity of Real-time Assessment and Real-time monitoring
data. This is accomplished by drafting the requirement to mitigate the risk of unauthorized disclosure (confidentiality)
or modification (integrity). For this Standard, the SDT relied on the definitions of confidentiality and integrity as
defined by National Institute of Standards and Technology (NIST):
•

Confidentiality is defined as, “Preserving authorized restrictions on information access and disclosure,
including means for protecting personal privacy and proprietary information.” 2

•

Integrity is defined as, “Guarding against improper information modification or destruction, and includes
ensuring information non-repudiation and authenticity.” 3

The SDT asserts that the availability of this data is already required by the performance obligation of the Operating
and Planning Reliability Standards. The SDT drafted CIP-012 to address the data while being transmitted. The SDT
maintains that this data resides within BES Cyber Systems, and while at rest is protected by CIP-003 through CIP-011.
Alignment with IRO and TOP standards
The SDT recognized the FERC reference to additional Reliability Standards and the responsibilities to protect the
applicable data in accordance with NERC Reliability Standards TOP-003 and IRO-010. The SDT used these references
to drive the identification of sensitive BES data and chose to base the CIP-012 requirements on the Real-time data
specification elements in these standards. This approach provides consistent scoping of identified data, and does not
require each entity to devise its own list or inventory of this data. Many entities are required to provide this data
under agreements executed with their RC, BA or TOP. The SDT asserts that typically the RC, BA or TOP will identify
2
3

NIST Special Publication 800-53A, Revision 4, page B-3
NIST Special Publication 800-53A, Revision 4, page B-6
NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1| May 2018
1

0 Requirement R1

all data requiring protection for CIP-012-1 through the TOP-003 and IRO-010 Reliability Standards. However, the SDT
noted that there may be special instances during which Real-time Assessment or Real-time monitoring data is not
identified by the RC, BA, or TOP. This would include data that may be exchanged between a Responsible Entity’s
primary and backup Control Center.
Identification of Where Security Protection is Applied by the Responsible Entity
The SDT noted the need for a Responsible Entity to identify where it will apply protection for applicable data. The
SDT did not specify the location where CIP-012 security protection must be applied to provide latitude for Responsible
Entities to implement the security controls in a manner best fitting their individual circumstances. This latitude
ensures entities can still take advantage of security measures, such as deep packet inspection implemented at or near
the EAP when ESPs are present, while maintaining the capability to protect the applicable data being transmitted
between Control Centers.
The SDT also recognizes that CIP-012 security protection may be applied to a Cyber Asset that is not an identified BES
Cyber Asset or EACMS. The identification of the Cyber Asset as the location where security protection is applied does
not expand the scope of Cyber Assets identified as applicable under Cyber Security Standards CIP-002 through CIP011.
The SDT understands that in data exchanges between Control Centers, a single entity may not be responsible for both
ends of the communication link. The SDT intends for a Responsible Entity to identify only where it applied security
protection. The Responsible Entity should not be held accountable for identifying where a neighboring entity applied
security protection at the neighboring entity’s facility. A Responsible Entity, however, may decide to take
responsibility for both ends of a communication link. For example, it may place a router in a neighboring entity’s data
center. In a scenario like this, where a Responsible Entity has taken responsibility for applying security protection on
both ends of the communication link, the Responsible Entity should identify where it applied security protection at
both ends of the link. The SDT intends for there to be alignment between the identification of where security
protection is applied in CIP-012 R1, Part 1.2 and the identification of Responsible Entity responsibilities in CIP-012 R1,
Part 1.3.
Control Center Ownership
The requirements address protection for Real-time Assessment and Real-time monitoring data while being
transmitted between Control Centers owned by a single Responsible Entity. They also cover the applicable data
transmitted between Control Centers owned by two or more separate Responsible Entities. Unlike protection
between a single Responsible Entity’s Control Centers, applying protection between Control Centers owned by more
than one Responsible Entity requires additional coordination. The requirements do not explicitly require formal
agreements between Responsible Entities partnering for protection of applicable data. It is strongly recommended,
however, that these partnering entities develop agreements, or use existing ones, to define responsibilities to ensure
the security objective is met. An example noted in FERC Order No. 822 Paragraph 59 is, “if several registered entities
have joint responsibility for a cryptographic key management system used between their respective Control Centers,
they should have the prerogative to come to a consensus on which organization administers that particular key
management system."
As an example, the reference model below shows some of the data transmissions between Control Centers that a
Responsible Entity should consider to be in-scope. The example does not include all possible scenarios. The solid
green lines are in-scope communications. The dashed red lines are out-of-scope communications.

NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1| May 2018
2

0 Requirement R1

This reference model is an example and does not include all possible scenarios.

NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1| May 2018
3

References
Here are several references to assist entities in developing plan(s) for protection of communication links:
•

NIST Special Publication 800-53A, Revision 4: Security and Privacy Controls for Federal Information Systems
and Organizations

•

NIST Special Publication 800-82: Guide to Industrial Control Systems (ICS) Security

•

NIST Special Publication 800-175B: Guideline for Using Cryptographic Standards in the Federal Government:
Cryptographic Mechanisms

•

NIST Special Publication 800-47: Security Guide for Interconnecting Information Technology Systems

NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1| May 2018
4

DRAFT

Cyber Security –
Communications between
Control Centers
Technical Rationale and Justification for
Reliability Standard CIP-012-1

March May 2018

NERC | Report Title | Report Date
I

Table of Contents
Preface ...................................................................................................................................................................... iii
Introduction .............................................................................................................................................................. iv
Requirement R1 ......................................................................................................................................................... 1
General Considerations for Requirement R1...................................................................................................... 1
Overview of confidentiality and integrity ........................................................................................................... 1
Alignment with IRO and TOP standards ............................................................................................................. 1
Identification of Where Security Protection is Applied by the Responsible Entity ............................................ 2
Control Center Ownership .................................................................................................................................. 2
References.................................................................................................................................................................. 4

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Preface
The vision for the Electric Reliability Organization (ERO) Enterprise, which is comprised of the North American Electric
Reliability Corporation (NERC) and the eight Regional Entities (REs), is a highly reliable and secure North American
bulk power system (BPS). Our mission is to assure the effective and efficient reduction of risks to the reliability and
security of the grid.
The North American BPS is divided into eight RE boundaries as shown in the map and corresponding table below.

The North American BPS is divided into eight RE boundaries. The highlighted areas denote overlap as some load-serving entities
participate in one Region while associated Transmission Owners/Operators participate in another.

FRCC

Florida Reliability Coordinating Council

MRO

Midwest Reliability Organization

NPCC

Northeast Power Coordinating Council

RF

ReliabilityFirst

SERC

SERC Reliability Corporation

SPP RE

Southwest Power Pool Regional Entity

Texas RE

Texas Reliability Entity

WECC

Western Electricity Coordinating Council

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Introduction
This document explains the technical rationale and justification for the proposed Reliability Standard CIP-012-1. It
will provide stakeholders and the ERO Enterprise with an understanding of the technology and technical
requirements in the Reliability Standard. It also contains information on the SDT’s intent in drafting the requirements.
This Technical Rationale and Justification for CIP-012-1 is not a Reliability Standard and should not be considered
mandatory and enforceable.
On January 21, 2016, the Federal Energy Regulatory Commission (FERC or Commission) issued Order No. 822,
approving seven Critical Infrastructure Protection (CIP) Reliability Standards and new or modified terms in the
Glossary of Terms Used in NERC Reliability Standards, and directing modifications to the CIP Reliability Standards.
Among others, the Commission directed the North American Electric Reliability Corporation (NERC) to “develop
modifications to the CIP Reliability Standards to require Responsible Entities 1 to implement controls to protect, at a
minimum, communication links and sensitive bulk electric system data communicated between bulk electric system
Control Centers in a manner that is appropriately tailored to address the risks posed to the bulk electric system by
the assets being protected (i.e., high, medium, or low impact).” (Order 822, Paragraph 53)
In response to the directive in Order No. 822, the Project 2016-02 standard drafting team (SDT) drafted Reliability
Standard CIP-012-1 to require Responsible Entities to implement controls to protect sensitive Bulk Electric System
(BES) data and communications links between BES Control Centers. Due to the sensitivity of the data being
communicated between Control Centers, as defined in the Glossary of Terms Used in NERC Reliability Standards, the
standard applies to all impact levels (i.e., high, medium, or low impact).
Although the Commission directed NERC to develop modifications to CIP-006, the SDT determined that modifications
to CIP-006 would not be appropriate. There are differences between the plan(s) required to be developed and
implemented for CIP-012-1 and the protection required in CIP-006-6 Requirement R1 Part 1.10. CIP-012-1
Requirements R1 and R2 protect the applicable data during transmission between two separate Control Centers. CIP006 Requirement R1 Part 1.10 protects nonprogrammable communication components within an Electronic Security
Perimeter (ESP) but outside of a Physical Security Perimeter (PSP). The transmission of applicable data between
Control Centers takes place outside of an ESP. Therefore, the protection contained in CIP-006-6 Requirement R1 Part
1.10 does not apply.
The SDT drafted requirements to provide Responsible Entities the latitude to protect the communication links, the
data, or both to satisfy the security objective consistent with the capabilities of the Responsible Entity’s operational
environment.
CIP-012 Exemption (4.2.3) for certain Control Centers
As the SDT drafted CIP-012, it became aware of certain generating plant or Transmission substation situations where
such field assets could be dual-classified as Control Centers based on the current Control Center definition. However,
their communications to their normal BA or TOP Control Center are not the type of communications that are the
intended scope of CIP-012 as they do not differ from any other generating plant or substation. The SDT wrote an
exemption (Section 4.2.3 within CIP-012) for this particular scenario which is described in further detail below.

1

As used in the CIP Standards, a Responsible Entity refers to the registered entities subject to the CIP Standards.
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Introduction

Figure 1
Figure 1 above pictures a typical scenario with two Control Centers communicating (in this instance Entity C’s RC
Control Center and Entity A’s TOP Control Center). The communication between them is the intended scope of CIP012’s requirements if it meets the types of data inclusions and exclusions within the standard. The TOP Control Center
is communicating with an RTU at two of Entity B’s generating plants (Stations Alpha and Beta) and those RTU’s are
gathering information from each generating unit’s control system. Each generating unit at each plant has an HMI
(Human/Machine Interface; an operator workstation) that the local personnel use to operate their respective units.
Entity B decides that the generating unit at Station Beta, a small peaking facility, will only have an operator on site
during the day and the operator at Station Alpha should be able to remotely start the unit at Station Beta if necessary.

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Introduction

Figure 2
In Figure 2, Entity B installs a dedicated communications circuit from the control system on Station Beta’s control
system and puts a dedicated HMI at Station Alpha the operator can use. Station Alpha is now “one or more facilities
hosting operating personnel that monitor and control the BES in real time to perform the reliability tasks of…a
Generator Operator for generation Facilities at two or more locations.” It can now be dual-classified not only as a
generation resource but also as a Control Center.
The communications to the TOP and RC Control Centers from Figure 1 have not changed at all. No new cyber systems
are in place that can impact multiple units. No cyber systems have been added performing Control Center functions.
No additional risk from cyber systems has been added. The only thing that has changed is an HMI for Station Beta
has been moved within close physical proximity to an HMI for Station Alpha.

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Introduction

Figure 3
The SDT realized how this suddenly makes the communication noted in Figure 3 between Station Alpha and Entity
A’s TOP Control Center subject to CIP-012 although nothing has changed between them. There is no new risk
involved. Two HMI’s have been moved into the same room and suddenly a new NERC CIP standard applies to two
entities.
This is an anamoly of the current Control Center definition defining a facility, room, or building from which something
can be done without regard to how its done or with what systems. This is a generation specific example, but the SDT
can envision substations with an HMI or protective relay that “operating personnel” within the substation could use
to impact an adjacent substation. The SDT realizes that in the criteria for TO’s and GOP’s the “two or more geographic
locations” is not a precise enough filter for capturing what a Control Center truly is. The SDT’s attempts to address
this issue by clarifying the definition of Control Center pointed out larger issues that are not within the SDT’s SAR to
address at this time. Therefore the SDT is handling the issue this creates for CIP-012 by the 4.2.3 exemption within
the CIP-012 standard which reads:
4.2.3.
A Control Center at a generation resource or Transmission station or substation that
transmits to another Control Center Real-time Assessment or Real-time monitoring data pertaining only to
the generation resource or Transmission station or substation at which the transmitting Control Center is
located.
Control Centers located at a generation resource or Transmission station or substation that transmits Realtime Assessment and Real-time monitoring data to another Control Center and that data pertains only to
the generation resource or Transmission station or substation at which the Control Center is located.
The intent of this exemption is to exclude the normal RTU-style communication from a field asset about that field
asset’s status from CIP-012. Throughout this scenario or others like it, that communication has not changed and is
still the same data pertaining only to the single location. The SDT recognizes that this communication is not the
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Introduction

intent of the standard for protecting communications between Control Centers and this type of communications
can be using older legacy communication technology and protocols.

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Requirement R1
R1. The Responsible Entity shall implement, except under CIP Exceptional Circumstances, one or more

documented plan(s) to mitigate the risk of unauthorized disclosure or modification of Real-time
Assessment and Real-time monitoring data while being transmitted between any applicable Control
Centers. This requirement excludes oral communications. The Responsible Entity is not required to
include oral communications in its plan. The plan shall include: [Violation Risk Factor: Medium] [Time
Horizon: Operations Planning]
1.1

Identification of security protection used to mitigate the risk of unauthorized disclosure or
modification of Real-time Assessment and Real-time monitoring while being transmitted
between Control Centers;

1.2

Identification of where the Responsible Entity applied security protection for transmitting Realtime Assessment and Real-time monitoring data between Control Centers; and

1.3

If he Control Centers are owned or operated by different Responsible Entities,identify the
responsibilities of each Responsible Entity for applying security protection to the transmission of
Real-time Assessment and Real-time monitoring data between those Control Centers.

General Considerations for Requirement R1
Requirement R1 focuses on implementing a documented plan to protect information that is critical to the Real-time
operations of the Bulk Electric System while in transit between applicable Control Centers. The SDT does not intend
for the listed order of the three requirement parts to convey any sequence or significance.
Overview of confidentiality and integrity
The SDT drafted CIP-012-1 to address confidentiality and integrity of Real-time Assessment and Real-time monitoring
data. This is accomplished by drafting the requirement to mitigate the risk of unauthorized disclosure (confidentiality)
or modification (integrity). For this Standard, the SDT relied on the definitions of confidentiality and integrity as
defined by National Institute of Standards and Technology (NIST):
•

Confidentiality is defined as, “Preserving authorized restrictions on information access and disclosure,
including means for protecting personal privacy and proprietary information.” 2

•

Integrity is defined as, “Guarding against improper information modification or destruction, and includes
ensuring information non-repudiation and authenticity.” 3

The SDT asserts that the availability of this data is already required by the performance obligation of the Operating
and Planning Reliability Standards. The SDT drafted CIP-012 to address the data while being transmitted. The SDT
maintains that this data resides within BES Cyber Systems, and while at rest is protected by CIP-003 through CIP-011.
Alignment with IRO and TOP standards
The SDT recognized the FERC reference to additional Reliability Standards and the responsibilities to protect the
applicable data in accordance with NERC Reliability Standards TOP-003 and IRO-010. The SDT used these references
to drive the identification of sensitive BES data and chose to base the CIP-012 requirements on the Real-time data
specification elements in these standards. This approach provides consistent scoping of identified data, and does not
require each entity to devise its own list or inventory of this data. Many entities are required to provide this data
2
3

NIST Special Publication 800-53A, Revision 4, page B-3
NIST Special Publication 800-53A, Revision 4, page B-6
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0 Requirement R1

under agreements executed with their RC, BA or TOP. The SDT asserts that typically the RC, BA or TOP will identify
all data requiring protection for CIP-012-1 through the TOP-003 and IRO-010 Reliability Standards. However, the SDT
noted that there may be special instances during which Real-time Assessment or Real-time Monitoring monitoring
data is not identified by the RC, BA, or TOP. This would include data that may be exchanged between a Responsible
Entity’s primary and backup Control Center.
Identification of Where Security Protection is Applied by the Responsible Entity
The SDT noted the need for a Responsible Entity to identify where it will apply protection for applicable data. The
SDT did not specify the location where CIP-012 security protection must be applied to provide latitude for Responsible
Entities to implement the security controls in a manner best fitting their individual circumstances. This latitude
ensures entities can still take advantage of security measures, such as deep packet inspection implemented at or near
the EAP when ESPs are present, while maintaining the capability to protect the applicable data being transmitted
between Control Centers.
The SDT also recognizes that CIP-012 security protection may be applied to a Cyber Asset that is not an identified BES
Cyber Asset or EACMS. The identification of the Cyber Asset as the location where security protection is applied does
not expand the scope of Cyber Assets identified as applicable under Cyber Security Standards CIP-002 through CIP011.
The SDT understands that in data exchanges between Control Centers, a single entity may not be responsible for both
ends of the communication link. The SDT intends for a Responsible Entity to identify only where it applied security
protection. The Responsible Entity should not be held accountable for identifying where a neighboring entity applied
security protection at the neighboring entity’s facility. A Responsible Entity, however, may decide to take
responsibility for both ends of a communication link. For example, it may place a router in a neighboring entity’s data
center. In a scenario like this, where a Responsible Entity has taken responsibility for applying security protection on
both ends of the communication link, the Responsible Entity should identify where it applied security protection at
both ends of the link. The SDT intends for there to be alignment between the identification of where security
protection is applied in CIP-012 R1, Part 1.2 and the identification of Responsible Entity responsibilities in CIP-012 R1,
Part 1.3.
Control Center Ownership
The requirements address protection for Real-time Assessment and Real-time monitoring data while being
transmitted between Control Centers owned by a single Responsible Entity. They also cover the applicable data
transmitted between Control Centers owned by two or more separate Responsible Entities. Unlike protection
between a single Responsible Entity’s Control Centers, applying protection between Control Centers owned by more
than one Responsible Entity requires additional coordination. The requirements do not explicitly require formal
agreements between Responsible Entities partnering for protection of applicable data. It is strongly recommended,
however, that these partnering entities develop agreements, or use existing ones, to define responsibilities to ensure
the security objective is met. An example noted in FERC Order No. 822 Paragraph 59 is, “if several registered entities
have joint responsibility for a cryptographic key management system used between their respective Control Centers,
they should have the prerogative to come to a consensus on which organization administers that particular key
management system."
As an example, the reference model below shows some of the data transmissions between Control Centers that a
Responsible Entity should consider to be in-scope. The example does not include all possible scenarios. The solid
green lines are in-scope communications. The dashed red lines are out-of-scope communications.

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0 Requirement R1

This reference model is an example and does not include all possible scenarios.

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References
Here are several references to assist entities in developing plan(s) for protection of communication links:
•

NIST Special Publication 800-53A, Revision 4: Security and Privacy Controls for Federal Information Systems
and Organizations

•

NIST Special Publication 800-82: Guide to Industrial Control Systems (ICS) Security

•

NIST Special Publication 800-175B: Guideline for Using Cryptographic Standards in the Federal Government:
Cryptographic Mechanisms

•

NIST Special Publication 800-47: Security Guide for Interconnecting Information Technology Systems

NERC | Technical Rationale and Justification for Relaibility Standard CIP-01202-1| Mayrch 2018
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DRAFT
Cyber Security –
Communications
Between Control
Centers
Implementation Guidance for CIP-012-1

NERC | Report Title | Report Date
I

Table of Contents
Introduction ................................................................................................................................................................3
Requirements .............................................................................................................................................................4
General Considerations ..............................................................................................................................................5
Identification of Security Protection ...................................................................................................................5
Identification of Where Security Protection is Applied by the Responsible Entity.............................................5
Reference Model ........................................................................................................................................................7
Reference Model Discussion ...............................................................................................................................7
Identification of Security Protection ...................................................................................................................8
Identification of Where Security Protection is Applied by the Responsible Entity.............................................9
Identification of Responsibilities when the Control Centers are Owned or Operated by Different Responsible
Entities.................................................................................................................................................................9
References ............................................................................................................................................................... 12

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Introduction
The Project 2016-02 SDT drafted this Implementation Guidance to provide example approaches for compliance
with CIP-012-1. Implementation Guidance does not prescribe the only approach, but highlights one or more
approaches that would be effective in achieving compliance with the standard. Because Implementation Guidance
only provides examples, entities may choose alternative approaches that better fit their individual situations 1.
Responsible Entities may find it useful to consider this Implementation Guidance document along with the
additional context and background provided in the SDT-developed Technical Rationale and Justification for CIP012-1 document.

Background

The Commission issued Order No. 822 on January 21, 2016. Order 822 approving seven CIP Reliability Standards
and new or modified definitions, and directed modifications be made to the CIP Reliability Standards. Among
other items, the Commission directed NERC to “develop modifications to the CIP Reliability Standards to require
responsible entities to implement controls to protect, at a minimum, communication links and sensitive bulk
electric system data communicated between bulk electric system Control Centers in a manner that is
appropriately tailored to address the risks posed to the bulk electric system by the assets being protected (i.e.,
high, medium, or low impact).” (Order 822, Paragraph 53)
In response to the directive in Order No. 822, the Project 2016-02 standard drafting team (SDT) drafted Reliability
Standard CIP-012-1 to require Responsible Entities to implement controls to protect sensitive Bulk Electric System
(BES) data and communications links between BES Control Centers. Due to the sensitivity of the data being
communicated between Control Centers, the standard applies to all impact levels (i.e., high, medium, or low
impact).
The SDT drafted requirements to provide Responsible Entities the latitude to protect the communication links,
the data, or both, to satisfy the security objective consistent with the capabilities of the Responsible Entity’s
operational environment.

1

NERC’s Compliance Guidance Policy
NERC | DRAFT CIP-012-1 Implementation Guidance | May 2018
3

Requirements
R1.

The Responsible Entity shall implement, except under CIP Exceptional Circumstances, one or
more documented plan(s) to mitigate the risk of unauthorized disclosure or modification of
Real-time Assessment and Real-time monitoring data while being transmitted between any
applicable Control Centers. The Responsible Entity is not required to include oral
communications in its plan. The plan shall include: [Violation Risk Factor: Medium] [Time
Horizon: Operations Planning]
1.1. Identification of security protection used to mitigate the risk of unauthorized disclosure or
modification of Real-time Assessment and Real-time monitoring data while being
transmitted between Control Centers;
1.2. Identification of where the Responsible Entity applied security protection for transmitting
Real-time Assessment and Real-time monitoring and control data between Control
Centers; and
1.3. If the Control Centers are owned or operated by different Responsible Entities, identify the
responsibilities of each Responsible Entity for applying security protection to the
transmission of Real-time Assessment and Real-time monitoring data between those
Control Centers.

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General Considerations
Plan Development
As noted in the Technical Rationale and Justification for CIP-012-1, the focus of Requirement R1 is implementing
a documented plan to protect information that is critical to the real-time operations of the Bulk Electric System
while in transit between applicable Control Centers. The number of plan(s) and their content may vary depending
on a Responsible Entity's management structure and operating conditions. The Responsible Entity may document
as many plans as necessary to meet its needs. For instance, a Responsible Entity may choose to document one
plan per Control Center or choose an all-inclusive, single plan for its Control Center communication environment.
A Responsible Entity may choose to document one plan for communications between Control Centers it owns and
a separate plan for communications between its Control Centers and the Control Centers of a neighboring Entity.
The number and structure of the plans is at the discretion of the Responsible Entity as long as the plan(s) include
the required elements described in parts 1.1, 1.2, and 1.3 of Requirement R1.
Identification of Security Protection
Entities have latitude to identify and choose which security protection is used to mitigate the risk of unauthorized
disclosure or modification of Real-time Assessment and Real-time monitoring data while being transmitted
between Control Centers.
This security protection could consist of logical protection, physical protection, or some combination of both. To
determine security protection, the requirement specifies that it must mitigate the risk of unauthorized disclosure
or modification of applicable data.
Security protection implementation can be demonstrated in many ways. If a Responsible Entity uses physical
protection, it may demonstrate implementation through review of an applicable Control Center floor plan with
details subsequently confirmed through visual inspection, which identifies the physical security measures in place
protecting the communication link. If the Responsible Entity uses logical protection, it may demonstrate
implementation through an export of the device configuration which applies the security protection. Alternatively,
a Responsible Entity may demonstrate implementation through security control monitoring, using an automated
monitoring tool to generate reports on the encryption service used to protect a communications link. Where the
operational obligations of an entire communication link, including both endpoints, belong to the Control Center
of another Responsible Entity, the Responsible Entity without operational obligations for the communication link
may demonstrate compliance by ensuring the communications link endpoint is within its Control Center, which
could be limited to including the communication link endpoint within a PSP.
Identification of Where Security Protection is Applied by the Responsible Entity
A Responsible Entity should consider its environment when identifying where security protections should be
applied. One approach is to implement security within the Control Center itself to ensure that data confidentiality
and integrity is protected throughout the transmission. The Responsible Entity can identify where security
protection is applied using a logical or physical location The application of security in accordance with CIP-012
requirements does not add additional assets to the scope of the CIP Reliability Standards. Locations of applied
security protection may vary based on many factors such as impact levels of the Control Center, different
technologies, or infrastructures. Where the operational obligations of an entire communication link, including
both endpoints, belong to the Control Center of another Responsible Entity, the Responsible Entity without
operational obligations for the communication link may demonstrate compliance by ensuring the communications
link endpoint is within its Control Center, which could be limited to including the communication link endpoint
within a PSP.
Identification of where a Responsible Entity applies security protection could be demonstrated with a list or a
Control Center diagram showing either physical or logical security controls. Physical diagrams may require visual

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confirmation of these controls. These diagrams or a list could be included within the plan developed for R1. A
Responsible Entity could also use labels to identify on-site devices where CIP-012 security protection is applied.
When exchanging data between two entities, if a Responsible Entity only manages one end of a communication
link, the Responsible Entity is not responsible for identifying where the security protection is applied by the
neighboring entity with which it is exchanging data. However, if a Responsible Entity has taken responsibility for
both ends of the communication link (such as by placing a router within the neighboring entity’s data center), then
the Responsible Entity shall identify where the security protection is applied at both ends of the link.
Similarly, if a Responsible Entity owns and operates both Control Centers which are exchanging data (such as in
the case of a primary and backup Control Center), then the Responsible Entity shall identify where security
protection is applied at both ends of the link.
Identification of Responsibilities when the Control Centers are Owned or Operated by Different
Responsible Entities

The Technical Rationale and Justification for CIP-012-1 identifies key considerations in the Control Center
Ownership section when communications between Control Centers with different owners or operators. Many
operational relationships between Responsible Entities are unique. Consequently, there is no single way to
identify responsibilities for applying security protection to the transmission of Real-time Assessment and Realtime monitoring data between Control Centers.
Implementation of responsibilities could also be demonstrated in many ways. Some examples include a joint
procedure, a memorandum of understanding, or meeting minutes between the two parties where responsibilities
are defined.
Where the operational obligations of an entire communication link, including both endpoints, belong to the
Control Center of another Responsible Entity, the Responsible Entity without operational obligations for the
communication link may demonstrate compliance by ensuring the communications link endpoint is within its
Control Center, which could be limited to including the communication link endpoint within a PSP. These
responsibilities should be included in both Responsible Entities’ plans satisfying requirement part 1.3.

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Reference Model
For this Implementation Guidance, the SDT uses a basic reference model of Primary and Backup Control Centers
(Entity Alpha) to illustrate approaches to demonstrating compliance. These Control Centers communicate to each
other and to a neighboring entity’s Control Center (Entity Beta) in configurations outlined by the diagrams in this
section. The SDT recognizes that the reference model does not contain many of the complexities of a real Control
Center. For this Implementation Guidance, the registration or functions performed in the reference model Control
Center are also not considered. A high level block diagram of the basic reference model is shown below in Figure
1. This Implementation Guidance is developed from the perspective of Entity Alpha.

Entity Alpha’s Primary
Control Center

Communication between Entity Alpha’s
Primary and Backup Control Center

Communication between Entity Alpha’s
Primary Control Center and Entity Beta’s Control Center

Entity Alpha’s Backup
Control Center

Communication between Entity Alpha’s
Backup Control Center and Entity Beta’s Control Center

Entity Beta’s Control
Center

Figure 1: High Level Block Diagram of Reference Model Control Centers

Reference Model Discussion
Requirement R1 requires the implementation of a documented plan. To comply with requirement R1, one
approach to a plan is to first determine which communications are in scope of CIP-012-1. There are multiple ways
to identify an entity’s scope in R1. For example, Entity Alpha in the reference model may first identify the Control
Centers with which it communicates. Entity Alpha would determine that there are three: Entity Alpha’s Primary
Control Center, Entity Alpha’s Backup Control Center, and Entity Beta’s Control Center. Entity Alpha does not need
to consider whether Entity Beta further shares its data with another Entity. That is the responsibility of Entity
Beta and is outside of Entity Alpha’s purview. Additionally, Entity Alpha does not need to consider any
communications to other non-Control Center facilities such as generating plants or substations. These
communications are out of scope for CIP-012-1.
Now that Entity Alpha has identified the Control Centers with which it communicates, Entity Alpha identifies
either: (1) the Real-time Assessment and Real-time monitoring data; or (2) communication links which are used
to transmit Real-time Assessment and Real-time monitoring data between Control Centers. In either case, Entity
Alpha should refer to the data specification for Real-time Assessment and Real-time monitoring data identified in
NERC | DRAFT CIP-012-1 Implementation Guidance | May 2018
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TOP-003-3 and IRO-010-2. For this reference model scenario, identifying the communication links used to
transmit Real-time Assessment and Real-time monitoring data may be the most straightforward approach.
Through an evaluation of communication links between Control Centers and an evaluation of how it transmits and
receives Real-time Assessment and Real-time monitoring data, Entity Alpha determined that it communicates
applicable data between its primary and backup Control Centers across a single communication link. Entity Alpha
also determined that it communicates applicable data to and from Entity Beta’s Control Center across one of two
links that originate from either Entity Alpha’s primary or backup Control Center using the Inter-Control Center
Communications Protocol (ICCP).
With an identified scope of communications links, Entity Alpha now considers the three required elements of its
required communications between Control Centers for its plan.
Identification of Security Protection

2

•

Entity Alpha must ensure that protection is applied where identified in its CIP-012-1 plan. The protection
must also meet the security objective of mitigating the risk of unauthorized disclosure or modification of
applicable data while in transit between Control Centers. The identification of security protection could
be demonstrated by a network diagram similar to that shown in Figure 2 or Figure 3.

•

In a simple case where the security protection is applied sufficiently close to the Control Center, such as
within the Physical Security Perimeter of the Control Center, Entity Alpha may use a single security
protection method to meet the security objective. For this case, shown in Figure 2, Entity Alpha
implements a Virtual Private Network (VPN) connection across a private leased communication circuit for
each of its three in-scope communication links. To meet the security objective, Entity Alpha further states
that its VPN uses Internet Protocol security (IPsec) with encryption.

•

For more complex scenarios, Entity Alpha may need to use a combination of security controls. For
instance, in Figure 3, Entity Alpha uses a combination of physical security controls (physical access control)
and logical security controls (encrypted communications consistent with the first scenario above) to meet
the security objective. The SDT notes that the same technical architecture could exist where the
responsibilities of the registered entities are different. Therefore as shown in Figure 2 & 3, in the scenario
where entity Alpha owns and operationally manages the communication link and endpoint equipment,
Entity Beta is responsible for ensuring the communication endpoint of the communication link is within a
Control Center. Entity Beta ensures Entity Alpha’s communication link endpoint equipment is within a
Control Center by including the communication endpoint within a Control Center PSP. The physical
controls for the PSP are described in CIP-006 documentation and do not need to be repeated for this
requirement. This satisfies Entity Beta’s obligation for Part 1.1 and 1.2.

•

While these scenarios are all specific to communication links, it is possible that Entity Alpha and Entity
Beta achieve the security objective by applying protection to the data rather than the communication
links. In this scenario, the application enabling the data exchange between Control Centers may be
capable of applying security controls directly to the data. These security controls mitigate the risk of
unauthorized disclosure or modification of applicable data rather than relying on lower level network
services to provide this security. For instance, Entity Alpha and Entity Beta may apply security protection
at the application layer by using Secure ICCP to exchange applicable data. According to a report released
by Sandia National Labs 2, Secure ICCP provides “data integrity indirectly by providing a cryptographic
checksum. Secure ICCP provides data confidentiality by encrypting ICCP data exchanges.” Methods other
than Secure ICCP could also be used to apply security protection to the data at the application layer.

•

It is theoretically possible that Entity Alpha and Entity Beta could exchange Real-time Assessment data
between Control Centers by email. In that scenario, one approach may be for Entity Alpha to email the

https://energy.gov/sites/prod/files/oeprod/DocumentsandMedia/19-Secure_ICCP_Integration.pdf
NERC | DRAFT CIP-012-1 Implementation Guidance | May 2018
8

applicable data to Entity Beta’s Control Center in a protected container such as an encrypted zip file. Entity
Alpha and Entity Beta can then exchange the password to that encrypted container through another
method, such as by phone. While the notional example of protecting data exchanged by email is a useful
illustration of how to achieve the security objective of CIP-012-1, it is extremely unlikely to be used in
practice. The characteristics of email communication are inconsistent with the requirements of Real-time
data exchange.
Identification of Where Security Protection is Applied by the Responsible Entity

Similar to the identification of security protection above, the identification of where security protection is applied
can also be demonstrated by a network diagram similar to those found in Figures 2 and 3.
•

Figure 2 shows the identification where CIP-012-1 security protection is applied for the Entity Alpha
reference model when a single encrypted tunnel is used to implement the required protection. Entity
Alpha has identified that security protection is applied at each of its Control Centers on the external
Ethernet interface on the WAN router. While the diagram depicts where Entity Beta has applied security
protection for illustrative purposes, Entity Alpha is not responsible for identifying where Entity Beta has
applied security protection.

•

In order to understand the application of security protection in context of who controls the
communication link, it may be helpful to identify both where CIP-012-1 security protection is applied and
the location of the telecommunications carrier (telco) demarcation point. Figure 3 provides such an
example where the telco demarcation point may not be within the Control Center and based the facts
and circumstances surrounding this scenario, Entity Alpha has implemented a combination of security
controls to comply with CIP-012-1. In this scenario, Entity Alpha identifies that it has applied physical
security protection for its PSP and continuing for its WAN router and that it has applied logical security
protection (encryption) at the WAN router. Entity Alpha has also identified the telco demarcation point at
a point in the telecommunications cabling connecting to Entity Alpha’s WAN router, perhaps at a punch
down block for example. In Figure 3, the telco demarcation point is inside the same room as the WAN
router. The telco demarcation points are referenced in the drawing for clarity, but are not part of the plan.

•

Figure 2 & 3 provides an example of where the operational obligations of an entire communications link,
including both endpoints, belong to Entity Alpha. In this case, Entity Beta may be responsible for ensuring
the communications endpoint of the communications link is within their Control Center. Entity Beta
ensures Entity Alpha’s communication link endpoint equipment is within a Control Center by including the
communication endpoint within a Control Center PSP. The documentation provided for Part 1.1 by Entity
Beta fulfils this obligation.

•

The data-centric scenario described above is less intuitive for identifying where security protection is
applied by Entity Alpha. If security protection is applied at the application layer (such as Secure ICCP),
Entity Alpha could reasonably identify the application or service applying the security (such as the Secure
ICCP service) as the location of where security protection is applied.

Identification of Responsibilities when the Control Centers are Owned or Operated by Different
Responsible Entities

Entity Alpha and Entity Beta may determine they each are responsible for one end of the VPN configuration on
their respective WAN routers. Entity Alpha and Entity Beta have agreed to a 30 character pre-shared key for IPSec
authentication.
Rather than use a pre-shared key, Entity Alpha and Entity Beta may decide to use digital certificates for the IPSec
authentication using a trusted certificate authority. In that scenario, Entity Alpha and Entity Beta would agree on
who is the party responsible for managing the certificate authority.
In the example where the communication link and endpoint equipment are owned by Entity Alpha, both entities
should include ownership responsibilities in their plans satisfying requirement 1.3. Examples include but are not
NERC | DRAFT CIP-012-1 Implementation Guidance | May 2018
9

limited to, a letter indicating ownership or responsibility, a copy of a contract indicating ownership or
responsibilities, an excerpt from an operational agreement or manual indicating ownership or responsibility.

Entity Alpha’s Primary
Control Center

Entity Alpha’s CIP-012
security protection applied
at the external interface of
the WAN router

Entity Alpha’s CIP-012
security protection applied
at the external interface of
the WAN router

Entity Alpha’s Backup
Control Center

WAN Router

WAN Router

ESP Firewall

ESP Firewall

Operator Application Database
Workstations Server
Server

ICCP
Server

Operator Application Database
Workstations Server
Server

ICCP
Server

Communications Carrier
Entity Beta’s CIP-012
security protection applied
at the external interface of
the WAN router

Entity Beta’s
Control Center
WAN Router

ESP Firewall

Operator Application Database
Workstations Server
Server

In the case where Entity Alpha owns
and operationally manages the
communication link and endpoint
equipment, Entity Beta ensures
Entity Alpha’s endpoint equipment
is within the Control Center. Entity
Alpha includes any logical security
protection applied to the
communication link in their plan

ICCP
Server

Figure 2: Network diagram and identification of where security protection is applied

NERC | DRAFT CIP-012-1 Implementation Guidance | May 2018
10

Entity Alpha’s CIP-012
physical security
protection applied

Physically secured area

Physically secured area

Entity Alpha’s Primary
Control Center

WAN Router
Entity Alpha’s CIP-012
logical security
protection applied

ESP Firewall

Entity Alpha’s Backup
Control Center

WAN Router
Telco
Demarcation
Point

Telco
Demarcation
Point

Entity Alpha’s CIP-012
physical security
protection applied

Entity Alpha’s CIP-012
logical security
protection applied

ESP Firewall

Encrypted
Communications
Operator Application Database
Workstations Server
Server

ICCP
Server

Operator Application Database
Workstations Server
Server

ICCP
Server

Communications Carrier
Entity Beta’s CIP-012
security protection
applied

Entity Beta’s
Control Center
WAN Router

ESP Firewall

Operator Application Database
Workstations Server
Server

In the case where Entity Alpha owns
and operationally manages the
communication link and endpoint
equipment, Entity Beta ensures
Entity Alpha’s endpoint equipment
is within the Control Center. Entity
Alpha includes any logical security
protection applied to the
communication link in their plan

ICCP
Server

Figure 3: Network diagram using a combination of controls for CIP-012-1

NERC | DRAFT CIP-012-1 Implementation Guidance | May 2018
11

References
Mitre Common Weakness Enumeration (CWE™) list of software weakness types
https://cwe.mitre.org/data/definitions/327.html
Cryptographic Standards and Guidelines
https://csrc.nist.gov/Projects/Cryptographic-Standards-and-Guidelines
NIST Special Publication 800-175B
Guideline for Using Cryptographic Standards in the Federal Government: Cryptographic Mechanisms
http://nvlpubs.nist.gov/nistpubs/SpecialPublications/NIST.SP.800-175B.pdf
Guide to Cryptography
https://www.owasp.org/index.php/Guide_to_Cryptography#Symmetric_Cryptography

NERC | DRAFT CIP-012-1 Implementation Guidance | May 2018
12

DRAFT
Cyber Security –
Communications
Between Control
Centers
Implementation Guidance for CIP-012-1

NERC | Report Title | Report Date
I

Table of Contents
Introduction ................................................................................................................................................................3
Requirements .............................................................................................................................................................4
General Considerations ..............................................................................................................................................5
Identification of Security Protection ...................................................................................................................5
Identification of Where Security Protection is Applied by the Responsible Entity.............................................5
Reference Model ........................................................................................................................................................7
Reference Model Discussion ...............................................................................................................................7
Identification of Security Protection ...................................................................................................................8
Identification of Where Security Protection is Applied by the Responsible Entity.............................................9
Identification of Responsibilities when the Control Centers are Owned or Operated by Different Responsible
Entities.................................................................................................................................................................9
References ............................................................................................................................................................... 12

NERC | DRAFT CIP-012-1 Implementation Guidance | March May 2018
2

Introduction
The Project 2016-02 SDT drafted this Implementation Guidance to provide example approaches for compliance
with CIP-012-1. Implementation Guidance does not prescribe the only approach, but highlights one or more
approaches that would be effective in achieving compliance with the standard. Because Implementation Guidance
only provides examples, entities may choose alternative approaches that better fit their individual situations 1.
Responsible Entities may find it useful to consider this Implementation Guidance document along with the
additional context and background provided in the SDT-developed Technical Rationale and Justification for CIP012-1 document.

Background

The Commission issued Order No. 822 on January 21, 2016. Order 822 approving sevenapproving seven CIP
Reliability Standards and new or modified definitions, and directed modifications be made to the CIP Reliability
Standards. Among other items, the Commission directed NERC to “develop modifications to the CIP Reliability
Standards to require responsible entities to implement controls to protect, at a minimum, communication links
and sensitive bulk electric system data communicated between bulk electric system Control Centers in a manner
that is appropriately tailored to address the risks posed to the bulk electric system by the assets being protected
(i.e., high, medium, or low impact).” (Order 822, Paragraph 53)
In response to the directive in Order No. 822, the Project 2016-02 standard drafting team (SDT) drafted Reliability
Standard CIP-012-1 to require Responsible Entities to implement controls to protect sensitive Bulk Electric System
(BES) data and communications links between BES Control Centers. Due to the sensitivity of the data being
communicated between Control Centers, the standard applies to all impact levels (i.e., high, medium, or low
impact).
The SDT drafted requirements to provide Responsible Entities the latitude to protect the communication links,
the data, or both, to satisfy the security objective consistent with the capabilities of the Responsible Entity’s
operational environment.

1

NERC’s Compliance Guidance Policy
NERC | DRAFT CIP-012-1 Implementation Guidance | March May 2018
3

Requirements
R1.

The Responsible Entity shall implement, except under CIP Exceptional Circumstances, one or
more documented plan(s) to mitigate the risk of unauthorized disclosure or modification of
Real-time Assessment and Real-time monitoring data while being transmitted between any
applicable Control Centers. This requirement excludes oral communicationsThe Responsible
Entity is not required to include oral communications in its plan. The plan shall include:
[Violation Risk Factor: Medium] [Time Horizon: Operations Planning]
1.1. Identification of security protection used to mitigate the risk of unauthorized disclosure or
modification of Real-time Assessment and Real-time monitoring data while being
transmitted between Control Centers;
1.2. Identification of where the Responsible Entity applied security protection for transmitting
Real-time Assessment and Real-time monitoring and control data between Control
Centers; and
1.3. If the Control Centers are owned or operated by different Responsible Entities, identify the
responsibilities of each Responsible Entity for applying security protection to the
transmission of Real-time Assessment and Real-time monitoring data between those
Control Centers.

NERC | DRAFT CIP-012-1 Implementation Guidance | March May 2018
4

General Considerations
Plan Development
As noted in the Technical Rationale and Justification for CIP-012-1, the focus of Requirement R1 is implementing
a documented plan to protect information that is critical to the real-time operations of the Bulk Electric System
while in transit between applicable Control Centers. The number of plan(s) and their content may vary depending
on a Responsible Entity's management structure and operating conditions. The Responsible Entity may document
as many plans as necessary to meet its needs. For instance, a Responsible Entity may choose to document one
plan per Control Center or choose an all-inclusive, single plan for its Control Center communication environment.
A Responsible Entity may choose to document one plan for communications between Control Centers it owns and
a separate plan for communications between its Control Centers and the Control Centers of a neighboring Entity.
The number and structure of the plans is at the discretion of the Responsible Entity as long as the plan(s) include
the required elements described in parts 1.1, 1.2, and 1.3 of Requirement R1.
Identification of Security Protection
Entities have latitude to identify and choose which security protection is used to mitigate the risk of unauthorized
disclosure or modification of Real-time Assessment and Real-time monitoring data while being transmitted
between Control Centers.
This security protection could consist of logical protection, physical protection, or some combination of both. To
determine security protection, the requirement specifies that it must mitigate the risk of unauthorized disclosure
or modification of applicable data.
Security protection implementation can be demonstrated in many ways. If a Responsible Entity uses physical
protection, it may demonstrate implementation through review of an applicable Control Center floor plan with
details subsequently confirmed through visual inspection, which identifies the physical security measures in place
protecting the communication link. If the Responsible Entity uses logical protection, it may demonstrate
implementation through an export of the device configuration which applies the security protection. Alternatively,
a Responsible Entity may demonstrate implementation through security control monitoring, using an automated
monitoring tool to generate reports on the encryption service used to protect a communications link. Where the
operational obligations of an entire communication link, including both endpoints, belong to the Control Center
of another Responsible Entity, the Responsible Entity without operational obligations for the communication link
may demonstrate compliance by ensuring the communications link endpoint is within its Control Center, which
could be limited to including the communication link endpoint within a PSP.
Identification of Where Security Protection is Applied by the Responsible Entity
A Responsible Entity should consider its environment when identifying where security protections should be
applied. One approach is to implement security within the Control Center itself to ensure that data confidentiality
and integrity is protected throughout the transmission. The Responsible Entity can identify where security
protection is applied using a logical or physical location The application of security in accordance with CIP-012
requirements does not add additional assets to the scope of the CIP Reliability Standards. Locations of applied
security protection may vary based on many factors such as impact levels of the Control Center, different
technologies, or infrastructures. Where the operational obligations of an entire communication link, including
both endpoints, belong to the Control Center of another Responsible Entity, the Responsible Entity without
operational obligations for the communication link may demonstrate compliance by ensuring the communications
link endpoint is within its Control Center, which could be limited to including the communication link endpoint
within a PSP.
Identification of where a Responsible Entity applies security protection could be demonstrated with a list or a
Control Center diagram showing either physical or logical security controls. Physical diagrams may require visual
NERC | DRAFT CIP-012-1 Implementation Guidance | March May 2018
5

confirmation of these controls. These diagrams or a list could be included within the plan developed for R1. A
Responsible Entity could also use labels to identify on-site devices where CIP-012 security protection is applied.
When exchanging data between two entities, if a Responsible Entity only manages one end of a communication
link, the Responsible Entity is not responsible for identifying where the security protection is applied by the
neighboring entity with whomwhich it is exchanging data. However, if a Responsible Entity has taken
responsibility for both ends of the communication link (such as by placing a router within the neighboring entity’s
data center), then the Responsible Entity shall identify where the security protection is applied at both ends of
the link.
Similarly, if a Responsible Entity owns and operates both Control Centers which are exchanging data (such as in
the case of a primary and backup Control Center), then the Responsible Entity shall identify where security
protection is applied at both ends of the link.
Identification of Responsibilities when the Control Centers are Owned or Operated by Different
Responsible Entities

The Technical Rationale and Justification for CIP-012-1 identifies key considerations in the Control Center
Ownership section when communications between Control Centers with different owners or operators. Many
operational relationships between Responsible Entities are unique. Consequently, there is no single way to
identify responsibilities for applying security protection to the transmission of Real-time Assessment and Realtime monitoring data between Control Centers.
Implementation of responsibilities could also be demonstrated in many ways. Some examples include a joint
procedure, a memorandum of understanding, or meeting minutes between the two parties where responsibilities
are defined.
Where the operational obligations of an entire communication link, including both endpoints, belong to the
Control Center of another Responsible Entity, the Responsible Entity without operational obligations for the
communication link may demonstrate compliance by ensuring the communications link endpoint is within its
Control Center, which could be limited to including the communication link endpoint within a PSP. These
responsibilities should be included in both Responsible Entities’ plans satisfying requirement part 1.3.

NERC | DRAFT CIP-012-1 Implementation Guidance | March May 2018
6

Reference Model
For this Implementation Guidance, the SDT uses a basic reference model of Primary and Backup Control Centers
(Entity Alpha) to illustrate approaches to demonstrating compliance. These Control Centers communicate to each
other and to a neighboring entity’s Control Center (Entity Beta) in configurations outlined by the diagrams in this
section. The SDT recognizes that the reference model does not contain many of the complexities of a real Control
Center. For this Implementation Guidance, the registration or functions performed in the reference model Control
Center are also not considered. A high level block diagram of the basic reference model is shown below in Figure
1. This Implementation Guidance is developed from the perspective of Entity Alpha.

Entity Alpha’s Primary
Control Center

Communication between Entity Alpha’s
Primary and Backup Control Center

Communication between Entity Alpha’s
Primary Control Center and Entity Beta’s Control Center

Entity Alpha’s Backup
Control Center

Communication between Entity Alpha’s
Backup Control Center and Entity Beta’s Control Center

Entity Beta’s Control
Center

Figure 1: High Level Block Diagram of Reference Model Control Centers

Reference Model Discussion
Requirement R1 requires the implementation of a documented plan. To comply with requirement R1, one
approach to a plan is to first determine which communications are in scope of CIP-012-1. There are multiple ways
to identify an entity’s scope in R1. For example, Entity Alpha in the reference model may first identify the Control
Centers with which it communicates. Entity Alpha would determine that there are three: Entity Alpha’s Primary
Control Center, Entity Alpha’s Backup Control Center, and Entity Beta’s Control Center. Entity Alpha does not
need to consider whether Entity Beta further shares its data with another Entity. That is the responsibility of
Entity Beta and is outside of Entity Alpha’s purview. Additionally, Entity Alpha does not need to consider any
communications to other non-Control Center facilities such as generating plants or substations. These
communications are out of scope for CIP-012-1.
Now that Entity Alpha has identified the Control Centers with which it communicates, Entity Alpha identifies
either: (1) the Real-time Assessment and Real-time monitoring data; or (2) communication links which are used
to transmit Real-time Assessment and Real-time monitoring data between Control Centers. In either case, Entity
Alpha should refer to the data specification for Real-time Assessment and Real-time monitoring data identified in
NERC | DRAFT CIP-012-1 Implementation Guidance | March May 2018
7

TOP-003-3 and IRO-010-2. For this reference model scenario, identifying the communication links used to
transmit Real-time Assessment and Real-time monitoring data may be the most straightforward approach.
Through an evaluation of communication links between Control Centers and an evaluation of how it transmits and
receives Real-time Assessment and Real-time monitoring data, Entity Alpha determined that it communicates
applicable data between its primary and backup Control Centers across a single communication link. Entity Alpha
also determined that it communicates applicable data to and from Entity Beta’s Control Center across one of two
links that originate from either Entity Alpha’s primary or backup Control Center using the Inter-Control Center
Communications Protocol (ICCP).
With an identified scope of communications links, Entity Alpha now considers the three required elements of its
required communications between Control Centers for its plan.
Identification of Security Protection

2

•

Entity Alpha must ensure that protection is applied where identified in its CIP-012-1 plan. The protection
must also meet the security objective of mitigating the risk of unauthorized disclosure or modification of
applicable data while in transit between Control Centers. The identification of security protection could
be demonstrated by a network diagram similar to that shown in Figure 2 or Figure 3.

•

In a simple case where the security protection is applied sufficiently close to the Control Center, such as
within the Physical Security Perimeter of the Control Center, Entity Alpha may use a single security
protection method to meet the security objective. For this case, shown in Figure 2, Entity Alpha
implements a Virtual Private Network (VPN) connection across a private leased communication circuit for
each of its three in-scope communication links. To meet the security objective, Entity Alpha further states
that its VPN uses Internet Protocol security (IPsec) with encryption.

•

For more complex scenarios, Entity Alpha may need to use a combination of security controls. For
instance, in Figure 3, Entity Alpha uses a combination of physical security controls (physical access control)
and logical security controls (encrypted communications consistent with the first scenario above) to meet
the security objective. The SDT notes that the same technical architecture could exist where the
responsibilities of the registered entities are different. AlternatelyTherefore as shown in Figure 2 & 3, in
the scenario where entity Alpha owns and operationally manages the communication link and endpoint
equipment, Entity Beta is responsible for ensuring the communication endpoint of the communication
link is within a Control Center. Entity Beta ensures Entity Alpha’s communication link endpoint equipment
is within a Control Center by including the communication endpoint within a Control Center PSP. The
physical controls for the PSP are described in CIP-006 documentation and do not need to be repeated for
this requirement. This satisfies Entity Beta’s obligation for Part 1.1 and 1.2.

•

While these scenarios are all specific to communication links, it is possible that Entity Alpha and Entity
Beta achieve the security objective by applying protection to the data rather than the communication
links. In this scenario, the application enabling the data exchange between Control Centers may be
capable of applying security controls directly to the data. These security controls mitigate the risk of
unauthorized disclosure or modification of applicable data rather than relying on lower level network
services to provide this security. For instance, Entity Alpha and Entity Beta may apply security protection
at the application layer by using Secure ICCP to exchange applicable data. According to a report released
by Sandia National Labs 2, Secure ICCP provides “data integrity indirectly by providing a cryptographic
checksum. Secure ICCP provides data confidentiality by encrypting ICCP data exchanges.” Methods other
than Secure ICCP could also be used to apply security protection to the data at the application layer.

•

It is theoretically possible that Entity Alpha and Entity Beta could exchange Real-time Assessment data
between Control Centers by email. In that scenario, one approach may be for Entity Alpha to email the

https://energy.gov/sites/prod/files/oeprod/DocumentsandMedia/19-Secure_ICCP_Integration.pdf
NERC | DRAFT CIP-012-1 Implementation Guidance | March May 2018
8

applicable data to Entity Beta’s Control Center in a protected container such as an encrypted zip file. Entity
Alpha and Entity Beta can then exchange the password to that encrypted container through another
method, such as by phone. While the notional example of protecting data exchanged by email is a useful
illustration of how to achieve the security objective of CIP-012-1, it is extremely unlikely to be used in
practice. The characteristics of email communication are inconsistent with the requirements of Real-time
data exchange.
Identification of Where Security Protection is Applied by the Responsible Entity

Similar to the identification of security protection above, the identification of where security protection is applied
can also be demonstrated by a network diagram similar to those found in Figures 2 and 3.
•

Figure 2 shows the identification where CIP-012-1 security protection is applied for the Entity Alpha
reference model when a single encrypted tunnel is used to implement the required protection. Entity
Alpha has identified that security protection is applied at each of its Control Centers on the external
Ethernet interface on the WAN router. While the diagram depicts where Entity Beta has applied security
protection for illustrative purposes, Entity Alpha is not responsible for identifying where Entity Beta has
applied security protection.

•

In order to understand the application of security protection in context of who controls the
communication link, it may be helpful to identify both where CIP-012-1 security protection is applied and
the location of the telecommunications carrier (telco) demarcation point. Figure 3 provides such an
example where the telco demarcation point may not be within the Control Center and based the facts
and circumstances surrounding this scenario, Entity Alpha hascircumstances’ surrounding this scenario,
Entity Alpha has implemented a combination of security controls to comply with CIP-012-1. In this
scenario, Entity Alpha identifies that it has applied physical security protection for its PSP and continuing
for its WAN router and that it has applied logical security protection (encryption) at the WAN router. Entity
Alpha has also identified the telco demarcation point at a point in the telecommunications cabling
connecting to Entity Alpha’s WAN router, perhaps at a punch down block for example. In Figure 3, the
telco demarcation point is inside the same room as the WAN router. The telco demarcation points are
referenced in the drawing for clarity, but are not part of the plan.

•

Figure 2 & 3 provides an example of where the operational obligations of an entire communications link,
including both endpoints, belong to Entity Alpha. In this case, Entity Beta may be responsible for ensuring
the communications endpoint of the communications link is within their Control Center. Entity Beta
ensures Entity Alpha’s communication link endpoint equipment is within a Control Center by including the
communication endpoint within a Control Center PSP. The documentation provided for Part 1.1 by Entity
Beta fulfils this obligation.

•

The data-centric scenario described above is less intuitive for identifying where security protection is
applied by Entity Alpha. If security protection is applied at the application layer (such as Secure ICCP),
Entity Alpha could reasonably identify the application or service applying the security (such as the Secure
ICCP service) as the location of where security protection is applied.

Identification of Responsibilities when the Control Centers are Owned or Operated by Different
Responsible Entities

Entity Alpha and Entity Beta may determine they each are responsible for one end of the VPN configuration on
their respective WAN routers. Entity Alpha and Entity Beta have agreed to a 30 character pre-shared key for IPSec
authentication.
Rather than use a pre-shared key, Entity Alpha and Entity Beta may decide to use digital certificates for the IPSec
authentication using a trusted certificate authority. In that scenario, Entity Alpha and Entity Beta would agree on
who is the party responsible for managing the certificate authority.

NERC | DRAFT CIP-012-1 Implementation Guidance | March May 2018
9

In the example where the communication link and endpoint equipment are owned by Entity Alpha, both entities
should include ownership responsibilities in their plans satisfying requirement 1.3. Examples include but are not
limited to, a letter stating indicating ownership or responsibility, a copy of a contract indicating ownership or
responsibilities, an excerpt from an operational agreement or manual indicating ownership or responsibility.

Entity Alpha’s Primary
Control Center

Entity Alpha’s CIP-012
security protection applied
at the external interface of
the WAN router

Entity Alpha’s CIP-012
security protection applied
at the external interface of
the WAN router

Entity Alpha’s Backup
Control Center

WAN Router

WAN Router

ESP Firewall

ESP Firewall

Operator Application Database
Workstations Server
Server

ICCP
Server

Operator Application Database
Workstations Server
Server

ICCP
Server

Communications Carrier
Entity Beta’s CIP-012
security protection applied
at the external interface of
the WAN router

Entity Beta’s
Control Center
WAN Router

ESP Firewall

Operator Application Database
Workstations Server
Server

In the case where Entity Alpha owns
and operationally manages the
communication link and endpoint
equipment, Entity Beta ensures
Entity Alpha’s endpoint equipment
is within the Control Center. Entity
Alpha includes any logical security
protection applied to the
communication link in their plan

ICCP
Server

Figure 2: Network diagram and identification of where security protection is applied

NERC | DRAFT CIP-012-1 Implementation Guidance | March May 2018
10

Entity Alpha’s CIP-012
physical security
protection applied

Physically secured area

Physically secured area

Entity Alpha’s Primary
Control Center

WAN Router
Entity Alpha’s CIP-012
logical security
protection applied

ESP Firewall

Entity Alpha’s Backup
Control Center

WAN Router
Telco
Demarcation
Point

Telco
Demarcation
Point

Entity Alpha’s CIP-012
physical security
protection applied

Entity Alpha’s CIP-012
logical security
protection applied

ESP Firewall

Encrypted
Communications
Operator Application Database
Workstations Server
Server

ICCP
Server

Operator Application Database
Workstations Server
Server

ICCP
Server

Communications Carrier
Entity Beta’s CIP-012
security protection
applied

Entity Beta’s
Control Center
WAN Router

ESP Firewall

Operator Application Database
Workstations Server
Server

In the case where Entity Alpha owns
and operationally manages the
communication link and endpoint
equipment, Entity Beta ensures
Entity Alpha’s endpoint equipment
is within the Control Center. Entity
Alpha includes any logical security
protection applied to the
communication link in their plan

ICCP
Server

Figure 3: Network diagram using a combination of controls for CIP-012-1

NERC | DRAFT CIP-012-1 Implementation Guidance | March May 2018
11

References
Mitre Common Weakness Enumeration (CWE™) list of software weakness types
https://cwe.mitre.org/data/definitions/327.html
Cryptographic Standards and Guidelines
https://csrc.nist.gov/Projects/Cryptographic-Standards-and-Guidelines
NIST Special Publication 800-175B
Guideline for Using Cryptographic Standards in the Federal Government: Cryptographic Mechanisms
http://nvlpubs.nist.gov/nistpubs/SpecialPublications/NIST.SP.800-175B.pdf
Guide to Cryptography
https://www.owasp.org/index.php/Guide_to_Cryptography#Symmetric_Cryptography

NERC | DRAFT CIP-012-1 Implementation Guidance | March May 2018
12

Reliability Standard Audit Worksheet1
CIP-012-1 – Cyber Security – Communications between Control Centers
This section to be completed by the Compliance Enforcement Authority.
Audit ID:
Registered Entity:
NCR Number:
Compliance Enforcement Authority:
Compliance Assessment Date(s) 2:
Compliance Monitoring Method:
Names of Auditors:

Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
Registered name of entity being audited
NCRnnnnn
Region or NERC performing audit
Month DD, YYYY, to Month DD, YYYY
[On-site Audit | Off-site Audit | Spot Check]
Supplied by CEA

Applicability of Requirements
R1

BA
X

DP

GO
X

GOP
X

PA/PC

RC
X

Legend:
Text with blue background:
Text entry area with Green background:
Text entry area with white background:

RP

RSG

TO
X

TOP
X

TP

TSP

Fixed text – do not edit
Entity-supplied information
Auditor-supplied information

NERC developed this Reliability Standard Audit Worksheet (RSAW) language in order to facilitate NERC’s and the Regional Entities’ assessment of a registered entity’s
compliance with this Reliability Standard. The NERC RSAW language is written to specific versions of each NERC Reliability Standard. Entities using this RSAW should
choose the version of the RSAW applicable to the Reliability Standard being assessed. While the information included in this RSAW provides some of the methodology
that NERC has elected to use to assess compliance with the requirements of the Reliability Standard, this document should not be treated as a substitute for the
Reliability Standard or viewed as additional Reliability Standard requirements. In all cases, the Regional Entity should rely on the language contained in the Reliability
Standard itself, and not on the language contained in this RSAW, to determine compliance with the Reliability Standard. NERC’s Reliability Standards can be found on
NERC’s website. Additionally, NERC Reliability Standards are updated frequently, and this RSAW may not necessarily be updated with the same frequency. Therefore,
it is imperative that entities treat this RSAW as a reference document only, and not as a substitute or replacement for the Reliability Standard. It is the responsibility
of the registered entity to verify its compliance with the latest approved version of the Reliability Standards, by the applicable governmental authority, relevant to its
registration status.

1

The RSAW may provide a non-exclusive list, for informational purposes only, of examples of the types of evidence a registered entity may produce or may be asked to
produce to demonstrate compliance with the Reliability Standard. A registered entity’s adherence to the examples contained within this RSAW does not necessarily
constitute compliance with the applicable Reliability Standard, and NERC and the Regional Entity using this RSAW reserve the right to request additional evidence from
the registered entity that is not included in this RSAW. This RSAW may include excerpts from FERC Orders and other regulatory references which are provided for ease
of reference only, and this document does not necessarily include all applicable Order provisions. In the event of a discrepancy between FERC Orders, and the language
included in this document, FERC Orders shall prevail.
2

Compliance Assessment Date(s): The date(s) the actual compliance assessment (on-site audit, off-site spot check, etc.) occurs.

DRAFT NERC Reliability Standard Audit Worksheet

Findings
(This section to be completed by the Compliance Enforcement Authority)
Req.
Finding
Summary and Documentation
R1

Req.

Areas of Concern

Req.

Recommendations

Req.

Positive Observations

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft4_v1 Revision Date: June 11, 2018 RSAW Template: RSAW2017R3.0
2

Functions Monitored

DRAFT NERC Reliability Standard Audit Worksheet

Subject Matter Experts
Identify the Subject Matter Expert(s) responsible for this Reliability Standard.
Registered Entity Response (Required; Insert additional rows if needed):
SME Name
Title
Organization

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft4_v1 Revision Date: June 11, 2018 RSAW Template: RSAW2017R3.0
3

Requirement(s)

DRAFT NERC Reliability Standard Audit Worksheet

Registered Entity Response (Required):
Question 1: Does the Registered Entity own or operate an applicable Control Center? ☐ Yes ☐ No
If no:
1. Provide evidence in the space below that the Registered Entity does not own or operate an applicable
Control Center. This evidence may include, but is not limited to:
• Evidence that the Registered Entity does not own or operate an applicable Control Center; or
• Evidence or a reference to evidence from the Registered Entity’s CIP-002 compliance program
that demonstrates the Registered Entity does not own or operate an applicable Control Center.
2. The remainder of this RSAW may be left blank.
[Note: A separate spreadsheet or other document may be used. If so, provide the document reference
below.]

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft4_v1 Revision Date: June 11, 2018 RSAW Template: RSAW2017R3.0
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DRAFT NERC Reliability Standard Audit Worksheet

R1 Supporting Evidence and Documentation
R1.

M1.

The Responsible Entity shall implement, except under CIP Exceptional Circumstances, one or more documented
plan(s) to mitigate the risk of unauthorized disclosure or modification of Real-time Assessment and Real-time
monitoring data while being transmitted between any applicable Control Centers. The Responsible Entity is not
required to include oral communications in its plan. The plan shall include: [Violation Risk Factor: Medium] [Time
Horizon: Operations Planning]
1.1

Identification of security protection used to mitigate the risk of unauthorized disclosure or modification of
Real-time Assessment and Real-time monitoring data while being transmitted between Control Centers;

1.2

Identification of where the Responsible Entity applied security protection for transmitting Real-time
Assessment and Real-time monitoring data between Control Centers; and

1.3

If the Control Centers are owned or operated by different Responsible Entities, identify the responsibilities
of each Responsible Entity for applying security protection to the transmission of Real-time Assessment
and Real-time monitoring data between those Control Centers.

Evidence may include, but is not limited to, documented plan(s) that meet the security objective of Requirement
R1 and documentation demonstrating the implementation of the plan(s).

Registered Entity Response (Required):
Compliance Narrative:

Provide a brief explanation, in your own words, of how you comply with this Requirement. References to supplied
evidence, including links to the appropriate page, are recommended.

Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.
Relevant
Revision
Page(s)
or
Document
or
Description of Applicability
File Name
Document Title
Version
Date
Section(s)
of Document

Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft4_v1 Revision Date: June 11, 2018 RSAW Template: RSAW2017R3.0
5

DRAFT NERC Reliability Standard Audit Worksheet

Compliance Assessment Approach Specific to CIP-012-1, R1
This section to be completed by the Compliance Enforcement Authority
If the Registered Entity has answered “No” to Question 1, verify the Registered Entity does not own or
operate an applicable Control Center.
Note: If the Registered Entity does not own or operate an applicable Control Center, the remainder of
this RSAW is not applicable.
Verify the entity has implemented, except under CIP Exceptional Circumstances, one or more
documented plan(s) to mitigate the risk of the unauthorized disclosure or modification of Real-time
Assessment and Real-time monitoring data while being transmitted between any applicable Control
Centers.
Verify the documented plans collectively include identification of security protection used to mitigate
the risk of unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring
data while being transmitted between any applicable Control Centers.
Verify the documented plans collectively include identification of where the Responsible Entity applied
security protection for transmitting Real-time Assessment and Real-time monitoring data between any
applicable Control Centers.
If Real-time Assessment or Real-time monitoring data is transmitted between any applicable Control
Centers owned or operated by different Responsible Entities, verify the documented plans collectively
include identification of the responsibilities of each Responsible Entity for applying security protection
to these transmissions.
Verify the documented plans collectively achieve the security objective of mitigating the risk of the
unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring data while
being transmitted between any applicable Control Centers.
If the Responsible Entity has declared and responded to CIP Exceptional Circumstances, verify the
Responsible Entity has adhered to the applicable cyber security policies.
Notes to Auditor:
1. The Responsible Entity is not required to include oral communications in its plan.
2. See Applicability Section 4.2.3 for a decription of Control Centers that are exempt from this
Standard.
Auditor Notes:

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft4_v1 Revision Date: June 11, 2018 RSAW Template: RSAW2017R3.0
6

DRAFT NERC Reliability Standard Audit Worksheet

Additional Information:
Reliability Standard
The full text of CIP-012-1 may be found on the NERC Web Site (www.nerc.com) under “Program Areas &
Departments”, “Standards,” “Reliability Standards.”
In addition to the Reliability Standard, there is an applicable Implementation Plan available on the NERC Web
Site.
In addition to the Reliability Standard, there is background information available on the NERC Web Site.
Capitalized terms in the Reliability Standard refer to terms in the NERC Glossary, which may be found on the
NERC Web Site.
Sampling Methodology
Sampling is essential for auditing compliance with NERC Reliability Standards since it is not always possible
or practical to test 100% of either the equipment, documentation, or both, associated with the full suite of
enforceable standards. The Sampling Guide contained in the Compliance Monitoring and Enforcement Manual
(see NERC website) provided by the Electric Reliability Organization help to establish a minimum sample set
for monitoring and enforcement uses in audits of NERC Reliability Standards.
Regulatory Language
FERC Order 822 P53-56, 58, and 62
Selected Glossary Terms
The following Glossary terms are provided for convenience only. Please refer to the NERC web site for the
current enforceable terms.
CIP Exceptional Circumstance
A situation that involves or threatens to involve one or more of the following, or similar, conditions that
impact safety or BES reliability: a risk of injury or death; a natural disaster; civil unrest; an imminent or existing
hardware, software, or equipment failure; a Cyber Security Incident requiring emergency assistance; a
response by emergency services; the enactment of a mutual assistance agreement; or an impediment of large
scale workforce availability.
Control Center
One or more facilities hosting operating personnel that monitor and control the Bulk Electric System (BES) in
real-time to perform the reliability tasks, including their associated data centers, of:
1) a Reliability Coordinator,
2) a Balancing Authority,
3) a Transmission Operator for transmission Facilities at two or more locations, or
4) a Generator Operator for generation Facilities at two or more locations.

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft4_v1 Revision Date: June 11, 2018 RSAW Template: RSAW2017R3.0
7

DRAFT NERC Reliability Standard Audit Worksheet

Real-time Assessment
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.)
Real-time
Present time as opposed to future time.

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft4_v1 Revision Date: June 11, 2018 RSAW Template: RSAW2017R3.0
8

DRAFT NERC Reliability Standard Audit Worksheet

Revision History for RSAW
Version
Draft1 v1
Draft1 v2
Draft1 v3

Date
07/28/2017
08/01/2017
08/02/2017

Reviewers
NERC Stds Group
RSAW Task Force
RSAW Task Force

Draft1 v4

08/07/2017

RSAW Task Force,
2016-02 SDT

Draft2 v1

10/27/2017

RSAW Task Force

Draft2 v2

11/27/2017

RSAW Task Force,
Standard Drafting
Team

Draft3 v0

03/20/2018

RSAW Task Force

Revision Description
New document
Modified Question to clarify applicability
Response to MRO comments. Moved Questions
1 and 2 above R1. Made text changes to Q1 and
to R2 Compliance Assessment Approach.
Response to TexasRE and SDT comments.
Clarified scope of Q1 to be data transmitted
between Control Centers. Removed extra space
from Auditor Notes.
Modified title.
Modified Q2 to conform with new language.
Modified R1 with new Requirement text and new
Compliance Assessment Approach.
Modified R2 with new Compliance Assessment
Approach.
Removed Operational Planning Analysis from the
Selected Glossary Terms.
Modified footer with revised version and date.
Response to comments:
• RF: Footnote 1 page 1 added space after
“references.”
• RF: Changed “Tasf” to “Task” in Revision
History.
• Response to SERC CIPC and Southern
Company comments to Draft 1.
• Modified Question 1 to include reference
to CIP-002.
• Added an item to the R1 Compliance
Assessment Approach to verify the
effectiveness of the process.
• Modified the R2 Compliance Assessment
Approaches to clarify that the review is
for implementation.
Modified for Draft 3 language:
• Removed Requirement R2
• Modified Requirement R1 language to
match the Standard
• Modified the R1 Compliannce Assessment
Approach

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft4_v1 Revision Date: June 11, 2018 RSAW Template: RSAW2017R3.0
9

DRAFT NERC Reliability Standard Audit Worksheet

•

Draft3 v1

04/03/2018

ERO Enterprise

Draft3 v2

4/25/2018

NERC Legal

Draft4 v0

5/19/2018

RSAW Task Force

Draft4 v1

6/4/2018

RSAW Task Force

Draft4 v2

6/11/2018

NERC Compliance
/NERC Legal

Removed “CIP Exceptional Circumstance”
from the Selected Glossary Terms
• Revised the definition of “Control Center”
in Selected Glossary Terms to match the
definition posted alongside CIP-012-1
Draft 3
• Consideration of Comments from RF
o Changed Sampling Methodology
section to match current NERC
documents. Will also need to be
reflected in the RSAW Template.
Addressed comments. No text changes were
made.
Modified for Draft 4 language:
• Modified Question 1 to reference
“applicable” Control Centers
• Modified Requirement R1 language to
match the Standard
• Modified the R1 Compliance Assessment
Approach
• Modified the Note to Auditor in
Compliance Assessment Approach
• Restored the definition of “CIP
Exceptional Circumstance” to the
Selected Glossary Terms
• Restored the approved definition of
“Control Center” to the Selected Glossary
Terms
Modified language of Question 1 to more closely
match the Standard.
Addressed corrections/comments from NERC:
• Corrected “entity” to “Registered Entity”
in Question 1
• Addressed question regarding use of (s) in
certain cases
• Corrected “of responsibilities” to “of the
responsibilities” in CAA item 5
• Addressed comment regarding CAA item
5
• Addressed comment regarding additional
Note to Auditor
• Removed underlining from definition of
Control Center

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft4_v1 Revision Date: June 11, 2018 RSAW Template: RSAW2017R3.0
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DRAFT NERC Reliability Standard Audit Worksheet

•
•

Inserted hyphen into real-time in Control
Center definition
Added “any applicable” Control Center to
CAA items 3, 4, and 6.

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft4_v1 Revision Date: June 11, 2018 RSAW Template: RSAW2017R3.0
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Reliability Standard Audit Worksheet1
CIP-012-1 – Cyber Security – Communications between Control Centers
This section to be completed by the Compliance Enforcement Authority.
Audit ID:
Registered Entity:
NCR Number:
Compliance Enforcement Authority:
Compliance Assessment Date(s) 2:
Compliance Monitoring Method:
Names of Auditors:

Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
Registered name of entity being audited
NCRnnnnn
Region or NERC performing audit
Month DD, YYYY, to Month DD, YYYY
[On-site Audit | Off-site Audit | Spot Check]
Supplied by CEA

Applicability of Requirements
R1

BA
X

DP

GO
X

GOP
X

PA/PC

RC
X

Legend:
Text with blue background:
Text entry area with Green background:
Text entry area with white background:

RP

RSG

TO
X

TOP
X

TP

TSP

Fixed text – do not edit
Entity-supplied information
Auditor-supplied information

1 NERC developed this Reliability Standard Audit Worksheet (RSAW) language in order to facilitate NERC’s and the Regional Entities’ assessment of a registered entity’s
compliance with this Reliability Standard. The NERC RSAW language is written to specific versions of each NERC Reliability Standard. Entities using this RSAW should
choose the version of the RSAW applicable to the Reliability Standard being assessed. While the information included in this RSAW provides some of the methodology
that NERC has elected to use to assess compliance with the requirements of the Reliability Standard, this document should not be treated as a substitute for the
Reliability Standard or viewed as additional Reliability Standard requirements. In all cases, the Regional Entity should rely on the language contained in the Reliability
Standard itself, and not on the language contained in this RSAW, to determine compliance with the Reliability Standard. NERC’s Reliability Standards can be found on
NERC’s website. Additionally, NERC Reliability Standards are updated frequently, and this RSAW may not necessarily be updated with the same frequency. Therefore,
it is imperative that entities treat this RSAW as a reference document only, and not as a substitute or replacement for the Reliability Standard. It is the responsibility
of the registered entity to verify its compliance with the latest approved version of the Reliability Standards, by the applicable governmental authority, relevant to its
registration status.

The RSAW may provide a non-exclusive list, for informational purposes only, of examples of the types of evidence a registered entity may produce or may be asked to
produce to demonstrate compliance with the Reliability Standard. A registered entity’s adherence to the examples contained within this RSAW does not necessarily
constitute compliance with the applicable Reliability Standard, and NERC and the Regional Entity using this RSAW reserve the right to request additional evidence from
the registered entity that is not included in this RSAW. This RSAW may include excerpts from FERC Orders and other regulatory references which are provided for ease
of reference only, and this document does not necessarily include all applicable Order provisions. In the event of a discrepancy between FERC Orders, and the language
included in this document, FERC Orders shall prevail.
2

Compliance Assessment Date(s): The date(s) the actual compliance assessment (on-site audit, off-site spot check, etc.) occurs.

DRAFT NERC Reliability Standard Audit Worksheet

Findings
(This section to be completed by the Compliance Enforcement Authority)
Req.
Finding
Summary and Documentation
R1

Req.

Areas of Concern

Req.

Recommendations

Req.

Positive Observations

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft4_v10 Revision Date: June 114May 19, 2018 RSAW Template: RSAW2017R3.0
2

Functions Monitored

DRAFT NERC Reliability Standard Audit Worksheet

Subject Matter Experts
Identify the Subject Matter Expert(s) responsible for this Reliability Standard.
Registered Entity Response (Required; Insert additional rows if needed):
SME Name
Title
Organization

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft4_v10 Revision Date: June 114May 19, 2018 RSAW Template: RSAW2017R3.0
3

Requirement(s)

DRAFT NERC Reliability Standard Audit Worksheet

Registered Entity Response (Required):
Question 1: Does the Registered Entity own or operate a an applicable Control Center? ☐ Yes ☐ No
If no:
1. Provide evidence in the space below that the Registered Entity does not own or operate one or
morean applicable Control Centers. This evidence may include, but is not limited to:
• Evidence that the Registered Entity does not own or operate a an applicable Control Center; or
• Evidence or a reference to evidence from the Registered Entity’s CIP-002 compliance program
that demonstrates the entity Registered Entity does not own or operate a an applicable Control
Center.
2. The remainder of this RSAW may be left blank.
[Note: A separate spreadsheet or other document may be used. If so, provide the document reference
below.]

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft4_v10 Revision Date: June 114May 19, 2018 RSAW Template: RSAW2017R3.0
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DRAFT NERC Reliability Standard Audit Worksheet

R1 Supporting Evidence and Documentation
R1.

M1.

The Responsible Entity shall implement, except under CIP Exceptional Circumstances, one or more documented
plan(s) to mitigate the risk of unauthorized disclosure or modification of Real-time Assessment and Real-time
monitoring data while being transmitted between any applicable Control Centers. The Responsible Entity is not
required to includeThis requirement excludes oral communications in its plan. The plan shall include: [Violation
Risk Factor: Medium] [Time Horizon: Operations Planning]
1.1

Identification of security protection used to mitigate the risk of unauthorized disclosure or modification of
Real-time Assessment and Real-time monitoring data while being transmitted between Control Centers;

1.2

Identification of where the Responsible Entity applied security protection for transmitting Real-time
Assessment and Real-time monitoring data between Control Centers; and

1.3

If the Control Centers are owned or operated by different Responsible Entities, identify the responsibilities
of each Responsible Entity for applying security protection to the transmission of Real-time Assessment
and Real-time monitoring data between those Control Centers.

Evidence may include, but is not limited to, documented plan(s) that meet the security objective of Requirement
R1 and documentation demonstrating the implementation of the plan(s).

Registered Entity Response (Required):
Compliance Narrative:

Provide a brief explanation, in your own words, of how you comply with this Requirement. References to supplied
evidence, including links to the appropriate page, are recommended.

Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.
Relevant
Revision
Page(s)
or
Document
or
Description of Applicability
File Name
Document Title
Version
Date
Section(s)
of Document

Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft4_v10 Revision Date: June 114May 19, 2018 RSAW Template: RSAW2017R3.0
5

DRAFT NERC Reliability Standard Audit Worksheet

Compliance Assessment Approach Specific to CIP-012-1, R1
This section to be completed by the Compliance Enforcement Authority
If the Registered Entity has answered “No” to Question 1, verify the Registered Entity does not own or
operate an applicable Control Center.
Note: If the Registered Entity does not own or operate an applicable Control Center, the remainder of
this RSAW is not applicable.
Verify the entity has implemented, except under CIP Exceptional Circumstances, one or more
documented plan(s) to mitigate the risk of the unauthorized disclosure or modification of Real-time
Assessment and Real-time monitoring data while being transmitted between any applicable Control
Centers.
Verify the documented plans collectively include identification of security protection used to mitigate
the risk of unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring
data while being transmitted between any applicable Control Centers.
Verify the documented plans collectively include identification of where the Responsible Entity applied
security protection for transmitting Real-time Assessment and Real-time monitoring data between any
applicable Control Centers.
If Real-time Assessment or Real-time monitoring data is transmitted between any applicable Control
Centers owned or operated by different Responsible Entities, Vverify the documented plans collectively
include identification of the responsibilities of each Responsible Entity for applying security protection
to these transmissionsthe transmission of Real-time Assessment and Real-time monitoring data
between Control Centers, when the Control Centers are owned or operated by different Responsible
Entities.
Verify the documented plans collectively achieve the security objective of mitigating the risk of the
unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring data while
being transmitted between any applicable Control Centers.
If the Responsible Entity has declared and responded to CIP Exceptional Circumstances, verify the
Responsible Entity has adhered to the applicable cyber security policies.
Notes to Auditor:
1. The Responsible Entity is not required to include oral communications in its plan.Oral
communications are not in scope for CIP-012-1.
1.2. See Applicability Section 4.2.3 for a decription of Control Centers that are exempt from this
Standard.
Auditor Notes:

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft4_v10 Revision Date: June 114May 19, 2018 RSAW Template: RSAW2017R3.0
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DRAFT NERC Reliability Standard Audit Worksheet

Additional Information:
Reliability Standard
The full text of CIP-012-1 may be found on the NERC Web Site (www.nerc.com) under “Program Areas &
Departments”, “Standards,” “Reliability Standards.”
In addition to the Reliability Standard, there is an applicable Implementation Plan available on the NERC Web
Site.
In addition to the Reliability Standard, there is background information available on the NERC Web Site.
Capitalized terms in the Reliability Standard refer to terms in the NERC Glossary, which may be found on the
NERC Web Site.
Sampling Methodology
Sampling is essential for auditing compliance with NERC Reliability Standards since it is not always possible
or practical to test 100% of either the equipment, documentation, or both, associated with the full suite of
enforceable standards. The Sampling Guide contained in the Compliance Monitoring and Enforcement Manual
(see NERC website) provided by the Electric Reliability Organization help to establish a minimum sample set
for monitoring and enforcement uses in audits of NERC Reliability Standards.
Regulatory Language
FERC Order 822 P53-56, 58, and 62
Selected Glossary Terms
The following Glossary terms are provided for convenience only. Please refer to the NERC web site for the
current enforceable terms.
CIP Exceptional Circumstance
A situation that involves or threatens to involve one or more of the following, or similar, conditions that
impact safety or BES reliability: a risk of injury or death; a natural disaster; civil unrest; an imminent or existing
hardware, software, or equipment failure; a Cyber Security Incident requiring emergency assistance; a
response by emergency services; the enactment of a mutual assistance agreement; or an impediment of large
scale workforce availability.
Control Center
One or more facilities hosting operating personnel that monitor and control the Bulk Electric System (BES) in
real-time to perform the reliability tasks, including their associated data centers, of:
1) a Reliability Coordinator,
2) a Balancing Authority,
3) a Transmission Operator for transmission Facilities at two or more locations, or
4) a Generator Operator for generation Facilities at two or more locations.
One or more facilities, including their associated data centers, that monitor and control the Bulk Electric
System (BES) and also host operating personnel who:
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft4_v10 Revision Date: June 114May 19, 2018 RSAW Template: RSAW2017R3.0
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DRAFT NERC Reliability Standard Audit Worksheet

1) perform the Real-time reliability-related tasks of a Reliability Coordinator; or
2) perform the Real-time reliability-related tasks of a Balancing Authority; or
3) perform the Real-time reliability-related tasks of a Transmission Operator for Transmission Facilities at
two or more locations; or
4) can act independently as the Generator Operator to develop specific dispatch instructions for
generation Facilities at two or more locations; or
5) can operate or direct the operation of a Transmission Owner’s BES Transmission Facilities in Real-time.
Operating personnel do not include:
1) plant operators located at a generator plant site or personnel at a centrally located dispatch center
who relay dispatch instructions without making any modifications; or
2) Transmission Owner or Transmission Operator field switching personnel.
Real-time Assessment
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.)
Real-time
Present time as opposed to future time.

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft4_v10 Revision Date: June 114May 19, 2018 RSAW Template: RSAW2017R3.0
8

DRAFT NERC Reliability Standard Audit Worksheet

Revision History for RSAW
Version
Draft1 v1
Draft1 v2
Draft1 v3

Date
07/28/2017
08/01/2017
08/02/2017

Reviewers
NERC Stds Group
RSAW Task Force
RSAW Task Force

Draft1 v4

08/07/2017

RSAW Task Force,
2016-02 SDT

Draft2 v1

10/27/2017

RSAW Task Force

Draft2 v2

11/27/2017

RSAW Task Force,
Standard Drafting
Team

Draft3 v0

03/20/2018

RSAW Task Force

Revision Description
New document
Modified Question to clarify applicability
Response to MRO comments. Moved Questions
1 and 2 above R1. Made text changes to Q1 and
to R2 Compliance Assessment Approach.
Response to TexasRE and SDT comments.
Clarified scope of Q1 to be data transmitted
between Control Centers. Removed extra space
from Auditor Notes.
Modified title.
Modified Q2 to conform with new language.
Modified R1 with new Requirement text and new
Compliance Assessment Approach.
Modified R2 with new Compliance Assessment
Approach.
Removed Operational Planning Analysis from the
Selected Glossary Terms.
Modified footer with revised version and date.
Response to comments:
• RF: Footnote 1 page 1 added space after
“references.”
• RF: Changed “Tasf” to “Task” in Revision
History.
• Response to SERC CIPC and Southern
Company comments to Draft 1.
• Modified Question 1 to include reference
to CIP-002.
• Added an item to the R1 Compliance
Assessment Approach to verify the
effectiveness of the process.
• Modified the R2 Compliance Assessment
Approaches to clarify that the review is
for implementation.
Modified for Draft 3 language:
• Removed Requirement R2
• Modified Requirement R1 language to
match the Standard
• Modified the R1 Compliannce Assessment
Approach

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft4_v10 Revision Date: June 114May 19, 2018 RSAW Template: RSAW2017R3.0
9

DRAFT NERC Reliability Standard Audit Worksheet

•

Draft3 v1

04/03/2018

ERO Enterprise

Draft3 v2

4/25/2018

NERC Legal

Draft4 v0

5/19/2018

RSAW Task Force

Draft4 v1

6/4/2018

RSAW Task Force

Draft4 v2

6/11/2018

NERC Compliance
/NERC Legal

Removed “CIP Exceptional Circumstance”
from the Selected Glossary Terms
• Revised the definition of “Control Center”
in Selected Glossary Terms to match the
definition posted alongside CIP-012-1
Draft 3
• Consideration of Comments from RF
o Changed Sampling Methodology
section to match current NERC
documents. Will also need to be
reflected in the RSAW Template.
Addressed comments. No text changes were
made.
Modified for Draft 4 language:
• Modified Question 1 to reference
“applicable” Control Centers
• Modified Requirement R1 language to
match the Standard
• Modified the R1 Compliance Assessment
Approach
• Modified the Note to Auditor in
Compliance Assessment Approach
• Restored the definition of “CIP
Exceptional Circumstance” to the
Selected Glossary Terms
• Restored the approved definition of
“Control Center” to the Selected Glossary
Terms
Modified language of Question 1 to more closely
match the Standard.
Addressed corrections/comments from NERC:
• Corrected “entity” to “Registered Entity”
in Question 1
• Addressed question regarding use of (s) in
certain cases
• Corrected “of responsibilities” to “of the
responsibilities” in CAA item 5
• Addressed comment regarding CAA item
5
• Addressed comment regarding additional
Note to Auditor
• Removed underlining from definition of
Control Center

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft4_v10 Revision Date: June 114May 19, 2018 RSAW Template: RSAW2017R3.0
10

DRAFT NERC Reliability Standard Audit Worksheet

•
•

Inserted hyphen into real-time in Control
Center definition
Added “any applicable” Control Center to
CAA items 3, 4, and 6.

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_CIP-012-1_Draft4_v10 Revision Date: June 114May 19, 2018 RSAW Template: RSAW2017R3.0
11

Standards Announcement

Project 2016-02 Modifications to CIP Standards
Formal Comment Period Open through July 2, 2018
Now Available

A 45-day formal comment period for CIP-012-1 – Cyber Security - Communications between Control
Centers is open through 8 p.m. Eastern, Monday, July 2, 2018.
The Technical Rationale and Implementation Guidance Documents for CIP-012-1 will be posted within 15
days of the comment period opening.
Additionally, the CIP standard drafting team (SDT) proposed a revised Control Center definition during
the March 16 – April 30, 2018 comment and ballot period. Based on feedback received from industry,
the SDT decided to draft exemption language within the applicability section of CIP-012 instead of
revising the Control Center definition. Please see the Control Center definition consideration of
comments report for additional SDT responses on the new path taken by the SDT.
Commenting

Use the Standards Balloting and Commenting System (SBS) to submit comments. If you experience
difficulties navigating the SBS, contact Wendy Muller. An unofficial Word version of the comment form is
posted on the project page.
•

If you are having difficulty accessing the SBS due to a forgotten password, incorrect
credential error messages, or system lock-out, contact NERC IT support directly at
https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5 p.m. Eastern).

•

Passwords expire every 6 months and must be reset.

•

The SBS is not supported for use on mobile devices.

•

Please be mindful of ballot and comment period closing dates. We ask to allow at least 48
hours for NERC support staff to assist with inquiries. Therefore, it is recommended that users try
logging into their SBS accounts prior to the last day of a comment/ballot period.

Next Steps

An additional ballot for the Standard and a non-binding poll of the associated Violation Risk Factors and
Violation Severity Levels will be conducted June 22 – July 2, 2018.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Standards Developer, Jordan Mallory at (404) 446-2589.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | May-July, 2018

2

Comment Report
Project Name:

2016-02 Modifications to CIP Standards | CIP-012-1 Draft 4

Comment Period Start Date:

5/18/2018

Comment Period End Date:

7/3/2018

Associated Ballots:

2016-02 Modifications to CIP Standards CIP-012-1 AB 4 ST

There were 55 sets of responses, including comments from approximately 149 different people from approximately 101 companies
representing 10 of the Industry Segments as shown in the table on the following pages.

Questions
1. Control Center Exemption Language: The SDT drafted Exemption language in the Applicability section specifically for CIP-012-1 to exempt
Control Centers that only transmit data pertaining to a single co-located substation or generating plant. Do you agree with this revision? If
not, please provide the basis for your disagreement and an alternate proposal.

2. Requirement R1: The SDT modified Requirement R1 to state: “The Responsible Entity shall implement, except under CIP Exceptional
Circumstances, one or more documented plan(s) to mitigate the risk of unauthorized disclosure or modification of Real-time Assessment and
Real-time monitoring data while being transmitted between any applicable Control Centers. The Responsible Entity is not required to include
oral communications in its plan.” Do you agree with this revision? If not, please provide the basis for your disagreement and an alternate
proposal.

3. Implementation Plan: The SDT established the Implementation Plan to make the standard effective the first day of the first calendar quarter
that is twenty-four (24) calendar months after the effective date of the applicable governmental authority’s order approving the standard, or
as otherwise provided for by the applicable governmental authority. Do you agree with this proposal? If you think an alternate
implementation time period is needed, please provide a detailed explanation of actions and time needed to meet the implementation deadline.

4. Technical Rationale: The SDT modified the draft Technical Rationale for CIP-012 to further explain the need for the exemption for certain
Control Centers. Do you agree with the explanations and included diagrams in the draft Technical Rationale? If you do not agree, or if you
agree but have comments or suggestions for the draft Technical Rationale, please provide your recommendation and explanation.

5. The SDT modified the draft Implementation Guidance for CIP-012 to provide examples of how a Responsible Entity could comply with the
requirements. The draft Implementation Guidance does not prescribe the only approaches to compliance. Rather, it describes what the SDT
believes would be effective ways to comply with the standard. See NERC’s Compliance Guidance policy for information on Implementation
Guidance. Do you agree with the draft Implementation Guidance? If you do not agree, or if you agree but have comments or suggestions for
the draft Implementation Guidance, please provide your recommendation and explanation.

6. The SDT believes proposed CIP-012-1 provides entities with flexibility to meet the reliability objectives in a cost effective manner. Do you
agree? If you do not agree, or if you agree but have suggestions for improvement to enable more cost effective approaches, please provide
your recommendation and, if appropriate, technical justification.

Organization
Name
FirstEnergy FirstEnergy
Corporation

Brandon
McCormick

Name

Aaron
Ghodooshim

Brandon
McCormick

Segment(s)

3

Region

RF

FRCC

Group Name Group Member
Name

Group
Member
Organization

FirstEnergy
Corporation

Aaron
Ghdooshim

FirstEnergy FirstEnergy
Corporation

4

RF

Aubrey Short

FirstEnergy FirstEnergy
Corporation

1

RF

Theresa Ciancio

FirstEnergy FirstEnergy
Corporation

3

RF

Robert Loy

FirstEnergy FirstEnergy
Solutions

5

RF

Ann Ivanc

FirstEnergy FirstEnergy
Solutions

6

RF

Tim Beyrle

City of New
4
Smyrna Beach
Utilities
Commission

FRCC

Jim Howard

Lakeland
Electric

5

FRCC

Lynne Mila

City of
Clewiston

4

FRCC

Javier Cisneros

Fort Pierce
Utilities
Authority

3

FRCC

Randy Hahn

Ocala Utility
Services

3

FRCC

Don Cuevas

Beaches
Energy
Services

1

FRCC

Jeffrey Partington Keys Energy
Services

4

FRCC

Tom Reedy

6

FRCC

3

FRCC

FMPA

Florida
Municipal
Power Pool

Steven Lancaster Beaches
Energy
Services

Group
Member
Segment(s)

Group Member
Region

Santee
Cooper

Duke Energy

MRO

Chris Wagner

Colby Bellville

Dana Klem

1

1,3,5,6

1,2,3,4,5,6

Santee
Cooper

Mike Blough

Kissimmee
Utility
Authority

5

FRCC

Chris Adkins

City of
Leesburg

3

FRCC

Ginny Beigel

City of Vero
Beach

3

FRCC

Rene' Free

Santee
Cooper

1,3,5,6

SERC

Rodger Blakely

Santee
Cooper

1,3,5,6

SERC

Troy Lee

Santee
Cooper

1,3,5,6

SERC

Jennifer Richards Santee
Cooper

1,3,5,6

SERC

Chris Jimenez

Santee
Cooper

1,3,5,6

SERC

Duke Energy

1

RF

Lee Schuster

Duke Energy

3

FRCC

Dale Goodwine

Duke Energy

5

SERC

Greg Cecil

Duke Energy

6

RF

Joseph
DePoorter

Madison Gas
& Electric

3,4,5,6

MRO

Larry Heckert

Alliant Energy 4

MRO

Amy Casucelli

Xcel Energy

1,3,5,6

MRO

Michael
Brytowski

Great River
Energy

1,3,5,6

MRO

Jodi Jensen

Western Area 1,6
Power
Administration

MRO

Kayleigh
Wilkerson

Lincoln
Electric
System

1,3,5,6

MRO

Mahmood Safi

Omaha Public 1,3,5,6
Power District

MRO

Brad Parret

Minnesota
Powert

1,5

MRO

Terry Harbour

MidAmerican
Energy
Company

1,3

MRO

FRCC,RF,SERC Duke Energy Doug Hils

MRO

MRO NSRF

Southern
Pamela Hunter 1,3,5,6
Company Southern
Company
Services, Inc.

Northeast
Power
Coordinating
Council

Ruida Shu

SERC

1,2,3,4,5,6,7,8,9,10 NPCC

Southern
Company

RSC no
Dominion

Tom Breene

Wisconsin
3,5,6
Public Service
Corporation

MRO

Jeremy Voll

Basin Electric 1
Power
Cooperative

MRO

Kevin Lyons

Central Iowa
Power
Cooperative

1

MRO

Mike Morrow

Midcontinent
ISO

2

MRO

Katherine Prewitt Southern
1
Company
Services, Inc.

SERC

Joel Dembowski Southern
Company Alabama
Power
Company

3

SERC

William D. Shultz Southern
Company
Generation

5

SERC

Jennifer G.
Sykes

Southern
Company
Generation
and Energy
Marketing

6

SERC

Guy V. Zito

Northeast
Power
Coordinating
Council

10

NPCC

Randy
MacDonald

New
Brunswick
Power

2

NPCC

Wayne Sipperly

New York
Power
Authority

4

NPCC

Glen Smith

Entergy
Services

4

NPCC

Brian Robinson

Utility Services 5

NPCC

Alan Adamson

New York
State
Reliability
Council

NPCC

7

Edward Bedder

Orange &
Rockland
Utilities

1

NPCC

David Burke

Orange &
Rockland
Utilities

3

NPCC

Michele Tondalo UI

1

NPCC

Laura Mcleod

NB Power

1

NPCC

David
Ramkalawan

Ontario Power 5
Generation
Inc.

NPCC

Helen Lainis

IESO

2

NPCC

Michael
Schiavone

National Grid

1

NPCC

Michael Jones

National Grid

3

NPCC

Michael Forte

Con Ed Consolidated
Edison

1

NPCC

Peter Yost

Con Ed 3
Consolidated
Edison Co. of
New York

NPCC

Sean Cavote

PSEG

4

NPCC

Kathleen
Goodman

ISO-NE

2

NPCC

Paul Malozewski Hydro One
3
Networks, Inc.

NPCC

Quintin Lee

Eversource
Energy

NPCC

Dermot Smyth

Con Ed 1,5
Consolidated
Edison Co. of
New York

NPCC

Dermot Smyth

Con Ed 1,5
Consolidated
Edison Co. of
New York

NPCC

Salvatore
Spagnolo

New York
Power
Authority

1

NPCC

Shivaz Chopra

New York
Power
Authority

6

NPCC

1

Southwest
Power Pool,
Inc. (RTO)

Shannon
Mickens

PPL Shelby Wade
Louisville Gas
and Electric
Co.

Associated
Electric
Cooperative,
Inc.

Todd Bennett

2

1,3,5,6

3

MRO,SPP RE

RF,SERC

SPP
Standards
Review
Group

PPL NERC
Registered
Affiliates

AECI

David Kiguel

Independent

NA - Not
Applicable

NPCC

Silvia Mitchell

NextEra
6
Energy Florida Power
and Light Co.

NPCC

Caroline Dupuis

Hydro Quebec 1

NPCC

Chantal Mazza

Hydro Quebec 2

NPCC

Gregory Campoli New York
Independent
System
Operator

2

NPCC

Shannon
Mickens

Southwest
Power Pool
Inc.

2

MRO

Don Schmit

Nebraska
Public Power
District

5

NA - Not
Applicable

John Allen

City Utilities of 4
Springfield,
Missouri

MRO

Louis Guidry

Cleco

SERC

Robert Gray

Board of
3
Public Utilities
(Kansas City,
KS) BPU

MRO

Steven Keller

Southwest
Power Pool
Inc.

MRO

Charlie Freibert

LG&E and KU 3
Energy, LLC

SERC

Brenda Truhe

PPL Electric
Utilities
Corporation

RF

Dan Wilson

LG&E and KU 5
Energy, LLC

SERC

Linn Oelker

LG&E and KU 6
Energy, LLC

SERC

Michael Bax

Central
1
Electric Power
Cooperative
(Missouri)

SERC

Adam Weber

Central
3
Electric Power

SERC

1,3,5,6

2

1

Cooperative
(Missouri)
Stephen Pogue

M and A
3
Electric Power
Cooperative

SERC

William Price

M and A
1
Electric Power
Cooperative

SERC

Jeff Neas

Sho-Me
3
Power Electric
Cooperative

SERC

Peter Dawson

Sho-Me
1
Power Electric
Cooperative

SERC

Mark Ramsey

N.W. Electric
Power
Cooperative,
Inc.

1

NPCC

John Stickley

NW Electric
Power
Cooperative,
Inc.

3

SERC

Ted Hilmes

KAMO Electric 3
Cooperative

SERC

Walter Kenyon

KAMO Electric 1
Cooperative

SERC

Kevin White

Northeast
1
Missouri
Electric Power
Cooperative

SERC

Skyler Wiegmann Northeast
3
Missouri
Electric Power
Cooperative

SERC

Ryan Ziegler

Associated
Electric
Cooperative,
Inc.

1

SERC

Brian Ackermann Associated
Electric
Cooperative,
Inc.

6

SERC

Brad Haralson

5

SERC

Associated
Electric
Cooperative,
Inc.

1. Control Center Exemption Language: The SDT drafted Exemption language in the Applicability section specifically for CIP-012-1 to exempt
Control Centers that only transmit data pertaining to a single co-located substation or generating plant. Do you agree with this revision? If
not, please provide the basis for your disagreement and an alternate proposal.
Russell Martin II - Salt River Project - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
SRP agrees with the principal of the exemption. However, SRP would like to see a revision of the language simplified in a fashion similar to how this
question is constructed. "exempt Control Centers that only transmit data pertaining to a single-co-located substation or generation plant."
Likes

0

Dislikes

0

Response

Dana Klem - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO NSRF
Answer

No

Document Name
Comment
The Technical Rationale document, in addressing this exemption, identifies the “intent” of this exemption which is to “exclude the normal RTU-style
communication from a field asset about that field asset’s status from CIP-012”. This is commendable and the NSRF appreciates your identification of
RTU-style communication as an exemption as it relates to the Control Center definition. The NSRF would like to point out that there are violations of
Standards that have come down to discussions over intent. The NSRF strongly suggests that the drafting team include the Technical Rationale intent
for this exemption into the actual words of the exemption to avoid future misinterpretation of the exemption. NSRF suggests the following for drafting
team consideration, which also includes revisions for comments under #4 of this comment form:
The NSRF recommends that the exemption reads as:
A Control Center at a BES generation resource or Transmission station or substation that transmits to another Control Center Real-time Assessment or
Real-time monitoring data, such as RTU-style data, pertaining only to the generation resource or Transmission station or substation at which the data
transmitting transmitted Control Center is located.
Rationale: The first use of “Control Center” implies that the exemption is for a Control Center to start with. Where it is not a Control Center but a BES
facility that transmits data, via an RTU (RTU was added since it plays a pivotal point of intent within the Technical Rational document).
Likes

0

Dislikes
Response

0

Steven Rueckert - Western Electricity Coordinating Council - 10
Answer

No

Document Name
Comment
The exemption language of CIP-012-1 4.2.3 refers to real-time data derived from a single location at a generation or Transmission station. However,
the Control Center term, as defined In the Proposed Definition of Control Center, items (3) and (4), refers to “two or more locations” for Transmission
Operators and Generator Operators. They are conflicting one another and this could lead to misinterpretation and/or misapplication of the Standard’s
protections. WECC believe clarity related to control Center vs. control room is necessary.
Likes

0

Dislikes

0

Response

Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

No

Document Name
Comment
Language is very confusing. Based on Idaho Power’s understanding, this will eliminate smaller Control Centers but doesn't appear to have a large
impact.
Likes

0

Dislikes

0

Response

David Jendras - Ameren - Ameren Services - 1,3,6
Answer

No

Document Name
Comment
While Ameren supports the need for an Exemption for CIP-012-1, the exemption should be based on impact to reliable operations. We suggest
modifying the proposed wording in 4.2.3 to provide the exemption for Low Impact Control Centers as defined in CIP-002, Attachment 1. If a Control
Center regardless of its location meets the criteria for either a Medium Impact or High Impact facility then it should be protected appropriately.
Likes
Dislikes

0
0

Response

Aaron Smith - Omaha Public Power District - 1,3,5,6
Answer

No

Document Name
Comment
The Technical Rationale document, in addressing this exemption, identifies the “intent” of this exemption which is to “exclude the normal RTU-style
communication from a field asset about that field asset’s status from CIP-012”. This is commendable and the NSRF appreciates your identification of
RTU-style communication as an exemption as it relates to the Control Center definition. The NSRF would like to point out that there are violations of
Standards that have come down to discussion over intent; and the NSRF strongly suggests that the drafting team include the Technical Rationale intent
for this exemption into the actual words of the exemption to avoid future misinterpretation of the exemption. NSRF suggests the following for drafting
team consideration, which also includes revisions for comments under #4 of this comment form:

The NSRF recommends that the exemption reads as:

A Control Center at a BES generation resource or Transmission station or substation that transmits to a nother Control Center Real-time Assessment or
Real-time monitoring
Likes

0

Dislikes

0

Response

Richard Jackson - U.S. Bureau of Reclamation - 1
Answer

No

Document Name
Comment
Reclamation does not support an exemption. Reclamation recommends that all Real-time Assessment and Real-time monitoring data be protected
against the risk of unauthorized disclosure or modification.
Instead of exempting certain Control Centers, Reclamation recommends the SDT revise the Control Center definition to give consideration to the
system-wide view a Control Center has versus the limited view held by Generator Operators as follows:
One or more BES facilities, including their associated Data Centers, that monitor and control the BES and also host System Operators who:
1. perform the Real-time reliability-related tasks of a Reliability Coordinator; or
2. perform the Real-time reliability-related tasks of a Balancing Authority; or

3. perform the Real-time reliability-related tasks of a Transmission Operator for any BES Transmission Facilities; or
4. can act independently as the Generator Operator to develop specific dispatch instructions for any BES generation Facilities; or
5. can operate or direct the operation of a Transmission Owner’s BES Transmission Facilities in Real-time.
Section 4.2.3, as presently written, does not clearly explain why certain Control Centers would be exempted. If an exemption is provided, Reclamation
recommends the SDT incorporate language from the Technical Rationale in the exemption to avoid future confusion (i.e., Control Center implies the
exemption is for a Control Center, but the data may be transmitted by a BES facility such as an RTU).
Likes

0

Dislikes

0

Response

Brandon McCormick - Brandon McCormick On Behalf of: Ginny Beigel, City of Vero Beach, 3; Lynne Mila, City of Clewiston, 4; Mike Blough,
Kissimmee Utility Authority, 5, 3; Tom Reedy, Florida Municipal Power Pool, 6; - Brandon McCormick, Group Name FMPA
Answer

No

Document Name
Comment
: FMPA agrees with the following comments submitted by MRO NSRF:
The Technical Rationale document, in addressing this exemption, identifies the “intent” of this exemption which is to “exclude the normal RTU-style
communication from a field asset about that field asset’s status from CIP-012”. This is commendable and the NSRF appreciates your identification of
RTU-style communication as an exemption as it relates to the Control Center definition. The NSRF would like to point out that there are violations of
Standards that have come down to discussions over intent. The NSRF strongly suggests that the drafting team include the Technical Rationale intent
for this exemption into the actual words of the exemption to avoid future misinterpretation of the exemption. NSRF suggests the following for drafting
team consideration, which also includes revisions for comments under #4 of this comment form:
The NSRF recommends that the exemption reads as:
A Control Center at a BES generation resource or Transmission station or substation that transmits to another Control Center Real-time Assessment or
Real-time monitoring data, such as RTU-style data, pertaining only to the generation resource or Transmission station or substation at which
the data transmitting transmitted Control Center is located.
Rationale: The first use of “Control Center” implies that the exemption is for a Control Center to start with. Where it is not a Control Center but a BES
facility that transmits data, via an RTU (RTU was added since it plays a pivotal point of intent within the Technical Rational document)
Likes

0

Dislikes

0

Response

Douglas Webb - Douglas Webb On Behalf of: Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; James McBee,
Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; Jessica Tucker, Great Plains Energy - Kansas City Power and Light Co., 5,

1, 3, 6; Jim Flucke, Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; Megan Wagner, Westar Energy, 6, 3, 1, 5; - Douglas
Webb
Answer

No

Document Name
Comment
Kansas City Power and Light Company incorporates the Edison Electric Institute's response to Question No. 1.
Likes

0

Dislikes

0

Response

Richard Montgomery - Florida Municipal Power Agency - 3,4,5,6
Answer

No

Document Name
Comment
FMPA agrees with the following comments submitted by MRO NSRF:
The Technical Rationale document, in addressing this exemption, identifies the “intent” of this exemption which is to “exclude the normal RTU-style
communication from a field asset about that field asset’s status from CIP-012”. This is commendable and the NSRF appreciates your identification of
RTU-style communication as an exemption as it relates to the Control Center definition. The NSRF would like to point out that there are violations of
Standards that have come down to discussions over intent. The NSRF strongly suggests that the drafting team include the Technical Rationale intent
for this exemption into the actual words of the exemption to avoid future misinterpretation of the exemption. NSRF suggests the following for drafting
team consideration, which also includes revisions for comments under #4 of this comment form:
The NSRF recommends that the exemption reads as:
A Control Center at a BES generation resource or Transmission station or substation that transmits to another Control Center Real-time Assessment or
Real-time monitoring data, such as RTU-style data, pertaining only to the generation resource or Transmission station or substation at which
the data transmitting transmitted Control Center is located.
Rationale: The first use of “Control Center” implies that the exemption is for a Control Center to start with. Where it is not a Control Center but a BES
facility that transmits data, via an RTU (RTU was added since it plays a pivotal point of intent within the Technical Rational document)
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Response

Carol Chinn - Florida Municipal Power Agency - 3,4,5,6
Answer

No

Document Name
Comment
FMPA agrees with the following comments submitted by MRO NSRF:
The Technical Rationale document, in addressing this exemption, identifies the “intent” of this exemption which is to “exclude the normal RTU-style
communication from a field asset about that field asset’s status from CIP-012”. This is commendable and the NSRF appreciates your identification of
RTU-style communication as an exemption as it relates to the Control Center definition. The NSRF would like to point out that there are violations of
Standards that have come down to discussions over intent. The NSRF strongly suggests that the drafting team include the Technical Rationale intent
for this exemption into the actual words of the exemption to avoid future misinterpretation of the exemption. NSRF suggests the following for drafting
team consideration, which also includes revisions for comments under #4 of this comment form:
The NSRF recommends that the exemption reads as:
A Control Center at a BES generation resource or Transmission station or substation that transmits to another Control Center Real-time Assessment or
Real-time monitoring data, such as RTU-style data, pertaining only to the generation resource or Transmission station or substation at which
the data transmitting transmitted Control Center is located.
Rationale: The first use of “Control Center” implies that the exemption is for a Control Center to start with. Where it is not a Control Center but a BES
facility that transmits data, via an RTU (RTU was added since it plays a pivotal point of intent within the Technical Rational document)
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Response

Joe McKinney - Florida Municipal Power Agency - 3,4,5,6
Answer

No

Document Name
Comment
FMPA agrees with the following comments submitted by MRO NSRF:
The Technical Rationale document, in addressing this exemption, identifies the “intent” of this exemption which is to “exclude the normal RTU-style
communication from a field asset about that field asset’s status from CIP-012”. This is commendable and the NSRF appreciates your identification of
RTU-style communication as an exemption as it relates to the Control Center definition. The NSRF would like to point out that there are violations of
Standards that have come down to discussions over intent. The NSRF strongly suggests that the drafting team include the Technical Rationale intent
for this exemption into the actual words of the exemption to avoid future misinterpretation of the exemption. NSRF suggests the following for drafting
team consideration, which also includes revisions for comments under #4 of this comment form:
The NSRF recommends that the exemption reads as:
A Control Center at a BES generation resource or Transmission station or substation that transmits to another Control Center Real-time Assessment or
Real-time monitoring data, such as RTU-style data, pertaining only to the generation resource or Transmission station or substation at which
the data transmitting transmitted Control Center is located.

Rationale: The first use of “Control Center” implies that the exemption is for a Control Center to start with. Where it is not a Control Center but a BES
facility that transmits data, via an RTU (RTU was added since it plays a pivotal point of intent within the Technical Rational document)
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0

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0

Response

Chris Gowder - Florida Municipal Power Agency - 3,4,5,6
Answer

No

Document Name
Comment
Comments: FMPA agrees with the following comments submitted by MRO NSRF:
The Technical Rationale document, in addressing this exemption, identifies the “intent” of this exemption which is to “exclude the normal RTU-style
communication from a field asset about that field asset’s status from CIP-012”. This is commendable and the NSRF appreciates your identification of
RTU-style communication as an exemption as it relates to the Control Center definition. The NSRF would like to point out that there are violations of
Standards that have come down to discussions over intent. The NSRF strongly suggests that the drafting team include the Technical Rationale intent
for this exemption into the actual words of the exemption to avoid future misinterpretation of the exemption. NSRF suggests the following for drafting
team consideration, which also includes revisions for comments under #4 of this comment form:
The NSRF recommends that the exemption reads as:
A Control Center at a BES generation resource or Transmission station or substation that transmits to another Control Center Real-time Assessment or
Real-time monitoring data, such as RTU-style data, pertaining only to the generation resource or Transmission station or substation at which
the data transmitting transmitted Control Center is located.
Rationale: The first use of “Control Center” implies that the exemption is for a Control Center to start with. Where it is not a Control Center but a BES
facility that transmits data, via an RTU (RTU was added since it plays a pivotal point of intent within the Technical Rational document
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0

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Response

Chris Scanlon - Exelon - 1
Answer

No

Document Name

CIP 12 Figures.pdf

Comment
While Exelon supports the need for an Exemption for CIP-012-1, we have a concern that the language may still lack necessary clarity. For this reason,
we suggest language similar to the following:

4.2.3 A generating station, Transmission station or substation that is also a Control Center, but meets one of the following criteria:
4.2.3.1 Aggregates and transmits Real-time Assessment and Real-time monitoring data from two or more Generation resource(s), Transmission
station(s) and/or substation(s) but all aggregated data coming from these locations is contained within the same physical perimeter. (see Figure 1)
4.2.3.2 Does not aggregate and transmit Real-time Assessment and Real-time monitoring data from a location outside the physical perimeter where
it resides. (see Figure 2)
(See CIP 12 Figures.pdf)

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Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

No

Document Name
Comment
The Exemption Language is ambiguous with regard to situations where an entity could have BES assets polling Non-BES data from other
locations/facilities.
Example 1: Weather Data from remote locations. No effect on generation but weather station is not physically at this facility.
Example 2: Operations of small hydro sites (under 10 mw) which are aggregated at the Low Impact BES facility but are located at other facilities.
In this example, these Low Impact Control Centers are only identified as Control Centers because they have the Capability, NOT the Responsibility, to
control another Low Impact BES site. The capability is there so that technicians at one site can monitor alarms at the other Low Impact site. But these
sites are not staffed around the clock, and their function is not to perform operations at the other site. We suggest a clarification on the exemption
language below.
Current Language:
A Control Center at a generation resource or Transmission station or substation that transmits to another Control Center Real-time Assessment or Realtime monitoring data pertaining only to the generation resource or Transmission station or substation at which the transmitting Control Center is located.
Language Suggestion:
A Control Center at a generation resource or Transmission station or substation where all of the BES data being transmitted to another Control Center,
pertains to the generation resource or Transmission station or substation at which the transmitting Control Center is located.
This language is intended to prevent small sites with Non BES data coming from other locations from being unnecessarily included in the standard.
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Response

Stephanie Burns - Stephanie Burns On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Stephanie
Burns
Answer

No

Document Name
Comment
ITC is concerned with the use of Control Center in the exemption and the confusion it may cause with the originally intended definition of Control
Center. ITC instead recommends the following language:
Exemption:
BES generation resource or Transmission station or substation that transmits Realtime monitoring or Assessment data to another Control Center, such
as telemetry data, pertaining only to the generation resource or Transmission station.
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Eli Rivera - Central Electric Cooperative, Inc. (Redmond, Oregon) - NA - Not Applicable - Texas RE
Answer

No

Document Name
Comment
CenterPoint Energy Houston Electric, LLC (“CenterPoint Energy”) agrees with Edison Electric Institute’s (EEI) comments.
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0

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Andy Fuhrman - Andy Fuhrman On Behalf of: Theresa Allard, Minnkota Power Cooperative Inc., 1; - Andy Fuhrman
Answer

No

Document Name
Comment
Please refer to MRO NERC Standards Review Forum (NSRF) comments.

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Shelby Wade - PPL - Louisville Gas and Electric Co. - 1,3,5,6 - SERC,RF, Group Name PPL NERC Registered Affiliates
Answer

No

Document Name
Comment
Under the current definition of Control Center per the NERC Glossary of terms, what qualifies as an associated data center is unclear (e.g., associated
computer room, remote computer room, distributed front-end processor).
PPL NERC Registered Affiliates requests clarification regarding treatment of aggregation of SCADA data, in particular:
•
•

Please provide additional information and a diagram for the scope and exemptions for SCADA data from multiple substations to a remote
computer room where data is aggregated at the remote computer room prior to transmitting to a data center that is associated with the
Operations Center.
Please provide additional information and a diagram regarding communications scope of CIP-012-1 (e.g. SCADA data from various substation
control buildings that are at a single location and communicating back via a network used for all substation communications back to head end
computer room, aggregated and then sent to Data Center).

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Andrea Koch - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

No

Document Name

CIP 12 Figures.pdf

Comment
While EEI supports the need for an Exemption for CIP-012-1, we are concerned that the language may still lack necessary clarity. For this reason, we
suggest language similar to the following:
4.2.3 A generating station, Transmission station or substation that is also a Control Center, but meets one of the following criteria:
4.2.3.1 Aggregates and transmits Real-time Assessment and Real-time monitoring data from two or more Generation resource(s), Transmission
station(s) and/or substation(s) but all aggregated data comes from locations that are contained within the same physical perimeter. (see EEI Figure 1)
4.2.3.2 The Control Center does not aggregate and transmit Real-time Assessment and Real-time monitoring data from location(s) outside the
physical perimeter where it resides. (see EEI Figure 2)
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Tho Tran - Tho Tran On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; - Tho Tran
Answer

No

Document Name
Comment
Oncor supports EEI's comment.
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Warren Cross - ACES Power Marketing - 1,3,4,5 - MRO,WECC,Texas RE,SERC
Answer

No

Document Name
Comment
The intent of the exclusion is a positive direction, but it needs re-worded for clarity. ACES is concerned that by identifying the facility as a NERC defined,
Control Center, and not a NERC defined, Facility, it will have unintended consequences of being in scope to other standards that do not directly exempt
it as a Control Center.

ACES would support the following modification:

“A BES generation resource or Transmission station or substation that transmits Real-time Assessment or Real-time monitoring data via RTU to a
Control Center, and the transmitted data pertains only to that generation resource or Transmission station or substation.”
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Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - MRO, Group Name SPP Standards Review Group
Answer
Document Name

No

Comment
The SPP Standards Review Group has a concern that the proposed Exemption will modify the current “Control Center” definition that potentially
changes how High and Low impacts assets are evaluated. The review group is proposing some language (shown below) to help maintain consistency
with the “Control Center” Definition and the proposed Exemption mentioned in the documentation. Additionally, the introduction of the term “Control
System” as well as the diagrams and explanations in the rationale present complexity pertaining to the current process of identifying BES Cyber
Systems. We would suggest that the drafting team remove the term “Control System” from all proposed language associated with this project.
Section 4.2.3. (Applicability Section –Standard)
A BES generation resource or Transmission station or substation that transmits to a Control Center Real-time Assessment or Real-time monitoring
data, such as RTU-style data, pertaining only to the generation resource or Transmission station or substation at which the data transmitted is
located.
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Response

Teresa Cantwell - Lower Colorado River Authority - 1,5
Answer

Yes

Document Name
Comment
None.
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0

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0

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Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6
Answer

Yes

Document Name
Comment
PacifiCorp agrees with the SDT providing the exemption language within the standard coupled with the clarification provided in the technical rationale
document in the absence of revising the Control Center definition. If additional edits to the exemption language changes the scope of what is covered in
the final version or is the technical rationale is not ERO-endorsed prior to the final ballot, PacifiCorp may alter its final vote. PAC understands that time
and the SAR are obstacles for the SDT at this time, further development of the Control Center definition should be resolved before more standards
regarding Control Centers are introduced.
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Darnez Gresham - Darnez Gresham On Behalf of: Annette Johnston, Berkshire Hathaway Energy - MidAmerican Energy Co., 1, 3; - Darnez
Gresham
Answer

Yes

Document Name
Comment
MEC agrees with the SDT providing the exemption language in the applicability of the standard coupled with the explanation in the technical rationale
document in the absence of revising the Control Center definition. If additional edits to the exemption language changes the scope of what is covered in
the final version, MEC will change its vote on the final ballot. MEC understands that time and the SAR are obstacles for the SDT at this time, however,
issues with the existing Control Center definition should be resolved before more standards regarding Control Centers are introduced.
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Kevin Salsbury - Berkshire Hathaway - NV Energy - 5
Answer

Yes

Document Name
Comment
NV Energy agrees with the SDT providing the exemption language within the standard coupled with the clarification provided in the technical rationale
document in the absence of revising the Control Center definition.
Please note, that NV Energy may alter its vote, If additional edits to the exemption language changes the scope of what is covered in the final version
or if the technical rationale is not ERO-endorsed prior to the final ballot. NV Energy understands that a unknown expedited timeline and the original
SAR are obstacles for the SDT at this time, and that this Standard will be approved in the near term, but we believe that further development of the
Control Center definition should be resolved before more standards regarding Control Centers are introduced.
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Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name

Yes

Comment
None
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0

Response

Marty Hostler - Northern California Power Agency - 5
Answer

Yes

Document Name
Comment
What about a similar Control Center that also receives data?
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0

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0

Response

Dennis Sismaet - Northern California Power Agency - 6
Answer

Yes

Document Name
Comment
What about a similar Control Center that also receives data?
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0

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Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Document Name
Comment

Yes

Southern Company supports the proposed exemption language.
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0

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David Francis - Midcontinent ISO, Inc. - 2 - MRO,SERC,RF
Answer

Yes

Document Name
Comment
Adding the wording "within the same geographical location" might help with the clarification of located
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0

Response

Steve Rose - City Water, Light and Power of Springfield, IL - 1,3,5
Answer

Yes

Document Name
Comment

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0

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0

Response

Thomas Foltz - AEP - 5
Answer

Yes

Document Name
Comment

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0
0

Response

Todd Bennett - Associated Electric Cooperative, Inc. - 3, Group Name AECI
Answer

Yes

Document Name
Comment

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0

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0

Response

Aubrey Short - FirstEnergy - FirstEnergy Corporation - 4
Answer

Yes

Document Name
Comment

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0

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0

Response

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 3, Group Name FirstEnergy Corporation
Answer

Yes

Document Name
Comment

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0

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0

Response

Patricia Lynch - NRG - NRG Energy, Inc. - 5,6
Answer
Document Name

Yes

Comment

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0

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0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment

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0

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0

Response

David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment

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0

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0

Response

Michael Shaw - Lower Colorado River Authority - 1
Answer

Yes

Document Name
Comment

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0

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0

Jeanne Kurzynowski - CMS Energy - Consumers Energy Company - 1,3,4,5 - RF
Answer

Yes

Document Name
Comment

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0

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0

Response

Jeff Johnson - Jeff Johnson On Behalf of: Martine Blair, Sempra - San Diego Gas and Electric, 3, 5, 1; - Jeff Johnson
Answer

Yes

Document Name
Comment

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0

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0

Response

Barry Lawson - National Rural Electric Cooperative Association - 4
Answer

Yes

Document Name
Comment

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0

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0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion
Answer
Document Name
Comment

Yes

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0

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0

Response

Douglas Johnson - American Transmission Company, LLC - 1
Answer

Yes

Document Name
Comment

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0

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0

Response

James Anderson - CMS Energy - Consumers Energy Company - 1
Answer

Yes

Document Name
Comment

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0

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0

Response

Chris Wagner - Santee Cooper - 1, Group Name Santee Cooper
Answer

Yes

Document Name
Comment

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0

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Response

0

Martin Sidor - NRG - NRG Energy, Inc. - 5,6
Answer

Yes

Document Name
Comment

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0

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0

Response

David Greyerbiehl - CMS Energy - Consumers Energy Company - 5
Answer

Yes

Document Name
Comment

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0

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0

Response

Quintin Lee - Eversource Energy - 1
Answer

Yes

Document Name
Comment

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0

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0

Response

Lynn Goldstein - PNM Resources - Public Service Company of New Mexico - 3
Answer
Document Name
Comment

Yes

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0

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0

Response

Steven Mavis - Edison International - Southern California Edison Company - 1
Answer
Document Name
Comment
Please see comments submitted by Edison Electric Institute.
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Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
While the SDT believes the “integrity and availability of sensitive bulk electric system data”, as noted in FERC Order No. 822, paragraph 54, is
addressed in R1, Texas RE notes the use of the term “or”: Identification of security protection used to mitigate the risk of unauthorized disclosure or
modification of Real-time Assessment and Real-time monitoring and control data while being transmitted between Control Centers. In its response, the
SDT specifically referenced the Consideration of Issue or Directive document. In that document, the SDT makes clear that entities may elect, solely at
their discretion, to protect communications links, data, or both.
Texas RE believes this directly conflicts with the plain language in FERC Order No. 822, P. 54. FERC made it clear that protections should apply to
both communication links and sensitive data. However, the SDT has specified such protections could be potentially applied solely to communications
links or sensitive data. That is, the SDT has endorsed permitting responsible entities to simply elect to plan and implement physical protections for
communications links. This would “mitigate” the risk of an unauthorized disclosure or modification of data using one of the delineated methods. As
such, the responsible entity would potentially be compliant with the standard without proposing or implementing any logical protections for sensitive data
during its transmission. This appears counter to FERC’s intent to protect “both the integrity and availability of sensitive bulk electric system
data.” FERC Order No. 822, P. 54. Texas RE maintains its recommendation to 1) change “or” to “and”; and 2) change the phrase risk of unauthorized
disclosure or modification to integrity and availability of sensitive bulk electric system data.
Furthermore, Texas RE is also concerned with the SDT’s shortsighted approach to securing this type of data, which permits discretion around security
matters that are not in controversy and are widely considered vulnerabilities that must be mitigated. This approach is also not consistent with the
“defense in depth” philosophy, which is a fundamental aspect of cyber security domains. In other words, it is a more consistent with the defense in depth
concept to mitigate the risk of unauthorized disclosure and modification for this data versus one without the other.
Additionally, since GO does not appear in the definition of Control Center, Texas RE suggests removing GO from the applicability section.

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0

2. Requirement R1: The SDT modified Requirement R1 to state: “The Responsible Entity shall implement, except under CIP Exceptional
Circumstances, one or more documented plan(s) to mitigate the risk of unauthorized disclosure or modification of Real-time Assessment and
Real-time monitoring data while being transmitted between any applicable Control Centers. The Responsible Entity is not required to include
oral communications in its plan.” Do you agree with this revision? If not, please provide the basis for your disagreement and an alternate
proposal.
Dennis Sismaet - Northern California Power Agency - 6
Answer

No

Document Name
Comment
This is too prescriptive and unnecessary. IRO-010-2 R3.3 and TOP-003-3 R5.3 already provide reliability assurance requirements for RCs, BAs, GOs,
GOPs, TOPs, TOs, and DPs. Additionally, NERC has a Standards Efficiency Initiative underway to get rid of standards and requirements such as CIP012-1 and its' requirement 1.
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0

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Marty Hostler - Northern California Power Agency - 5
Answer

No

Document Name
Comment
This is too prescriptive and unnecessary. IRO-010-2 R3.3 and TOP-003-3 R5.3 already provide reliability assurance requirements for RCs, BAs, GOs,
GOPs, TOPs, TOs, and DPs. Additionally, NERC has a Standards Efficiency Initiative underway to get rid of standards and requirements such as CIP012-1 and its' requirement 1.
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0

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Andy Fuhrman - Andy Fuhrman On Behalf of: Theresa Allard, Minnkota Power Cooperative Inc., 1; - Andy Fuhrman
Answer
Document Name
Comment

No

Please refer to MRO NERC Standards Review Forum (NSRF) comments.
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Chris Gowder - Florida Municipal Power Agency - 3,4,5,6
Answer

No

Document Name
Comment
: FMPA agrees with the below comments submitted by the NSRF:

The NSRF has the following three concerns and the double jeopardy of noncompliance with R1 and part 1.3.
Concern one (1); R1 states “The Responsible Entity shall implement …” where the Responsible Entity is noted within section 4.1, Functional
Entities. So, each BA, GOP, GO, RC, TOP and TO shall implement a documented plan (s) to mitigate the risk of unauthorized disclosure or
modification of Real-time Assessments and Real-time monitoring data. Part 1.3 states that “If the Control Centers are owned or operated by different
Responsible Entities” which they will be (unless there is a vertically integrated Entity), those different Entities
already need to satisfy R1 since they are in section 4.1. This part 1.3 is redundant and is recommended to be removed.
Concern two (2); R1.3 states “… identify the responsibilities…” this identification of responsibilities is ambiguous as each Entity can only identify their
own responsibilities to “mitigate the risk of unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring data…” per
R1. In essence, just repeating the words within R1 is not enhancing system reliability by any means. Recommended to be removed for this concern.
Concern three (3) is similar to concern 1, where one Entity needs to identify the other Entity which will be a different entity (unless they are a vertically
integrated Entity); those different Entities already need to satisfy R1 since they are in section 4.1. This part 1.3 is redundant and is recommended to be
removed.
The NSRF recommends that part 1.3 be deleted in its entirety as all Functional Entities will be required to satisfy R1 and part 1.1 and 1.2.
The NSRF agrees with adding “except under CIP Exceptional Circumstances” in R1.
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Richard Montgomery - Florida Municipal Power Agency - 3,4,5,6
Answer
Document Name

No

Comment
FMPA agrees with the below comments submitted by the NSRF:

The NSRF has the following three concerns and the double jeopardy of noncompliance with R1 and part 1.3.
Concern one (1); R1 states “The Responsible Entity shall implement …” where the Responsible Entity is noted within section 4.1, Functional
Entities. So, each BA, GOP, GO, RC, TOP and TO shall implement a documented plan (s) to mitigate the risk of unauthorized disclosure or
modification of Real-time Assessments and Real-time monitoring data. Part 1.3 states that “If the Control Centers are owned or operated by different
Responsible Entities” which they will be (unless there is a vertically integrated Entity), those different Entities
already need to satisfy R1 since they are in section 4.1. This part 1.3 is redundant and is recommended to be removed.
Concern two (2); R1.3 states “… identify the responsibilities…” this identification of responsibilities is ambiguous as each Entity can only identify their
own responsibilities to “mitigate the risk of unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring data…” per
R1. In essence, just repeating the words within R1 is not enhancing system reliability by any means. Recommended to be removed for this concern.
Concern three (3) is similar to concern 1, where one Entity needs to identify the other Entity which will be a different entity (unless they are a vertically
integrated Entity); those different Entities already need to satisfy R1 since they are in section 4.1. This part 1.3 is redundant and is recommended to be
removed.
The NSRF recommends that part 1.3 be deleted in its entirety as all Functional Entities will be required to satisfy R1 and part 1.1 and 1.2.
The NSRF agrees with adding “except under CIP Exceptional Circumstances” in R1.
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Brandon McCormick - Brandon McCormick On Behalf of: Ginny Beigel, City of Vero Beach, 3; Lynne Mila, City of Clewiston, 4; Mike Blough,
Kissimmee Utility Authority, 5, 3; Tom Reedy, Florida Municipal Power Pool, 6; - Brandon McCormick, Group Name FMPA
Answer

No

Document Name
Comment
FMPA agrees with the below comments submitted by the NSRF:
The NSRF has the following three concerns and the double jeopardy of noncompliance with R1 and part 1.3.
Concern one (1); R1 states “The Responsible Entity shall implement …” where the Responsible Entity is noted within section 4.1, Functional
Entities. So, each BA, GOP, GO, RC, TOP and TO shall implement a documented plan (s) to mitigate the risk of unauthorized disclosure or
modification of Real-time Assessments and Real-time monitoring data. Part 1.3 states that “If the Control Centers are owned or operated by different
Responsible Entities” which they will be (unless there is a vertically integrated Entity), those different Entities already need to satisfy R1 since they are in
section 4.1. This part 1.3 is redundant and is recommended to be removed.

Concern two (2); R1.3 states “… identify the responsibilities…” this identification of responsibilities is ambiguous as each Entity can only identify their
own responsibilities to “mitigate the risk of unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring data…” per
R1. In essence, just repeating the words within R1 is not enhancing system reliability by any means. Recommended to be removed for this concern.
Concern three (3) is similar to concern 1, where one Entity needs to identify the other Entity which will be a different entity (unless they are a vertically
integrated Entity); those different Entities already need to satisfy R1 since they are in section 4.1. This part 1.3 is redundant and is recommended to be
removed.
The NSRF recommends that part 1.3 be deleted in its entirety as all Functional Entities will be required to satisfy R1 and part 1.1 and 1.2.
The NSRF agrees with adding “except under CIP Exceptional Circumstances” in R1
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Richard Jackson - U.S. Bureau of Reclamation - 1
Answer

No

Document Name
Comment
It is not clear how a CIP Exceptional Circumstance would impact the mitigation of the risk of unauthorized disclosure or modification of Real-time
Assessment and Real-time monitoring data; therefore, Reclamation asserts that an exception for CIP Exceptional Circumstances is not necessary.
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Aaron Smith - Omaha Public Power District - 1,3,5,6
Answer

No

Document Name
Comment
Comments: The NSRF has the following three concerns and the double jeopardy of noncompliance with R1 and part 1.3.

Concern one (1); R1 states “The Responsible Entity shall implement …” where the Responsible Entity is noted within section 4.1, Functional
Entities. So, each BA, GOP, GO, RC, TOP and TO shall implement a documented plan (s) to mitigate the risk of unauthorized disclosure or
modification of Real-time Assessments and Real-time monitoring data. Then in part 1.3 it states that “If the Control Centers are owned or operated by
different Responsible Entities” which they will be (unless there is a vertically integrated Entity), those different Entities already need to satisfy R1 since
they are in section 4.1. This part 1.3 is redundant and is recommended to be removed.

Concern two (2); R1.3 states “… identify the responsibilities…” this identification of responsibilities is ambiguous as each Entity can only identify their
own responsibilities to “mitigate the risk of unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring data…” per
R1. In essence, just repeating the words within R1 is not enhancing system reliability by any means. Recommended to be removed for this concern.

Concern three (3) is similar to concern 1, where one Entity needs to identify the other Entity which will be a different entity (unless they are a vertically
integrated Entity); those different Entities already need to satisfy R1 since they are in section 4.1. This part 1.3 is redundant and is recommended to be
removed.

The NSRF recommends that part 1.3 be deleted in its entirety as all Functional Entities will be required to satisfy R1 and part 1.1 and 1.2.

The NSRF agrees with adding “except under CIP Exceptional Circumstances” in R1.
Likes

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0

Response

Dana Klem - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO NSRF
Answer

No

Document Name
Comment
The NSRF has the following three concerns and the double jeopardy of noncompliance with R1 and part 1.3.
Concern one (1); R1 states “The Responsible Entity shall implement …” where the Responsible Entity is noted within section 4.1, Functional
Entities. So, each BA, GOP, GO, RC, TOP and TO shall implement a documented plan (s) to mitigate the risk of unauthorized disclosure or
modification of Real-time Assessments and Real-time monitoring data. Part 1.3 states that “If the Control Centers are owned or operated by different
Responsible Entities” which they will be (unless there is a vertically integrated Entity), those different Entities already need to satisfy R1 since they are in
section 4.1. This part 1.3 is redundant and is recommended to be removed.
Concern two (2); R1.3 states “… identify the responsibilities…” this identification of responsibilities is ambiguous as each Entity can only identify their
own responsibilities to “mitigate the risk of unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring data…” per
R1. In essence, just repeating the words within R1 is not enhancing system reliability by any means. Recommended to be removed for this concern.
Concern three (3) is similar to concern 1, where one Entity needs to identify the other Entity which will be a different entity (unless they are a vertically
integrated Entity); those different Entities already need to satisfy R1 since they are in section 4.1. This part 1.3 is redundant and is recommended to be
removed.
The NSRF recommends that part 1.3 be deleted in its entirety as all Functional Entities will be required to satisfy R1 and part 1.1 and 1.2.
The NSRF agrees with adding “except under CIP Exceptional Circumstances” in R1.

Likes

0

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0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - MRO, Group Name SPP Standards Review Group
Answer

Yes

Document Name
Comment
The SPP Standards Review Group has no issues with the language proposed, however, we would recommend that the SDT include an example
pertaining to the under CIP Exceptional Circumstances in the Implementation Guidance Document.
Likes

0

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0

Response

David Francis - Midcontinent ISO, Inc. - 2 - MRO,SERC,RF
Answer

Yes

Document Name
Comment
Adding that statement clarifies the excludes meaning
Likes

0

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0

Response

Warren Cross - ACES Power Marketing - 1,3,4,5 - MRO,WECC,Texas RE,SERC
Answer

Yes

Document Name
Comment
ACES supports the modified R1.
Likes
Dislikes

0
0

Response

Tho Tran - Tho Tran On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; - Tho Tran
Answer

Yes

Document Name
Comment
Oncor supports EEI's comment.
Likes

0

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0

Response

Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer

Yes

Document Name
Comment
Southern Company supports the proposed revisions.
Likes

0

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0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
None
Likes

0

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Response

0

Andrea Koch - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

Yes

Document Name
Comment
EEI supports the Requirement 1 revisions. EEI also supports the flexibility provided by Requirement 1; however, there are many different approaches
to mitigating the risk of unauthorized disclosure or modification of data in transit. Additional guidance that explores various approaches and evaluates
their effectiveness in mitigating risk may be helpful before entities make implementation investments for CIP-012-1.
Likes

0

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0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion
Answer

Yes

Document Name
Comment
Is <> the same as operational data? Operational data is in other Standards
Likes

0

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0

Response

Eli Rivera - Central Electric Cooperative, Inc. (Redmond, Oregon) - NA - Not Applicable - Texas RE
Answer

Yes

Document Name
Comment
CenterPoint Energy Houston Electric, LLC (“CenterPoint Energy”) agrees with Edison Electric Institute’s (EEI) comments.
Likes

0

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0

Response

Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy

Answer

Yes

Document Name
Comment
Duke Energy agrees with the proposed revision.
Likes

0

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0

Response

Chris Scanlon - Exelon - 1
Answer

Yes

Document Name
Comment
Exelon supports the Requirement 1 revisions. Exelon also supports the flexibility provided by Requirement 1; however, there are many different
approaches to mitigating the risk of unauthorized disclosure or modification of data in transit. Additional guidance that explores various approaches and
evaluates their effectiveness in mitigating risk may be helpful before entities make implementation investments for CIP-012-1.
Likes

0

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0

Response

Barry Lawson - National Rural Electric Cooperative Association - 4
Answer

Yes

Document Name
Comment
NRECA supports the modified R1; however, we request that the SDT provide clarification on why R1.3 is needed, especially when R1, R1.1 and R1.2
seem to have an overlap in what is required with R1.3. With a clarification on the need for R1.3, NRECA believes that will help registered entities to
better understand why R1.3 is necessary. With this clarification, it may not be necessary to remove R1.3.
Likes

0

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0

Response

Kevin Salsbury - Berkshire Hathaway - NV Energy - 5

Answer

Yes

Document Name
Comment
NV Energy agrees with the requirement based on the newly introduced paragraph in the Implementation Guidance, “Where the operational obligations
of an entire communication link, including both endpoints, belong to the Control Center of another Responsible Entity, the Responsible Entity without
operational obligations for the communication link may demonstrate compliance by ensuring the communications link endpoint is within its Control
Center, which could be limited to including the communication link endpoint within a PSP.”
NV Energy would like the following edit added “or where other physical protections are applied.” NV Energy believes that this will allow entities flexibility
where their devices that perform this function are located within its location. NV Energy believes the VPN examples provided are necessary and should
remain within the Guidance document. If the newly introduced paragraph or the VPN example are removed or if the implementation guidance is not
ERO-endorsed prior to the final ballot, NV Energy may alter its final vote.
Likes

0

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0

Response

Darnez Gresham - Darnez Gresham On Behalf of: Annette Johnston, Berkshire Hathaway Energy - MidAmerican Energy Co., 1, 3; - Darnez
Gresham
Answer

Yes

Document Name
Comment
MEC agrees with the requirement based on the newly introduced sentence in the Implementation Guidance, “Where the operational obligations of an
entire communication link, including both endpoints, belong to the Control Center of another Responsible Entity, the Responsible Entity without
operational obligations for the communication link may demonstrate compliance by ensuring the communications link endpoint is within its Control
Center, which could be limited to including the communication link endpoint within a PSP.” MEC would like the following edit added “or where other
physical protections are applied.” This will provide more flexibility for entities. MEC also likes the VPN example provided. Inclusion of the newly
introduced sentence, the VPN example and ERO-endorsement of the implementation guidance are needed in the final version for MEC to vote yes on
the final ballot.
Likes

0

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0

Response

Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6
Answer
Document Name
Comment

Yes

PacifiCorp agrees with the requirement based on the newly introduced paragraph in the Implementation Guidance, “Where the operational obligations
of an entire communication link, including both endpoints, belong to the Control Center of another Responsible Entity, the Responsible Entity without
operational obligations for the communication link may demonstrate compliance by ensuring the communications link endpoint is within its Control
Center, which could be limited to including the communication link endpoint within a PSP.” PacifiCorp would like the following edit added “or where other
physical protections are applied.” PacifiCorp feels that this will allow entities flexibility where the devices that perform this are located within its
location. PacifiCorp also likes the VPN examples provided. If the newly introduced paragraph or the VPN example are removed or if the implementation
guidance is not ERO-endorsed prior to the final ballot, PacifiCorp may alter its final vote.
Likes

0

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0

Response

Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

Yes

Document Name
Comment
It is always good to include exceptions for unforeseen circumstances and emergencies.
Likes

0

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0

Response

Todd Bennett - Associated Electric Cooperative, Inc. - 3, Group Name AECI
Answer

Yes

Document Name
Comment
AECI and members of the AECI group are supportive of the comments provided by NRECA.
Likes

0

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0

Response

Russell Martin II - Salt River Project - 1,3,5,6 - WECC
Answer
Document Name

Yes

Comment
SRP agrees the data should be protected. SRP also agrees the protections for the data in scope must ensure the data has not been modified, and that
FERC directed NERC to “specify how the confidentiality, integrity, and availability of each type of bulk electric system data should be protected while it
is being transmitted.” However, SRP takes exception to the extent the proposed standard requires the data in scope to be protected. FERC Order 822
states on page 36, “…we recognize that not all communication network components and data pose the same risk to bulk electric system reliability and
may not require the same level of protection.” However, the proposed standard applies the same criteria of protection against unauthorized disclosure
across all of the data within the defined scope. SRP does not agree viewing of the Real-time Assessment and Real-time monitoring and control data
without context will decrease the reliable operation of the BES and asserts confidentiality does not need to be protected for all data under this scope.
Along with this, SRP would like a clarification of how the SDT defines Real-Time Assessment Data.
Additionally, SRP recognizes the SDT is not specifying the controls used to protect confidentiality and integrity. However, the only method available to
achieve the proposed required objective is to implement encryption. FERC Order 822 states on page 39, “it is reasonable to conclude that any lag in
communication speed resulting from implementation of protections [encryption technologies] should only be measureable on the order of milliseconds
and, therefore, will not adversely impact Control Center communications,” but SRP asserts this statement only refers to a single data stream. It is
unknown what encryption will do when dealing with multiple data streams being transmitted at once, from one to many points, not only to the latency
added for the reliable operation of the BES, but also to the computing resources
Likes

0

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0

Response

Teresa Cantwell - Lower Colorado River Authority - 1,5
Answer

Yes

Document Name
Comment
None
Likes

0

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0

Response

Lynn Goldstein - PNM Resources - Public Service Company of New Mexico - 3
Answer

Yes

Document Name
Comment

Likes
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0
0

Response

Quintin Lee - Eversource Energy - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

David Greyerbiehl - CMS Energy - Consumers Energy Company - 5
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Martin Sidor - NRG - NRG Energy, Inc. - 5,6
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Chris Wagner - Santee Cooper - 1, Group Name Santee Cooper
Answer
Document Name

Yes

Comment

Likes

0

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0

Response

James Anderson - CMS Energy - Consumers Energy Company - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Douglas Johnson - American Transmission Company, LLC - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Stephanie Burns - Stephanie Burns On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Stephanie
Burns
Answer

Yes

Document Name
Comment

Likes
Dislikes

0
0

Response

Jeff Johnson - Jeff Johnson On Behalf of: Martine Blair, Sempra - San Diego Gas and Electric, 3, 5, 1; - Jeff Johnson
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Douglas Webb - Douglas Webb On Behalf of: Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; James McBee,
Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; Jessica Tucker, Great Plains Energy - Kansas City Power and Light Co., 5,
1, 3, 6; Jim Flucke, Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; Megan Wagner, Westar Energy, 6, 3, 1, 5; - Douglas
Webb
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

Jeanne Kurzynowski - CMS Energy - Consumers Energy Company - 1,3,4,5 - RF
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Michael Shaw - Lower Colorado River Authority - 1

Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Patricia Lynch - NRG - NRG Energy, Inc. - 5,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

David Jendras - Ameren - Ameren Services - 1,3,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Steven Rueckert - Western Electricity Coordinating Council - 10
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 3, Group Name FirstEnergy Corporation
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Aubrey Short - FirstEnergy - FirstEnergy Corporation - 4
Answer

Yes

Document Name
Comment

Likes

0

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0

Response

David Maier - Intermountain REA - 3
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Thomas Foltz - AEP - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Steve Rose - City Water, Light and Power of Springfield, IL - 1,3,5
Answer

Yes

Document Name
Comment

Likes
Dislikes

0
0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE does not have comments on this question.
Likes

0

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0

Response

Joe McKinney - Florida Municipal Power Agency - 3,4,5,6
Answer
Document Name
Comment
: FMPA agrees with the below comments submitted by the NSRF:

The NSRF has the following three concerns and the double jeopardy of noncompliance with R1 and part 1.3.
Concern one (1); R1 states “The Responsible Entity shall implement …” where the Responsible Entity is noted within section 4.1, Functional
Entities. So, each BA, GOP, GO, RC, TOP and TO shall implement a documented plan (s) to mitigate the risk of unauthorized disclosure or
modification of Real-time Assessments and Real-time monitoring data. Part 1.3 states that “If the Control Centers are owned or operated by different
Responsible Entities” which they will be (unless there is a vertically integrated Entity), those different Entities
already need to satisfy R1 since they are in section 4.1. This part 1.3 is redundant and is recommended to be removed.
Concern two (2); R1.3 states “… identify the responsibilities…” this identification of responsibilities is ambiguous as each Entity can only identify their
own responsibilities to “mitigate the risk of unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring data…” per
R1. In essence, just repeating the words within R1 is not enhancing system reliability by any means. Recommended to be removed for this concern.
Concern three (3) is similar to concern 1, where one Entity needs to identify the other Entity which will be a different entity (unless they are a vertically
integrated Entity); those different Entities already need to satisfy R1 since they are in section 4.1. This part 1.3 is redundant and is recommended to be
removed.
The NSRF recommends that part 1.3 be deleted in its entirety as all Functional Entities will be required to satisfy R1 and part 1.1 and 1.2.
The NSRF agrees with adding “except under CIP Exceptional Circumstances” in R1.
Likes

0

Dislikes

0

Response

Carol Chinn - Florida Municipal Power Agency - 3,4,5,6
Answer
Document Name
Comment
: FMPA agrees with the below comments submitted by the NSRF:

The NSRF has the following three concerns and the double jeopardy of noncompliance with R1 and part 1.3.
Concern one (1); R1 states “The Responsible Entity shall implement …” where the Responsible Entity is noted within section 4.1, Functional
Entities. So, each BA, GOP, GO, RC, TOP and TO shall implement a documented plan (s) to mitigate the risk of unauthorized disclosure or
modification of Real-time Assessments and Real-time monitoring data. Part 1.3 states that “If the Control Centers are owned or operated by different
Responsible Entities” which they will be (unless there is a vertically integrated Entity), those different Entities
already need to satisfy R1 since they are in section 4.1. This part 1.3 is redundant and is recommended to be removed.
Concern two (2); R1.3 states “… identify the responsibilities…” this identification of responsibilities is ambiguous as each Entity can only identify their
own responsibilities to “mitigate the risk of unauthorized disclosure or modification of Real-time Assessment and Real-time monitoring data…” per
R1. In essence, just repeating the words within R1 is not enhancing system reliability by any means. Recommended to be removed for this concern.
Concern three (3) is similar to concern 1, where one Entity needs to identify the other Entity which will be a different entity (unless they are a vertically
integrated Entity); those different Entities already need to satisfy R1 since they are in section 4.1. This part 1.3 is redundant and is recommended to be
removed.
The NSRF recommends that part 1.3 be deleted in its entirety as all Functional Entities will be required to satisfy R1 and part 1.1 and 1.2.
The NSRF agrees with adding “except under CIP Exceptional Circumstances” in R1.
Likes

0

Dislikes
Response

0

3. Implementation Plan: The SDT established the Implementation Plan to make the standard effective the first day of the first calendar quarter
that is twenty-four (24) calendar months after the effective date of the applicable governmental authority’s order approving the standard, or
as otherwise provided for by the applicable governmental authority. Do you agree with this proposal? If you think an alternate
implementation time period is needed, please provide a detailed explanation of actions and time needed to meet the implementation
deadline.
Russell Martin II - Salt River Project - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
Overall, SRP does not agree with twenty-four (24) calendar months for the implementation of Requirements R1, as R1 and R2 from the second draft
have been merged. Although SRP recognizes the SDT is not specifying the controls to be used to protect confidentiality and integrity, the only examples
provided in the implementation guidance includes encryption. If there are other methods available to achieve the security objective, SRP asks the SDT
to provide them. However, the only method available to achieve the proposed required objective, on the ICCP network, is to implement encryption. As
FERC order 822 states on page 37, “if several registered entities have joint responsibility for a cryptographic key management system used between
their respective Control Centers, they should have the prerogative to come to a consensus on which organization administers that particular key
management system.” Furthermore, the FERC order states on page 38, “While responsible entities are required to exchange real-time and operational
planning data necessary to operate the bulk electric system using mutually agreeable security protocols, there is no technical specification for how this
transfer of information should incorporate mandatory security controls.” These are activities and specifications that must be created and agreed upon by
all registered entities involved in the data transfer. As such the timeline is reliant on registered entities working together on a common solution and
would not be achievable within 24 calendar months.
Additionally, if encryption fails, SRP would lose Real-time Assessment and Real-time monitoring and control data. There are many opportunities for
encryption to fail that must be addressed. The implementation of encryption requires a pilot to truly understand and address the mechanisms of failure,
the impacts encryption would cause on the exchange of the data, and the computing resources required. A pilot also requires a great amount of
coordination to execute, not only within the industry, but may also include carriers, vendors, and possibly third-party encryption key program managers.
Because of the aforementioned reasons and concerns, SRP is recommending a phased implementation for CIP-012-1. A 24 month implementation is
appropriate, but only for Requirement R1. The 24 months for R1 would provide time to coordinate and create an industry-wide solution. SRP is
proposing the SDT include an additional 12 months for the plan implementation aspect of Requirement R1. The additional 12 months would be used for
a pilot and course correction if needed, in addition to understanding, formulating, and executing maintenance strategies.
Likes

0

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0

Response

Steven Rueckert - Western Electricity Coordinating Council - 10
Answer
Document Name
Comment

No

WECC believes the Implementation Plan of 24 months is unnecessary and the standard 18-month Implementation Plan should suffice. However, if the
clarification sought in question 1 above is provided, WECC would not vote NO solely based on the length of the Implementation Plan.
Likes

0

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0

Response

Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

No

Document Name
Comment
Duke Energy disagrees that twenty-four calendar (24) months is enough time for implementation. We reiterate our previous comment and suggest a
staggered implementation plan for CIP-012 specifically concerning coordination with neighboring entities. We consider it possible for an entity to gather
necessary data, convening of internal work groups, and drafting of security protection plans in the proposed 24 month Implementation Plan. However,
we feel that the coordination with other entities that will be necessary for R1.3 will take longer than the proposed 24 months, especially with internal
work already taking place. We recommend the drafting team consider a staggered implementation plan for internal work (18 months) compared to
external coordination work (36 months). When considering coordination/testing with neighboring entities, possible equipment upgrades/lead times that
could ensue, we feel that additional time above the proposed 24-month Implementation Plan is warranted.
Likes

0

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0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
BPA agrees with the intent of the FERC Directive. BPA is concerned about the proposed solution and its implementation timeline.
BPA requests that the SDT incorporate a pilot project to validate the proposed solution; is designed to address the FERC directive. Additionally, BPA
requests the implementation timeframe to be extended to a 36 month phased implementation timeline; to begin upon successful completion of the pilot
project. The industry needs 36 months due to the large amount of applicable data, access to funds, budget cycle, and resources to perform work
required.
BPA is concerned about 3rd party encryption keys and the risks they pose, including the expiration of encryption keys. When an encryption key expires,
the data flow ceases immediately to include Real-time Assessment and Real-time monitoring and control data. BPA requests that controls be put in
place to ensure mitigation measures do not allow encryption keys to expire. Additionally, BPA is concerned that there is a risk of the certificate authority

being unavailable for authentication, impacting maintenance of reliable communications between control centers for operation of the Bulk Electric
System.
BPA also agrees with SRP comments, as follows:
“Overall, SRP does not agree with twenty-four (24) calendar months for the implementation of Requirements R1, as R1 and R2 from the second draft
have been merged. Although SRP recognizes the SDT is not specifying the controls to be used to protect confidentiality and integrity, the only examples
provided in the implementation guidance includes encryption. If there are other methods available to achieve the security objective, SRP asks the SDT
to provide them. However, the only method available to achieve the proposed required objective, on the ICCP network, is to implement encryption. As
FERC order 822 states on page 37, “if several registered entities have joint responsibility for a cryptographic key management system used between
their respective Control Centers, they should have the prerogative to come to a consensus on which organization administers that particular key
management system.” Furthermore, the FERC order states on page 38, “While responsible entities are required to exchange real-time and operational
planning data necessary to operate the bulk electric system using mutually agreeable security protocols, there is no technical specification for how this
transfer of information should incorporate mandatory security controls.” These are activities and specifications that must be created and agreed upon by
all registered entities involved in the data transfer. As such the timeline is reliant on registered entities working together on a common solution and
would not be achievable within 24 calendar months.
Additionally, if encryption fails, SRP would lose Real-time Assessment and Real-time monitoring and control data. There are many opportunities for
encryption to fail that must be addressed. The implementation of encryption requires a pilot to truly understand and address the mechanisms of failure,
the impacts encryption would cause on the exchange of the data, and the computing resources required. A pilot also requires a great amount of
coordination to execute, not only within the industry, but may also include carriers, vendors, and possibly third-party encryption key program managers.
Because of the aforementioned reasons and concerns, SRP is recommending a phased implementation for CIP-012-1. A 24 month implementation is
appropriate, but only for Requirement R1. The 24 months for R1 would provide time to coordinate and create an industry-wide solution. SRP is
proposing the SDT include an additional 12 months for the plan implementation aspect of Requirement R1. The additional 12 months would be used for
a pilot and course correction if needed, in addition to understanding, formulating, and executing maintenance strategies.”
Likes

0

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0

Response

Marty Hostler - Northern California Power Agency - 5
Answer

No

Document Name
Comment
No, this standard should never be implemented! This is too prescriptive and unnecessary. IRO-010-2 R3.3 and TOP-003-3 R5.3 already provide
reliability assurance requirements for RCs, BAs, GOs, GOPs, TOPs, TOs, and DPs. Additionally, NERC has a Standards Efficiency Initiative underway
to get rid of standards and requirements such as CIP-012-1 and its' requirement 1.
Likes

0

Dislikes
Response

0

Dennis Sismaet - Northern California Power Agency - 6
Answer

No

Document Name
Comment
No, this standard should never be implemented! This is too prescriptive and unnecessary. IRO-010-2 Question 3
Likes

0

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0

Response

Joe McKinney - Florida Municipal Power Agency - 3,4,5,6
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Chris Gowder - Florida Municipal Power Agency - 3,4,5,6
Answer

No

Document Name
Comment

Likes

0

Dislikes

0

Response

Teresa Cantwell - Lower Colorado River Authority - 1,5
Answer
Document Name
Comment

Yes

None
Likes

0

Dislikes

0

Response

Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

Yes

Document Name
Comment
The implementation plan is agreeable for a new CIP requirement to provide ample time to evaluate the impact and prepare the appropriate controls and
procedures.
Likes

0

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0

Response

David Jendras - Ameren - Ameren Services - 1,3,6
Answer

Yes

Document Name
Comment
Ameren supports the proposed twenty-four (24) month implementation plan due to the complexity of securing control center to control center
communications, which will require significant external coordination, procurement and installation of new technology and processes, legal reviews, and
training.
Technical challenges to implementing the standard will also be significant. For example, entities may deploy Secure ICCP as their CIP-012-1 solution.
The Pacific Northwest National Laboratory’s (“PNNL”) June 2017 report, “Secure ICCP,” identifies technical and other challenges for entities
implementing secure ICCP (e.g., limited industry experience, documentation, support, difficulties with software upgrades and patching). The PNNL
report is available at: https://www.pnnl.gov/main/publications/external/technical_reports/PNNL-26729.pdf.
While these issues are not insurmountable they will take time, and should not be inappropriately rushed.
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Richard Jackson - U.S. Bureau of Reclamation - 1
Answer

Yes

Document Name
Comment
None
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Kevin Salsbury - Berkshire Hathaway - NV Energy - 5
Answer

Yes

Document Name
Comment
With any Standard that provides multiple iterations for proving compliance, a longer timeline is necessary, and we support a 24 month window for
implementation.
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Chris Scanlon - Exelon - 1
Answer

Yes

Document Name
Comment
Exelon supports the proposed twenty-four (24) month implementation plan due to the complexity of securing control center to control center
communications, which will require significant external coordination, procurement and installation of new technology and processes, legal reviews, and
training.
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Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion
Answer

Yes

Document Name
Comment
Considering the complexity, it is estimated that 36 calendar months would be required to comply.
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Andrea Koch - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

Yes

Document Name
Comment
EEI supports the proposed twenty-four (24) month implementation plan due to the complexity of securing control center to control center
communications, which will require significant external coordination, procurement and installation of new technology and processes, legal reviews, and
training.
Technical challenges to implementing the standard will also be significant. For example, entities may deploy Secure ICCP as their CIP-012-1 solution.
The Pacific Northwest National Laboratory’s (“PNNL”) June 2017 report, “Secure ICCP,” identifies technical and other challenges for entities
implementing secure ICCP (e.g., limited industry experience, documentation, limited user community, support, difficulties with software upgrades and
patching). The report details the implementation of Secure ICCP using the same EMS vendor software. Similar installations using different or
comingled EMS vendor software may prove to be even more challenging. The PNNL report is available at:
https://www.pnnl.gov/main/publications/external/technical_reports/PNNL-26729.pdf.
In order to ensure there is sufficient time to address such reliability and compliance issues, EEI supports NERC’s proposed twenty-four (24) month
implementation plan.
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Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Document Name
Comment

Yes

Southern Company supports the proposed twenty-four (24) month implementation plan.
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Tho Tran - Tho Tran On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; - Tho Tran
Answer

Yes

Document Name
Comment
Oncor supports EEI's comment.
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0

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0

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Warren Cross - ACES Power Marketing - 1,3,4,5 - MRO,WECC,Texas RE,SERC
Answer

Yes

Document Name
Comment
:ACES believes that twenty-four (24) calendar months after the effective date of the applicable governmental authority’s order approving the standard
for implementation is appropriate.
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David Francis - Midcontinent ISO, Inc. - 2 - MRO,SERC,RF
Answer
Document Name
Comment

Yes

However, because this may invovle third parites equiement being place or added to a PSP based on the Technical Rationale and Justification for
Reliability Standard guidance may need extended design and implementation efforts in meeting the PSP security requirments
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Lynn Goldstein - PNM Resources - Public Service Company of New Mexico - 3
Answer

Yes

Document Name
Comment
While it will take less time for entities to implement intra-entity solutions, it will take time for inter-entity solutions to be drafted and agreed upon. Since
both entities will need to agree on not just implementing a technical solution (e.g. IPSec, Secure ICCP), but how to maintain it (e.g. cryptography key
management).
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Steve Rose - City Water, Light and Power of Springfield, IL - 1,3,5
Answer

Yes

Document Name
Comment

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0

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Thomas Foltz - AEP - 5
Answer
Document Name
Comment

Yes

Likes

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David Maier - Intermountain REA - 3
Answer

Yes

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Comment

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0

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Todd Bennett - Associated Electric Cooperative, Inc. - 3, Group Name AECI
Answer

Yes

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Comment

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0

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Aubrey Short - FirstEnergy - FirstEnergy Corporation - 4
Answer

Yes

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Comment

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0

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Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 3, Group Name FirstEnergy Corporation

Answer

Yes

Document Name
Comment

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0

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Dana Klem - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO NSRF
Answer

Yes

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Comment

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0

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Patricia Lynch - NRG - NRG Energy, Inc. - 5,6
Answer

Yes

Document Name
Comment

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0

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Aaron Smith - Omaha Public Power District - 1,3,5,6
Answer

Yes

Document Name
Comment

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0

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Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

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Comment

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0

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Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6
Answer

Yes

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Comment

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0

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David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

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Comment

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0

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0

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Michael Shaw - Lower Colorado River Authority - 1
Answer

Yes

Document Name
Comment

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0

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0

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Jeanne Kurzynowski - CMS Energy - Consumers Energy Company - 1,3,4,5 - RF
Answer

Yes

Document Name
Comment

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0

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0

Response

Brandon McCormick - Brandon McCormick On Behalf of: Ginny Beigel, City of Vero Beach, 3; Lynne Mila, City of Clewiston, 4; Mike Blough,
Kissimmee Utility Authority, 5, 3; Tom Reedy, Florida Municipal Power Pool, 6; - Brandon McCormick, Group Name FMPA
Answer

Yes

Document Name
Comment

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0

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0

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Douglas Webb - Douglas Webb On Behalf of: Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; James McBee,
Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; Jessica Tucker, Great Plains Energy - Kansas City Power and Light Co., 5,
1, 3, 6; Jim Flucke, Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; Megan Wagner, Westar Energy, 6, 3, 1, 5; - Douglas
Webb
Answer
Document Name
Comment

Yes

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0

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Richard Montgomery - Florida Municipal Power Agency - 3,4,5,6
Answer

Yes

Document Name
Comment

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0

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0

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Carol Chinn - Florida Municipal Power Agency - 3,4,5,6
Answer

Yes

Document Name
Comment

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0

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Darnez Gresham - Darnez Gresham On Behalf of: Annette Johnston, Berkshire Hathaway Energy - MidAmerican Energy Co., 1, 3; - Darnez
Gresham
Answer

Yes

Document Name
Comment

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0

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0

Jeff Johnson - Jeff Johnson On Behalf of: Martine Blair, Sempra - San Diego Gas and Electric, 3, 5, 1; - Jeff Johnson
Answer

Yes

Document Name
Comment

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0

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0

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Barry Lawson - National Rural Electric Cooperative Association - 4
Answer

Yes

Document Name
Comment

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0

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0

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Stephanie Burns - Stephanie Burns On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Stephanie
Burns
Answer

Yes

Document Name
Comment

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0

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0

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Eli Rivera - Central Electric Cooperative, Inc. (Redmond, Oregon) - NA - Not Applicable - Texas RE
Answer
Document Name
Comment

Yes

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0

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Andy Fuhrman - Andy Fuhrman On Behalf of: Theresa Allard, Minnkota Power Cooperative Inc., 1; - Andy Fuhrman
Answer

Yes

Document Name
Comment

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0

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0

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Douglas Johnson - American Transmission Company, LLC - 1
Answer

Yes

Document Name
Comment

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0

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James Anderson - CMS Energy - Consumers Energy Company - 1
Answer

Yes

Document Name
Comment

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0

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

Yes

Document Name
Comment

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0

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Martin Sidor - NRG - NRG Energy, Inc. - 5,6
Answer

Yes

Document Name
Comment

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0

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David Greyerbiehl - CMS Energy - Consumers Energy Company - 5
Answer

Yes

Document Name
Comment

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0

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Quintin Lee - Eversource Energy - 1
Answer
Document Name
Comment

Yes

Likes

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0

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Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - MRO, Group Name SPP Standards Review Group
Answer

Yes

Document Name
Comment

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0

4. Technical Rationale: The SDT modified the draft Technical Rationale for CIP-012 to further explain the need for the exemption for certain
Control Centers. Do you agree with the explanations and included diagrams in the draft Technical Rationale? If you do not agree, or if you
agree but have comments or suggestions for the draft Technical Rationale, please provide your recommendation and explanation.
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - MRO, Group Name SPP Standards Review Group
Answer

No

Document Name
Comment
The SPP Standards Review Group has a concern that the proposed Exemption will modify the current “Control Center” definition that potentially
changes how High and Low impacts assets are evaluated. The review group is proposing some language (shown below) to help maintain consistency
with the “Control Center” Definition and the proposed Exemption mentioned in the documentation. Additionally, the introduction of the term “Control
System” as well as the diagrams and explanations in the rationale present complexity pertaining to the current process of identifying BES Cyber
Systems. We would suggest that the drafting team remove the term “Control System” from all proposed language associated with this project.
Section 4.2.3. (Applicability Section –Standard)
A BES generation resource or Transmission station or substation that transmits to a Control Center Real-time Assessment or Real-time monitoring
data, such as RTU-style data, pertaining only to the generation resource or Transmission station or substation at which the data transmitted is
located.
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David Francis - Midcontinent ISO, Inc. - 2 - MRO,SERC,RF
Answer

No

Document Name
Comment
Increases security risk with repair personnel going into a PSP without knowning all the CIP security requirments for such devises and have in house
personnel escorting the repair personnel during any repair work
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David Greyerbiehl - CMS Energy - Consumers Energy Company - 5
Answer

No

Document Name
Comment
In the Technical Rationale document, please specify what type of date under TOP-003 and IRO-010 should be excluded from the CIP-012
requirements.
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0

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0

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James Anderson - CMS Energy - Consumers Energy Company - 1
Answer

No

Document Name
Comment
In the Technical Rationale document, please specify what type of date under TOP-003 and IRO-010 should be excluded from the CIP-012
requirements.
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0

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0

Response

Andy Fuhrman - Andy Fuhrman On Behalf of: Theresa Allard, Minnkota Power Cooperative Inc., 1; - Andy Fuhrman
Answer

No

Document Name
Comment
Please refer to MRO NERC Standards Review Forum (NSRF) comments.
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0

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Stephanie Burns - Stephanie Burns On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Stephanie
Burns
Answer

No

Document Name
Comment
The technical rational should show examples of demarcation points for the protections or define the demarcation points. For example, if a leased line or
router is not owned by the entity, however the entity chose to deploy a firewall to encrypt the traffic ahead of the router, then the firewall shall be the
demarcation point, not the router. Explanations left to the entity without proper guidance may lead to confusion. Furthermore, while entities may not
own both sides of the links, technologies such as VPN require both sides to follow the same configuration in order to encrypt data. If the other side is
not equipped to encrypt the data, the link will remain unsecure.
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Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

No

Document Name
Comment
Duke Energy suggests the drafting team consider adding a diagram that demonstrates under what circumstances a generating resource or
Transmission sub would be applicable to this standard. With the added exemption language, it would be helpful for the industry to have a couple of
examples where the exemption would not apply to existing generation resources and Transmission subs.
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Chris Gowder - Florida Municipal Power Agency - 3,4,5,6
Answer

No

Document Name
Comment
FMPA agrees with the following comments submitted by the NSRF:
The NSRF does not agree that Figure 2 and related discussion within the Technical Rationale document applies to Transmission stations and
substations and generation resources as being “Control Centers”. The NSRF believes that the Control Center definition was developed with the intent to
apply to functionally manned control centers that monitor and control the BES; a center that hosts System Operators that have specific training
requirements and in some instances certifications to meet the requirements of their position. It appears the drafting team is expanding the Control
Center definition for a field asset application in order to meet the needs of an exemption for CIP-012. Consider also, that in the last sentence of the first
paragraph of the Reference Model Discussion in the Implementation Guidance it correctly states “Additionally, Entity Alpha does not need to consider
any communications to other non-Control Center facilities such as generating plants or substations. These communications are out of scope for CIP012-1” [emphasis added] The NSRF does agree that RTU-style data transmission between BES generation and Transmission stations and substations

need to be explicitly excluded from CIP-012. The NSRF, under Comment #1 on this form, has provided revision language that meets our comments
here and those already addressed
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0

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Joe McKinney - Florida Municipal Power Agency - 3,4,5,6
Answer

No

Document Name
Comment
FMPA agrees with the following comments submitted by the NSRF:
The NSRF does not agree that Figure 2 and related discussion within the Technical Rationale document applies to Transmission stations and
substations and generation resources as being “Control Centers”. The NSRF believes that the Control Center definition was developed with the intent to
apply to functionally manned control centers that monitor and control the BES; a center that hosts System Operators that have specific training
requirements and in some instances certifications to meet the requirements of their position. It appears the drafting team is expanding the Control
Center definition for a field asset application in order to meet the needs of an exemption for CIP-012. Consider also, that in the last sentence of the first
paragraph of the Reference Model Discussion in the Implementation Guidance it correctly states “Additionally, Entity Alpha does not need to consider
any communications to other non-Control Center facilities such as generating plants or substations. These communications are out of scope for CIP012-1” [emphasis added].
Likes

0

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0

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Carol Chinn - Florida Municipal Power Agency - 3,4,5,6
Answer

No

Document Name
Comment
FMPA agrees with the following comments submitted by the NSRF:
The NSRF does not agree that Figure 2 and related discussion within the Technical Rationale document applies to Transmission stations and
substations and generation resources as being “Control Centers”. The NSRF believes that the Control Center definition was developed with the intent to
apply to functionally manned control centers that monitor and control the BES; a center that hosts System Operators that have specific training
requirements and in some instances certifications to meet the requirements of their position. It appears the drafting team is expanding the Control
Center definition for a field asset application in order to meet the needs of an exemption for CIP-012. Consider also, that in the last sentence of the first
paragraph of the Reference Model Discussion in the Implementation Guidance it correctly states “Additionally, Entity Alpha does not need to consider

any communications to other non-Control Center facilities such as generating plants or substations. These communications are out of scope for CIP012-1” [emphasis added].
Likes

0

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0

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Richard Montgomery - Florida Municipal Power Agency - 3,4,5,6
Answer

No

Document Name
Comment
FMPA agrees with the following comments submitted by the NSRF:
The NSRF does not agree that Figure 2 and related discussion within the Technical Rationale document applies to Transmission stations and
substations and generation resources as being “Control Centers”. The NSRF believes that the Control Center definition was developed with the intent to
apply to functionally manned control centers that monitor and control the BES; a center that hosts System Operators that have specific training
requirements and in some instances certifications to meet the requirements of their position. It appears the drafting team is expanding the Control
Center definition for a field asset application in order to meet the needs of an exemption for CIP-012. Consider also, that in the last sentence of the first
paragraph of the Reference Model Discussion in the Implementation Guidance it correctly states “Additionally, Entity Alpha does not need to consider
any communications to other non-Control Center facilities such as generating plants or substations. These communications are out of scope for CIP012-1” [emphasis added].
Likes

0

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0

Response

Brandon McCormick - Brandon McCormick On Behalf of: Ginny Beigel, City of Vero Beach, 3; Lynne Mila, City of Clewiston, 4; Mike Blough,
Kissimmee Utility Authority, 5, 3; Tom Reedy, Florida Municipal Power Pool, 6; - Brandon McCormick, Group Name FMPA
Answer

No

Document Name
Comment
Comments: FMPA agrees with the following comments submitted by the NSRF:
The NSRF does not agree that Figure 2 and related discussion within the Technical Rationale document applies to Transmission stations and
substations and generation resources as being “Control Centers”. The NSRF believes that the Control Center definition was developed with the intent to
apply to functionally manned control centers that monitor and control the BES; a center that hosts System Operators that have specific training
requirements and in some instances certifications to meet the requirements of their position. It appears the drafting team is expanding the Control
Center definition for a field asset application in order to meet the needs of an exemption for CIP-012. Consider also, that in the last sentence of the first
paragraph of the Reference Model Discussion in the Implementation Guidance it correctly states “Additionally, Entity Alpha does not need to consider

any communications to other non-Control Center facilities such as generating plants or substations. These communications are out of scope for CIP012-1” [emphasis added].
The NSRF does agree that RTU-style data transmission between BES generation and Transmission stations and substations need to be explicitly
excluded from CIP-012. The NSRF, under Comment #1 on this form, has provided revision language that meets our comments here and those already
addressed
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0

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0

Response

Jeanne Kurzynowski - CMS Energy - Consumers Energy Company - 1,3,4,5 - RF
Answer

No

Document Name
Comment
In the Technical Rationale document, please specify what type of date under TOP-003 and IRO-010 should be excluded from the CIP-012
requirements.
Likes

0

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0

Response

Richard Jackson - U.S. Bureau of Reclamation - 1
Answer

No

Document Name
Comment
Reclamation recommends that all Real-time Assessment and Real-time monitoring data be protected against the risk of unauthorized disclosure or
modification. Reclamation asserts that the need to protect the data from a GOP Control Center with the ability to control more than two geographically
separated facilities is no different than the need to protect the data from each single location, and no different from the need to protect data from a GOP
Control Center to an RC or BA Control Center.
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0

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0

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Aaron Smith - Omaha Public Power District - 1,3,5,6

Answer

No

Document Name
Comment
The NSRF does not agree that Figure 2 and related discussion within the Technical Rationale document applies to Transmission stations and
substations and generation resources as being “Control Centers”. The NSRF believes that the Control Center definition was developed with the intent to
apply to functionally manned control centers that monitor and control the BES; a center that hosts System Operators that have specific training
requirements and in some instances certifications to meet the requirements of their position. It appears the drafting team is expanding the Control
Center definition for a field asset application in order to meet the needs of an exemption for CIP-012. Consider also, that in the last sentence of the first
paragraph of the Reference Model Discussion in the Implementation Guidance it correctly states “Additionally, Entity Alpha does not need to consider
any communications to other non-Control Center facilities such as generating plants or substations. These communications are out of scope for CIP012-1” [emphasis added].

The NSRF does agree that RTU-style data transmission between BES generation and Transmission stations and substations need to be explicitly
excluded from CIP-012. The NSRF, under Comment #1 on this form, has provided revision language that meets our comments here and those already
addressed.
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0

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0

Response

David Jendras - Ameren - Ameren Services - 1,3,6
Answer

No

Document Name
Comment
We believe that any of the technical rationale that can be condensed into clear, concise language should be moved into the CIP-012-1 as a defined
requirement. Responsible Entities are audited to the Requirements in the Standard. Leaving this much information as Technical Rationale invites
subjective audit interpretation unnecessarily increases compliance risk for the entity.
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0

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Laura Nelson - IDACORP - Idaho Power Company - 1
Answer
Document Name
Comment

No

Idaho Power believes Figures 2 & 3 start to muddy the waters a little bit in terms of the initial intent of the CIP-012. Figure 2 seems to state that Station
Alpha would be considered a control center, but Figure 3 seems to state that the communication between Station Alpha and the TOP control center
would not be in scope of CIP-012. While Idaho Power would agree that in the end that seems to get to of the objective of the initial intent of CIP-012,
this seems like a confusing way to reach that conclusion.
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0

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Dana Klem - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO NSRF
Answer

No

Document Name
Comment
The NSRF does not agree that Figure 2 and related discussion within the Technical Rationale document applies to Transmission stations and
substations and generation resources as being “Control Centers”. The NSRF believes that the Control Center definition was developed with the intent to
apply to functionally manned control centers that monitor and control the BES; a center that hosts System Operators that have specific training
requirements and in some instances certifications to meet the requirements of their position. It appears the drafting team is expanding the Control
Center definition for a field asset application in order to meet the needs of an exemption for CIP-012. Consider also, that in the last sentence of the first
paragraph of the Reference Model Discussion in the Implementation Guidance it correctly states “Additionally, Entity Alpha does not need to consider
any communications to other non-Control Center facilities such as generating plants or substations. These communications are out of scope for CIP012-1” [emphasis added].
The NSRF does agree that RTU-style data transmission between BES generation and Transmission stations and substations need to be explicitly
excluded from CIP-012. The NSRF, under Comment #1 on this form, has provided revision language that meets our comments here and those already
addressed.
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0

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0

Response

Thomas Foltz - AEP - 5
Answer

No

Document Name
Comment

AEP requests the SDT consider including some statements in the Technical Rationale to address the possibility that data requests made related to
TOP-003 and/or IRO-010 include other data that is not Real-time Assessment data or Real-time monitoring data, and how the Responsible Entity could
exclude this other data from the security requirements.

The following text on page vi may need to be edited for sake of clarity “The only thing that has changed is an HMI for Station Beta has been moved
within close physical proximity to an HMI for Station Alpha.”
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Lynn Goldstein - PNM Resources - Public Service Company of New Mexico - 3
Answer

Yes

Document Name
Comment
PNM Resources supports EEI’s comments on this question.
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0

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0

Response

Warren Cross - ACES Power Marketing - 1,3,4,5 - MRO,WECC,Texas RE,SERC
Answer

Yes

Document Name
Comment
No comments.
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0

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0

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Quintin Lee - Eversource Energy - 1
Answer
Document Name
Comment

Yes

We feel that the example presented in the Technical Guidance reflects the Exemption accurately, however, the SDT is compounding the Control Center
issue by having another explanation of a Control Center/control center to those already present in CIP-002, CIP-014, and the NERC Glossary, and now
CIP-012. We recommend a single document that explains the Control Center / control center topic.
Likes

0

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0

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Tho Tran - Tho Tran On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; - Tho Tran
Answer

Yes

Document Name
Comment
Oncor supports EEI's comment.
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0

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0

Response

Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer

Yes

Document Name
Comment
Southern Company supports the need to exempt certain Control Centers. Barring the ability to address the Control Center definition fully, Southern
recognizes that the proposed Standard addresses the need for an exemption in an appropriate way.
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0

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Andrea Koch - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

Yes

Document Name

CIP 12 Figures.pdf

Comment

EEI supports the need for an exemption and explanation for digital control systems installed at generating stations and Transmission stations and
substations that may also be classified as Control Centers. However, we have concerns that some parts of the Technical Rationale may align too
closely with NERC’s description of Implementation Guidance. (see Technical Rationale Transition Plan)
In the redline edits provided by the SDT, Figures 2 and 3 provide examples of communications between two generating stations, while technically
conforming to the definition of a Control Center, are outside the intended scope of CIP-012-1 standard. While the language and figures provide needed
clarity, we suggest the SDT consider using diagrams that more closely conforms to the figures provided within our comments. We have provided these
suggested changes because we are concerned that the issues of aggregated communications along with situations where Facilities contained within a
single confined area are not clearly addressed in the Technical Rationale. We believe the diagrams provided more clearly define the limitations of the
exemption.
As stated above, we are concerned that the examples and approaches provided in the Technical Rationale may be better contained in the
Implementation Guidance given the above referenced NERC document suggests that Implementation Guidance is where examples and approaches are
to be used to illustrate how to comply with a Reliability Standard.
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Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion
Answer

Yes

Document Name
Comment
We feel that the example presented in the Technical Guidance reflects the Exemption accurately, however, the SDT is compounding the Control Center
issue by having another explanation of a Control Center/control center to those already present in CIP-002, CIP-014, and the NERC Glossary, and now
CIP-012. We recommend a single document that explains the Control Center / control center topic.
Likes

0

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0

Response

Eli Rivera - Central Electric Cooperative, Inc. (Redmond, Oregon) - NA - Not Applicable - Texas RE
Answer

Yes

Document Name
Comment
CenterPoint Energy Houston Electric, LLC (“CenterPoint Energy”) agrees with Edison Electric Institute’s (EEI) comments.
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0

Dislikes

0

Response

Chris Scanlon - Exelon - 1
Answer

Yes

Document Name
Comment
Exelon supports the need for an exemption and explanation for digital control systems installed at generating stations and Transmission stations and
substations that may also be classified as Control Centers. However, we have concerns that some parts of the Technical Rationale may align too
closely with NERC’s description of Implementation Guidance. (see Technical Rationale Transition Plan)
In the redline edits provided by the SDT, Figures 2 and 3 provide examples of communications between two generating stations, while technically
conforming to the definition of a Control Center, are outside the intended scope of CIP-012-1 standard. While the language and figures provide needed
clarity, we suggest the SDT consider using diagrams that more closely conform to the figures provided within our comments. We have provided these
suggested changes because we are concerned that the issues of aggregated communications along with situations where Facilities contained within a
single confined area are not clearly addressed in the Technical Rationale. We believe the diagrams provided more clearly define the limitations of the
exemption.
Exelon is also concerned that the examples and approaches provided in the Technical Rationale may be better contained in the Implementation
Guidance given the above referenced NERC document suggests that Implementation Guidance is where examples and approaches are to be used to
illustrate how to comply with a Reliability Standard.
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Kevin Salsbury - Berkshire Hathaway - NV Energy - 5
Answer

Yes

Document Name
Comment
NV Energy understands that a unknown expedited timeline and the original SAR are obstacles for the SDT at this time, and that this Standard will be
approved in the near term, but we believe that further development of the Control Center definition should be resolved before more standards regarding
Control Centers are introduced.
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0

Darnez Gresham - Darnez Gresham On Behalf of: Annette Johnston, Berkshire Hathaway Energy - MidAmerican Energy Co., 1, 3; - Darnez
Gresham
Answer

Yes

Document Name
Comment
While MEC understands that time and the SAR are obstacles for the SDT at this time, however, issues with the existing Control Center definition should
be resolved before more standards regarding Control Centers are introduced.
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Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6
Answer

Yes

Document Name
Comment
PAC understands that time and the SAR are obstacles for the SDT at this time, further development of the Control Center definition should be resolved
before more standards regarding Control Centers are introduced.
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Russell Martin II - Salt River Project - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
SRP agrees with the Technical Rationale and Justification for CIP-012 provided by the SDT. However, SRP continues to maintain that an additional 12
months be considered for the plan implementation aspect of Requirement R1. PDF page 6, paragraph 3 of section title Identification of Where Security
Protection is Applied by the Responsible Entity states "The SDT understands that in data exchanges between Control Centers, a single entity may not
be responsible for both ends of the communication link." With the intent of the standard being to secure communications between Control Centers
(including communication between two separate entities Control Centers), this will call for inter-entity cooperation to ensure both sides of link are
secure. This is where the additional 12 months would be necessary, for coordination of efforts from both entities.
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Response

Teresa Cantwell - Lower Colorado River Authority - 1,5
Answer

Yes

Document Name
Comment
None
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Dennis Sismaet - Northern California Power Agency - 6
Answer

Yes

Document Name
Comment

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0

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Marty Hostler - Northern California Power Agency - 5
Answer

Yes

Document Name
Comment

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0

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0

Response

Martin Sidor - NRG - NRG Energy, Inc. - 5,6

Answer

Yes

Document Name
Comment

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0

Response

Chris Wagner - Santee Cooper - 1, Group Name Santee Cooper
Answer

Yes

Document Name
Comment

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0

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0

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Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment

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0

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0

Response

Douglas Johnson - American Transmission Company, LLC - 1
Answer

Yes

Document Name
Comment

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0

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0

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Jeff Johnson - Jeff Johnson On Behalf of: Martine Blair, Sempra - San Diego Gas and Electric, 3, 5, 1; - Jeff Johnson
Answer

Yes

Document Name
Comment

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0

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0

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Douglas Webb - Douglas Webb On Behalf of: Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; James McBee,
Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; Jessica Tucker, Great Plains Energy - Kansas City Power and Light Co., 5,
1, 3, 6; Jim Flucke, Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; Megan Wagner, Westar Energy, 6, 3, 1, 5; - Douglas
Webb
Answer

Yes

Document Name
Comment

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0

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0

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Michael Shaw - Lower Colorado River Authority - 1
Answer

Yes

Document Name
Comment

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0

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0

David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment

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0

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0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment

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0

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0

Response

Patricia Lynch - NRG - NRG Energy, Inc. - 5,6
Answer

Yes

Document Name
Comment

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0

Response

Steven Rueckert - Western Electricity Coordinating Council - 10
Answer
Document Name
Comment

Yes

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0

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0

Response

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 3, Group Name FirstEnergy Corporation
Answer

Yes

Document Name
Comment

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0

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0

Response

Aubrey Short - FirstEnergy - FirstEnergy Corporation - 4
Answer

Yes

Document Name
Comment

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0

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0

Response

David Maier - Intermountain REA - 3
Answer

Yes

Document Name
Comment

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0

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0

Response

Steve Rose - City Water, Light and Power of Springfield, IL - 1,3,5

Answer

Yes

Document Name
Comment

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0

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0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE does not have comments on this question.
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0

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0

5. The SDT modified the draft Implementation Guidance for CIP-012 to provide examples of how a Responsible Entity could comply with the
requirements. The draft Implementation Guidance does not prescribe the only approaches to compliance. Rather, it describes what the SDT
believes would be effective ways to comply with the standard. See NERC’s Compliance Guidance policy for information on Implementation
Guidance. Do you agree with the draft Implementation Guidance? If you do not agree, or if you agree but have comments or suggestions for
the draft Implementation Guidance, please provide your recommendation and explanation.
Thomas Foltz - AEP - 5
Answer

No

Document Name
Comment

AEP requests the SDT consider including some statements in the Implementation Guidance to address the possibility that data requests made related
to TOP-003 and/or IRO-010 include other data that is not Real-time Assessment data or Real-time monitoring data, and how the Responsible Entity
could exclude this other data from the security requirements.
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Russell Martin II - Salt River Project - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
Overall, SRP does not agree with twenty-four (24) calendar months for the implementation of Requirements R1, as R1 and R2 from the second draft
have been merged. Although SRP recognizes the SDT is not specifying the controls to be used to protect confidentiality and integrity, the only examples
provided in the implementation guidance includes encryption. If there are other methods available to achieve the security objective, SRP asks the SDT
to provide them. However, the only method available to achieve the proposed required objective, on the ICCP network, is to implement encryption. As
FERC order 822 states on page 37, “if several registered entities have joint responsibility for a cryptographic key management system used between
their respective Control Centers, they should have the prerogative to come to a consensus on which organization administers that particular key
management system.” Furthermore, the FERC order states on page 38, “While responsible entities are required to exchange real-time and operational
planning data necessary to operate the bulk electric system using mutually agreeable security protocols, there is no technical specification for how this
transfer of information should incorporate mandatory security controls.” These are activities and specifications that must be created and agreed upon by
all registered entities involved in the data transfer. As such the timeline is reliant on registered entities working together on a common solution and
would not be achievable within 24 calendar months.
Additionally, if encryption fails, SRP would lose Real-time Assessment and Real-time monitoring and control data. There are many opportunities for
encryption to fail that must be addressed. The implementation of encryption requires a pilot to truly understand and address the mechanisms of failure,
the impacts encryption would cause on the exchange of the data, and the computing resources required. A pilot also requires a great amount of
coordination to execute, not only within the industry, but may also include carriers, vendors, and possibly third-party encryption key program managers.
Because of the aforementioned reasons and concerns, SRP is recommending a phased implementation for CIP-012-1. A 24 month implementation is
appropriate, but only for Requirement R1. The 24 months for R1 would provide time to coordinate and create an industry-wide solution. SRP is

proposing the SDT include an additional 12 months for the plan implementation aspect of Requirement R1. The additional 12 months would be used for
a pilot and course correction if needed, in addition to understanding, formulating, and executing maintenance strategies.
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Response

Dana Klem - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO NSRF
Answer

No

Document Name
Comment
Based upon NSRF comments to delete Requirement 1, Part 1.3 as identified under #2 of this comment form, the section within the Implementation
Guidance titled “Identification of Responsibilities when the Control Centers are Owned or Operated by Different Responsible Entities” would need to be
revised or eliminated. In addition, the Reference Model section of the Implementation Guide would also need be revised in those areas that reflect
Responsible Entity accountability for other Responsible Entities.
The drafting team in earlier response to comments has stated that the Implementation Guidance would be submitted as a Standard Application Guide to
NERC. This is imperative for Responsible Entities and Regional Entities to understand the intent and consistent application of this non-prescriptive
Standard.
The NSRF questions when any type of Guidance is needed when the Standard is clearly written. As stated in FERC Order 693 section 253, FERC
states “…The most critical element of a Reliability Standard is the Requirements. As NERC explains, “the Requirements within a standard define what
an entity must do to be compliant . . . [and] binds an entity to certain obligations of performance under section 215 of the FPA.” If properly drafted, a
Reliability Standard may be enforced in the absence of specified Measures or Levels of Non-Compliance”.
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David Jendras - Ameren - Ameren Services - 1,3,6
Answer

No

Document Name
Comment
As with technical rationale any implementation guidance that can be condensed into clear, concise language should be moved into the CIP-012-1 as a
defined requirement. Responsible Entities are audited to the Requirements in the Standard. In our opinion, leaving this much information as
implementation guidance invites subjective audit interpretation and therefore unnecessarily increases compliance risk for the entity. The inclusion of
acceptable means/methods within the verbiage of a Requirement does not necessarily make it prescriptive because the wording can state "or any other
means that addresses the XXX risk". In addition, this type of guidance provides explicit compliance help which on its face increases overall BES
reliability because entities may rely on the guidance to be compliant and not err by misinterpreting what can be done.

Likes

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Aaron Smith - Omaha Public Power District - 1,3,5,6
Answer

No

Document Name
Comment
: Based upon NSRF comments to delete Requirement 1, Part 1.3 as identified under #2 of this comment form the section within the Implementation
Guidance titled “Identification of Responsibilities when the Control Centers are Owned or Operated by Different Responsible Entities” would need to be
revised or eliminated. In addition, the Reference Model section of the Implementation Guide would also need be revised in those areas that reflect
Responsible Entity accountability for other Responsible Entities.

The drafting team in earlier response to comments has stated that the Implementation Guidance would be submitted as a Standard Application Guide to
NERC. This is imperative for Resonsible Entities and Regional Entities to understand intent and consistent application of this non-prescriptive Standard.
The NSRF questions when any type of Guidance is needed when the Standard is clearly written. As stated in FERC Order 693 section 253, FERC
states “…The most critical element of a Reliability Standard is the Requirements. As NERC explains, “the Requirements within a standard define what
an entity must do to be compliant . . . [and] binds an entity to certain obligations of performance under section 215 of the FPA.” If properly drafted, a
Reliability Standard may be enforced in the absence of specified Measures or Levels of Non-Compliance
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0

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Response

Jeanne Kurzynowski - CMS Energy - Consumers Energy Company - 1,3,4,5 - RF
Answer

No

Document Name
Comment
In the Implementation Guidance document, please specify what type of date under TOP-003 and IRO-010 should be excluded from the CIP-012
requirements.
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0

Brandon McCormick - Brandon McCormick On Behalf of: Ginny Beigel, City of Vero Beach, 3; Lynne Mila, City of Clewiston, 4; Mike Blough,
Kissimmee Utility Authority, 5, 3; Tom Reedy, Florida Municipal Power Pool, 6; - Brandon McCormick, Group Name FMPA
Answer

No

Document Name
Comment
The example “Identification of Responsibilities when the Control Centers are Owned or Operated by Different Responsible Entities, the language
indicates the communication link endpoint is within a PSP. If the Control Center is rated as a Low Impact per the CIP-002-5.1a Attachment 1 Criteria
3.1, the term PSP does not apply and is not required by the Standard.
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0

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Douglas Webb - Douglas Webb On Behalf of: Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; James McBee,
Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; Jessica Tucker, Great Plains Energy - Kansas City Power and Light Co., 5,
1, 3, 6; Jim Flucke, Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; Megan Wagner, Westar Energy, 6, 3, 1, 5; - Douglas
Webb
Answer

No

Document Name
Comment
Kansas City Power and Light Company incorporates the Edison Electric Institute's response to Question No. 5.
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Richard Montgomery - Florida Municipal Power Agency - 3,4,5,6
Answer

No

Document Name
Comment
The example “Identification of Responsibilities when the Control Centers are Owned or Operated by Different Responsible Entities, the language
indicates the communication link endpoint is within a PSP. If the Control Center is rated as a Low Impact per the CIP-002-5.1a Attachment 1 Criteria
3.1, the term PSP does not apply and is not required by the Standard
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0
0

Response

Carol Chinn - Florida Municipal Power Agency - 3,4,5,6
Answer

No

Document Name
Comment
The example “Identification of Responsibilities when the Control Centers are Owned or Operated by Different Responsible Entities, the language
indicates the communication link endpoint is within a PSP. If the Control Center is rated as a Low Impact per the CIP-002-5.1a Attachment 1 Criteria
3.1, the term PSP does not apply and is not required by the Standard
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0

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0

Response

Joe McKinney - Florida Municipal Power Agency - 3,4,5,6
Answer

No

Document Name
Comment
The example “Identification of Responsibilities when the Control Centers are Owned or Operated by Different Responsible Entities, the language
indicates the communication link endpoint is within a PSP. If the Control Center is rated as a Low Impact per the CIP-002-5.1a Attachment 1 Criteria
3.1, the term PSP does not apply and is not required by the Standard.
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0

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0

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Chris Gowder - Florida Municipal Power Agency - 3,4,5,6
Answer

No

Document Name
Comment
The example “Identification of Responsibilities when the Control Centers are Owned or Operated by Different Responsible Entities, the language
indicates the communication link endpoint is within a PSP. If the Control Center is rated as a Low Impact per the CIP-002-5.1a Attachment 1 Criteria
3.1, the term PSP does not apply and is not required by the Standard
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0

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Response

Chris Scanlon - Exelon - 1
Answer

No

Document Name
Comment
Generally, Exelon supports the Implementation Guidance, but ask the SDT to consider the following suggested changes:
1. Address how an entity might effectively identify Control Centers (as defined by the NERC Glossary) that would be exempted from complying
with CIP-012-1 as a result of the newly developed Exemption 4.2.3 language.
2. There are many different approaches to mitigating the risk of unauthorized disclosure or modification of data in transit. Additional guidance that
explores various approaches and evaluates their effectiveness in mitigating risk may be helpful before entities make implementation
investments for CIP-012-1.
3. Exelon suggests the SDT consider removing or modifying the email example (last bullet on page 8) since email and the associated password
exchange recommended (e.g., by phone) i “inconsistent with the requirements of Real-time data exchange” as indicated in the draft
Implementation Guidance.
While Exwlon recognizes that approval of Implementation Guidance goes beyond the responsibility of the SDT, we suggest the final version of
Implementation Guidance be approved by the ERO and posted with the Standard before any final ballot.
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0

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0

Response

Stephanie Burns - Stephanie Burns On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Stephanie
Burns
Answer

No

Document Name
Comment
Comments above in question 4 apply here as well.
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0

Eli Rivera - Central Electric Cooperative, Inc. (Redmond, Oregon) - NA - Not Applicable - Texas RE
Answer

No

Document Name
Comment
CenterPoint Energy Houston Electric, LLC (“CenterPoint Energy”) agrees with Edison Electric Institute’s (EEI) comments.
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0

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0

Response

Andy Fuhrman - Andy Fuhrman On Behalf of: Theresa Allard, Minnkota Power Cooperative Inc., 1; - Andy Fuhrman
Answer

No

Document Name
Comment
Please refer to MRO NERC Standards Review Forum (NSRF) comments.
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0

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Response

James Anderson - CMS Energy - Consumers Energy Company - 1
Answer

No

Document Name
Comment
In the Implementation Guidance document, please specify what type of date under TOP-003 and IRO-010 should be excluded from the CIP-012
requirements.
Likes

0

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0

Response

Andrea Koch - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

No

Document Name
Comment
Generally, EEI supports the Implementation Guidance, but ask the SDT to consider the following suggested changes:
1. Address how an entity might effectively identify Control Centers (as defined by the NERC Glossary) that would be exempted from complying
with CIP-012-1 as a result of the newly developed Exemption 4.2.3 language.
2. There are many different approaches to mitigating the risk of unauthorized disclosure or modification of data in transit. Additional guidance that
explores various approaches and evaluates their effectiveness in mitigating risk may be helpful before entities make implementation
investments for CIP-012-1.
3. EEI suggests the SDT consider removing or modifying the email example (last bullet on page 8) since email and the associated password
exchange recommended (e.g., by phone) i “inconsistent with the requirements of Real-time data exchange” as indicated in the draft
Implementation Guidance.
While EEI recognizes that approval of Implementation Guidance goes beyond the responsibility of the SDT, we suggest the final version of
Implementation Guidance be approved by the ERO and posted with the Standard before any final ballot.
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0

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0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
On pages 5 and 6 of the Implementation Guidance document, BPA believes additional clarity is needed to identify each entity’s responsibility, as
follows: “Where the operational obligations of an entire communication link, including both endpoints, belong to the Control Center of another
Responsible Entity A, the Responsible Entity without operational obligations (B) for the communication link Responsible Entity B may demonstrate
compliance by ensuring the communications link endpoint is within B’s Control Center, which could be limited to including the communication link
endpoint within B’s PSP.”
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0

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0

Response

Chris Wagner - Santee Cooper - 1, Group Name Santee Cooper
Answer
Document Name

No

Comment
The guidance provides encryption as a method. The industry has not been able to test security controls such as encryption, to ensure that reliability is
not impacted. Concerned that encryption of data will create an adverse impact to reliability. It is unclear the amount of latency that may be added or
amount of computing resources required to encrypt and decrypt this data every 6 seconds.
Additionally, the burden should not be placed on a Registered Entity to prove that a neighbor’s control room has the appropriate protections in
place. We should only have the burden for our own control room.
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0

Response

David Greyerbiehl - CMS Energy - Consumers Energy Company - 5
Answer

No

Document Name
Comment
In the Implementation Guidance document, please specify what type of date under TOP-003 and IRO-010 should be excluded from the CIP-012
requirements.
Likes

0

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0

Response

Marty Hostler - Northern California Power Agency - 5
Answer

No

Document Name
Comment
IRO-010-2 R3.3 and TOP-003-3 R5.3 already provide reliability assurance requirements for RCs, BAs, GOs, GOPs, TOPs, TOs, and DPs; and they are
not presriptive. Consequently, CIP-012 is and its' draft implementation quidance are not needed.
Additionally, NERC has a Standards Efficiency Initiative underway to get rid of standards and requirements such as CIP-012-1 and its' Requirement 1.
Likes

0

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0

Dennis Sismaet - Northern California Power Agency - 6
Answer

No

Document Name
Comment
IRO-010-2 R3.3 and TOP-003-3 R5.3 already provide reliability assurance requirements for RCs, BAs, GOs, GOPs, TOPs, TOs, and DPs; and they are
not prescriptive. Consequently, CIP-012 is and its' draft implementation guidance are not needed. Additionally, NERC has a Standards Efficiency
Initiative underway to get rid of standards and requirements such as CIP-012-1 and its' requirement 1.
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0

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0

Response

Tho Tran - Tho Tran On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; - Tho Tran
Answer

No

Document Name
Comment
Oncor supports EEI's comment.
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0

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0

Response

David Francis - Midcontinent ISO, Inc. - 2 - MRO,SERC,RF
Answer

No

Document Name
Comment
For the same reasons stated in response for question 4 with third party personnel entering a PSP
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0

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0

Response

Lynn Goldstein - PNM Resources - Public Service Company of New Mexico - 3

Answer

No

Document Name
Comment
PNM Resources supports EEI’s comments on this question.
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0

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0

Response

Teresa Cantwell - Lower Colorado River Authority - 1,5
Answer

Yes

Document Name
Comment
None
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0

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0

Response

Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6
Answer

Yes

Document Name
Comment
PacifiCorp agrees with modifications made to the implementation guidance, specifically the newly introduced paragraph, “Where the operational
obligations of an entire communication link, including both endpoints, belong to the Control Center of another Responsible Entity, the Responsible Entity
without operational obligations for the communication link may demonstrate compliance by ensuring the communications link endpoint is within its
Control Center, which could be limited to including the communication link endpoint within a PSP.” PacifiCorp would like the following edit added “or
where other physical protections are applied.” PacifiCorp feels that this will allow entities flexibility where the devices that perform this are located within
its location. PacifiCorp also likes the VPN examples provided. If the newly introduced paragraph or the VPN examples are removed or if the
implementation guidance is not ERO-endorsed prior to the final ballot, PacifiCorp may alter its final vote.
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0

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Response

0

Richard Jackson - U.S. Bureau of Reclamation - 1
Answer

Yes

Document Name
Comment
None
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0

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0

Response

Darnez Gresham - Darnez Gresham On Behalf of: Annette Johnston, Berkshire Hathaway Energy - MidAmerican Energy Co., 1, 3; - Darnez
Gresham
Answer

Yes

Document Name
Comment
MEC agrees with modifications made to the Implementation Guidance, specifically the newly introduced sentence, “Where the operational obligations of
an entire communication link, including both endpoints, belong to the Control Center of another Responsible Entity, the Responsible Entity without
operational obligations for the communication link may demonstrate compliance by ensuring the communications link endpoint is within its Control
Center, which could be limited to including the communication link endpoint within a PSP.” MEC would like to see “or where other physical protections
are applied.” This will provide more flexibility for entities. MEC also likes the VPN example provided. Inclusion of the newly introduced sentence, the
VPN example and ERO-endorsement of the implementation guidance are needed in the final version for MEC to vote yes on the final ballot.
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0

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0

Response

Kevin Salsbury - Berkshire Hathaway - NV Energy - 5
Answer

Yes

Document Name
Comment
NV Energy agrees with the requirement based on the newly introduced paragraph in the Implementation Guidance, “Where the operational obligations
of an entire communication link, including both endpoints, belong to the Control Center of another Responsible Entity, the Responsible Entity without
operational obligations for the communication link may demonstrate compliance by ensuring the communications link endpoint is within its Control
Center, which could be limited to including the communication link endpoint within a PSP.”
NV Energy would like the following edit added “or where other physical protections are applied.” NV Energy believes that this will allow entities flexibility
where their devices that perform this function are located within its location. NV Energy believes the VPN examples provided are necessary and should

remain within the Guidance document. If the newly introduced paragraph or the VPN example are removed or if the implementation guidance is not
ERO-endorsed prior to the final ballot, NV Energy may alter its final vote.
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0

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0

Response

Douglas Johnson - American Transmission Company, LLC - 1
Answer

Yes

Document Name
Comment
American Transmission Company LLC (ATC) agrees that the controls prescribed by CIP-006 satisfy CIP-012 Requirement R1 Parts 1.1 and 1.2, and
appreciates being able to leverage Standards that are already implemented and enforceable as opposed to creating a new requirement. ATC cautions
that this approach could re-create ‘spaghetti’ requirements placing Registered Entities in potential double jeopardy if conditions of non-compliance
occur. ATC requests consideration of inclusion of statements in a CIP-012 CMEP Practice Guide to instruct Regional Compliance Enforcement
Agencies to audit in a manner that does not place the Registered Entities at odds with both CIP-006-6 and CIP-012 for individual instances of potential
non-compliance.
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Response

Warren Cross - ACES Power Marketing - 1,3,4,5 - MRO,WECC,Texas RE,SERC
Answer

Yes

Document Name
Comment
No comments.
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0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - MRO, Group Name SPP Standards Review Group
Answer
Document Name

Yes

Comment
The SPP Standards Review Group would ask that the drafting team provide us some feedback on the next steps in their process on how they plan to
get the Implementation Guidance Document formalized and coordinated with the CIP-012-1 Standard. From our prospective, this document was well
put together and we would hate to see this document to be left out of the approval process for the CIP project.
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0

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0

Response

Steve Rose - City Water, Light and Power of Springfield, IL - 1,3,5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

David Maier - Intermountain REA - 3
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Aubrey Short - FirstEnergy - FirstEnergy Corporation - 4
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 3, Group Name FirstEnergy Corporation
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Steven Rueckert - Western Electricity Coordinating Council - 10
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Patricia Lynch - NRG - NRG Energy, Inc. - 5,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Michael Shaw - Lower Colorado River Authority - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Jeff Johnson - Jeff Johnson On Behalf of: Martine Blair, Sempra - San Diego Gas and Electric, 3, 5, 1; - Jeff Johnson
Answer

Yes

Document Name
Comment

Likes
Dislikes

0
0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Martin Sidor - NRG - NRG Energy, Inc. - 5,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Quintin Lee - Eversource Energy - 1
Answer
Document Name

Yes

Comment

Likes

0

Dislikes

0

Response

Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer
Document Name
Comment
No comment at this time.
Likes

0

Dislikes

0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE prefers commenting on Implementation Guidance once the standard language is in its final form.
Likes

0

Dislikes
Response

0

6. The SDT believes proposed CIP-012-1 provides entities with flexibility to meet the reliability objectives in a cost effective manner. Do you
agree? If you do not agree, or if you agree but have suggestions for improvement to enable more cost effective approaches, please provide
your recommendation and, if appropriate, technical justification.
Dennis Sismaet - Northern California Power Agency - 6
Answer

No

Document Name
Comment
IRO-010-2 R3.3 and TOP-003-3 R5.3 already provide reliability assurance requirements for RCs, BAs, GOs, GOPs, TOPs, TOs, and DPs; they provide
flexibility to meet reliability objectives in a cost effective manner. Proposed CIP-012 does not, and is not needed. Additionally, NERC has a Standards
Efficiency Initiative underway to get rid of standards and requirements such as CIP-012-1 and its' Requirement 1.

Likes

0

Dislikes

0

Response

Marty Hostler - Northern California Power Agency - 5
Answer

No

Document Name
Comment
IRO-010-2 R3.3 and TOP-003-3 R5.3 already provide reliability assurance requirements for RCs, BAs, GOs, GOPs, TOPs, TOs, and DPs; they provide
flexibility to meet reliability objectives in a cost effective manner. Proposed CIP-012 does not and is not needed. Additionally, NERC has a Standards
Efficiency Initiative underway to get rid of standards and requirements such as CIP-012-1 and its' Requirement 1.
Likes

0

Dislikes

0

Response

David Greyerbiehl - CMS Energy - Consumers Energy Company - 5
Answer
Document Name
Comment

No

More flexibility and less guidance could lead to inconsistency on requirement implementation among different entities.
Likes

0

Dislikes

0

Response

Chris Wagner - Santee Cooper - 1, Group Name Santee Cooper
Answer

No

Document Name
Comment
Significant capital may need to be budgeted in order to implement architecture improvements to address the required computing resources for
encryption and decryption of data. Encryption adds a burden for on-going maintenance and management. There is concern of the impacts on real-time
operations for encryption and decryption of data.
Likes

0

Dislikes

0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
BPA believes that if the data must be protected throughout the transmission, it would seem that could only be accomplished with encryption. For cases
where the existing equipment is not capable of encryption, replacement will be costly and implementation lengthy. While the proposed standard and
implementation guidance do not require encryption, no other solution seems viable.
Due to BPA’s large amount of applicable data, access to funds and budget cycle, and resources to perform work required, the solution will be costly.
BPA also agrees with SRP’s comments as follows:
“SRP does not agree the current standard and implementation plan can be executed in a cost effective manner. Encryption has been the only presented
solution provided by auditors and SDT guidance to protect both confidentiality and integrity for the data within this scope. If the implementation
timeframe remains at 24 months, more resources and capital will be required versus a phased implementation. A phased implementation provides the
ability to not only ensure the most effective plan, but also provides the ability to plan more accurately within budget cycles. More importantly, if
encryption fails, SRP would lose Real-time Assessment and Real-time monitoring and control data. SRP is concerned a 24 month implementation
timeline would impact reliability as there are many opportunities for encryption to fail that must be addressed. This has a direct correlation on cost when
addressing those opportunities during this timeframe.

Additionally, SRP would like to see reference models of methods that do not require encryption as a method to protect communications between Control
Centers.”
Likes

0

Dislikes

0

Response

James Anderson - CMS Energy - Consumers Energy Company - 1
Answer

No

Document Name
Comment
More flexibility and less guidance could lead to inconsistency on requirement implementation among different entities.
Likes

0

Dislikes

0

Response

Stephanie Burns - Stephanie Burns On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; - Stephanie
Burns
Answer

No

Document Name
Comment
ITC does not agree with this approach being cost effective. This is especially true for larger balancing authorities that own and pay for many routers
and circuits to receive ICCP data they require for real time operation. Many routers deployed today may not have encryption capabilities and many
circuits may not have adequate bandwidth to support additional encryption overhead. In addition the methods to connect to the control center such as
the lease lines, or communication circuits, may need to change to accommodate the new protection requirements.
Likes

0

Dislikes

0

Response

Chris Gowder - Florida Municipal Power Agency - 3,4,5,6
Answer
Document Name
Comment

No

Undetermined
Likes

0

Dislikes

0

Response

Joe McKinney - Florida Municipal Power Agency - 3,4,5,6
Answer

No

Document Name
Comment
Undetermined
Likes

0

Dislikes

0

Response

Carol Chinn - Florida Municipal Power Agency - 3,4,5,6
Answer

No

Document Name
Comment
Undetermined
Likes

0

Dislikes

0

Response

Richard Montgomery - Florida Municipal Power Agency - 3,4,5,6
Answer
Document Name
Comment
Undetermined

No

Likes

0

Dislikes

0

Response

Brandon McCormick - Brandon McCormick On Behalf of: Ginny Beigel, City of Vero Beach, 3; Lynne Mila, City of Clewiston, 4; Mike Blough,
Kissimmee Utility Authority, 5, 3; Tom Reedy, Florida Municipal Power Pool, 6; - Brandon McCormick, Group Name FMPA
Answer

No

Document Name
Comment
Undetermined
Likes

0

Dislikes

0

Response

Jeanne Kurzynowski - CMS Energy - Consumers Energy Company - 1,3,4,5 - RF
Answer

No

Document Name
Comment
More flexibility and less guidance could lead to inconsistency on requirement implementation among different entities.
Likes

0

Dislikes

0

Response

Richard Jackson - U.S. Bureau of Reclamation - 1
Answer

No

Document Name
Comment
Reclamation recommends the term “plan” be replaced with the term “process” throughout the CIP-012-1 standard, Technical Rationale, Implementation
Guidance, and associated documents. A plan is an unwarranted layer of compliance that does not improve the reliability of the BES. The processes an
entity implements have defined controls that reduce the entity’s risks to the BES and thereby improve BES reliability.

Likes

0

Dislikes

0

Response

David Jendras - Ameren - Ameren Services - 1,3,6
Answer

No

Document Name
Comment
As currently worded in draft 4 we believe that there is too much potential risk to support a "yes" response to this question.
Likes

0

Dislikes

0

Response

Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

No

Document Name
Comment
The options for flexibility aren’t clearly presented in the draft standard and the language provided.
Likes

0

Dislikes

0

Response

Russell Martin II - Salt River Project - 1,3,5,6 - WECC
Answer

No

Document Name
Comment
SRP does not agree the current standard and implementation plan can be executed in a cost effective manner. Encryption has been the only presented
solution provided by auditors and SDT guidance to protect both confidentiality and integrity for the data within this scope. If the implementation
timeframe remains at 24 months, more resources and capital will be required versus a phased implementation. A phased implementation provides the
ability to not only ensure the most effective plan, but also provides the ability to plan more accurately within budget cycles. More importantly, if
encryption fails, SRP would lose Real-time Assessment and Real-time monitoring and control data. SRP is concerned a 24 month implementation

timeline would impact reliability as there are many opportunities for encryption to fail that must be addressed. This has a direct correlation on cost when
addressing those opportunities during this timeframe.
Additionally, SRP would like to see reference models of methods that do not require encryption as a method to protect communications between Control
Centers.
Likes

0

Dislikes

0

Response

Warren Cross - ACES Power Marketing - 1,3,4,5 - MRO,WECC,Texas RE,SERC
Answer

Yes

Document Name
Comment
ACES does agree with the cost effective approach, if the wording is revised from Control Center to Facility. A Control Center has much more
compliance obligations than a Facility.
Likes

0

Dislikes

0

Response

Teresa Cantwell - Lower Colorado River Authority - 1,5
Answer

Yes

Document Name
Comment
None
Likes

0

Dislikes

0

Response

David Francis - Midcontinent ISO, Inc. - 2 - MRO,SERC,RF
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

Quintin Lee - Eversource Energy - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Martin Sidor - NRG - NRG Energy, Inc. - 5,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Douglas Johnson - American Transmission Company, LLC - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Chris Scanlon - Exelon - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Kevin Salsbury - Berkshire Hathaway - NV Energy - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Jeff Johnson - Jeff Johnson On Behalf of: Martine Blair, Sempra - San Diego Gas and Electric, 3, 5, 1; - Jeff Johnson
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

Darnez Gresham - Darnez Gresham On Behalf of: Annette Johnston, Berkshire Hathaway Energy - MidAmerican Energy Co., 1, 3; - Darnez
Gresham
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Douglas Webb - Douglas Webb On Behalf of: Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; James McBee,
Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; Jessica Tucker, Great Plains Energy - Kansas City Power and Light Co., 5,
1, 3, 6; Jim Flucke, Great Plains Energy - Kansas City Power and Light Co., 5, 1, 3, 6; Megan Wagner, Westar Energy, 6, 3, 1, 5; - Douglas
Webb
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Michael Shaw - Lower Colorado River Authority - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Patricia Lynch - NRG - NRG Energy, Inc. - 5,6
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

Steven Rueckert - Western Electricity Coordinating Council - 10
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Aaron Ghodooshim - FirstEnergy - FirstEnergy Corporation - 3, Group Name FirstEnergy Corporation
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Aubrey Short - FirstEnergy - FirstEnergy Corporation - 4
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

David Maier - Intermountain REA - 3
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Thomas Foltz - AEP - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Steve Rose - City Water, Light and Power of Springfield, IL - 1,3,5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - MRO, Group Name SPP Standards Review Group
Answer
Document Name
Comment

N/A
Likes

0

Dislikes

0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE does not have comments on this question.
Likes

0

Dislikes

0

Response

Andrea Koch - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
No comment
Likes

0

Dislikes

0

Response

Andy Fuhrman - Andy Fuhrman On Behalf of: Theresa Allard, Minnkota Power Cooperative Inc., 1; - Andy Fuhrman
Answer
Document Name
Comment
This has not been determined due to the need for revisions to the proposed standard.

Likes

0

Dislikes

0

Response

Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer
Document Name
Comment
No comment at this time.
Likes

0

Dislikes

0

Response

Dana Klem - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO NSRF
Answer
Document Name
Comment
Undetermined at this time.
Likes

0

Dislikes
Response

0

Standards Announcement
Reminder

Project 2016-02 Modifications to CIP Standards
Additional Ballot and Non-binding Polls Open through July 2, 2018
Now Available

The additional ballot and non-binding Poll for CIP-012-1 – Cyber Security - Communications between
Control Centers is open through 8 p.m. Eastern, Monday, July 2, 2018.
The standard drafting team’s considerations of the responses received from the last comment period
reflected in this draft of the standard.
Balloting

Members of the ballot pools associated with this project can log in to the Standards Balloting and
Commenting System (SBS) and submit their votes. If you experience difficulty navigating the SBS,
contact Wendy Muller.
•

If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential
error messages, or system lock-out, contact NERC IT support directly at https://support.nerc.net/
(Monday – Friday, 8 a.m. - 5 p.m. Eastern).

•

Passwords expire every 6 months and must be reset.

•

The SBS is not supported for use on mobile devices.

•

Please be mindful of ballot and comment period closing dates. We ask to allow at least 48 hours
for NERC support staff to assist with inquiries. Therefore, it is recommended that users try logging
into their SBS accounts prior to the last day of a comment/ballot period.

Note: If a member cast a vote in the previous ballot, that vote will not carry over to the additional
ballot. It is the responsibility of the registered voter in the ballot pool to cast a vote again in the
additional ballot. To ensure a quorum is reached, if you do not want to vote affirmative or negative,
cast an abstention.
Next Steps

The ballot results will be announced and posted on the project page. The drafting team will review all
responses received during the comment period and determine the next steps of the project.

For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Standards Developer, Jordan Mallory (via email) or at (404)
446-2589.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement | CIP-012-1 Ballot Open Reminder
Project 2016-02 Modifications to CIP Standards | December 1, 2017

2

Standards Announcement

Project 2016-02 Modifications to CIP Standards
Formal Comment Period Open through July 2, 2018
Now Available

A 45-day formal comment period for CIP-012-1 – Cyber Security - Communications between Control
Centers is open through 8 p.m. Eastern, Monday, July 2, 2018.
The Technical Rationale and Implementation Guidance Documents for CIP-012-1 will be posted within 15
days of the comment period opening.
Additionally, the CIP standard drafting team (SDT) proposed a revised Control Center definition during
the March 16 – April 30, 2018 comment and ballot period. Based on feedback received from industry,
the SDT decided to draft exemption language within the applicability section of CIP-012 instead of
revising the Control Center definition. Please see the Control Center definition consideration of
comments report for additional SDT responses on the new path taken by the SDT.
Commenting

Use the Standards Balloting and Commenting System (SBS) to submit comments. If you experience
difficulties navigating the SBS, contact Wendy Muller. An unofficial Word version of the comment form is
posted on the project page.
•

If you are having difficulty accessing the SBS due to a forgotten password, incorrect
credential error messages, or system lock-out, contact NERC IT support directly at
https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5 p.m. Eastern).

•

Passwords expire every 6 months and must be reset.

•

The SBS is not supported for use on mobile devices.

•

Please be mindful of ballot and comment period closing dates. We ask to allow at least 48
hours for NERC support staff to assist with inquiries. Therefore, it is recommended that users try
logging into their SBS accounts prior to the last day of a comment/ballot period.

Next Steps

An additional ballot for the Standard and a non-binding poll of the associated Violation Risk Factors and
Violation Severity Levels will be conducted June 22 – July 2, 2018.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Standards Developer, Jordan Mallory at (404) 446-2589.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement | Project 2016-02 Modifications to CIP Standards
CIP-012-1 | May-July, 2018

2

Index - NERC Balloting Tool

NERC Balloting Tool (/)

Page 1 of 18

Dashboard (/)

Users

Ballots

Comment Forms

Login (/Users/Login) / Register (/Users/Register)

BALLOT RESULTS
Comment: View Comment Results (/CommentResults/Index/136)
Ballot Name: 2016-02 Modifications to CIP Standards CIP-012-1 AB 4 ST
Voting Start Date: 6/22/2018 12:01:00 AM
Voting End Date: 7/3/2018 8:00:00 PM
Ballot Type: ST
Ballot Activity: AB
Ballot Series: 4
Total # Votes: 233
Total Ballot Pool: 309
Quorum: 75.4
Weighted Segment Value: 68.45

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Negative
Fraction
w/
Comment

Segment:
1

80

1

41

0.661

21

0.339

0

3

15

Segment:
2

7

0.5

4

0.4

1

0.1

0

1

1

Segment:
3

73

1

36

0.692

16

0.308

0

4

17

Segment:
4

17

1

8

0.8

2

0.2

0

1

6

Segment:
5

73

1

24

0.533

21

0.467

0

2

26

Segment:
6

46

1

18

0.563

14

0.438

0

5

9

Segment:
7

2

0

0

0

0

0

0

1

1

Segment:
8

3

0.2

2

0.2

0

0

0

0

1

Segment:
9

1

0.1

1

0.1

0

0

0

0

0

2

0.2

0

0

0

Segment

Segment: 7
0.7
5
0.5
© 2018
NERC
Ver
4.2.1.0
Machine
Name:
ERODVSBSWB02
10

https://sbs.nerc.net/BallotResults/Index/247

Negative
Votes
w/o
Comment

Abstain

No
Vote

9/10/2018

Index - NERC Balloting Tool

Page 2 of 18

Segment

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Totals:

309

6.5

139

4.449

77

Negative
Fraction
w/
Comment

Negative
Votes
w/o
Comment

Abstain

No
Vote

2.051

0

17

76

BALLOT POOL MEMBERS
Show All

Segment

 entries

Organization

Search: Search

Voter

Designated
Proxy

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Allete - Minnesota Power,
Inc.

Jamie Monette

Abstain

N/A

1

American Transmission
Company, LLC

Douglas Johnson

Affirmative

N/A

1

APS - Arizona Public Service
Co.

Michelle
Amarantos

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

John Shaver

None

N/A

1

Associated Electric
Cooperative, Inc.

Ryan Ziegler

Affirmative

N/A

1

Austin Energy

Thomas
Standifur

None

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Affirmative

N/A

1

Basin Electric Power
Cooperative

David Rudolph

None

N/A

1

BC Hydro and Power
Authority

Patricia
Robertson

Affirmative

N/A

Affirmative

N/A

1
Berkshire Hathaway Energy Terry Harbour
© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB02
MidAmerican Energy Co.

https://sbs.nerc.net/BallotResults/Index/247

Joe Tarantino

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 3 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Bonneville Power
Administration

Kammy RogersHolliday

Negative

Comments
Submitted

1

Brazos Electric Power
Cooperative, Inc.

Tony Kroskey

Negative

Third-Party
Comments

1

Cedar Falls Utilities

Adam Peterson

None

N/A

1

CenterPoint Energy Houston
Electric, LLC

Daniela
Hammons

Affirmative

N/A

1

Central Electric Power
Cooperative (Missouri)

Michael Bax

Affirmative

N/A

1

Central Hudson Gas &
Electric Corp.

Frank Pace

Affirmative

N/A

1

City Utilities of Springfield,
Missouri

Michael Buyce

None

N/A

1

CMS Energy - Consumers
Energy Company

James Anderson

Negative

Comments
Submitted

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Dominion - Dominion Virginia
Power

Larry Nash

Affirmative

N/A

1

Duke Energy

Laura Lee

Negative

Comments
Submitted

1

Edison International Southern California Edison
Company

Steven Mavis

Affirmative

N/A

1

Entergy - Entergy Services,
Inc.

Oliver Burke

Affirmative

N/A

1

Eversource Energy

Quintin Lee

Affirmative

N/A

1

Exelon

Chris Scanlon

Negative

Comments
Submitted

1

FirstEnergy - FirstEnergy
Corporation

Julie Severino

Affirmative

N/A

1

Great Plains Energy - Kansas
City Power and Light Co.

James McBee

Negative

Third-Party
Comments

1

Great River Energy

Gordon Pietsch

None

N/A

Douglas Webb

© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB02

https://sbs.nerc.net/BallotResults/Index/247

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 4 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Hydro One Networks, Inc.

Payam
Farahbakhsh

Affirmative

N/A

1

Hydro-Qu?bec TransEnergie

Nicolas Turcotte

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Laura Nelson

Negative

Comments
Submitted

1

Imperial Irrigation District

Jesus Sammy
Alcaraz

None

N/A

1

International Transmission
Company Holdings
Corporation

Michael Moltane

Negative

Comments
Submitted

1

Lincoln Electric System

Danny Pudenz

Negative

Third-Party
Comments

1

Long Island Power Authority

Robert Ganley

Affirmative

N/A

1

Los Angeles Department of
Water and Power

faranak sarbaz

None

N/A

1

Lower Colorado River
Authority

Michael Shaw

Affirmative

N/A

1

M and A Electric Power
Cooperative

William Price

Affirmative

N/A

1

Manitoba Hydro

Mike Smith

None

N/A

1

MEAG Power

David Weekley

Affirmative

N/A

1

Memphis Light, Gas and
Water Division

Allan Long

None

N/A

1

Minnkota Power Cooperative
Inc.

Theresa Allard

Negative

Comments
Submitted

1

Muscatine Power and Water

Andy Kurriger

Negative

Third-Party
Comments

1

N.W. Electric Power
Cooperative, Inc.

Mark Ramsey

Affirmative

N/A

1

National Grid USA

Michael Jones

Affirmative

N/A

1

Nebraska Public Power
District

Jamison Cawley

Negative

Third-Party
Comments

1

New York Power Authority

Salvatore
Spagnolo

None

N/A

Stephanie
Burns

Scott Miller

Andy Fuhrman

© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB02

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 5 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

1

NextEra Energy - Florida
Power and Light Co.

Mike ONeil

Affirmative

N/A

1

NiSource - Northern Indiana
Public Service Co.

Steve Toosevich

Affirmative

N/A

1

Northeast Missouri Electric
Power Cooperative

Kevin White

Affirmative

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Negative

Third-Party
Comments

1

Ohio Valley Electric
Corporation

Scott
Cunningham

Affirmative

N/A

1

Omaha Public Power District

Doug Peterchuck

Negative

Comments
Submitted

1

Oncor Electric Delivery

Lee Maurer

Negative

Comments
Submitted

1

OTP - Otter Tail Power
Company

Charles Wicklund

Negative

Third-Party
Comments

1

Peak Reliability

Scott Downey

Affirmative

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Laurie Williams

Affirmative

N/A

1

PPL Electric Utilities
Corporation

Brenda Truhe

Affirmative

N/A

1

PSEG - Public Service
Electric and Gas Co.

Joseph Smith

Affirmative

N/A

1

Public Utility District No. 1 of
Chelan County

Jeff Kimbell

None

N/A

1

Public Utility District No. 1 of
Snohomish County

Long Duong

Abstain

N/A

1

Puget Sound Energy, Inc.

Theresa
Rakowsky

Affirmative

N/A

1

Sacramento Municipal Utility
District

Arthur Starkovich

Affirmative

N/A

1

Salt River Project

Steven Cobb

Negative

Comments
Submitted

Negative

Comments
Submitted

1
Santee Cooper
Chris Wagner
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Tho Tran

Joe Tarantino

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 6 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

1

SCANA - South Carolina
Electric and Gas Co.

Tom Hanzlik

Abstain

N/A

1

Seattle City Light

Pawel Krupa

None

N/A

1

Seminole Electric
Cooperative, Inc.

Mark Churilla

None

N/A

1

Sempra - San Diego Gas and
Electric

Martine Blair

Affirmative

N/A

1

Sho-Me Power Electric
Cooperative

Peter Dawson

Affirmative

N/A

1

Southern Company Southern Company Services,
Inc.

Katherine Prewitt

Affirmative

N/A

1

Southern Indiana Gas and
Electric Co.

Steve Rawlinson

Affirmative

N/A

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

None

N/A

1

Tennessee Valley Authority

Howell Scott

Affirmative

N/A

1

Tri-State G and T
Association, Inc.

Tracy Sliman

Affirmative

N/A

1

U.S. Bureau of Reclamation

Richard Jackson

Negative

Comments
Submitted

1

Westar Energy

Allen Klassen

Negative

Third-Party
Comments

1

Western Area Power
Administration

sean erickson

Negative

Third-Party
Comments

1

Xcel Energy, Inc.

Dean Schiro

Affirmative

N/A

2

California ISO

Richard Vine

Abstain

N/A

2

Electric Reliability Council of
Texas, Inc.

Brandon Gleason

Affirmative

N/A

2

Independent Electricity
System Operator

Leonard Kula

Affirmative

N/A

2

ISO New England, Inc.

Michael Puscas

None

N/A

2

Midcontinent ISO, Inc.

Terry BIlke

Negative

Third-Party
Comments

Jeff Johnson

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 7 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

2

New York Independent
System Operator

Gregory Campoli

Affirmative

N/A

2

PJM Interconnection, L.L.C.

Mark Holman

Affirmative

N/A

3

AEP

Aaron Austin

Affirmative

N/A

3

AES - Indianapolis Power
and Light Co.

Bette White

None

N/A

3

APS - Arizona Public Service
Co.

Vivian Vo

Affirmative

N/A

3

Arkansas Electric
Cooperative Corporation

Philip Huff

Affirmative

N/A

3

Associated Electric
Cooperative, Inc.

Todd Bennett

Affirmative

N/A

3

Austin Energy

W. Dwayne
Preston

Affirmative

N/A

3

Basin Electric Power
Cooperative

Jeremy Voll

None

N/A

3

BC Hydro and Power
Authority

Hootan Jarollahi

Affirmative

N/A

3

Berkshire Hathaway Energy MidAmerican Energy Co.

Annette Johnston

Affirmative

N/A

3

Bonneville Power
Administration

Rebecca Berdahl

Negative

Comments
Submitted

3

Central Electric Power
Cooperative (Missouri)

Adam Weber

Affirmative

N/A

3

City of Farmington

Linda JacobsonQuinn

Abstain

N/A

3

City of Leesburg

Chris Adkins

None

N/A

3

City of Vero Beach

Ginny Beigel

Negative

Comments
Submitted

3

City Utilities of Springfield,
Missouri

Scott Williams

None

N/A

3

Cleco Corporation

Michelle Corley

Negative

Third-Party
Comments

3

Con Ed - Consolidated

Peter Yost

Affirmative

N/A

Darnez
Gresham

Brandon
McCormick

Louis Guidry

Edison Machine
Co. of New
YorkERODVSBSWB02
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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 8 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Cowlitz County PUD

Russell Noble

None

N/A

3

Duke Energy

Lee Schuster

Negative

Comments
Submitted

3

Edison International Southern California Edison
Company

Romel Aquino

None

N/A

3

Empire District Electric Co.

Kalem Long

None

N/A

3

Eversource Energy

Sharon Flannery

Affirmative

N/A

3

Exelon

John Bee

Negative

Comments
Submitted

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

Affirmative

N/A

3

Georgia System Operations
Corporation

Scott McGough

Affirmative

N/A

3

Great Plains Energy - Kansas
City Power and Light Co.

Jessica Tucker

Negative

Third-Party
Comments

3

Great River Energy

Brian Glover

Negative

Third-Party
Comments

3

Hydro One Networks, Inc.

Paul Malozewski

None

N/A

3

KAMO Electric Cooperative

Ted Hilmes

Affirmative

N/A

3

Lincoln Electric System

Jason Fortik

Negative

Third-Party
Comments

3

M and A Electric Power
Cooperative

Stephen Pogue

Affirmative

N/A

3

Manitoba Hydro

Karim Abdel-Hadi

None

N/A

3

MEAG Power

Roger Brand

Scott Miller

Affirmative

N/A

3

Modesto Irrigation District

Jack Savage

Nick Braden

Affirmative

N/A

3

Muscatine Power and Water

Seth Shoemaker

Negative

Third-Party
Comments

3

National Grid USA

Brian Shanahan

Affirmative

N/A

3

Nebraska Public Power
District

Tony Eddleman

Negative

Third-Party
Comments

None

N/A

3
New York Power Authority
David Rivera
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Douglas Webb

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 9 of 18

Voter

3

NiSource - Northern Indiana
Public Service Co.

Aimee Harris

3

North Carolina Electric
Membership Corporation

doug white

3

Northeast Missouri Electric
Power Cooperative

3

Designated
Proxy

Ballot

NERC
Memo

Affirmative

N/A

Affirmative

N/A

Skyler Wiegmann

Affirmative

N/A

NW Electric Power
Cooperative, Inc.

John Stickley

Affirmative

N/A

3

Ocala Utility Services

Neville Bowen

None

N/A

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Negative

Third-Party
Comments

3

OTP - Otter Tail Power
Company

Wendi Olson

Negative

Third-Party
Comments

3

Owensboro Municipal Utilities

Thomas Lyons

Affirmative

N/A

3

Platte River Power Authority

Jeff Landis

Affirmative

N/A

3

PNM Resources - Public
Service Company of New
Mexico

Lynn Goldstein

Affirmative

N/A

3

Portland General Electric Co.

Angela Gaines

Affirmative

N/A

3

PPL - Louisville Gas and
Electric Co.

Charles Freibert

Affirmative

N/A

3

PSEG - Public Service
Electric and Gas Co.

Jeffrey Mueller

Affirmative

N/A

3

Public Utility District No. 1 of
Chelan County

Joyce Gundry

Abstain

N/A

3

Puget Sound Energy, Inc.

Lynda Kupfer

Affirmative

N/A

3

Rutherford EMC

Tom Haire

None

N/A

3

Sacramento Municipal Utility
District

Nicole Looney

Affirmative

N/A

3

Salt River Project

Robert
Kondziolka

Negative

Comments
Submitted

3

Santee Cooper

James Poston

Negative

Comments
Submitted

Scott Brame

Joe Tarantino

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 10 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

3

SCANA - South Carolina
Electric and Gas Co.

Scott Parker

None

N/A

3

Seattle City Light

Tuan Tran

Affirmative

N/A

3

Seminole Electric
Cooperative, Inc.

James Frauen

Abstain

N/A

3

Sempra - San Diego Gas and
Electric

Bridget Silvia

Affirmative

N/A

3

Sho-Me Power Electric
Cooperative

Jeff Neas

Affirmative

N/A

3

Silicon Valley Power - City of
Santa Clara

Val Ridad

None

N/A

3

Snohomish County PUD No.
1

Holly Chaney

Abstain

N/A

3

Southern Company Alabama Power Company

Joel Dembowski

Affirmative

N/A

3

Southern Indiana Gas and
Electric Co.

Fred Frederick

Affirmative

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

Marc Donaldson

None

N/A

3

TECO - Tampa Electric Co.

Ronald Donahey

None

N/A

3

Tennessee Valley Authority

Ian Grant

Affirmative

N/A

3

Tri-State G and T
Association, Inc.

Janelle Marriott
Gill

None

N/A

3

WEC Energy Group, Inc.

Thomas Breene

Negative

Third-Party
Comments

3

Westar Energy

Bryan Taggart

Negative

Third-Party
Comments

3

Xcel Energy, Inc.

Michael Ibold

Affirmative

N/A

4

American Public Power
Association

Jack Cashin

None

N/A

4

Arkansas Electric
Cooperative Corporation

Alice Wright

Affirmative

N/A

4

Austin Energy

Esther Weekes

Affirmative

N/A

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 11 of 18

Voter

4

City of Clewiston

Lynne Mila

4

City Utilities of Springfield,
Missouri

4

Designated
Proxy
Brandon
McCormick

Ballot

NERC
Memo

Negative

Comments
Submitted

John Allen

None

N/A

FirstEnergy - FirstEnergy
Corporation

Aubrey Short

Affirmative

N/A

4

Georgia System Operations
Corporation

Andrea Barclay

Affirmative

N/A

4

Indiana Municipal Power
Agency

Jack Alvey

None

N/A

4

National Rural Electric
Cooperative Association

Barry Lawson

Affirmative

N/A

4

North Carolina Electric
Membership Corporation

John Lemire

Affirmative

N/A

4

Public Utility District No. 1 of
Snohomish County

John Martinsen

Abstain

N/A

4

Sacramento Municipal Utility
District

Beth Tincher

Affirmative

N/A

4

Seattle City Light

Hao Li

Affirmative

N/A

4

Seminole Electric
Cooperative, Inc.

Charles
Wubbena

None

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

None

N/A

4

Utility Services, Inc.

Brian EvansMongeon

None

N/A

4

WEC Energy Group, Inc.

Anthony
Jankowski

Negative

Third-Party
Comments

5

Acciona Energy North
America

George Brown

None

N/A

5

AEP

Thomas Foltz

Affirmative

N/A

5

Ameren - Ameren Missouri

Sam Dwyer

Negative

Comments
Submitted

5

APS - Arizona Public Service
Co.

Kelsi Rigby

Affirmative

N/A

Scott Berry

Scott Brame

Joe Tarantino

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 12 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Arkansas Electric
Cooperative Corporation

Moses Harris

Affirmative

N/A

5

Associated Electric
Cooperative, Inc.

Brad Haralson

Affirmative

N/A

5

Austin Energy

Shirley Mathew

Affirmative

N/A

5

Avista - Avista Corporation

Glen Farmer

None

N/A

5

Basin Electric Power
Cooperative

Mike Kraft

None

N/A

5

BC Hydro and Power
Authority

Helen Hamilton
Harding

Affirmative

N/A

5

Boise-Kuna Irrigation District
- Lucky Peak Power Plant
Project

Mike Kukla

Affirmative

N/A

5

Bonneville Power
Administration

Scott Winner

Negative

Comments
Submitted

5

BP Wind Energy North
America Inc.

Carla Holly

None

N/A

5

Choctaw Generation Limited
Partnership, LLLP

Rob Watson

Affirmative

N/A

5

Cleco Corporation

Stephanie
Huffman

Negative

Third-Party
Comments

5

CMS Energy - Consumers
Energy Company

David
Greyerbiehl

Negative

Comments
Submitted

5

Colorado Springs Utilities

Jeff Icke

None

N/A

5

Con Ed - Consolidated
Edison Co. of New York

William Winters

Affirmative

N/A

5

Dairyland Power Cooperative

Tommy Drea

None

N/A

5

Dominion - Dominion
Resources, Inc.

Lou Oberski

None

N/A

5

Duke Energy

Dale Goodwine

Negative

Comments
Submitted

5

Edison International Southern California Edison
Company

Selene Willis

Affirmative

N/A

Louis Guidry

Alyson Slanover

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 13 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

5

EDP Renewables North
America LLC

Heather Morgan

None

N/A

5

Entergy

Jamie Prater

Affirmative

N/A

5

Exelon

Ruth Miller

Negative

Comments
Submitted

5

FirstEnergy - FirstEnergy
Solutions

Robert Loy

Affirmative

N/A

5

Great Plains Energy - Kansas
City Power and Light Co.

Harold Wyble

Negative

Third-Party
Comments

5

Great River Energy

Preston Walsh

Negative

Third-Party
Comments

5

Gridforce Energy
Management, LLC

David Blackshear

None

N/A

5

Hydro-Qu?bec Production

Junji Yamaguchi

None

N/A

5

JEA

John Babik

None

N/A

5

Kissimmee Utility Authority

Mike Blough

Negative

Comments
Submitted

5

Lakeland Electric

Jim Howard

Negative

Third-Party
Comments

5

Lincoln Electric System

Kayleigh
Wilkerson

Negative

Third-Party
Comments

5

Los Angeles Department of
Water and Power

Glenn Barry

None

N/A

5

Manitoba Hydro

Yuguang Xiao

None

N/A

5

Massachusetts Municipal
Wholesale Electric Company

David Gordon

Affirmative

N/A

5

MEAG Power

Steven Grego

Affirmative

N/A

5

Muscatine Power and Water

Neal Nelson

Negative

Third-Party
Comments

5

NB Power Corporation

Laura McLeod

None

N/A

5

Nebraska Public Power
District

Don Schmit

Negative

Third-Party
Comments

5

New York Power Authority

Erick Barrios

None

N/A

Douglas Webb

Brandon
McCormick

Scott Miller

© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB02

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 14 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

5

NextEra Energy

Allen Schriver

Affirmative

N/A

5

NiSource - Northern Indiana
Public Service Co.

Kathryn Tackett

Affirmative

N/A

5

North Carolina Electric
Membership Corporation

Robert Beadle

Affirmative

N/A

5

Northern California Power
Agency

Marty Hostler

Negative

Comments
Submitted

5

OGE Energy - Oklahoma
Gas and Electric Co.

John Rhea

Negative

Third-Party
Comments

5

Omaha Public Power District

Mahmood Safi

Negative

Comments
Submitted

5

Ontario Power Generation
Inc.

David
Ramkalawan

Affirmative

N/A

5

OTP - Otter Tail Power
Company

Cathy Fogale

Negative

Third-Party
Comments

5

Portland General Electric Co.

Ryan Olson

None

N/A

5

PPL - Louisville Gas and
Electric Co.

JULIE
HOSTRANDER

None

N/A

5

PSEG - PSEG Fossil LLC

Tim Kucey

Affirmative

N/A

5

Public Utility District No. 1 of
Chelan County

Haley Sousa

Abstain

N/A

5

Public Utility District No. 1 of
Snohomish County

Sam Nietfeld

Abstain

N/A

5

Puget Sound Energy, Inc.

Eleanor Ewry

Affirmative

N/A

5

Sacramento Municipal Utility
District

Susan Oto

Affirmative

N/A

5

Salt River Project

Kevin Nielsen

Negative

Comments
Submitted

5

Santee Cooper

Tommy Curtis

Negative

Comments
Submitted

5

SCANA - South Carolina
Electric and Gas Co.

Alyssa Hubbard

None

N/A

5

Seattle City Light

Faz Kasraie

None

N/A

Scott Brame

Joe Tarantino

© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB02

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 15 of 18

Voter

5

Seminole Electric
Cooperative, Inc.

Brenda Atkins

5

Sempra - San Diego Gas and
Electric

Daniel Frank

5

Silicon Valley Power - City of
Santa Clara

5

Designated
Proxy

Ballot

NERC
Memo

None

N/A

None

N/A

Sandra Pacheco

None

N/A

Southern Company Southern Company
Generation

William D. Shultz

Affirmative

N/A

5

SunPower

Bradley Collard

None

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

None

N/A

5

Talen Generation, LLC

Matthew
McMillan

None

N/A

5

TECO - Tampa Electric Co.

Frank L Busot

None

N/A

5

Tennessee Valley Authority

M Lee Thomas

Affirmative

N/A

5

U.S. Bureau of Reclamation

Wendy Center

Negative

Comments
Submitted

5

WEC Energy Group, Inc.

Linda Horn

Negative

Third-Party
Comments

5

Xcel Energy, Inc.

Gerry Huitt

Affirmative

N/A

6

APS - Arizona Public Service
Co.

Jonathan Aragon

Affirmative

N/A

6

Arkansas Electric
Cooperative Corporation

Bruce Walkup

Affirmative

N/A

6

Austin Energy

Andrew Gallo

Affirmative

N/A

6

Basin Electric Power
Cooperative

Paul Huettl

None

N/A

6

Berkshire Hathaway PacifiCorp

Sandra Shaffer

Affirmative

N/A

6

Bonneville Power
Administration

Andrew Meyers

Negative

Comments
Submitted

6

Cleco Corporation

Robert Hirchak

Negative

Third-Party
Comments

Andrey
Komissarov

Louis Guidry

© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB02

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 16 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Con Ed - Consolidated
Edison Co. of New York

Christopher
Overberg

Affirmative

N/A

6

Dominion - Dominion
Resources, Inc.

Sean Bodkin

Affirmative

N/A

6

Duke Energy

Greg Cecil

Negative

Comments
Submitted

6

Edison International Southern California Edison
Company

Kenya Streeter

None

N/A

6

Entergy

Julie Hall

Affirmative

N/A

6

Exelon

Becky Webb

Negative

Comments
Submitted

6

FirstEnergy - FirstEnergy
Solutions

Ann Ivanc

Affirmative

N/A

6

Florida Municipal Power Pool

Tom Reedy

Brandon
McCormick

Negative

Comments
Submitted

6

Great Plains Energy - Kansas
City Power and Light Co.

Jim Flucke

Douglas Webb

Negative

Third-Party
Comments

6

Lincoln Electric System

Eric Ruskamp

Negative

Third-Party
Comments

6

Los Angeles Department of
Water and Power

Anton Vu

Affirmative

N/A

6

Luminant - Luminant Energy

Brenda Hampton

Abstain

N/A

6

Manitoba Hydro

Blair Mukanik

None

N/A

6

Modesto Irrigation District

James McFall

Affirmative

N/A

6

Muscatine Power and Water

Ryan Streck

Negative

Third-Party
Comments

6

NextEra Energy - Florida
Power and Light Co.

Silvia Mitchell

None

N/A

6

NiSource - Northern Indiana
Public Service Co.

Joe O'Brien

Affirmative

N/A

6

Northern California Power
Agency

Dennis Sismaet

Negative

Comments
Submitted

6

OGE Energy - Oklahoma

Sing Tay

Negative

Third-Party
Comments

Gas and
ElectricName:
Co. ERODVSBSWB02
© 2018 - NERC Ver 4.2.1.0
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Nick Braden

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 17 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Omaha Public Power District

Joel Robles

None

N/A

6

Portland General Electric Co.

Daniel Mason

Affirmative

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

Affirmative

N/A

6

Public Utility District No. 1 of
Chelan County

Davis Jelusich

Abstain

N/A

6

Public Utility District No. 2 of
Grant County, Washington

LeRoy Patterson

None

N/A

6

Sacramento Municipal Utility
District

Jamie Cutlip

Affirmative

N/A

6

Salt River Project

Bobby Olsen

Negative

Comments
Submitted

6

Santee Cooper

Michael Brown

Negative

Comments
Submitted

6

Seattle City Light

Charles Freeman

Affirmative

N/A

6

Seminole Electric
Cooperative, Inc.

Trudy Novak

Abstain

N/A

6

Snohomish County PUD No.
1

Franklin Lu

Abstain

N/A

6

Southern Company Southern Company
Generation and Energy
Marketing

Jennifer Sykes

Affirmative

N/A

6

Southern Indiana Gas and
Electric Co.

Brad Lisembee

None

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Rick Applegate

Abstain

N/A

6

Talen Energy Marketing, LLC

Jennifer
Hohenshilt

None

N/A

6

TECO - Tampa Electric Co.

Benjamin Smith

None

N/A

6

Tennessee Valley Authority

Marjorie Parsons

Affirmative

N/A

6

WEC Energy Group, Inc.

David Hathaway

Negative

Third-Party
Comments

6

Westar Energy

Megan Wagner

Negative

Third-Party
Comments

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Douglas Webb

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 18 of 18

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Xcel Energy, Inc.

Carrie Dixon

Affirmative

N/A

7

Exxon Mobil

Jay Barnett

None

N/A

7

Luminant Mining Company
LLC

Stewart Rake

Abstain

N/A

8

David Kiguel

David Kiguel

Affirmative

N/A

8

Massachusetts Attorney
General

Frederick Plett

None

N/A

8

Roger Zaklukiewicz

Roger
Zaklukiewicz

Affirmative

N/A

9

Commonwealth of
Massachusetts Department
of Public Utilities

Donald Nelson

Affirmative

N/A

10

Midwest Reliability
Organization

Russel Mountjoy

Affirmative

N/A

10

New York State Reliability
Council

ALAN
ADAMSON

Affirmative

N/A

10

Northeast Power
Coordinating Council

Guy V. Zito

Affirmative

N/A

10

ReliabilityFirst

Anthony
Jablonski

Affirmative

N/A

10

SERC Reliability Corporation

Drew Slabaugh

Affirmative

N/A

10

Texas Reliability Entity, Inc.

Rachel Coyne

Negative

Comments
Submitted

10

Western Electricity
Coordinating Council

Steven Rueckert

Negative

Comments
Submitted

Previous

1

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Showing 1 to 309 of 309 entries

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NERC Balloting Tool (/)

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Users

Dashboard (/)

Ballots

Comment Forms

Login (/Users/Login) / Register (/Users/Register)

BALLOT RESULTS
Ballot Name: 2016-02 Modifications to CIP Standards CIP-012-1 Non-binding Poll AB 4 NB
Voting Start Date: 6/22/2018 12:01:00 AM
Voting End Date: 7/5/2018 8:00:00 PM
Ballot Type: NB
Ballot Activity: AB
Ballot Series: 4
Total # Votes: 224
Total Ballot Pool: 290
Quorum: 77.24
Weighted Segment Value: 69.77
Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes

Negative
Fraction

Abstain

No
Vote

Segment:
1

75

1

36

0.75

12

0.25

13

13

Segment:
2

7

0.3

3

0.3

0

0

3

1

Segment:
3

70

1

30

0.714

12

0.286

12

15

Segment:
4

14

0.8

6

0.6

2

0.2

1

5

Segment:
5

69

1

23

0.59

16

0.41

9

21

Segment:
6

42

1

14

0.583

10

0.417

9

9

Segment:
7

2

0

0

0

0

0

1

1

Segment:
8

3

0.2

2

0.2

0

0

0

1

Segment:
9

1

0.1

1

0.1

0

0

0

0

Segment:
10

7

0.5

5

0.5

0

0

2

0

52

1.563

50

66

Segment

Totals:
290
5.9
120
4.337
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Page 2 of 17

BALLOT POOL MEMBERS
Show All

Segment

 entries

Organization

Search: Search

Voter

Designated
Proxy

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

American Transmission
Company, LLC

Douglas Johnson

Affirmative

N/A

1

APS - Arizona Public Service
Co.

Michelle
Amarantos

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

John Shaver

None

N/A

1

Associated Electric
Cooperative, Inc.

Ryan Ziegler

Affirmative

N/A

1

Austin Energy

Thomas
Standifur

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Affirmative

N/A

1

Basin Electric Power
Cooperative

David Rudolph

None

N/A

1

BC Hydro and Power
Authority

Patricia
Robertson

Abstain

N/A

1

Berkshire Hathaway Energy MidAmerican Energy Co.

Terry Harbour

Affirmative

N/A

1

Bonneville Power
Administration

Kammy RogersHolliday

Negative

Comments
Submitted

1

Brazos Electric Power
Cooperative, Inc.

Tony Kroskey

Affirmative

N/A

1

Cedar Falls Utilities

Adam Peterson

None

N/A

Affirmative

N/A

1

CenterPoint Energy Houston
Daniela
Electric,
LLC
Hammons
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Segment

Organization

Page 3 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Central Electric Power
Cooperative (Missouri)

Michael Bax

Affirmative

N/A

1

Central Hudson Gas &
Electric Corp.

Frank Pace

Affirmative

N/A

1

City Utilities of Springfield,
Missouri

Michael Buyce

None

N/A

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Dominion - Dominion Virginia
Power

Larry Nash

Abstain

N/A

1

Duke Energy

Laura Lee

Negative

Comments
Submitted

1

Edison International Southern California Edison
Company

Steven Mavis

Affirmative

N/A

1

Entergy - Entergy Services,
Inc.

Oliver Burke

Affirmative

N/A

1

Eversource Energy

Quintin Lee

Affirmative

N/A

1

Exelon

Chris Scanlon

Abstain

N/A

1

FirstEnergy - FirstEnergy
Corporation

Julie Severino

Affirmative

N/A

1

Great Plains Energy Kansas City Power and Light
Co.

James McBee

Negative

Comments
Submitted

1

Great River Energy

Gordon Pietsch

None

N/A

1

Hydro One Networks, Inc.

Payam
Farahbakhsh

Affirmative

N/A

1

Hydro-Qu?bec TransEnergie

Nicolas Turcotte

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Laura Nelson

Abstain

N/A

1

Imperial Irrigation District

Jesus Sammy
Alcaraz

None

N/A

Negative

Comments
Submitted

1

International Transmission
Michael Moltane
Company Holdings
Corporation
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Stephanie
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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 4 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Lincoln Electric System

Danny Pudenz

Abstain

N/A

1

Long Island Power Authority

Robert Ganley

Abstain

N/A

1

Los Angeles Department of
Water and Power

faranak sarbaz

Affirmative

N/A

1

Lower Colorado River
Authority

Michael Shaw

Affirmative

N/A

1

M and A Electric Power
Cooperative

William Price

Affirmative

N/A

1

Manitoba Hydro

Mike Smith

None

N/A

1

MEAG Power

David Weekley

Affirmative

N/A

1

Memphis Light, Gas and
Water Division

Allan Long

Affirmative

N/A

1

Minnkota Power Cooperative
Inc.

Theresa Allard

Negative

Comments
Submitted

1

Muscatine Power and Water

Andy Kurriger

Negative

Comments
Submitted

1

N.W. Electric Power
Cooperative, Inc.

Mark Ramsey

Affirmative

N/A

1

National Grid USA

Michael Jones

Affirmative

N/A

1

Nebraska Public Power
District

Jamison Cawley

Abstain

N/A

1

New York Power Authority

Salvatore
Spagnolo

None

N/A

1

NextEra Energy - Florida
Power and Light Co.

Mike ONeil

Affirmative

N/A

1

NiSource - Northern Indiana
Public Service Co.

Steve Toosevich

Affirmative

N/A

1

Northeast Missouri Electric
Power Cooperative

Kevin White

Affirmative

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Negative

Comments
Submitted

1

Ohio Valley Electric
Corporation

Scott
Cunningham

Affirmative

N/A

Scott Miller

Andy Fuhrman

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Segment

Organization

Page 5 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Omaha Public Power District

Doug Peterchuck

Negative

Comments
Submitted

1

OTP - Otter Tail Power
Company

Charles Wicklund

Negative

Comments
Submitted

1

Peak Reliability

Scott Downey

None

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Laurie Williams

Affirmative

N/A

1

PPL Electric Utilities
Corporation

Brenda Truhe

Abstain

N/A

1

PSEG - Public Service
Electric and Gas Co.

Joseph Smith

Abstain

N/A

1

Public Utility District No. 1 of
Chelan County

Jeff Kimbell

None

N/A

1

Public Utility District No. 1 of
Snohomish County

Long Duong

Abstain

N/A

1

Puget Sound Energy, Inc.

Theresa
Rakowsky

Affirmative

N/A

1

Sacramento Municipal Utility
District

Arthur Starkovich

Affirmative

N/A

1

Salt River Project

Steven Cobb

Negative

Comments
Submitted

1

Santee Cooper

Chris Wagner

Abstain

N/A

1

SCANA - South Carolina
Electric and Gas Co.

Tom Hanzlik

Abstain

N/A

1

Seattle City Light

Pawel Krupa

None

N/A

1

Seminole Electric
Cooperative, Inc.

Mark Churilla

None

N/A

1

Sempra - San Diego Gas
and Electric

Martine Blair

Affirmative

N/A

1

Sho-Me Power Electric
Cooperative

Peter Dawson

Affirmative

N/A

Affirmative

N/A

1

Southern Company Katherine Prewitt
Southern Company Services,
Inc.
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Jeff Johnson

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 6 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

None

N/A

1

Tennessee Valley Authority

Howell Scott

Abstain

N/A

1

Tri-State G and T
Association, Inc.

Tracy Sliman

Affirmative

N/A

1

U.S. Bureau of Reclamation

Richard Jackson

Negative

Comments
Submitted

1

Westar Energy

Allen Klassen

Negative

No Comment
Submitted

1

Western Area Power
Administration

sean erickson

Negative

Comments
Submitted

2

California ISO

Richard Vine

Abstain

N/A

2

Electric Reliability Council of
Texas, Inc.

Brandon Gleason

Affirmative

N/A

2

Independent Electricity
System Operator

Leonard Kula

Affirmative

N/A

2

ISO New England, Inc.

Michael Puscas

None

N/A

2

Midcontinent ISO, Inc.

Terry BIlke

Abstain

N/A

2

New York Independent
System Operator

Gregory Campoli

Abstain

N/A

2

PJM Interconnection, L.L.C.

Mark Holman

Affirmative

N/A

3

AEP

Aaron Austin

Affirmative

N/A

3

AES - Indianapolis Power
and Light Co.

Bette White

Affirmative

N/A

3

APS - Arizona Public Service
Co.

Vivian Vo

Affirmative

N/A

3

Arkansas Electric
Cooperative Corporation

Philip Huff

Affirmative

N/A

3

Associated Electric
Cooperative, Inc.

Todd Bennett

Affirmative

N/A

3

Austin Energy

W. Dwayne
Preston

Affirmative

N/A

None

N/A

3

Basin Electric Power
Jeremy Voll
Cooperative
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Segment

Organization

Page 7 of 17

Voter

3

Berkshire Hathaway Energy MidAmerican Energy Co.

Annette Johnston

3

Bonneville Power
Administration

3

Designated
Proxy

NERC
Memo

Affirmative

N/A

Rebecca Berdahl

Negative

Comments
Submitted

Central Electric Power
Cooperative (Missouri)

Adam Weber

Affirmative

N/A

3

City of Farmington

Linda JacobsonQuinn

Abstain

N/A

3

City of Leesburg

Chris Adkins

None

N/A

3

City of Vero Beach

Ginny Beigel

Negative

Comments
Submitted

3

City Utilities of Springfield,
Missouri

Scott Williams

None

N/A

3

Cleco Corporation

Michelle Corley

Negative

Comments
Submitted

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Affirmative

N/A

3

Cowlitz County PUD

Russell Noble

None

N/A

3

Duke Energy

Lee Schuster

Negative

Comments
Submitted

3

Edison International Southern California Edison
Company

Romel Aquino

None

N/A

3

Eversource Energy

Sharon Flannery

Affirmative

N/A

3

Exelon

John Bee

Abstain

N/A

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

Affirmative

N/A

3

Georgia System Operations
Corporation

Scott McGough

Affirmative

N/A

3

Great Plains Energy Kansas City Power and Light
Co.

Jessica Tucker

Negative

Comments
Submitted

3

Great River Energy

Brian Glover

Negative

Comments
Submitted

None

N/A

3 - NERC Ver 4.2.1.0
Hydro One
Networks,
Paul Malozewski
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Darnez
Gresham

Ballot

Brandon
McCormick

Louis Guidry

Douglas Webb

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 8 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

3

KAMO Electric Cooperative

Ted Hilmes

Affirmative

N/A

3

Lincoln Electric System

Jason Fortik

Abstain

N/A

3

M and A Electric Power
Cooperative

Stephen Pogue

Affirmative

N/A

3

Manitoba Hydro

Karim Abdel-Hadi

None

N/A

3

MEAG Power

Roger Brand

Scott Miller

Affirmative

N/A

3

Modesto Irrigation District

Jack Savage

Nick Braden

Abstain

N/A

3

Muscatine Power and Water

Seth Shoemaker

Negative

Comments
Submitted

3

National Grid USA

Brian Shanahan

Affirmative

N/A

3

Nebraska Public Power
District

Tony Eddleman

Abstain

N/A

3

New York Power Authority

David Rivera

None

N/A

3

NiSource - Northern Indiana
Public Service Co.

Aimee Harris

Affirmative

N/A

3

North Carolina Electric
Membership Corporation

doug white

Affirmative

N/A

3

Northeast Missouri Electric
Power Cooperative

Skyler Wiegmann

Affirmative

N/A

3

NW Electric Power
Cooperative, Inc.

John Stickley

Affirmative

N/A

3

Ocala Utility Services

Randy Hahn

Negative

Comments
Submitted

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Negative

Comments
Submitted

3

OTP - Otter Tail Power
Company

Wendi Olson

Negative

Comments
Submitted

3

Owensboro Municipal
Utilities

Thomas Lyons

Affirmative

N/A

3

Platte River Power Authority

Jeff Landis

Affirmative

N/A

3

PNM Resources - Public
Service Company of New
Mexico

Lynn Goldstein

Affirmative

N/A

Scott Brame

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Segment

Organization

Page 9 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Portland General Electric Co.

Angela Gaines

Affirmative

N/A

3

PPL - Louisville Gas and
Electric Co.

Charles Freibert

None

N/A

3

PSEG - Public Service
Electric and Gas Co.

Jeffrey Mueller

Abstain

N/A

3

Public Utility District No. 1 of
Chelan County

Joyce Gundry

Abstain

N/A

3

Puget Sound Energy, Inc.

Lynda Kupfer

Affirmative

N/A

3

Rutherford EMC

Tom Haire

None

N/A

3

Sacramento Municipal Utility
District

Nicole Looney

Affirmative

N/A

3

Salt River Project

Robert
Kondziolka

Negative

Comments
Submitted

3

Santee Cooper

James Poston

Abstain

N/A

3

SCANA - South Carolina
Electric and Gas Co.

Scott Parker

None

N/A

3

Seattle City Light

Tuan Tran

Affirmative

N/A

3

Seminole Electric
Cooperative, Inc.

James Frauen

Abstain

N/A

3

Sempra - San Diego Gas
and Electric

Bridget Silvia

Affirmative

N/A

3

Sho-Me Power Electric
Cooperative

Jeff Neas

Affirmative

N/A

3

Silicon Valley Power - City of
Santa Clara

Val Ridad

None

N/A

3

Snohomish County PUD No.
1

Holly Chaney

Abstain

N/A

3

Southern Company Alabama Power Company

Joel Dembowski

Affirmative

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

Marc Donaldson

None

N/A

3

TECO - Tampa Electric Co.

Ronald Donahey

None

N/A

3

Tennessee Valley Authority

Ian Grant

Abstain

N/A

Joe Tarantino

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Segment

Organization

Page 10 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Tri-State G and T
Association, Inc.

Janelle Marriott
Gill

None

N/A

3

WEC Energy Group, Inc.

Thomas Breene

Negative

Comments
Submitted

3

Westar Energy

Bryan Taggart

Negative

No Comment
Submitted

3

Xcel Energy, Inc.

Michael Ibold

Abstain

N/A

4

American Public Power
Association

Jack Cashin

None

N/A

4

Austin Energy

Esther Weekes

Affirmative

N/A

4

City of Clewiston

Lynne Mila

Negative

Comments
Submitted

4

City Utilities of Springfield,
Missouri

John Allen

Affirmative

N/A

4

Georgia System Operations
Corporation

Andrea Barclay

Affirmative

N/A

4

Indiana Municipal Power
Agency

Jack Alvey

Scott Berry

None

N/A

4

North Carolina Electric
Membership Corporation

John Lemire

Scott Brame

Affirmative

N/A

4

Public Utility District No. 1 of
Snohomish County

John Martinsen

Abstain

N/A

4

Sacramento Municipal Utility
District

Beth Tincher

Affirmative

N/A

4

Seattle City Light

Hao Li

Affirmative

N/A

4

Seminole Electric
Cooperative, Inc.

Charles
Wubbena

None

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

None

N/A

4

Utility Services, Inc.

Brian EvansMongeon

None

N/A

4

WEC Energy Group, Inc.

Anthony
Jankowski

Negative

Comments
Submitted

5

Acciona Energy North

George Brown

None

N/A

Brandon
McCormick

Joe Tarantino

AmericaMachine Name: ERODVSBSWB01
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Organization

Page 11 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

5

AEP

Thomas Foltz

Affirmative

N/A

5

Ameren - Ameren Missouri

Sam Dwyer

Affirmative

N/A

5

APS - Arizona Public Service
Co.

Kelsi Rigby

Affirmative

N/A

5

Associated Electric
Cooperative, Inc.

Brad Haralson

Affirmative

N/A

5

Austin Energy

Shirley Mathew

Affirmative

N/A

5

Avista - Avista Corporation

Glen Farmer

None

N/A

5

Basin Electric Power
Cooperative

Mike Kraft

None

N/A

5

BC Hydro and Power
Authority

Helen Hamilton
Harding

Abstain

N/A

5

Boise-Kuna Irrigation District
- Lucky Peak Power Plant
Project

Mike Kukla

Affirmative

N/A

5

Bonneville Power
Administration

Scott Winner

Negative

Comments
Submitted

5

BP Wind Energy North
America Inc.

Carla Holly

None

N/A

5

Choctaw Generation Limited
Partnership, LLLP

Rob Watson

Affirmative

N/A

5

Cleco Corporation

Stephanie
Huffman

Negative

Comments
Submitted

5

CMS Energy - Consumers
Energy Company

David
Greyerbiehl

Negative

Comments
Submitted

5

Colorado Springs Utilities

Jeff Icke

None

N/A

5

Con Ed - Consolidated
Edison Co. of New York

William Winters

Affirmative

N/A

5

Dairyland Power Cooperative

Tommy Drea

None

N/A

5

Dominion - Dominion
Resources, Inc.

Lou Oberski

None

N/A

5

Duke Energy

Dale Goodwine

Negative

Comments
Submitted

Louis Guidry

Alyson
Slanover

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Segment

Organization

Page 12 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Edison International Southern California Edison
Company

Selene Willis

Affirmative

N/A

5

EDP Renewables North
America LLC

Heather Morgan

None

N/A

5

Entergy

Jamie Prater

Affirmative

N/A

5

Exelon

Ruth Miller

Abstain

N/A

5

FirstEnergy - FirstEnergy
Solutions

Robert Loy

Affirmative

N/A

5

Great Plains Energy Kansas City Power and Light
Co.

Harold Wyble

Negative

Comments
Submitted

5

Great River Energy

Preston Walsh

Negative

Comments
Submitted

5

Hydro-Qu?bec Production

Junji Yamaguchi

None

N/A

5

JEA

John Babik

Affirmative

N/A

5

Kissimmee Utility Authority

Mike Blough

Negative

Comments
Submitted

5

Lakeland Electric

Jim Howard

Negative

Comments
Submitted

5

Lincoln Electric System

Kayleigh
Wilkerson

Abstain

N/A

5

Los Angeles Department of
Water and Power

Glenn Barry

None

N/A

5

Manitoba Hydro

Yuguang Xiao

Affirmative

N/A

5

Massachusetts Municipal
Wholesale Electric Company

David Gordon

Affirmative

N/A

5

MEAG Power

Steven Grego

Affirmative

N/A

5

Muscatine Power and Water

Neal Nelson

Negative

Comments
Submitted

5

NB Power Corporation

Laura McLeod

Abstain

N/A

5

Nebraska Public Power
District

Don Schmit

Abstain

N/A

None

N/A

5 - NERC Ver 4.2.1.0
New York
PowerName:
Authority
Erick Barrios
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Douglas Webb

Brandon
McCormick

Scott Miller

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Segment

Organization

Page 13 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

5

NextEra Energy

Allen Schriver

Affirmative

N/A

5

NiSource - Northern Indiana
Public Service Co.

Kathryn Tackett

Affirmative

N/A

5

Northern California Power
Agency

Marty Hostler

Negative

Comments
Submitted

5

OGE Energy - Oklahoma
Gas and Electric Co.

John Rhea

Negative

Comments
Submitted

5

Omaha Public Power District

Mahmood Safi

Negative

Comments
Submitted

5

Ontario Power Generation
Inc.

David
Ramkalawan

Affirmative

N/A

5

OTP - Otter Tail Power
Company

Cathy Fogale

Negative

Comments
Submitted

5

Portland General Electric Co.

Ryan Olson

Affirmative

N/A

5

PPL - Louisville Gas and
Electric Co.

JULIE
HOSTRANDER

None

N/A

5

PSEG - PSEG Fossil LLC

Tim Kucey

Abstain

N/A

5

Public Utility District No. 1 of
Chelan County

Haley Sousa

Abstain

N/A

5

Public Utility District No. 1 of
Snohomish County

Sam Nietfeld

Abstain

N/A

5

Puget Sound Energy, Inc.

Eleanor Ewry

Affirmative

N/A

5

Sacramento Municipal Utility
District

Susan Oto

Affirmative

N/A

5

Salt River Project

Kevin Nielsen

Negative

Comments
Submitted

5

Santee Cooper

Tommy Curtis

Abstain

N/A

5

SCANA - South Carolina
Electric and Gas Co.

Alyssa Hubbard

None

N/A

5

Seattle City Light

Faz Kasraie

None

N/A

5

Seminole Electric
Cooperative, Inc.

Brenda Atkins

None

N/A

Affirmative

N/A

5

Sempra - San Diego Gas
Daniel Frank
and
Electric
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Joe Tarantino

Andrey
Komissarov

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Segment

Organization

Page 14 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Silicon Valley Power - City of
Santa Clara

Sandra Pacheco

None

N/A

5

Southern Company Southern Company
Generation

William D. Shultz

Affirmative

N/A

5

SunPower

Bradley Collard

None

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

None

N/A

5

Talen Generation, LLC

Matthew
McMillan

None

N/A

5

TECO - Tampa Electric Co.

Frank L Busot

None

N/A

5

Tennessee Valley Authority

M Lee Thomas

None

N/A

5

U.S. Bureau of Reclamation

Wendy Center

Negative

Comments
Submitted

5

Westar Energy

Laura Cox

Negative

Comments
Submitted

6

APS - Arizona Public Service
Co.

Jonathan Aragon

Affirmative

N/A

6

Arkansas Electric
Cooperative Corporation

Bruce Walkup

Affirmative

N/A

6

Austin Energy

Andrew Gallo

Affirmative

N/A

6

Basin Electric Power
Cooperative

Paul Huettl

None

N/A

6

Berkshire Hathaway PacifiCorp

Sandra Shaffer

Affirmative

N/A

6

Cleco Corporation

Robert Hirchak

Negative

Comments
Submitted

6

Con Ed - Consolidated
Edison Co. of New York

Christopher
Overberg

Affirmative

N/A

6

Dominion - Dominion
Resources, Inc.

Sean Bodkin

Affirmative

N/A

6

Duke Energy

Greg Cecil

Negative

Comments
Submitted

Douglas Webb

Louis Guidry

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Segment

Organization

Page 15 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Edison International Southern California Edison
Company

Kenya Streeter

None

N/A

6

Entergy

Julie Hall

Affirmative

N/A

6

Exelon

Becky Webb

Abstain

N/A

6

FirstEnergy - FirstEnergy
Solutions

Ann Ivanc

Affirmative

N/A

6

Florida Municipal Power Pool

Tom Reedy

Brandon
McCormick

Negative

Comments
Submitted

6

Great Plains Energy Kansas City Power and Light
Co.

Jim Flucke

Douglas Webb

Negative

Comments
Submitted

6

Lincoln Electric System

Eric Ruskamp

Abstain

N/A

6

Los Angeles Department of
Water and Power

Anton Vu

Affirmative

N/A

6

Luminant - Luminant Energy

Brenda Hampton

Abstain

N/A

6

Manitoba Hydro

Blair Mukanik

None

N/A

6

Muscatine Power and Water

Ryan Streck

Negative

Comments
Submitted

6

NextEra Energy - Florida
Power and Light Co.

Silvia Mitchell

None

N/A

6

NiSource - Northern Indiana
Public Service Co.

Joe O'Brien

Affirmative

N/A

6

Northern California Power
Agency

Dennis Sismaet

Negative

Comments
Submitted

6

OGE Energy - Oklahoma
Gas and Electric Co.

Sing Tay

Negative

Comments
Submitted

6

Omaha Public Power District

Joel Robles

None

N/A

6

Portland General Electric Co.

Daniel Mason

Affirmative

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

None

N/A

6

Public Utility District No. 1 of
Chelan County

Davis Jelusich

Abstain

N/A

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Segment

Organization

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Voter

6

Public Utility District No. 2 of
Grant County, Washington

LeRoy Patterson

6

Sacramento Municipal Utility
District

Jamie Cutlip

6

Salt River Project

6

Designated
Proxy

Ballot

NERC
Memo

None

N/A

Affirmative

N/A

Bobby Olsen

Negative

Comments
Submitted

Santee Cooper

Michael Brown

Abstain

N/A

6

Seattle City Light

Charles Freeman

Affirmative

N/A

6

Seminole Electric
Cooperative, Inc.

Trudy Novak

Abstain

N/A

6

Snohomish County PUD No.
1

Franklin Lu

Abstain

N/A

6

Southern Company Southern Company
Generation and Energy
Marketing

Jennifer Sykes

Affirmative

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Rick Applegate

Abstain

N/A

6

Talen Energy Marketing, LLC

Jennifer
Hohenshilt

None

N/A

6

TECO - Tampa Electric Co.

Benjamin Smith

None

N/A

6

Tennessee Valley Authority

Marjorie Parsons

Abstain

N/A

6

WEC Energy Group, Inc.

David Hathaway

Negative

Comments
Submitted

6

Westar Energy

Megan Wagner

Negative

Comments
Submitted

7

Exxon Mobil

Jay Barnett

None

N/A

7

Luminant Mining Company
LLC

Stewart Rake

Abstain

N/A

8

David Kiguel

David Kiguel

Affirmative

N/A

8

Massachusetts Attorney
General

Frederick Plett

None

N/A

8

Roger Zaklukiewicz

Roger
Zaklukiewicz

Affirmative

N/A

Joe Tarantino

Douglas Webb

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Voter

Designated
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Ballot

NERC
Memo

9

Commonwealth of
Massachusetts Department
of Public Utilities

Donald Nelson

Affirmative

N/A

10

Midwest Reliability
Organization

Russel Mountjoy

Affirmative

N/A

10

New York State Reliability
Council

ALAN
ADAMSON

Affirmative

N/A

10

Northeast Power
Coordinating Council

Guy V. Zito

Affirmative

N/A

10

ReliabilityFirst

Anthony
Jablonski

Affirmative

N/A

10

SERC Reliability Corporation

Drew Slabaugh

Affirmative

N/A

10

Texas Reliability Entity, Inc.

Rachel Coyne

Abstain

N/A

10

Western Electricity
Coordinating Council

Steven Rueckert

Abstain

N/A

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CIP-012-1
Project 2016-02 Modifications to the CIP
Standards: Consideration of Comments
August 2018

NERC | Report Title | Report Date
I

Table of Contents
Preface ...................................................................................................................................................................... iii
Introduction .............................................................................................................................................................. iv
Background............................................................................................................................................................ iv
CIP-012-1 Consideration of Comments...................................................................................................................... 5
Purpose................................................................................................................................................................... 5
Control Center Definition ....................................................................................................................................... 5
Control Center ........................................................................................................................................................ 5
Control Center Exemption Language ..................................................................................................................... 5
Requirement R1...................................................................................................................................................... 6
Implementation Plan .............................................................................................................................................. 9
Technical Rationale for CIP-012-1 .......................................................................................................................... 9
Implementation Guidance.................................................................................................................................... 11
Cost Effectiveness................................................................................................................................................. 13

NERC | CIP-012-1 Consideration of Comments Summary Report | August 2018
ii

Preface
The vision for the Electric Reliability Organization (ERO) Enterprise, which is comprised of the North American Electric
Reliability Corporation (NERC) and the seven Regional Entities (REs), is a highly reliable and secure North American
bulk power system (BPS). Our mission is to assure the effective and efficient reduction of risks to the reliability and
security of the grid.
The North American BPS is divided into seven RE boundaries as shown in the map and corresponding table below.
The multicolored area denotes overlap as some load-serving entities participate in one Region while associated
Transmission Owners/Operators participate in another.

FRCC

Florida Reliability Coordinating Council

MRO

Midwest Reliability Organization

NPCC

Northeast Power Coordinating Council

RF

ReliabilityFirst

SERC

SERC Reliability Corporation

Texas RE

Texas Reliability Entity

WECC

Western Electricity Coordinating Council

NERC | CIP-012-1 Consideration of Comments Summary Report | August 2018
iii

Introduction
Background

The Project 2016-02 Modifications to CIP Standards Drafting Team thanks all commenters who submitted
comments on the draft CIP-012-1 standard. This standard was posted for a 45-day public comment period through
Friday, April 30, 2018. Stakeholders were asked to provide feedback on the standards and associated documents
through a special electronic comment form. There were 58 sets of responses, including comments from
approximately 155 different people from approximately 108 companies representing the 10 Industry Segments as
shown in the table on the following pages.
All comments submitted may be reviewed in their original format on the standard’s project page.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give every
comment serious consideration in this process. If you feel there has been an error or omission, you can contact the
NERC standards developer, Jordan Mallory, at 404-446-2589 or at [email protected].

NERC | CIP-012-1 Consideration of Comments Summary Report | August 2018
iv

CIP-012-1 Consideration of Comments
Purpose

The Modification to CIP Standards drafting team appreciates industry’s comments on the CIP-012-1 standard. The
SDT reviewed all comments carefully and made changes to the standard accordingly. The following pages are a
summary of the comments received and how the CIP SDT addressed them. If a specific comment was not addressed
in the summary of comments, please contact the NERC standards developer.

Control Center Definition

Many commenters expressed concern with the proposed Control Center definition.
The SDT decided to draft exemption language within the applicability section of CIP-012 instead of revising the Control
Center definition. Please see the Control Center definition consideration of comments report for additional SDT
responses on the new path taken by the SDT.

Control Center

A commenter suggested that the SDT is compounding the Control Center issue by having another explanation of a
Control Center/control center to those already present in CIP-002, CIP-014, and the NERC Glossary, and now CIP012. We recommend a single document that explains the Control Center / control center topic.
The SDT is using this Technical Rationale document to explain its intent in developing the exclusion language in CIP012-1. The exclusion in CIP-012 is for communications between certain Control Centers and does not modify the
definition of Control Center. Use of the Control Center term in other standards is not within the scope of this SDT's
SAR.

Control Center Exemption Language

Some commenters provided various examples of language for clarity of the Control Center exemption language
within CIP-012. One example of the suggested language and the SDTs response is:
4.2.3 A generating station, Transmission station or substation that is also a Control Center, but meets one of the
following criteria:
4.2.3.1 Aggregates and transmits Real-time Assessment and Real-time monitoring data from two or more
Generation resource(s), Transmission station(s) and/or substation(s) but all aggregated data comes from
locations that are contained within the same physical perimeter. (see Figure 1)
4.2.3.2 The Control Center does not aggregate and transmit Real-time Assessment and Real-time monitoring
data from location(s) outside the physical perimeter where it resides. (see Figure 2)
The SDT appreciates the included diagrams with Figure 1 and 2 to explain the intent. The SDT asserts that in Figure 1
if an entity defines station at a granular level to where multiple stations are in one "Facility Yard", this would still be
considered one "location" and would not fall under the "two or more locations" attribute of the Control Center
definition. Since the definition of Control Center uses the term "location", the SDT does not want to introduce a
synonymous term of "physical perimeter" and considers the two equivalent.
The SDT also agrees with the scenario depicted in Figure 2. In this scenario, Station 1 could be considered a Control
Center depending on the functionality available through the communications to the dual-ported RTUs at other
locations. Assuming each separate location is reporting its data to the TOP Control Center with its own individual
RTU, that communication is exempted from CIP-012.
NERC | CIP-012-1 Consideration of Comments Summary Report | August 2018
5

CIP-012-1 Consideration of Comments

Based on these comments, the SDT has created a similar diagram to the ones provided and included it in the Technical
Rationale document.
Some commenters recommended the below change along with rationale drafted explaining the reason for the
exemption.
A Control Center at a BES generation resource or Transmission station or substation that transmits to another
Control Center Real-time Assessment or Real-time monitoring data, such as RTU-style data, pertaining only to the
generation resource or Transmission station or substation at which the data transmitting transmitted Control
Center is located.
Rationale: The first use of “Control Center” implies that the exemption is for a Control Center to start with. Where
it is not a Control Center but a BES facility that transmits data, via an RTU (RTU was added since it plays a pivotal
point of intent within the Technical Rational document).
The SDT modified the Technical Rationale document explaining the reason for the Control Center exemption. In
addition to the clarifying changes to the Control Center exemption, please see the updated redline that provides
clarifying changes in attempt to make the exemption clearer.
A commenter suggests that there could be increases in security risk with repair personnel going into a PSP without
knowing all the CIP security requirements for such devices and have in-house personnel escorting the repair
personnel during any repair work.
The SDT asserts that such risks are covered under other CIP standards such as CIP-006 and CIP-004.

Requirement R1

A commenter expressed that Real-time Assessments list a number of specific inputs that should be considered for
both “Real-time Assessment (RTA) and Real-time monitoring (RTm) data.” The commenter suggested there may
be an audit approach taken that would require consideration of both RTA AND RTm data for proof that an entity
provided adequate protections. The commenter requested that the SDT provide clarification on whether there is
a distinction between data used for the RTA and data used for RTm. The commenter recommended consideration
of the use of the inputs in the RTA NERC term with a caveat that Entities may choose to protect additional data if
they feel the need to expand the scope.
The SDT relied on IRO-010-2 Requirement 1 and TOP-003-3 Requirement R1 that requires RCs, BAs, and TOPs to
identify data used for RTA and RTm. The SDT stated in the Implementation Guidance that entities may choose to
protect the data, the communication links, or both. The intent is that it may often be easier to identity the
communication links over which two Control Centers exchange RTA and RTm data (as well as other data) and protect
those communication links which protect all data flowing over them.
Some commenters questioned if CIP Exceptional Circumstance language needed to be added CIP-012-1.
The CIP Exceptional Circumstance language has been added to CIP-012.
A commenter expressed that "security protection used to mitigate risk" is too ambiguous. The commenter
requested the SDT consider including two concepts in Requirement R1. The first concept is to clarify whether
currently in place ICCP should be encrypted. The commenter noted that the requirement states "while being
transmitted between any Control Centers." The commenter further noted that the draft Implementation Guidance
has content talking about "both ends of the link" but did not include the expectations for the data while on the
NERC | CIP-012-1 Consideration of Comments Summary Report | August 2018
6

CIP-012-1 Consideration of Comments

link. The commenter was concerned with latency (primarily for generation control) if secure encryption is expected
over the ICCP. Second concept is to include examples that include but are not limiting for security protection.
The SDT asserts that defining a plan to mitigate the risk of modification and disclosure of applicable data allows the
Responsible Entity to document the processes that are supportable within its organization and offers flexibility in
methods to meet the security objective. The SDT notes that the Implementation Guidance document offers examples
of how to comply with the standard.
The SDT encourages Responsible Entities to submit additional scenarios as Implementation Guidance 1 through prequalified organizations for endorsement consideration.
Some commenters expressed that CIP-012 is unnecessary and that IRO-010 and TOP-003 already require a mutually
agreeable security protocol. Additionally, another commenter expressed concern about the overlap between CIP012 and TOP-003-3/IRO-010-2. The commenter questioned whether these standards should be combined.
FERC Order No. 822 paragraph 60 recognizes those requirements in IRO-010 and TOP-003 and states the reliability
gap to be addressed as “while responsible entities are required to exchange real-time and operational planning data
necessary to operate the bulk electric system using mutually agreeable security protocols, there is no technical
specification for how this transfer of information should incorporate mandatory security controls.” The modification
of these other standards to remove the mutually agreeable security protocol requirement is outside the scope of this
team’s SAR.
A commenter requested clarity on the Responsible Entity in charge of securing the data being transmitted from a
generator on RC, BA, and TOP equipment. The commenter suggested that the RC, BA, and TOP identify the GOP
responsibilities under Part 1.3.
If the Generator is not a Control Center then CIP-012 does not apply as it is only between Control Centers. However,
if the Generator is an applicable Control Center, then Requirement R1 Part 1.3 is intended to require the entities to
document their responsibilities.
A commenter requested the SDT clarify whether CIP-012-1 applies to low, medium, or high BES Cyber Systems. The
commenter requested the SDT also consider how to incorporate the scoping criteria into CIP-002.
The SDT asserts that the applicability is to data being transmitted between Control Centers of all impact levels in
response to FERC Order 822 paragraph 58.
Some commenters noted that Real-time monitoring is not a defined term and that the R in Real-time should not
be capitalized. In addition, the commenters expressed concern that coordination between Control Centers may
result in compromises that may not satisfy the needs of the entities involved.
The term "Monitor" has been lowercased. “Real-time" is defined in the NERC Glossary of Terms and correctly used.
A commenter expressed concern that Operations Planning Analysis (OPA) data is not included in CIP-012-1. In
addition, the commenter also noticed the Violation Time Horizon is for Operations Planning. Since the SDT has
indicated reasons for excluding OPA data, the commenter asked whether the relevant Violation Time Horizon
should be Real-time Operation.

1

NERC Compliance Guidance Policy: https://www.nerc.com/pa/comp/guidance/Documents/Pre-qualified_org_submittal_with_form.pdf
NERC | CIP-012-1 Consideration of Comments Summary Report | August 2018
7

CIP-012-1 Consideration of Comments

Please see CIP-012-1 Consideration of Comments Summary Response for the OPA part. Due to the plan being drafted
ahead of time; it would not be considered a Real-time Horizon and should remain operations planning horizon.
A commenter disagreed that having a plan adds to the reliability of protecting data used for Real-time Assessment
and Real-time monitoring and commented that a plan is not needed. Some commenters recommended replacing
the term “plan” with “process” throughout CIP-012-1, the Technical Rationale, Implementation Guidance, and
other associated documents. Additionally, some commenters recommended that entities not be required to have
a plan in Requirement R1, but have an actionable Requirement to implement. A suggestion was provided.
Based on industry feedback from a prior comment period, the SDT chose a requirement structure that is consistent
with many other CIP standards to implement a documented plan. With regard to the use of the “process” instead of
"plan", the SDT notes that the term ‘documented process’ refers to a set of required instructions specific to the
Responsible Entity, designed to achieve a specific outcome. The plan to meet R1 may simply include documentation
of the required elements of the Parts of CIP-012-1 Requirement R1. The plan also allows for R1 Part 1.3 to document
the entities’ responsibilities.
A commenter asked whether the current set of standards address those additional vulnerabilities in the entity’s IT
Security Plan. The commenter suggested that the current plan should be updated to include these additional risks,
threats and integrated solution(s) that are already performed by the entity.
The documented plan(s) will need to address the security protection in place to mitigate the risk of unauthorized
disclosure and unauthorized modification of applicable data transmitted between any Control Centers in accordance
with the specified attributes in the Requirement Parts.
Some commenters questioned whether Requirement 1 Part 1.3 is needed.
Requirement R1 Part 1.3 provides entities a mechanism to specify which entity is responsible for the application of
security controls, but not the actual security controls the other entity is responsible for. The SDT believes this is
necessary for validation in an audit for an entity to have documented which controls it is responsible for in order to
prevent the simultaneous auditing of multiple entities for each communication link between Control Centers
operated by different Responsible Entities. Additionally, where data is transmitted between different entities, the
SDT asserts that it is necessary for both entities to understand the responsibilities of applying the security controls
for the entire transmission in order to ensure that the data is protected. Additional information has been added to
the technical rationale document.
Some entities requested additional guidance around the different approaches to mitigating the risk of
unauthorized disclosure or modification of data in transit.
The SDT encourages entities to work with prequalified organizations to submit Implementation Guidance for
consideration.
A commenter asked if Real-time Data was operational data.
The term Real-time monitoring data was chosen for consistency with the data specification in TOP-003 and IRO-010
standards.
A commenter noted that the “SDT is not specifying the controls used to protect confidentiality and integrity.
However, the only method available to achieve the proposed required objective is to implement encryption. FERC
Order 822 states on page 39, “it is reasonable to conclude that any lag in communication speed resulting from
implementation of protections [encryption technologies] should only be measureable on the order of milliseconds
NERC | CIP-012-1 Consideration of Comments Summary Report | August 2018
8

CIP-012-1 Consideration of Comments

and, therefore, will not adversely impact Control Center communications,” but a commenter asserts this statement
only refers to a single data stream. It is unknown what encryption will do when dealing with multiple data streams
being transmitted at once, from one to many points, not only to the latency added for the reliable operation of the
BES, but also to the computing resources.”
The SDT agrees that encryption is a way to mitigate the identified risk and will be widely used as the method to do
so, but does not want to be prescriptive due to new and improved technology in the future. The objective is to
mitigate the identified risk and may require capacity updates to infrastructure in order to do so.
A commenter requested examples be provided on what a CIP exceptional circumstance would be.
The SDT’s intent for including CIP Exceptional Circumstances within CIP-012 is to allow for scenarios where, for
reliability reasons, restoration of availability of the data flowing between Control Centers may need to take
precedence over temporarily unavailable security controls. For example, if two Control Centers are using encryption
that is offloaded onto hardware cards and that encryption hardware fails, or if a key management system fails and
numerous entities lose communication, the entities may need to restore the data flow as soon as possible for
reliability purposes even if the encryption cannot be restored at the same time.

Implementation Plan

Some commenters stated that the 24-month timeline is not enough and requested the implementation timeline
be increased to 36 months or a phased-in approach. Additionally, a commenter acknowledged that the standard
and implementation plan are silent on physical security for the equipment being used to provide the data
protection. The commenter provided an example of protection for a router that is located in another Entity’s
facility.
The SDT lengthened the implementation timeline in previous drafts based on industry input, but 24 months has met
with widespread industry approval in later comment periods. The SDT concluded that a twenty-four (24) month
implementation period is appropriate.
Some commenters noted the difficulty on providing responses to the implementation timeline until the Control
Center definition is developed.
The SDT understands the uncertainty associated with CIP-012 if the Control Center definition is also under
modification. The SDT attempted to modify the Control Center definition to handle issues brought about by CIP-012’s
communication scope but based on industry comments has chosen to address those specific communication
concerns through an exemption in CIP-012. The Control Center definition remains stable. Please see the
Consideration of Comments for the Control Center definition for additional information on the SDT’s approach.

Technical Rationale for CIP-012-1

Some entities requested the SDT consider including some statements in the Technical Rationale to address the
possibility that data requests made related to TOP-003 and/or IRO-010 include other data that is not Real-time
Assessment data or Real-time monitoring data and how the Responsible Entity could exclude this other data from
the security requirements.
The SDT agrees and has added a section on this topic to the Technical Rationale document.
A commenter noted that when addressing the security protections, the rationale should include that logical and
physical controls can be used. The commenter suggested this should include the team’s rationale for allowing these
alternatives.
NERC | CIP-012-1 Consideration of Comments Summary Report | August 2018
9

CIP-012-1 Consideration of Comments

The SDT asserts that the Technical Rationale document already specifies that logical or physical controls can be used
to achieve the required security objective.
A commenter noted that the number of regions needs to be updated.
The number of Regions has been updated to reflect the correct number.
Some commenters noted grammatical modifications:
•

In requirement R1 of the technical rationale document, the document should state document plan

•

The alignment with IRO and TOP standards: last sentence “Real-time Monitoring “, the M should not be
capitalized as it is not a NERC defined term.

•

There appears to be a typo in the footer as it shows Reliability Standard CIP-002-1, instead of CIP-012-1

The SDT agrees and has made the modifications as noted.
A commenter suggested a clarifying addition to the diagram on page 3 (Control Centers in Scope) of the Technical
Rationale document: “In order to make the diagram more closely align to the statement made on page 8 of the
Implementation Guidance which states:
‘Entity Alpha does not need to consider any communications to other non-Control Center facilities such as
generating plants or substations. These communications are out of scope for CIP-012-1.’
The statement above indicates that communications from a Control Center, to a non-Control Center (generation
or sub) are out of scope. We suggest that a dotted line be added to the diagram on page 3 (Control Centers in
Scope) of the Technical Rational and Justification document to show that communications from a GOP Control
Center to a GOP Control Room should be considered out of scope. It is possible that a scenario could exist where
GOP Control Centers pass information through a GOP Control Room out to Field Assets.”
The SDT asserts that the diagram clearly shows the communications that are in and out of scope. Additionally, this
diagram is simply one example and is not inclusive of all possible communication scenarios.
A commenter noted that adding control to the statement "Real-time monitoring" from TOP-003 and IRO-010 may
set an expectation that control data will be part of those standards by default. The commenter noted that the
proposed CIP-012-1 Implementation Guidance does not use “and control.” The commenter recommended that if
control is to be part of "Real-time monitoring" then the SDT should make the modifications to all documents,
including the Glossary, to reduce misunderstanding.
Based on comments from the prior ballot and comment period, the SDT removed "and control" from the requirement
for this posting. The SDT notes that the systems that provide control are generally the same systems that provide
monitoring. The SDT removed "and control" to be consistent with the TOP-003 and IRO-010 standards.
A commenter requested that the SDT be consistent with other CIP standards and suggested the SDT combine the
Technical Rationale document with the Implementation Guidance document within the draft standard. The
commenter also requested the SDT clarify that CIP-012 is a standalone standard that is not associated with all the
other CIP standards.
The Technical Rationale document and Implementation Guidance document serve two different purposes. The
Technical Rationale document provides the SDT’s intent and technical basis for the language in the standard. In
NERC | CIP-012-1 Consideration of Comments Summary Report | August 2018
10

CIP-012-1 Consideration of Comments

addition, the Technical Rationale document provides examples and diagrams to assist entities in understanding the
language of the standard. Implementation Guidance is a means for registered entities to develop examples or
approaches for ERO Enterprise endorsement to illustrate how registered entities could comply with a standard 2.
There is a project underway reviewing all of the current Technical Rationale documents and removing compliance
examples from each document to submit for ERO Enterprise endorsement. Therefore, the Technical Rationale
document and Implementation Guidance document cannot be merged together. While the applicability is different
from other CIP standards, CIP-012-1 is one standard within the CIP Standard family.
A commenter expressed concern regarding the BCAs and EACMS used for CIP-012-1 may be considered out of scope
for the rest of the CIP Reliability Standards based on a statement on Page 6: “The SDT also recognizes that CIP-012
security protection may be applied to a Cyber Asset that is not an identified BES Cyber Asset or EACMS. The
identification of the Cyber Asset as the location where security protection is applied does not expand the scope of
Cyber Assets identified as applicable under the CIP Cyber Security Standards CIP-002 through CIP-011.”
The SDT notes that the assets where the security protection is applied under CIP-012 may be in data transport or
telecom equipment that is between discrete ESPs and meet the exclusion in the CIP standards, but still be physically
within a Control Center and thus meet the intent of protecting the data while being transmitted between Control
Centers. CIP-012-1 neither expands nor diminishes the scope of applicable Cyber Assets under CIP-002 through CIP011.
Some commenters noted difficulty with implementing Secure ICCP in the past because of concerns over the
inability to guarantee a valid certificate at all times.
The SDT asserts that Secure ICCP is an option, but is one option to meeting the objective. The SDT included the
flexibility to meet the objective and mitigate the risk at the application, network, or transport layers or even with
physical security. Entities are allowed the implementation of physical or logical controls that best meet their
operational and reliability needs as long as it meets the security objective specified in CIP-012-1 Requirement R1.
A commenter requested that the SDT provide additional information and a diagram for the scope and exemptions
for SCADA data from multiple substations to a remote computer room where data is aggregated at the remote
computer room prior to transmitting to a data center that is associated with the Operations Center.
The SDT asserts that CIP-012 provides for the protection of data while being transmitted between Control Centers
only and thus excludes communications between Control Centers and field sites such as substations (FERC Order 822,
paragraph 57).
A commenter suggested that the SDT provide examples in the Technical Rationale under what circumstances a
generating resource or Transmission sub would be applicable to this standard.
The SDT asserts that the standard only applies to generation resources and Transmission substations when those
facilities also meet the definition of a Control Center. In all other cases, the standard does not apply to such facilities.

Implementation Guidance

A commenter mentioned that when addressing the security protection that can be used in meeting CIP-012,
examples of physical protection should be included in guidance. This should include details on how they can be
used to address various parts of the communication between Control Centers.

2

NERC Compliance Guidance Policy: https://www.nerc.com/pa/comp/guidance/Documents/Pre-qualified_org_submittal_with_form.pdf
NERC | CIP-012-1 Consideration of Comments Summary Report | August 2018
11

CIP-012-1 Consideration of Comments

The SDT has addressed an example within the implementation guidance document that includes physical protections.
Typically physical protection might be used to protect communication links where encryption terminates at a device
outside the Control Center in order to protect the data until it arrives inside the Control Center.
A commenter suggested that the last paragraph under Identification of where security protection is applied by the
Responsible Entity be split into two separate paragraphs. The commenter suggested the first paragraph would
describe how to handle “when exchanging data between two entities” and the second paragraph would focus on
“when a Responsible Entity owns and operates both Control Centers.”
The SDT agrees with the comment and split the paragraph into two separate paragraphs.
A commenter mentioned that the guidance document is good but until an entity does actual implementation and
experiences any issues that arise from the implementation of CIP-012 requirement one can only assume the
outcome.
The SDT notes there are a number of ways to demonstrate compliance with the requirement and encourages entities
to develop and submit additional examples of Implementation Guidance through pre-qualified organizations for
endorsement consideration.
A commenter stated that the implementation of R1.3 will require a standardized solution/technology between
entities and a hierarchy of entity responsibilities. The commenter recommended the SDT add guidance and a
requirement to identify the entity who is the controlling authority for the secure communications between two or
more entities.
The SDT agrees that there will be coordination necessary and designed R1.3 to have the involved entities document
those responsibilities. The requirement has been written to allow flexibility on how entities work together on this
requirement. The SDT notes there are a number of ways to demonstrate compliance with the requirement and
encourages entities to develop and submit additional examples of Implementation Guidance through a prequalified organization for endorsement consideration.
Some commenters requested that the SDT define “logical protection” or replace all instances of “logical
protection” with “encryption.”
The SDT contends that the standard is written to not specify a particular technology. This allows the requirement to
be flexible in encompassing future protection solutions.
Some commenters recognized the SDT is not specifying the controls to be used to protect confidentiality and
integrity and that the only examples provided in the implementation guidance include encryption. The
commenters requested that the SDT provide other methods available to achieve the security objective if they exist.
The commenter cited activities and specifications in FERC Order No. 822, such as key management between
separate Responsible Entities that must be created and agreed upon by all registered entities involved in the data
transfer. The commenter suggested such activities may not be achievable in the 24-month implementation period.
The commenter also noted that a Responsible Entity would lose Real-time Assessment and Real-time monitoring
and control data if encryption failed. The commenter suggested a pilot to implement encryption.
The SDT agrees that there will be coordination necessary and designed R1.3 to have the involved entities document
the responsibilities. The requirement has been written to allow flexibility on how entities work together on this
requirement. The SDT notes there are a number of ways to demonstrate compliance with the requirement and
encourages entities to develop and submit additional examples of Implementation Guidance through pre-qualified
NERC | CIP-012-1 Consideration of Comments Summary Report | August 2018
12

CIP-012-1 Consideration of Comments

organizations for endorsement consideration. Please see other comment responses on the 24 month implementation
plan. The SDT has included the CIP Exceptional Circumstances language in the requirement in order to allow for
encryption failures where reliability may require data to be transferred between Control Centers while the encryption
capability is being repaired.
A commenter identified that on page 5 under section “Identification of Where Security Protection is applied by the
Responsible Entity”, language should be added to address the situation where a Responsible Entity does not
manage either end of a communication link, indicating that this Responsible Entity does not have compliance
obligations to R1.2.
The SDT agrees and has added such language to clarify obligations in such instances. Requirement 1.3 is also key in
the documentation of such cases.
A couple of comments were received that the requirement should be less prescriptive, and additional technical
and implementation guidance is needed to provide clarity on the SDT intent and audited scope.
The SDT asserts that the requirement is objective based and describes the risk to be mitigated without prescribing
any technical solutions. There are a number of ways to demonstrate compliance with the requirement and the SDT
encourages entities to develop and submit additional examples of Implementation Guidance through pre-qualified
organizations for endorsement consideration.

Cost Effectiveness

A commenter expressed concern that if the data must be protected throughout the transmission, it would seem
that could only be accomplished with encryption. The commenter noted that are cases where the existing
equipment is not capable of encryption, replacement will be costly and implementation lengthy. In addition, the
commenter stated that due to the large amount of applicable data, access to funds and budget cycle, and resources
to perform work required, the solution will be costly.
The SDT has designed CIP-012 with flexibility so the entities can choose the most cost effective means to protect the
data while being transmitted between Control Centers. The SDT agrees encryption will be a widely used method and
can be accomplished at the application, network, transport, or physical layers or combinations thereof.
Some commenters noted that without clarity on ICCP between Control Centers, the commenters cannot be certain
of what is expected, the costs or flexibility.
The SDT notes that data in scope may not be limited to ICCP. This is dependent on the specifics of each entity or
entities.
A commenter acknowledged that more flexibility and less guidance could lead to inconsistency on requirement
implementation among different entities.
CIP-012 is written to allow for selection of the most practical solution for the entity or entities.
A commenter questioned how the SDT is addressing the scenario where a Responsible Entity identifies multiple
types of security protection and one of the forms fails but the data transmission is still protected, meeting the
intent of the standard.
In the event of a failure of a protection method, it is the Entity’s responsibility to demonstrate how compliance was
maintained during the event.
NERC | CIP-012-1 Consideration of Comments Summary Report | August 2018
13

CIP-012-1 Consideration of Comments

A commenter does not agree the current standard and implementation plan can be executed in a cost effective
manner. The commenter noted that encryption has been the only presented solution provided by auditors and
SDT guidance to protect both confidentiality and integrity for the data within this scope. The commenter noted
that more resources and capital will be required for a 24-month implementation versus a phased-in
implementation. The commenter further noted that a phased implementation provides the ability to not only
ensure the most effective plan, but also provides the ability to plan more accurately within budget cycles. In
addition, the commenter noted that if encryption fails, an entity would lose Real-time Assessment and Real-time
monitoring and control data. The commenter expressed concern that a 24-month implementation timeline would
impact reliability as there are many opportunities for encryption to fail that must be addressed. The commenter
suggested that this has a direct correlation on cost when addressing those opportunities during this timeframe.
Additionally, the commenter requested the SDT draft reference models of methods that do not require encryption
as a method to protect communications between Control Centers.
CIP-012 is written in a non-prescriptive manner to allow entities to select the protection methods that most
appropriately fit their organization. This allows for logical or physical protection as appropriate. Regarding guidance,
the SDT encourages entities to draft and submit guidance on other implementation examples.

NERC | CIP-012-1 Consideration of Comments Summary Report | August 2018
14

Standards Announcement

Project 2016-01 Modifications to CIP Standards
Draft Reliability Standard Audit Worksheet (RSAW) Posted for Industry
Comment through July 2, 2018
Now Available
The draft RSAW for CIP-012-1 − Cyber Security – Control Center Communication Networks is
posted on the project page for industry comment through 8 p.m. Eastern, Monday, July 2, 2018.
Submit feedback regarding the draft RSAW to [email protected].
For more information or assistance, contact Standards Developer, Jordan Mallory (via email) or at (404)
446-2589.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

CIP-012-1 – Cyber Security – Communications between Control Centers

Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).

Description of Current Draft

CIP-012-1 is being posted for a 10-day final ballot.
Completed Actions

Date

Standards Committee approved Standard Authorization Request
(SAR) for posting

March 9, 2016

SAR posted for comment

March 23 - April 21,
2016

SAR posted for comment

June 1 – June 30,
2016

Informal comment period

February 10- March
13, 2017

45-day formal comment period with initial ballot

July 27 – September
11, 2017

45-day formal comment period with additional ballot

October 27 –
December 11, 2017

45-day formal comment period with additional ballot

March 16 – April 30,
2018

45-day formal comment period with additional ballot

May 18 – July 2,
2018

10-day final ballot

August 3 – August
13, 2018
Anticipated Actions

NERC Board

Date

August 16, 2018

A. Introduction
1.

Title: Cyber Security – Communications between Control Centers

2.

Number: CIP-012-1

Draft 4 of CIP-012-1
August 2018

Page 1 of 5

CIP-012-1 – Cyber Security – Communications between Control Centers

3.

Purpose: To protect the confidentiality and integrity of Real-time Assessment and
Real-time monitoring data transmitted between Control Centers.

4.

Applicability:
4.1. Functional Entities: The requirements in this standard apply to the following
functional entities, referred to as “Responsible Entities,” that own or operate a
Control Center.
4.1.1. Balancing Authority
4.1.2. Generator Operator
4.1.3. Generator Owner
4.1.4. Reliability Coordinator
4.1.5. Transmission Operator
4.1.6. Transmission Owner
4.2. Exemptions: The following are exempt from Reliability Standard CIP-012-1:
4.2.1. Cyber Assets at Facilities regulated by the Canadian Nuclear Safety
Commission.
4.2.2. The systems, structures, and components that are regulated by the
Nuclear Regulatory Commission under a cyber security plan pursuant
to 10 C.F.R. Section 73.54.
4.2.3. A Control Center that transmits to another Control Center Real-time
Assessment or Real-time monitoring data pertaining only to the
generation resource or Transmission station or substation co-located
with the transmitting Control Center.

5.

Effective Date: See Implementation Plan for CIP-012-1.

B. Requirements and Measures
R1.

The Responsible Entity shall implement, except under CIP Exceptional Circumstances,
one or more documented plan(s) to mitigate the risks posed by unauthorized
disclosure and unauthorized modification of Real-time Assessment and Real-time
monitoring data while being transmitted between any applicable Control Centers. The
Responsible Entity is not required to include oral communications in its plan. The plan
shall include: [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]
1.1. Identification of security protection used to mitigate the risks posed by
unauthorized disclosure and unauthorized modification of Real-time Assessment
and Real-time monitoring data while being transmitted between Control
Centers;

Draft 4 of CIP-012-1
August 2018

Page 2 of 5

CIP-012-1 – Cyber Security – Communications between Control Centers

1.2. Identification of where the Responsible Entity applied security protection for
transmitting Real-time Assessment and Real-time monitoring data between
Control Centers; and
1.3. If the Control Centers are owned or operated by different Responsible Entities,
identification of the responsibilities of each Responsible Entity for applying
security protection to the transmission of Real-time Assessment and Real-time
monitoring data between those Control Centers.
M1. Evidence may include, but is not limited to, documented plan(s) that meet the
security objective of Requirement R1 and documentation demonstrating the
implementation of the plan(s).

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority” (CEA)
means NERC, the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below
is shorter than the time since the last audit, the CEA may ask an entity to provide
other evidence to show that it was compliant for the full-time period since the
last audit.
The Responsible Entity shall keep data or evidence to show compliance as
identified below unless directed by its CEA to retain specific evidence for a
longer period of time as part of an investigation.
•

The Responsible Entities shall keep data or evidence of each Requirement in
this Reliability Standard for three calendar years.

•

If a Responsible Entity is found non-compliant, it shall keep information
related to the non-compliance until mitigation is complete and approved or
for the time specified above, whichever is longer.

•

The CEA shall keep the last audit records and all requested and submitted
subsequent audit records.

1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers
to the identification of the processes that will be used to evaluate data or
information for the purpose of assessing performance or outcomes with the
associated Reliability Standard.
Draft 4 of CIP-012-1
August 2018

Page 3 of 5

CIP-012-1 – Cyber Security – Communications between Control Centers

Violation Severity Levels
Violation Severity Levels

R#

R1.

Lower VSL

N/A

Moderate VSL

The Responsible Entity
documented its plan(s) but
failed to include one of the
applicable Parts of the plan
as specified in Requirement
R1.

High VSL

The Responsible Entity
documented its plan(s) but
failed to include two of the
applicable Parts of the plan
as specified in Requirement
R1.

Severe VSL

The Responsible Entity failed
to document plan(s) for
Requirement R1;
Or
The Responsible Entity failed
to implement any Part of its
plan(s) for Requirement R1,
except under CIP Exceptional
Circumstances.

D. Regional Variances
None.

E. Associated Documents
Implementation Plan.

Technical Rationale for CIP-012-1.
Implementation Guidance.

Draft 4 of CIP-012-1
August 2018

Page 4 of 5

CIP-012-1 Version History

Version History
Version

Date

1

TBD

Draft 4 of CIP-012-1
August 2018

Action

Respond to FERC Order No. 822

Change
Tracking

N/A

Page 5 of 5

CIP-012-1 – Cyber Security – Communications between Control Centers

Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).

Description of Current Draft

This is the CIP-012-1 is being posted for fourtha 10-day final ballotdraft of the proposed
standard.
Completed Actions

Date

Standards Committee approved Standard Authorization Request
(SAR) for posting

March 9, 2016

SAR posted for comment

March 23 - April 21,
2016

SAR posted for comment

June 1 – June 30,
2016

Informal comment period

February 10- March
13, 2017

45-day formal comment period with initial ballot

July 27 – September
11, 2017

45-day formal comment period with additional ballot

October 27 –
December 11, 2017

45-day formal comment period with additional ballot

March 16 – April 30,
2018

45-day formal comment period with additional ballot

May 18 – July 2,
2018

10-day final ballot

July 30August 3 –
August 813, 2018
Anticipated Actions

10-day final ballot
NERC Board

Draft 4 of CIP-012-1
May August 2018

Date

July 30 – August 8,
2018
August 16, 2018

Page 1 of 6

CIP-012-1 – Cyber Security – Communications between Control Centers

A. Introduction
1.

Title: Cyber Security – Communications between Control Centers

2.

Number: CIP-012-1

3.

Purpose: To protect the confidentiality and integrity of Real-time Assessment and
Real-time monitoring data transmitted between Control Centers.

4.

Applicability:
4.1. Functional Entities: The requirements in this standard apply to the following
functional entities, referred to as “Responsible Entities,” that own or operate a
Control Center.
4.1.1. Balancing Authority
4.1.2. Generator Operator
4.1.3. Generator Owner
4.1.4. Reliability Coordinator
4.1.5. Transmission Operator
4.1.6. Transmission Owner
4.2. Exemptions: The following are exempt from Reliability Standard CIP-012-1:
4.2.1. Cyber Assets at Facilities regulated by the Canadian Nuclear Safety
Commission.
4.2.2. The systems, structures, and components that are regulated by the
Nuclear Regulatory Commission under a cyber security plan pursuant
to 10 C.F.R. Section 73.54.
4.2.3. A Control Center at a generation resource or Transmission station or
substation that transmits to another Control Center Real-time
Assessment or Real-time monitoring data pertaining only to the
generation resource or Transmission station or substation co-located
with at which the transmitting Control Center is located.

5.

Effective Date: See Implementation Plan for CIP-012-1.

B. Requirements and Measures
R1.

The Responsible Entity shall implement, except under CIP Exceptional Circumstances,
one or more documented plan(s) to mitigate the risks of posed by unauthorized
disclosure or and unauthorized modification of Real-time Assessment and Real-time
monitoring data while being transmitted between any applicable Control Centers. The
Responsible Entity is not required to include oral communications in its plan. The plan
shall include: [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]

Draft 4 of CIP-012-1
May August 2018

Page 2 of 6

CIP-012-1 – Cyber Security – Communications between Control Centers

1.1. Identification of security protection used to mitigate the risks posed by of
unauthorized disclosure or and unauthorized modification of Real-time
Assessment and Real-time monitoring data while being transmitted between
Control Centers;
1.2. Identification of where the Responsible Entity applied security protection for
transmitting Real-time Assessment and Real-time monitoring data between
Control Centers; and
1.3. If the Control Centers are owned or operated by different Responsible Entities,
identification ofy the responsibilities of each Responsible Entity for applying
security protection to the transmission of Real-time Assessment and Real-time
monitoring data between those Control Centers.
M1. Evidence may include, but is not limited to, documented plan(s) that meet the
security objective of Requirement R1 and documentation demonstrating the
implementation of the plan(s).

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority” (CEA)
means NERC, the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below
is shorter than the time since the last audit, the CEA may ask an entity to provide
other evidence to show that it was compliant for the full-time period since the
last audit.
The Responsible Entity shall keep data or evidence to show compliance as
identified below unless directed by its CEA to retain specific evidence for a
longer period of time as part of an investigation.
•

The Responsible Entities shall keep data or evidence of each Requirement in
this Reliability Standard for three calendar years.

•

If a Responsible Entity is found non-compliant, it shall keep information
related to the non-compliance until mitigation is complete and approved or
for the time specified above, whichever is longer.

•

The CEA shall keep the last audit records and all requested and submitted
subsequent audit records.

Draft 4 of CIP-012-1
May August 2018

Page 3 of 6

CIP-012-1 – Cyber Security – Communications between Control Centers

1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers
to the identification of the processes that will be used to evaluate data or
information for the purpose of assessing performance or outcomes with the
associated Reliability Standard.

Draft 4 of CIP-012-1
May August 2018

Page 4 of 6

CIP-012-1 – Cyber Security – Communications between Control Centers

Violation Severity Levels
Violation Severity Levels

R#

R1.

Lower VSL

N/A

Moderate VSL

The Responsible Entity
documented its plan(s) but
failed to include one of the
applicable Parts of the plan
as specified in Requirement
R1.

High VSL

The Responsible Entity
documented its plan(s) but
failed to include two of the
applicable Parts of the plan
as specified in Requirement
R1.

Severe VSL

The Responsible Entity failed
to document plan(s) for
Requirement R1;
Or
The Responsible Entity failed
to implement any Part of its
plan(s) for Requirement R1,
except under CIP Exceptional
Circumstances.

D. Regional Variances
None.

E. Associated Documents
Implementation Plan.

Technical Rationale for CIP-012-1.
Implementation Guidance.

Draft 4 of CIP-012-1
May August 2018

Page 5 of 6

CIP-012-1 Version History

Version History
Version

Date

1

TBD

Draft 4 of CIP-012-1
May August 2018

Action

Respond to FERC Order No. 822

Change
Tracking

N/A

Page 6 of 6

Implementation Plan

Project 2016-02 Modifications to CIP Standards
Reliability Standard CIP-012-1
Applicable Standard
•

Reliability Standard CIP-012-1 - Cyber Security – Communications between Control Centers

Requested Retirements
•

None

Prerequisite Standard

These standard(s) or definitions must be approved before the Applicable Standard becomes
effective:
•

None

Applicable Entities
•

Balancing Authority

•

Generator Operator

•

Generator Owner

•

Reliability Coordinator

•

Transmission Operator

•

Transmission Owner

Effective Date

Reliability Standard CIP-012-1 - Cyber Security – Communications between Control Centers
Where approval by an applicable governmental authority is required, Reliability Standard CIP-012-1
shall become effective on the first day of the first calendar quarter that is twenty-four (24) calendar
months after the effective date of the applicable governmental authority’s order approving the
standard, or as otherwise provided for by the applicable governmental authority.
Where approval by an applicable governmental authority is not required, Reliability Standard CIP012-1 shall become effective on the first day of the first calendar quarter that is twenty-four (24)
calendar months after the date the standard is adopted by the NERC Board of Trustees, or as
otherwise provided for in that jurisdiction.

Violation Risk Factor and Violation Severity Level
Justifications
Project 2016-02 Modifications to CIP Standards

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in CIP-012-1. Each requirement is assigned a VRF and a VSL. These elements support the determination of
an initial value range for the Base Penalty Amount regarding violations of requirements in FERC-approved Reliability Standards, as defined in
the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT applied the following NERC criteria and FERC Guidelines when
developing the VRFs and VSLs for the requirements.

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•

Emergency operations

•

Vegetation management

•

Operator personnel training

•

Protection systems and their coordination

•

Operating tools and backup facilities

•

Reactive power and voltage control

•

System modeling and data exchange

•

Communication protocol and facilities

•

Requirements to determine equipment ratings

•

Synchronized data recorders

•

Clearer criteria for operationally critical facilities

•

Appropriate use of transmission loading relief.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | August 2018

2

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | August 2018

3

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL

Moderate VSL

The performance or product
measured almost meets the full
intent of the requirement.

The performance or product
measured meets the majority of
the intent of the requirement.

High VSL

The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet
some of the intent.

Severe VSL

The performance or product
measured does not
substantively meet the intent of
the requirement.

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | August 2018

4

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justifications for CIP-012-1, Requirement R1

Proposed VRF

Medium

NERC VRF Discussion

A VRF of Medium was assigned to this requirement. Cyber security plans enable effective implementation
of the CIP standard’s requirements to mitigate the risks posed by unauthorized disclosure and
unauthorized modification of data used for Real-time Assessments and Real-time monitoring while being
transmitted between Control Centers.

FERC VRF G1 Discussion

N/A

Guideline 1- Consistency
with Blackout Report
FERC VRF G2 Discussion

N/A

Guideline 2- Consistency
within a Reliability Standard
FERC VRF G3 Discussion
Guideline 3- Consistency
among Reliability Standards
FERC VRF G4 Discussion
Guideline 4- Consistency
with NERC Definitions of
VRFs
FERC VRF G5 Discussion

The requirement complements CIP-005-1, Requirement R1, CIP-006-6, Requirement R1, and CIP-007-6,
Requirement R1 which are related to security of networks and communications components. The
proposed VRF is consistent with these related requirements.
Failure to have the required plan would not, under Emergency, abnormal, or restorative conditions
anticipated by the preparations, be expected to adversely affect the electrical state or capability of the
Bulk Electric System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

N/A

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | August 2018

5

VRF Justifications for CIP-012-1, Requirement R1

Proposed VRF

Medium

Guideline 5- Treatment of
Requirements that Comingle More than One
Obligation
VSLs for CIP-012-1, Requirement R1

Lower
N/A

Moderate
The Responsible Entity
documented its plan(s) but
failed to include one of the
applicable Parts of the plan as
specified in Requirement R1.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | August 2018

High
The Responsible Entity
documented its plan(s) but
failed to include two of the
applicable Parts of the plan as
specified in Requirement R1.

Severe
The Responsible Entity failed to
document plan(s) for
Requirement R1;
Or
The Responsible Entity failed to
implement any Part of its plan(s)
for Requirement R1, except
under CIP Exceptional
Circumstances.

6

VSL Justifications for CIP-012-1 Requirements R1

FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency
in the Determination of
Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent

The requirement is new. Therefore, the proposed VSL does not have the unintended consequence of
lowering the level of compliance.

The requirement is for the Responsible Entity to implement one or more documented plan(s) as specified
in Requirement R1.
The moderate VSL addresses where the Responsible Entity documented its plan(s) but failed to include
one of the applicable parts of the plan as specified in Requirement R1.
The high VSL addresses where the Responsible Entity documented its plan(s) but failed to include two of
the applicable parts of the plan as specified in Requirement R1.
The severe VSL addresses where the Responsible Entity failed to document plan(s) for Requirement R1, or
where the Responsible Entity failed to implement plan(s) for Requirement R1.

Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement

The proposed VSL uses the same terminology as used in the associated requirement and is, therefore,
consistent with the requirement.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | August 2018

7

FERC VSL G4

Each VSL is based on a single violation and not cumulative violations.

Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | August 2018

8

Violation Risk Factor and Violation Severity Level
Justifications
Project 2016-02 Modifications to CIP Standards

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in CIP-012-1. Each requirement is assigned a VRF and a VSL. These elements support the determination of
an initial value range for the Base Penalty Amount regarding violations of requirements in FERC-approved Reliability Standards, as defined in
the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT applied the following NERC criteria and FERC Guidelines when
developing the VRFs and VSLs for the requirements.

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•

Emergency operations

•

Vegetation management

•

Operator personnel training

•

Protection systems and their coordination

•

Operating tools and backup facilities

•

Reactive power and voltage control

•

System modeling and data exchange

•

Communication protocol and facilities

•

Requirements to determine equipment ratings

•

Synchronized data recorders

•

Clearer criteria for operationally critical facilities

•

Appropriate use of transmission loading relief.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | May August 2018

2

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | May August 2018

3

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL

Moderate VSL

The performance or product
measured almost meets the full
intent of the requirement.

The performance or product
measured meets the majority of
the intent of the requirement.

High VSL

The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet
some of the intent.

Severe VSL

The performance or product
measured does not
substantively meet the intent of
the requirement.

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | May August 2018

4

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justifications for CIP-012-1, Requirement R1

Proposed VRF

Medium

NERC VRF Discussion

A VRF of Medium was assigned to this requirement. Cyber security plans enable effective implementation
of the CIP standard’s requirements to mitigate the risks of theposed by unauthorized disclosure or and
unauthorized modification of data used for Real-time Assessments and Real-time monitoring while being
transmitted between Control Centers.

FERC VRF G1 Discussion

N/A

Guideline 1- Consistency
with Blackout Report
FERC VRF G2 Discussion

N/A

Guideline 2- Consistency
within a Reliability Standard
FERC VRF G3 Discussion
Guideline 3- Consistency
among Reliability Standards
FERC VRF G4 Discussion

The requirement complements CIP-005-1, Requirement R1, CIP-006-6, Requirement R1, and CIP-007-6,
Requirement R1 which are related to security of networks and communications components. The
proposed VRF is consistent with these related requirements.

Guideline 4- Consistency
with NERC Definitions of
VRFs

Failure to have the requireda cyber security plan would not, under Emergency, abnormal, or restorative
conditions anticipated by the preparations, be expected to adversely affect the electrical state or
capability of the Bulk Electric System, or the ability to effectively monitor, control, or restore the Bulk
Electric System.

FERC VRF G5 Discussion

N/A

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | May August 2018

5

VRF Justifications for CIP-012-1, Requirement R1

Proposed VRF

Medium

Guideline 5- Treatment of
Requirements that Comingle More than One
Obligation
VSLs for CIP-012-1, Requirement R1

Lower
N/A

Moderate
The Responsible Entity
documented its plan(s) but
failed to include one of the
applicable Parts of the plan as
specified in Requirement R1.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | May August 2018

High
The Responsible Entity
documented its plan(s) but
failed to include two of the
applicable Parts of the plan as
specified in Requirement R1.

Severe
The Responsible Entity failed to
document plan(s) for
Requirement R1;
Or
The Responsible Entity failed to
implement any Part of its plan(s)
for Requirement R1, except
under CIP Exceptional
Circumstances.

6

VSL Justifications for CIP-012-1 Requirements R1

FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency
in the Determination of
Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent

The requirement is new. Therefore, the proposed VSL does not have the unintended consequence of
lowering the level of compliance.

The requirement is for the Responsible Entity to implement one or more documented plan(s) as specified
in Requirement R1.
The moderate VSL addresses where the Responsible Entity documented its plan(s) but failed to include
one of the applicable parts of the plan as specified in Requirement R1.
The high VSL addresses where the Responsible Entity documented its plan(s) but failed to include two of
the applicable parts of the plan as specified in Requirement R1.
The severe VSL addresses where the Responsible Entity failed to document plan(s) for Requirement R1, or
where the Responsible Entity failed to implement plan(s) for Requirement R1.

Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement

The proposed VSL uses the same terminology as used in the associated requirement and is, therefore,
consistent with the requirement.

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | May August 2018

7

FERC VSL G4

Each VSL is based on a single violation and not cumulative violations.

Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations

VRF and VSL Justifications
Project 2016-02 Modifications to CIP Standards | May August 2018

8

Cyber Security –
Communications between
Control Centers
Technical Rationale and Justification for
Reliability Standard CIP-012-1

August 2018

NERC | Report Title | Report Date
I

Table of Contents
Preface ........................................................................................................................ Error! Bookmark not defined.
Introduction .............................................................................................................................................................. iv
Requirement R1 ......................................................................................................................................................... 1
General Considerations for Requirement R1...................................................................................................... 1
Overview of confidentiality and integrity ........................................................................................................... 1
Alignment with IRO and TOP standards ............................................................................................................. 1
Identification of Where Security Protection is Applied by the Responsible Entity ............................................ 2
Control Center Ownership .................................................................................................................................. 2
References.................................................................................................................................................................. 4

NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1| August 2018
ii

Preface
The vision for the Electric Reliability Organization (ERO) Enterprise, which is comprised of the North American Electric
Reliability Corporation (NERC) and the seven Regional Entities (REs), is a highly reliable and secure North American
bulk power system (BPS). Our mission is to assure the effective and efficient reduction of risks to the reliability and
security of the grid.
The North American BPS is divided into seven RE boundaries as shown in the map and corresponding table below.
The multicolored area denotes overlap as some load-serving entities participate in one Region while associated
Transmission Owners/Operators participate in another.

FRCC

Florida Reliability Coordinating Council

MRO

Midwest Reliability Organization

NPCC

Northeast Power Coordinating Council

RF

ReliabilityFirst

SERC

SERC Reliability Corporation

Texas RE

Texas Reliability Entity

WECC

Western Electricity Coordinating Council

NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1| August 2018
iii

Introduction
This document explains the technical rationale and justification for the proposed Reliability Standard CIP-012-1. It
will provide stakeholders and the ERO Enterprise with an understanding of the technology and technical
requirements in the Reliability Standard. It also contains information on the SDT’s intent in drafting the requirements.
This Technical Rationale and Justification for CIP-012-1 is not a Reliability Standard and should not be considered
mandatory and enforceable.
On January 21, 2016, the Federal Energy Regulatory Commission (FERC or Commission) issued Order No. 822,
approving seven Critical Infrastructure Protection (CIP) Reliability Standards and new or modified terms in the
Glossary of Terms Used in NERC Reliability Standards, and directing modifications to the CIP Reliability Standards.
Among others, the Commission directed the North American Electric Reliability Corporation (NERC) to “develop
modifications to the CIP Reliability Standards to require Responsible Entities 1 to implement controls to protect, at a
minimum, communication links and sensitive bulk electric system data communicated between bulk electric system
Control Centers in a manner that is appropriately tailored to address the risks posed to the bulk electric system by
the assets being protected (i.e., high, medium, or low impact).” (Order 822, Paragraph 53)
In response to the directive in Order No. 822, the Project 2016-02 standard drafting team (SDT) drafted Reliability
Standard CIP-012-1 to require Responsible Entities to implement controls to protect sensitive Bulk Electric System
(BES) data and communications links between BES Control Centers. Due to the sensitivity of the data being
communicated between Control Centers, as defined in the Glossary of Terms Used in NERC Reliability Standards, the
standard applies to all impact levels (i.e., high, medium, or low impact).
Although the Commission directed NERC to develop modifications to CIP-006, the SDT determined that modifications
to CIP-006 would not be appropriate. There are differences between the plan(s) required to be developed and
implemented for CIP-012-1 and the protection required in CIP-006-6 Requirement R1 Part 1.10. CIP-012-1
Requirements R1 and R2 protect the applicable data during transmission between two separate Control Centers. CIP006-6 Requirement R1 Part 1.10 protects nonprogrammable communication components within an Electronic
Security Perimeter (ESP) but outside of a Physical Security Perimeter (PSP). The transmission of applicable data
between Control Centers takes place outside of an ESP. Therefore, the protection contained in CIP-006-6
Requirement R1 Part 1.10 does not apply.
The SDT drafted requirements to provide Responsible Entities the latitude to protect the communication links, the
data, or both to satisfy the security objective consistent with the capabilities of the Responsible Entity’s operational
environment.
CIP-012 Exemption (4.2.3) for certain Control Centers
In the process of drafting CIP-012, the SDT became aware of certain generating plant or Transmission substation
situations where such field assets could be dual-classified as Control Centers based on the current Control Center
definition. Their communications to their BA or TOP Control Centers, however, are not included in the intended
scope of CIP-012. This is because the communications do not differ from those of any other generating plant or
substation. The SDT wrote an exemption (Section 4.2.3 within CIP-012) for this particular scenario which is
described in further detail below.
I

1

As used in the CIP Standards, a Responsible Entity refers to the registered entities subject to the CIP Standards.
NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1| August 2018
iv

Introduction

Figure 1
Figure 1 presents a typical scenario with two Control Centers communicating (in this instance Entity C’s RC Control
Center and Entity A’s TOP Control Center). The communication between them is the intended scope of CIP-012’s
requirements if they meet the types of data inclusions and exclusions within the standard. The TOP Control Center
is communicating with an RTU at two of Entity B’s generating plants (Stations Alpha and Beta). Those RTU’s are
gathering information from each generating unit’s control system. Each generating unit at each plant has an HMI
(Human/Machine Interface; an operator workstation) that the local personnel use to operate their respective units.

Entity B decides that the generating unit at Station Beta, a small peaking facility, will only have an
operator on site during the day. The operator at Station Alpha should be able to remotely start the unit at

NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1| August 2018
v

Introduction

Station Beta if necessary.

Figure 2
In Figure 2, Entity B installs a dedicated communications circuit from the control system on Station Beta’s control
system and puts a dedicated HMI at Station Alpha operator use. Station Alpha is now “one or more facilities hosting
operating personnel that monitor and control the BES in real time to perform the reliability tasks of…a Generator
Operator for generation Facilities at two or more locations” Because stations Alpha and Beta are two different plant
locations. Station Alpha can now be dual-classified not only as a generation resource but also as a Control Center.
The communications to the TOP and RC Control Centers in Figure 1 have not changed. No new cyber systems are in
place that can impact multiple units. In addition, no cyber systems have been added performing Control Center
functions. The only change is that an HMI for Station Beta has been moved within close physical proximity to an HMI
for Station Alpha.

NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1| August 2018
vi

Introduction

Figure 3
Although nothing has changed between them, this proximity makes the communication noted in Figure 3 between
Station Alpha and Entity A’s TOP Control Center subject to CIP-012 without the exemption. Two HMIs have been
moved into the same room and a new NERC CIP standard applies to two entities.
This is an anomaly of the current Control Center definition of a facility, room, or building from which certain functions
can be performed without regard to how they are done or what systems they are using. This is a generation specific
example, but the potential situation exists where there are substations with an HMI or protective relay that
“operating personnel” within the substation could use to impact an adjacent substation. It is also clear that in the
criteria for TO’s and GOP’s the “two or more locations” is not a precise enough filter for defining what a Control
Center truly is. The SDT’s attempts to address this issue by clarifying the definition of Control Center pointed out
larger issues that are not within the SDT’s SAR to address at this time. Accordingly, the SDT is handling the issue
through the 4.2.3 exemption within the CIP-012 standard which reads:
4.2.3. A Control Center g that transmits to another Control Center the transmitting Control Center.
The intent of this exemption is to exclude from CIP-012 the normal RTU-style communication from a field asset
providing that field asset’s status. Throughout this scenario or others like it, that communication has not changed
and is still the same data pertaining only to the single location. The SDT recognizes that this communication is not
the intent of the standard for protecting communications between Control Centers and this type of
communications can be using older legacy communication technology and protocols.
The 4.2.3 exemption covers generation resources or Transmission station or substation locations that host
operating personnel and can control BES Facilities at more than one location, possibly making them co-located
Control Centers. The communication is exempt if each location is communicating the Real-time Assessment or Realtime monitoring data with another Control Center pertaining only to that location.

NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1| August 2018
vii

Introduction

The above diagrams were generation specific. The following diagram is a more generic example:

Figure 4
In Figure 4, each location is communicating only the Real-time Assessment or Real-time monitoring data pertaining
to that single location. The communication from Entity B location one (1) to Entity A would be exempt from CIP012-1.
If Location 2 communicates its data through Location 1,and Location 1 was both controlling and aggregating data
from multiple locations to Entity A’s TOP Control Center, the communication between Location 1 and Entity A’s TOP
Control Center would not be exempt from CIP-012.

NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1| August 2018
viii

Requirement R1
R1. The Responsible Entity shall implement, except under CIP Exceptional Circumstances, one or more
documented plan(s) to mitigate the risks posed by unauthorized disclosure and unauthorized
modification of Real-time Assessment and Real-time monitoring data while being transmitted
between any applicable Control Centers. The Responsible Entity is not required to include oral
communications in its plan. The plan shall include: [Violation Risk Factor: Medium] [Time Horizon:
Operations Planning]
1.1

Identification of security protection used to mitigate the risks posed by unauthorized disclosure
and unauthorized modification of Real-time Assessment and Real-time monitoring while being
transmitted between Control Centers;

1.2

Identification of where the Responsible Entity applied security protection for transmitting Realtime Assessment and Real-time monitoring data between Control Centers; and

1.3

If the Control Centers are owned or operated by different Responsible Entities, identification of
the responsibilities of each Responsible Entity for applying security protection to the
transmission of Real-time Assessment and Real-time monitoring data between those Control
Centers.

General Considerations for Requirement R1
Requirement R1 focuses on implementing a documented plan to protect information that is critical to the Real-time
operations of the Bulk Electric System while in transit between applicable Control Centers. The SDT does not intend
for the listed order of the three requirement parts to convey any sequence or significance.
Overview of confidentiality and integrity
The SDT drafted CIP-012-1 to address confidentiality and integrity of Real-time Assessment and Real-time monitoring
data. This is accomplished by drafting the requirement to mitigate the risks posed by unauthorized disclosure
(confidentiality) and unauthorized modification (integrity). For this Standard, the SDT relied on the definitions of
confidentiality and integrity as defined by National Institute of Standards and Technology (NIST):
•

Confidentiality is defined as, “Preserving authorized restrictions on information access and disclosure,
including means for protecting personal privacy and proprietary information.” 2

•

Integrity is defined as, “Guarding against improper information modification or destruction, and includes
ensuring information non-repudiation and authenticity.” 3

The SDT asserts that the availability of this data is already required by the performance obligation of the Operating
and Planning Reliability Standards. The SDT drafted CIP-012-1 to address the data while being transmitted. The SDT
maintains that this data resides within BES Cyber Systems, and while at rest is protected by CIP-003-6 through CIP011-2.
Alignment with IRO and TOP standards
The SDT recognized the FERC reference to additional Reliability Standards and the responsibilities to protect the
applicable data in accordance with NERC Reliability Standards TOP-003 and IRO-010. The SDT used these references
to drive the identification of sensitive BES data and chose to base the CIP-012-1 requirements on the Real-time data
2
3

NIST Special Publication 800-53A, Revision 4, page B-3
NIST Special Publication 800-53A, Revision 4, page B-6
NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1| August 2018
1

Requirement R1

specification elements in these standards. This approach provides consistent scoping of identified data, and does not
require each entity to devise its own list or inventory of this data. Many entities are required to provide this data
under agreements executed with their RC, BA or TOP. Data requiring protection in CIP-012-1 consists of a subset of
data that is identified by the RC, BA, and TOP in the TOP-003 and IRO-010 data specification standards, limited to
Real-time Assessment data and Real-time monitoring data. CIP-012-1 excludes other data typically transferred
between Control Centers such as Operational Planning Analysis data, weather data, market data, and other data that
is not used by the RC, BA, and TOP to perform Real-time reliability assessments and analysis identified in TOP-003
and IRO-010. The SDT determined that Operational Planning Analysis data, if rendered unavailable, degraded, or
misused, would not adversely impact the reliable operation of the BES within 15 minutes of the activation or exercise
of the compromise as detailed in CIP-002- 5.1a. The SDT notes that there may be special instances during which Realtime Assessment or Real-time monitoring data is not identified by the RC, BA, or TOP. This would include data that
may be exchanged between a Responsible Entity’s primary and backup Control Center.
Identification of Where Security Protection is Applied by the Responsible Entity
The SDT noted the need for a Responsible Entity to identify where it will apply protection for applicable data. The
SDT did not specify the location where CIP-012-1 security protection must be applied. This allows latitude for
Responsible Entities to implement the security controls in a manner best fitting their individual circumstances. This
latitude ensures entities can still take advantage of security measures, such as deep packet inspection implemented
at or near the EAP when ESPs are present, while maintaining the capability to protect the applicable data being
transmitted between Control Centers.
The SDT also recognizes that CIP-012 security protection may be applied to a Cyber Asset that is not an identified BES
Cyber Asset, Protected Cyber Asset, or EACMS. The identification of the Cyber Asset as the location where security
protection is applied does not expand the scope of Cyber Assets identified as applicable under Cyber Security
Standards CIP-002 through CIP-011.
The SDT understands that in data exchanges between Control Centers, a single entity may not be responsible for both
ends of the communication link. The SDT intends for a Responsible Entity to identify only where it applied security
protection. The Responsible Entity should not be held accountable for identifying where a neighboring entity applied
security protection at the neighboring entity’s facility. A Responsible Entity, however, may decide to take
responsibility for both ends of a communication link. For example, it may place a router in a neighboring entity’s data
center. In a scenario where a Responsible Entity has taken responsibility for applying security protection on both ends
of the communication link, the Responsible Entity should identify where it applied security protection at both ends
of the link. The SDT intends for there to be alignment between the identification of where security protection is
applied in CIP-012-1 Requirement R1, Part 1.2 and the identification of Responsible Entity responsibilities in CIP-0121 Requirement R1, Part 1.3.
Control Center Ownership
The standard requirements address protection for Real-time Assessment and Real-time monitoring data while being
transmitted between Control Centers owned by a single Responsible Entity. They also cover the applicable data
transmitted between Control Centers owned by two or more separate Responsible Entities. Unlike protection
between a single Responsible Entity’s Control Centers, applying protection between Control Centers owned by more
than one Responsible Entity requires additional coordination. The requirements do not explicitly require formal
agreements between Responsible Entities partnering for protection of applicable data. It is strongly recommended,
however, that these partnering entities develop agreements, or use existing ones, to define responsibilities to ensure
the security objective is met. An example noted in FERC Order No. 822 Paragraph 59 is, “if several registered entities
have joint responsibility for a cryptographic key management system used between their respective Control Centers,
they should have the prerogative to come to a consensus on which organization administers that particular key
management system."
NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1| August 2018
2

Requirement R1

As an example, Figure 5 shows several data transmissions between Control Centers that a Responsible Entity should
consider to be in-scope. The example does not include all possible scenarios. The solid green lines are in-scope
communications and the dashed red lines are out-of-scope communications.

Figure 5: This reference model is an example and does not include all possible scenarios.
The SDT included Part 1.3 of the plan to address the situation when multiple registered entities are involved with
protecting the data transmitted between Control Centers. Part 1.3 provides a mechanism to specify which entity is
responsible for the application of security controls. The SDT included this requirement part to address security
concerns as well as audit concerns. Where data is transmitted between different entities, the SDT asserts that it is
necessary for both entities to understand the responsibilities of applying security controls to ensure the data is
protected through its entire transmission and there is no security gap. The SDT also asserts this requirement part will
provide evidence which may prevent the simultaneous auditing of multiple entities for each communication link
between Control Centers when operated by different Responsible Entities. Security controls applied by the entity to
achieve compliance with Parts 1.1 and 1.2 of the plan should correlate to the documented responsibilities in Part 1.3
of the entity’s plan.

NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1| August 2018
3

References
Here are several references to assist entities in developing plan(s) for protection of communication links:
•

NIST Special Publication 800-53A, Revision 4: Security and Privacy Controls for Federal Information Systems
and Organizations

•

NIST Special Publication 800-82: Guide to Industrial Control Systems (ICS) Security

•

NIST Special Publication 800-175B: Guideline for Using Cryptographic Standards in the Federal Government:
Cryptographic Mechanisms

•

NIST Special Publication 800-47: Security Guide for Interconnecting Information Technology Systems

NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1| August 2018
4

DRAFT

Cyber Security –
Communications between
Control Centers
Technical Rationale and Justification for
Reliability Standard CIP-012-1

July August 2018

NERC | Report Title | Report Date
I

Table of Contents
Preface ........................................................................................................................ Error! Bookmark not defined.
Introduction .............................................................................................................................................................. iv
Requirement R1 ......................................................................................................................................................... 1
General Considerations for Requirement R1...................................................................................................... 1
Overview of confidentiality and integrity ........................................................................................................... 1
Alignment with IRO and TOP standards ............................................................................................................. 1
Identification of Where Security Protection is Applied by the Responsible Entity ............................................ 2
Control Center Ownership .................................................................................................................................. 2
References.................................................................................................................................................................. 4

NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1| May August 2018
ii

Preface
The vision for the Electric Reliability Organization (ERO) Enterprise, which is comprised of the North American
Electric Reliability Corporation (NERC) and the seven Regional Entities (REs), is a highly reliable and secure North
American bulk power system (BPS). Our mission is to assure the effective and efficient reduction of risks to the
reliability and security of the grid.
The North American BPS is divided into seven RE boundaries as shown in the map and corresponding table below.
The multicolored area denotes overlap as some load-serving entities participate in one Region while associated
Transmission Owners/Operators participate in another.

FRCC

Florida Reliability Coordinating Council

MRO

Midwest Reliability Organization

NPCC

Northeast Power Coordinating Council

RF

ReliabilityFirst

SERC

SERC Reliability Corporation

Texas RE

Texas Reliability Entity

WECC

Western Electricity Coordinating Council

NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1| May August 2018
iii

Introduction
This document explains the technical rationale and justification for the proposed Reliability Standard CIP-012-1. It
will provide stakeholders and the ERO Enterprise with an understanding of the technology and technical
requirements in the Reliability Standard. It also contains information on the SDT’s intent in drafting the
requirements. This Technical Rationale and Justification for CIP-012-1 is not a Reliability Standard and should not be
considered mandatory and enforceable.
On January 21, 2016, the Federal Energy Regulatory Commission (FERC or Commission) issued Order No. 822,
approving seven Critical Infrastructure Protection (CIP) Reliability Standards and new or modified terms in the
Glossary of Terms Used in NERC Reliability Standards, and directing modifications to the CIP Reliability Standards.
Among others, the Commission directed the North American Electric Reliability Corporation (NERC) to “develop
modifications to the CIP Reliability Standards to require Responsible Entities 1 to implement controls to protect, at a
minimum, communication links and sensitive bulk electric system data communicated between bulk electric system
Control Centers in a manner that is appropriately tailored to address the risks posed to the bulk electric system by
the assets being protected (i.e., high, medium, or low impact).” (Order 822, Paragraph 53)
In response to the directive in Order No. 822, the Project 2016-02 standard drafting team (SDT) drafted Reliability
Standard CIP-012-1 to require Responsible Entities to implement controls to protect sensitive Bulk Electric System
(BES) data and communications links between BES Control Centers. Due to the sensitivity of the data being
communicated between Control Centers, as defined in the Glossary of Terms Used in NERC Reliability Standards,
the standard applies to all impact levels (i.e., high, medium, or low impact).
Although the Commission directed NERC to develop modifications to CIP-006, the SDT determined that
modifications to CIP-006 would not be appropriate. There are differences between the plan(s) required to be
developed and implemented for CIP-012-1 and the protection required in CIP-006-6 Requirement R1 Part 1.10. CIP012-1 Requirements R1 and R2 protect the applicable data during transmission between two separate Control
Centers. CIP-006-6 Requirement R1 Part 1.10 protects nonprogrammable communication components within an
Electronic Security Perimeter (ESP) but outside of a Physical Security Perimeter (PSP). The transmission of
applicable data between Control Centers takes place outside of an ESP. Therefore, the protection contained in CIP006-6 Requirement R1 Part 1.10 does not apply.
The SDT drafted requirements to provide Responsible Entities the latitude to protect the communication links, the
data, or both to satisfy the security objective consistent with the capabilities of the Responsible Entity’s operational
environment.
CIP-012 Exemption (4.2.3) for certain Control Centers
As the SDTIn the process of draftinged CIP-012, ithe SDT became aware of certain generating plant or Transmission
substation situations where such field assets could be dual-classified as Control Centers based on the current
Control Center definition. However, tTheir communications to their normal BA or TOP Control Centers, however,
are not included in are not the type of communications that are the intended scope of CIP-012. This is because the
communications as they do not differ from those of any other generating plant or substation. The SDT wrote an
exemption (Section 4.2.3 within CIP-012) for this particular scenario which is described in further detail below.
I

1

As used in the CIP Standards, a Responsible Entity refers to the registered entities subject to the CIP Standards.
NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1| May August 2018
iv

Introduction

Figure 1
Figure 1 above pictures presents a typical scenario with two Control Centers communicating (in this instance Entity
C’s RC Control Center and Entity A’s TOP Control Center). The communication between them is the intended scope
of CIP-012’s requirements if it they meets the types of data inclusions and exclusions within the standard. The TOP
Control Center is communicating with an RTU at two of Entity B’s generating plants (Stations Alpha and Beta). and
tThose RTU’s are gathering information from each generating unit’s control system. Each generating unit at each
plant has an HMI (Human/Machine Interface; an operator workstation) that the local personnel use to operate their
respective units.

Entity B decides that the generating unit at Station Beta, a small peaking facility, will only have an
operator on site during the day. and tThe operator at Station Alpha should be able to remotely start the

NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1| May August 2018
v

Introduction

unit at Station Beta if necessary.

Figure 2
In Figure 2, Entity B installs a dedicated communications circuit from the control system on Station Beta’s control
system and puts a dedicated HMI at Station Alpha the operator can use. Station Alpha is now “one or more facilities
hosting operating personnel that monitor and control the BES in real time to perform the reliability tasks of…a
Generator Operator for generation Facilities at two or more locations.” Because stations Alpha and Beta are two
different plant locations. Station Alpha It can now be dual-classified not only as a generation resource but also as a
Control Center.
The communications to the TOP and RC Control Centers from in Figure 1 have not changed at all. No new cyber
systems are in place that can impact multiple units. In addition, Nno cyber systems have been added performing
Control Center functions. No additional risk from cyber systems has been added. The only thing that has changed is
that an HMI for Station Beta has been moved within close physical proximity to an HMI for Station Alpha.

NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1| May August 2018
vi

Introduction

Figure 3
The SDT realized how this suddenly makes Although nothing has changed between them, this proximity makes the
communication noted in Figure 3 between Station Alpha and Entity A’s TOP Control Center subject to CIP-012
although nothing has changed between themwithout the exemption. There is no new risk involved. Two HMI’s have
been moved into the same room and suddenly a new NERC CIP standard applies to two entities.
This is an anamoly anomaly of the current Control Center definition defining of a facility, room, or building from
which something certain functions can be done performed without regard to how its they are done or with what
systems they are using. This is a generation specific example, but the SDT can envisionpotential situation exists
where there are substations with an HMI or protective relay that “operating personnel” within the substation could
use to impact an adjacent substation. The SDT realizesIt is also clear that in the criteria for TO’s and GOP’s the “two
or more geographic locations” is not a precise enough filter for capturing defining what a Control Center truly is.
The SDT’s attempts to address this issue by clarifying the definition of Control Center pointed out larger issues that
are not within the SDT’s SAR to address at this time. Therefore Accordingly, the SDT is handling the issue this
creates for CIP-012 bythrough the 4.2.3 exemption within the CIP-012 standard which reads:
4.2.3. A Control Center generation resource or Transmission station or substation that transmits to another
Control Center at which the transmitting Control Center. is located
The intent of this exemption is to exclude from CIP-012 the normal RTU-style communication from a field asset
about providing that field asset’s status from CIP-012. Throughout this scenario or others like it, that
communication has not changed and is still the same data pertaining only to the single location. The SDT recognizes
that this communication is not the intent of the standard for protecting communications between Control Centers
and this type of communications can be using older legacy communication technology and protocols.
The 4.2.3 exemption covers generation resources or Transmission station or substation locations that host
operating personnel and can control BES Facilities at more than one location, possibly making them co-located
NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1| May August 2018
vii

Introduction

Control Centers. The communication is exempt if each location is communicating the Real-time Assessment or Realtime monitoring data with another Control Center pertaining only to that location.
The above diagrams were generation specific. The following diagram is a more generic example:

Figure 4
In Figure 4, each location is communicating only the Real-time Assessment or Real-time monitoring data pertaining
to that single location. The communication from Entity B location one (1) to Entity A would be exempt from CIP012-1.
If Location 2 communicateds its data through Location 1,and Location 1 was both controlling and aggregating data
from multiple locations to Entity A’s TOP Control Center, the communication between Location 1 and Entity A’s TOP
Control Center would not be exempt from CIP-012.

NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1| May August 2018
viii

Requirement R1
R1. The Responsible Entity shall implement, except under CIP Exceptional Circumstances, one or more
documented plan(s) to mitigate the risks ofposed by unauthorized disclosure andor unauthorized
modification of Real-time Assessment and Real-time monitoring data while being transmitted
between any applicable Control Centers. The Responsible Entity is not required to include oral
communications in its plan. The plan shall include: [Violation Risk Factor: Medium] [Time Horizon:
Operations Planning]
1.1

Identification of security protection used to mitigate the risks of posed by unauthorized
disclosure andor unauthorized modification of Real-time Assessment and Real-time monitoring
while being transmitted between Control Centers;

1.2

Identification of where the Responsible Entity applied security protection for transmitting Realtime Assessment and Real-time monitoring data between Control Centers; and

1.3

If the Control Centers are owned or operated by different Responsible Entities, identification ofy
the responsibilities of each Responsible Entity for applying security protection to the
transmission of Real-time Assessment and Real-time monitoring data between those Control
Centers.

General Considerations for Requirement R1
Requirement R1 focuses on implementing a documented plan to protect information that is critical to the Real-time
operations of the Bulk Electric System while in transit between applicable Control Centers. The SDT does not intend
for the listed order of the three requirement parts to convey any sequence or significance.
Overview of confidentiality and integrity
The SDT drafted CIP-012-1 to address confidentiality and integrity of Real-time Assessment and Real-time
monitoring data. This is accomplished by drafting the requirement to mitigate the risks of posed by unauthorized
disclosure (confidentiality) or and unauthorized modification (integrity). For this Standard, the SDT relied on the
definitions of confidentiality and integrity as defined by National Institute of Standards and Technology (NIST):
•

Confidentiality is defined as, “Preserving authorized restrictions on information access and disclosure,
including means for protecting personal privacy and proprietary information.” 2

•

Integrity is defined as, “Guarding against improper information modification or destruction, and includes
ensuring information non-repudiation and authenticity.” 3

The SDT asserts that the availability of this data is already required by the performance obligation of the Operating
and Planning Reliability Standards. The SDT drafted CIP-012-1 to address the data while being transmitted. The SDT
maintains that this data resides within BES Cyber Systems, and while at rest is protected by CIP-003-6 through CIP011-2.
Alignment with IRO and TOP standards
The SDT recognized the FERC reference to additional Reliability Standards and the responsibilities to protect the
applicable data in accordance with NERC Reliability Standards TOP-003 and IRO-010. The SDT used these references
to drive the identification of sensitive BES data and chose to base the CIP-012-1 requirements on the Real-time data
2
3

NIST Special Publication 800-53A, Revision 4, page B-3
NIST Special Publication 800-53A, Revision 4, page B-6
NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1| May August 2018
1

0 Requirement R1

specification elements in these standards. This approach provides consistent scoping of identified data, and does
not require each entity to devise its own list or inventory of this data. Many entities are required to provide this
data under agreements executed with their RC, BA or TOP. Data requiring protection in CIP-012-1 consists of a
subset of data that is identified by the RC, BA, and TOP in the TOP-003 and IRO-010 data specification standards,
limited to Real-time Assessment data and Real-time monitoring data. CIP-012-1 excludes other data typically
transferred between Control Centers such as Operational Planning Analysis data, weather data, market data, and
other data that is not used by the RC, BA, and TOP to perform Real-time reliability assessments and analysis
identified in TOP-003 and IRO-010. The SDT determined that Operational Planning Analysis data, if rendered
unavailable, degraded, or misused, would not adversely impact the reliable operation of the BES within 15 minutes
of the activation or exercise of the compromise as detailed in CIP-002- 5.1a. However, tThe SDT notesd that there
may be special instances during which Real-time Assessment or Real-time Monitoring monitoring data is not
identified by the RC, BA, or TOP. This would include data that may be exchanged between a Responsible Entity’s
primary and backup Control Center.
Identification of Where Security Protection is Applied by the Responsible Entity
The SDT noted the need for a Responsible Entity to identify where it will apply protection for applicable data. The
SDT did not specify the location where CIP-012-1 security protection must be applied. This allows to provide
latitude for Responsible Entities to implement the security controls in a manner best fitting their individual
circumstances. This latitude ensures entities can still take advantage of security measures, such as deep packet
inspection implemented at or near the EAP when ESPs are present, while maintaining the capability to protect the
applicable data being transmitted between Control Centers.
The SDT also recognizes that CIP-012 security protection may be applied to a Cyber Asset that is not an identified
BES Cyber Asset, Protected Cyber Asset, or EACMS. The identification of the Cyber Asset as the location where
security protection is applied does not expand the scope of Cyber Assets identified as applicable under Cyber
Security Standards CIP-002 through CIP-011.
The SDT understands that in data exchanges between Control Centers, a single entity may not be responsible for
both ends of the communication link. The SDT intends for a Responsible Entity to identify only where it applied
security protection. The Responsible Entity should not be held accountable for identifying where a neighboring
entity applied security protection at the neighboring entity’s facility. A Responsible Entity, however, may decide to
take responsibility for both ends of a communication link. For example, it may place a router in a neighboring
entity’s data center. In a scenario like this, where a Responsible Entity has taken responsibility for applying security
protection on both ends of the communication link, the Responsible Entity should identify where it applied security
protection at both ends of the link. The SDT intends for there to be alignment between the identification of where
security protection is applied in CIP-012-1 Requirement R1, Part 1.2 and the identification of Responsible Entity
responsibilities in CIP-012-1 Requirement R1, Part 1.3.
Control Center Ownership
The standard requirements address protection for Real-time Assessment and Real-time monitoring data while
being transmitted between Control Centers owned by a single Responsible Entity. They also cover the applicable
data transmitted between Control Centers owned by two or more separate Responsible Entities. Unlike protection
between a single Responsible Entity’s Control Centers, applying protection between Control Centers owned by
more than one Responsible Entity requires additional coordination. The requirements do not explicitly require
formal agreements between Responsible Entities partnering for protection of applicable data. It is strongly
recommended, however, that these partnering entities develop agreements, or use existing ones, to define
responsibilities to ensure the security objective is met. An example noted in FERC Order No. 822 Paragraph 59 is, “if
several registered entities have joint responsibility for a cryptographic key management system used between their

NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1| May August 2018
2

0 Requirement R1

respective Control Centers, they should have the prerogative to come to a consensus on which organization
administers that particular key management system."
As an example, the reference model belowFigure 5 shows severalsome of the data transmissions between Control
Centers that a Responsible Entity should consider to be in-scope. The example does not include all possible
scenarios. The solid green lines are in-scope communications and. Tthe dashed red lines are out-of-scope
communications.

Figure 5: This reference model is an example and does not include all possible scenarios.
The SDT included pPart 1.3 of the plan to address the situation when multiple registered entities are involved with
protecting the data transmitted between Control Centers. Part 1.3 provides a mechanism to specify which entity is
responsible for the application of security controls. The SDT included this requirement part to address security
concerns as well as audit concerns. Where data is transmitted between different entities, the SDT asserts that it is
necessary for both entities to understand the responsibilities of applying security controls to ensure the data is
protected through its entire transmission and there is no security gap. The SDT also asserts this requirement part
will provide evidence which may prevent the simultaneous auditing of multiple entities for each communication
link between Control Centers when operated by different Responsible Entities. Security controls applied by the
entity to achieve compliance with pParts 1.1 and 1.2 of the plan should correlate to the documented
responsibilities in pPart 1.3 of the entity’s plan.

NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1| May August 2018
3

References
Here are several references to assist entities in developing plan(s) for protection of communication links:
•

NIST Special Publication 800-53A, Revision 4: Security and Privacy Controls for Federal Information Systems
and Organizations

•

NIST Special Publication 800-82: Guide to Industrial Control Systems (ICS) Security

•

NIST Special Publication 800-175B: Guideline for Using Cryptographic Standards in the Federal
Government: Cryptographic Mechanisms

•

NIST Special Publication 800-47: Security Guide for Interconnecting Information Technology Systems

NERC | Technical Rationale and Justification for Relaibility Standard CIP-012-1| May August 2018
4

DRAFT Implementation Guidance
Pending Submittal for ERO Enterprise Endorsement

Cyber Security –
Communications
Between Control
Centers
Implementation Guidance for CIP-012-1

NERC | Report Title | Report Date
I

Table of Contents
Introduction ................................................................................................................................................................3
Requirements .............................................................................................................................................................4
General Considerations ..............................................................................................................................................5
Plan Development ...............................................................................................................................................5
Identification of Real-time Assessment and Real-time monitoring data ............................................................5
Identification of Security Protection ...................................................................................................................5
Identification of Where Security Protection is Applied by the Responsible Entity.............................................6
Reference Model ........................................................................................................................................................7
Reference Model Discussion ...............................................................................................................................7
Identification of Security Protection ...................................................................................................................8
Identification of Where Security Protection is Applied by the Responsible Entity.............................................9
Identification of Responsibilities when the Control Centers are Owned or Operated by Different Responsible
Entities.................................................................................................................................................................9
References ............................................................................................................................................................... 12

NERC | DRAFT CIP-012-1 Implementation Guidance | August 2018
2

Introduction
The Project 2016-02 SDT drafted this Implementation Guidance to provide example approaches for compliance
with CIP-012-1. Implementation Guidance does not prescribe the only approach, but highlights one or more
approaches that would be effective in achieving compliance with the standard. Because Implementation Guidance
only provides examples, entities may choose alternative approaches that better fit their individual situations 1.
Responsible Entities may find it useful to consider this Implementation Guidance document along with the
additional context and background provided in the SDT-developed Technical Rationale and Justification for CIP012-1 document.

Background

The Commission issued Order No. 822 on January 21, 2016. Order 822 approving seven CIP Reliability Standards
and new or modified definitions, and directed modifications be made to the CIP Reliability Standards. Among
other items, the Commission directed NERC to “develop modifications to the CIP Reliability Standards to require
responsible entities to implement controls to protect, at a minimum, communication links and sensitive bulk
electric system data communicated between bulk electric system Control Centers in a manner that is
appropriately tailored to address the risks posed to the bulk electric system by the assets being protected (i.e.,
high, medium, or low impact).” (Order 822, Paragraph 53)
In response to the directive in Order No. 822, the Project 2016-02 standard drafting team (SDT) drafted Reliability
Standard CIP-012-1 to require Responsible Entities to implement controls to protect sensitive Bulk Electric System
(BES) data and communications links between BES Control Centers. Due to the sensitivity of the data being
communicated between Control Centers, the standard applies to all impact levels (i.e., high, medium, or low
impact).
The SDT drafted requirements to provide Responsible Entities the latitude to protect the communication links,
the data, or both, to satisfy the security objective consistent with the capabilities of the Responsible Entity’s
operational environment.

1

NERC’s Compliance Guidance Policy
NERC | DRAFT CIP-012-1 Implementation Guidance | August2018
3

Requirements
R1.

The Responsible Entity shall implement, except under CIP Exceptional Circumstances, one or
more documented plan(s) to mitigate the risks posed by unauthorized disclosure and
unauthorized modification of Real-time Assessment and Real-time monitoring data while being
transmitted between any applicable Control Centers. The Responsible Entity is not required to
include oral communications in its plan. The plan shall include: [Violation Risk Factor: Medium]
[Time Horizon: Operations Planning]
1.1. Identification of security protection used to mitigate the risks posed by unauthorized
disclosure and unauthorized modification of Real-time Assessment and Real-time
monitoring data while being transmitted between Control Centers;
1.2. Identification of where the Responsible Entity applied security protection for transmitting
Real-time Assessment and Real-time monitoring data between Control Centers; and
1.3. If the Control Centers are owned or operated by different Responsible Entities,
identification of the responsibilities of each Responsible Entity for applying security
protection to the transmission of Real-time Assessment and Real-time monitoring data
between those Control Centers.

NERC | DRAFT CIP-012-1 Implementation Guidance | August2018
4

General Considerations
Plan Development
As noted in the Technical Rationale and Justification for CIP-012-1, the focus of Requirement R1 is implementing
a documented plan to protect information that is critical to the real-time operations of the Bulk Electric System
while in transit between applicable Control Centers. The number of plan(s) and their content may vary depending
on a Responsible Entity's management structure and operating conditions. The Responsible Entity may document
as many plans as necessary to meet its needs. For instance, a Responsible Entity may choose to document one
plan per Control Center or choose an all-inclusive, single plan for its Control Center communication environment.
A Responsible Entity may choose to document one plan for communications between Control Centers it owns and
a separate plan for communications between its Control Centers and the Control Centers of a neighboring Entity.
The number and structure of the plans is at the discretion of the Responsible Entity as long as the plan(s) include
the required elements described in Parts 1.1, 1.2, and 1.3 of Requirement R1.
Identification of Real-time Assessment and Real-time monitoring data
Responsible Entities can expect to receive or have received requests for Operations Planning Analysis, Real-time
Assessment and Real-time monitoring data from their RC(s), BA(s) and TOP(s). These data requests, pursuant to
the data specification from TOP-003 and IRO-010 requirements, may also include other types of data under the
same request. CIP-012 requires protection only for Real-time Assessment and Real-time monitoring data. If the
provided data specification does not indicate which data is Real-time Assessment and Real-time monitoring
data, Responsible Entities could choose to conduct an assessment to identify this data from among the other
data requested or being communicated. Once a data assessment is completed, the Responsible Entity should
confirm its findings with the other communicating entity before applying security controls. If the Real-time
Assessment and Real-time monitoring data is not clearly identified in the provided data specification, the
Responsible Entity should document the methodology used and all actions taken to identify the Real-time
Assessment and Real-time monitoring data.
Identification of Security Protection
Entities have latitude to identify and choose which security protection is used to mitigate the risks posed by
unauthorized disclosure and unauthorized modification of Real-time Assessment and Real-time monitoring data
while being transmitted between Control Centers.
This security protection could consist of logical protection, physical protection, or some combination of both. To
determine security protection, the requirement specifies that it must mitigate the risks posed by unauthorized
disclosure and unauthorized modification of applicable data.
Security protection implementation can be demonstrated in many ways. If a Responsible Entity uses physical
protection, it may demonstrate implementation through review of an applicable Control Center floor plan with
details subsequently confirmed through visual inspection, which identifies the physical security measures in place
protecting the communication link. If the Responsible Entity uses logical protection, it may demonstrate
implementation through an export of the device configuration which applies the security protection. Alternatively,
a Responsible Entity may demonstrate implementation through security control monitoring, using an automated
monitoring tool to generate reports on the encryption service used to protect a communications link. Where the
operational obligations of an entire communication link, including both endpoints, belong to the Control Center
of another Responsible Entity, the Responsible Entity without operational obligations for the communication link
may demonstrate compliance by ensuring the communications link endpoint is within its Control Center, which
could be limited to including the communication link endpoint within a PSP or where other physical protection is
applied.

NERC | DRAFT CIP-012-1 Implementation Guidance | August2018
5

Identification of Where Security Protection is Applied by the Responsible Entity
A Responsible Entity should consider its environment when identifying where security protections should be
applied. One approach is to implement security within the Control Center itself to ensure that data confidentiality
and integrity is protected throughout the transmission. The Responsible Entity can identify where security
protection is applied using a logical or physical location The application of security in accordance with CIP-012
requirements does not add additional assets to the scope of the CIP Reliability Standards. Locations of applied
security protection may vary based on many factors such as impact levels of the Control Center, different
technologies, or infrastructures. Where the operational obligations of an entire communication link, including
both endpoints, belong to the Control Center of another Responsible Entity, the Responsible Entity without
operational obligations for the communication link may demonstrate compliance by ensuring the communications
link endpoint is within its Control Center, which could be limited to including the communication link endpoint
within a PSP or where other physical protection is applied.
Identification of where a Responsible Entity applies security protection could be demonstrated with a list or a
Control Center diagram showing either physical or logical security controls. Physical diagrams may require visual
confirmation of these controls. These diagrams or a list could be included within the plan developed for R1. A
Responsible Entity could also use labels to identify on-site devices where CIP-012 security protection is applied.
When exchanging data between two entities, if a Responsible Entity only manages one end of a communication
link, the Responsible Entity is not responsible for identifying where the security protection is applied by the
neighboring entity with which it is exchanging data. However, if a Responsible Entity has taken responsibility for
both ends of the communication link (such as by placing a router within the neighboring entity’s data center), then
the Responsible Entity shall identify where the security protection is applied at both ends of the link.
Similarly, if a Responsible Entity owns and operates both Control Centers which are exchanging data (such as in
the case of a primary and backup Control Center), then the Responsible Entity shall identify where security
protection is applied at both ends of the link.
Identification of Responsibilities when the Control Centers are Owned or Operated by Different
Responsible Entities

The Technical Rationale and Justification for CIP-012-1 identifies key considerations in the Control Center
Ownership section when communications between Control Centers with different owners or operators. Many
operational relationships between Responsible Entities are unique. Consequently, there is no single way to
identify responsibilities for applying security protection to the transmission of Real-time Assessment and Realtime monitoring data between Control Centers.
Implementation of responsibilities could also be demonstrated in many ways. Some examples include a joint
procedure, a memorandum of understanding, or meeting minutes between the two parties where responsibilities
are defined. These responsibilities should be included in both Responsible Entities’ plans satisfying requirement
Part 1.3.
Where the operational obligations of an entire communication link, including both endpoints, belong to the
Control Center of another Responsible Entity, the Responsible Entity without operational obligations for the
communication link may demonstrate compliance by ensuring the communications link endpoint is within its
Control Center, which could be limited to including the communication link endpoint within a PSP or where other
physical protection is applied.

NERC | DRAFT CIP-012-1 Implementation Guidance | August2018
6

Reference Model
For this Implementation Guidance, the SDT uses a basic reference model of Primary and Backup Control Centers
(Entity Alpha) to illustrate approaches to demonstrating compliance. These Control Centers communicate to each
other and to a neighboring entity’s Control Center (Entity Beta) in configurations outlined by the diagrams in this
section. The SDT recognizes that the reference model does not contain many of the complexities of a real Control
Center. For this Implementation Guidance, the registration or functions performed in the reference model Control
Center are also not considered. A high level block diagram of the basic reference model is shown below in Figure
1. This Implementation Guidance is developed from the perspective of Entity Alpha.

Entity Alpha’s Primary
Control Center

Communication between Entity Alpha’s
Primary and Backup Control Center

Communication between Entity Alpha’s
Primary Control Center and Entity Beta’s Control Center

Entity Alpha’s Backup
Control Center

Communication between Entity Alpha’s
Backup Control Center and Entity Beta’s Control Center

Entity Beta’s Control
Center

Figure 1: High Level Block Diagram of Reference Model Control Centers

Reference Model Discussion
Requirement R1 requires the implementation of a documented plan. To comply with requirement R1, one
approach to a plan is to first determine which communications are in scope of CIP-012-1. There are multiple ways
to identify an entity’s scope in R1. For example, Entity Alpha in the reference model may first identify the Control
Centers with which it communicates. Entity Alpha would determine that there are three: Entity Alpha’s Primary
Control Center, Entity Alpha’s Backup Control Center, and Entity Beta’s Control Center. Entity Alpha does not need
to consider whether Entity Beta further shares its data with another Entity. That is the responsibility of Entity Beta
and is outside of Entity Alpha’s purview. Additionally, Entity Alpha does not need to consider any communications
to other non-Control Center facilities such as generating plants or substations. These communications are out of
scope for CIP-012-1.
Now that Entity Alpha has identified the Control Centers with which it communicates, Entity Alpha identifies
either: (1) the Real-time Assessment and Real-time monitoring data; or (2) communication links which are used
to transmit Real-time Assessment and Real-time monitoring data between Control Centers. In either case, Entity
Alpha should refer to the data specification for Real-time Assessment and Real-time monitoring data identified in
NERC | DRAFT CIP-012-1 Implementation Guidance | August2018
7

TOP-003-3 and IRO-010-2. For this reference model scenario, identifying the communication links used to transmit
Real-time Assessment and Real-time monitoring data may be the most straightforward approach. Through an
evaluation of communication links between Control Centers and an evaluation of how it transmits and receives
Real-time Assessment and Real-time monitoring data, Entity Alpha determined that it communicates applicable
data between its primary and backup Control Centers across a single communication link. Entity Alpha also
determined that it communicates applicable data to and from Entity Beta’s Control Center across one of two links
that originate from either Entity Alpha’s primary or backup Control Center using the Inter-Control Center
Communications Protocol (ICCP).
With an identified scope of communications links, Entity Alpha now considers the three required elements of its
required communications between Control Centers for its plan.
Identification of Security Protection

2

•

Entity Alpha must ensure that protection is applied where identified in its CIP-012-1 plan. The protection
must also meet the security objective of mitigating the risks posed by unauthorized disclosure and
unauthorized modification of applicable data while in transit between Control Centers. The identification
of security protection could be demonstrated by a network diagram similar to that shown in Figure 2 or
Figure 3.

•

In a simple case where the security protection is applied sufficiently close to the Control Center, such as
within the Physical Security Perimeter of the Control Center, Entity Alpha may use a single security
protection method to meet the security objective. For this case, shown in Figure 2, Entity Alpha
implements a Virtual Private Network (VPN) connection across a private leased communication circuit for
each of its three in-scope communication links. To meet the security objective, Entity Alpha further states
that its VPN uses Internet Protocol security (IPsec) with encryption.

•

For more complex scenarios, Entity Alpha may need to use a combination of security controls. For
instance, in Figure 3, Entity Alpha uses a combination of physical security controls (physical access control)
and logical security controls (encrypted communications consistent with the first scenario above) to meet
the security objective. The SDT notes that the same technical architecture could exist where the
responsibilities of the registered entities are different. Therefore as shown in Figure 2 & 3, in the scenario
where entity Alpha owns and operationally manages the communication link and endpoint equipment,
Entity Beta is responsible for ensuring the communication endpoint of the communication link is within a
Control Center. Entity Beta ensures Entity Alpha’s communication link endpoint equipment is within a
Control Center by including the communication endpoint within a Control Center PSP. The physical
controls for the PSP are described in CIP-006 documentation and do not need to be repeated for this
requirement. This satisfies Entity Beta’s obligation for Part 1.1 and 1.2.

•

While these scenarios are all specific to communication links, it is possible that Entity Alpha and Entity
Beta achieve the security objective by applying protection to the data rather than the communication
links. In this scenario, the application enabling the data exchange between Control Centers may be
capable of applying security controls directly to the data. These security controls mitigate the risks posed
by unauthorized disclosure and unauthorized modification of applicable data rather than relying on lower
level network services to provide this security. For instance, Entity Alpha and Entity Beta may apply
security protection at the application layer by using Secure ICCP to exchange applicable data. According
to a report released by Sandia National Labs 2, Secure ICCP provides “data integrity indirectly by providing
a cryptographic checksum. Secure ICCP provides data confidentiality by encrypting ICCP data exchanges.”
Methods other than Secure ICCP could also be used to apply security protection to the data at the
application layer.

https://energy.gov/sites/prod/files/oeprod/DocumentsandMedia/19-Secure_ICCP_Integration.pdf
NERC | DRAFT CIP-012-1 Implementation Guidance | August2018
8

Identification of Where Security Protection is Applied by the Responsible Entity

Similar to the identification of security protection above, the identification of where security protection is applied
can also be demonstrated by a network diagram similar to those found in Figures 2 and 3.
•

Figure 2 shows the identification where CIP-012-1 security protection is applied for the Entity Alpha
reference model when a single encrypted tunnel is used to implement the required protection. Entity
Alpha has identified that security protection is applied at each of its Control Centers on the external
Ethernet interface on the WAN router. While the diagram depicts where Entity Beta has applied security
protection for illustrative purposes, Entity Alpha is not responsible for identifying where Entity Beta has
applied security protection.

•

In order to understand the application of security protection in context of who controls the
communication link, it may be helpful to identify both where CIP-012-1 security protection is applied and
the location of the telecommunications carrier (telco) demarcation point. Figure 3 provides such an
example where the telco demarcation point may not be within the Control Center and based the facts
and circumstances surrounding this scenario, Entity Alpha has implemented a combination of security
controls to comply with CIP-012-1. In this scenario, Entity Alpha identifies that it has applied physical
security protection for its PSP and continuing for its WAN router and that it has applied logical security
protection (encryption) at the WAN router. Entity Alpha has also identified the telco demarcation point at
a point in the telecommunications cabling connecting to Entity Alpha’s WAN router, perhaps at a punch
down block for example. In Figure 3, the telco demarcation point is inside the same room as the WAN
router. The telco demarcation points are referenced in the drawing for clarity, but are not part of the plan.

•

Figures 2 & 3 provide an example of where the operational obligations of an entire communications link,
including both endpoints, belong to Entity Alpha. In this case, Entity Beta may be responsible for ensuring
the communications endpoint of the communications link is within their Control Center. Entity Beta
ensures Entity Alpha’s communication link endpoint equipment is within a Control Center by including the
communication endpoint within a Control Center PSP. The documentation provided for Part 1.1 by Entity
Beta fulfils this obligation.

•

The data-centric scenario described above is less intuitive for identifying where security protection is
applied by Entity Alpha. If security protection is applied at the application layer (such as Secure ICCP),
Entity Alpha could reasonably identify the application or service applying the security (such as the Secure
ICCP service) as the location of where security protection is applied.

Identification of Responsibilities when the Control Centers are Owned or Operated by Different
Responsible Entities

Entity Alpha and Entity Beta may determine they each are responsible for one end of the VPN configuration on
their respective WAN routers. Entity Alpha and Entity Beta have agreed to a 30 character pre-shared key for IPSec
authentication.
Rather than use a pre-shared key, Entity Alpha and Entity Beta may decide to use digital certificates for the IPSec
authentication using a trusted certificate authority. In that scenario, Entity Alpha and Entity Beta would agree on
who is the party responsible for managing the certificate authority.
In the example where the communication link and endpoint equipment are owned by Entity Alpha, both entities
should include ownership responsibilities in their plans satisfying requirement 1.3. Examples include but are not
limited to, a letter indicating ownership or responsibility, a copy of a contract indicating ownership or
responsibilities, an excerpt from an operational agreement or manual indicating ownership or responsibility.

NERC | DRAFT CIP-012-1 Implementation Guidance | August2018
9

Entity Alpha’s Primary
Control Center

Entity Alpha’s CIP-012
security protection applied
at the external interface of
the WAN router

Entity Alpha’s CIP-012
security protection applied
at the external interface of
the WAN router

Entity Alpha’s Backup
Control Center

WAN Router

WAN Router

ESP Firewall

ESP Firewall

Operator Application Database
Workstations Server
Server

ICCP
Server

Operator Application Database
Workstations Server
Server

ICCP
Server

Communications Carrier
Entity Beta’s CIP-012
security protection applied
at the external interface of
the WAN router

Entity Beta’s
Control Center
WAN Router

ESP Firewall

Operator Application Database
Workstations Server
Server

In the case where Entity Alpha owns
and operationally manages the
communication link and endpoint
equipment, Entity Beta ensures
Entity Alpha’s endpoint equipment
is within the Control Center. Entity
Alpha includes any logical security
protection applied to the
communication link in their plan

ICCP
Server

Figure 2: Network diagram and identification of where security protection is applied

NERC | DRAFT CIP-012-1 Implementation Guidance | August2018
10

Entity Alpha’s CIP-012
physical security
protection applied

Physically secured area

Physically secured area

Entity Alpha’s Primary
Control Center

WAN Router
Entity Alpha’s CIP-012
logical security
protection applied

ESP Firewall

Entity Alpha’s Backup
Control Center

WAN Router
Telco
Demarcation
Point

Telco
Demarcation
Point

Entity Alpha’s CIP-012
physical security
protection applied

Entity Alpha’s CIP-012
logical security
protection applied

ESP Firewall

Encrypted
Communications
Operator Application Database
Workstations Server
Server

ICCP
Server

Operator Application Database
Workstations Server
Server

ICCP
Server

Communications Carrier
Entity Beta’s CIP-012
security protection
applied

Entity Beta’s
Control Center
WAN Router

ESP Firewall

Operator Application Database
Workstations Server
Server

In the case where Entity Alpha owns
and operationally manages the
communication link and endpoint
equipment, Entity Beta ensures
Entity Alpha’s endpoint equipment
is within the Control Center. Entity
Alpha includes any logical security
protection applied to the
communication link in their plan

ICCP
Server

Figure 3: Network diagram using a combination of controls for CIP-012-1

NERC | DRAFT CIP-012-1 Implementation Guidance | August2018
11

References
Mitre Common Weakness Enumeration (CWE™) list of software weakness types
https://cwe.mitre.org/data/definitions/327.html
Cryptographic Standards and Guidelines
https://csrc.nist.gov/Projects/Cryptographic-Standards-and-Guidelines
NIST Special Publication 800-175B
Guideline for Using Cryptographic Standards in the Federal Government: Cryptographic Mechanisms
http://nvlpubs.nist.gov/nistpubs/SpecialPublications/NIST.SP.800-175B.pdf
Guide to Cryptography
https://www.owasp.org/index.php/Guide_to_Cryptography#Symmetric_Cryptography

NERC | DRAFT CIP-012-1 Implementation Guidance | August2018
12

DRAFT Implementation Guidance
Pending Submittal for ERO Enterprise Endorsement

Cyber Security –
Communications
Between Control
Centers
Implementation Guidance for CIP-012-1

NERC | Report Title | Report Date
I

Table of Contents
Introduction ................................................................................................................................................................3
Requirements .............................................................................................................................................................4
General Considerations ..............................................................................................................................................5
Plan Development ...............................................................................................................................................5
Identification of Real-time Assessment and Real-time monitoring data ............................................................5
Identification of Security Protection ...................................................................................................................5
Identification of Where Security Protection is Applied by the Responsible Entity.............................................6
Reference Model ........................................................................................................................................................7
Reference Model Discussion ...............................................................................................................................7
Identification of Security Protection ...................................................................................................................8
Identification of Where Security Protection is Applied by the Responsible Entity.............................................9
Identification of Responsibilities when the Control Centers are Owned or Operated by Different Responsible
Entities.................................................................................................................................................................9
References ............................................................................................................................................................... 12

NERC | DRAFT CIP-012-1 Implementation Guidance | May August 2018
2

Introduction
The Project 2016-02 SDT drafted this Implementation Guidance to provide example approaches for compliance
with CIP-012-1. Implementation Guidance does not prescribe the only approach, but highlights one or more
approaches that would be effective in achieving compliance with the standard. Because Implementation
Guidance only provides examples, entities may choose alternative approaches that better fit their individual
situations 1.
Responsible Entities may find it useful to consider this Implementation Guidance document along with the
additional context and background provided in the SDT-developed Technical Rationale and Justification for CIP012-1 document.

Background

The Commission issued Order No. 822 on January 21, 2016. Order 822 approving seven CIP Reliability Standards
and new or modified definitions, and directed modifications be made to the CIP Reliability Standards. Among
other items, the Commission directed NERC to “develop modifications to the CIP Reliability Standards to require
responsible entities to implement controls to protect, at a minimum, communication links and sensitive bulk
electric system data communicated between bulk electric system Control Centers in a manner that is
appropriately tailored to address the risks posed to the bulk electric system by the assets being protected (i.e.,
high, medium, or low impact).” (Order 822, Paragraph 53)
In response to the directive in Order No. 822, the Project 2016-02 standard drafting team (SDT) drafted
Reliability Standard CIP-012-1 to require Responsible Entities to implement controls to protect sensitive Bulk
Electric System (BES) data and communications links between BES Control Centers. Due to the sensitivity of the
data being communicated between Control Centers, the standard applies to all impact levels (i.e., high, medium,
or low impact).
The SDT drafted requirements to provide Responsible Entities the latitude to protect the communication links,
the data, or both, to satisfy the security objective consistent with the capabilities of the Responsible Entity’s
operational environment.

1

NERC’s Compliance Guidance Policy

NERC | DRAFT CIP-012-1 Implementation Guidance | AugustMay 2018
3

Requirements
R1.

The Responsible Entity shall implement, except under CIP Exceptional Circumstances, one or
more documented plan(s) to mitigate the risks of posed by unauthorized disclosure andor
unauthorized modification of Real-time Assessment and Real-time monitoring data while
being transmitted between any applicable Control Centers. The Responsible Entity is not
required to include oral communications in its plan. The plan shall include: [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning]
1.1. Identification of security protection used to mitigate the risks of posed by unauthorized
disclosure andor unauthorized modification of Real-time Assessment and Real-time
monitoring data while being transmitted between Control Centers;
1.2. Identification of where the Responsible Entity applied security protection for transmitting
Real-time Assessment and Real-time monitoring data between Control Centers; and
1.3. If the Control Centers are owned or operated by different Responsible Entities,
identification ofy the responsibilities of each Responsible Entity for applying security
protection to the transmission of Real-time Assessment and Real-time monitoring data
between those Control Centers.

NERC | DRAFT CIP-012-1 Implementation Guidance | AugustMay 2018
4

General Considerations
Plan Development
As noted in the Technical Rationale and Justification for CIP-012-1, the focus of Requirement R1 is implementing
a documented plan to protect information that is critical to the real-time operations of the Bulk Electric System
while in transit between applicable Control Centers. The number of plan(s) and their content may vary
depending on a Responsible Entity's management structure and operating conditions. The Responsible Entity
may document as many plans as necessary to meet its needs. For instance, a Responsible Entity may choose to
document one plan per Control Center or choose an all-inclusive, single plan for its Control Center
communication environment. A Responsible Entity may choose to document one plan for communications
between Control Centers it owns and a separate plan for communications between its Control Centers and the
Control Centers of a neighboring Entity. The number and structure of the plans is at the discretion of the
Responsible Entity as long as the plan(s) include the required elements described in pParts 1.1, 1.2, and 1.3 of
Requirement R1.
Identification of Real-time Assessment and Real-time monitoring data
Responsible Entities can expect to receive or have received requests for Operations Planning Analysis, Real-time
Assessment and Real-time monitoring data from their RC(s), BA(s) and TOP(s). These data requests, pursuant to
the data specification from TOP-003 and IRO-010 requirements, may also include other types of data under the
same request. CIP-012 requires protection only for Real-time Assessment and Real-time monitoring data. If the
provided data specification does not indicate which data is Real-time Assessment and Real-time monitoring
data, Responsible Entities could choose to conduct an assessment to identify this data from among the other
data requested or being communicated. Once a data assessment is completed, the Responsible Entity should
confirm its findings with the other communicating entity before applying security controls. If the Real-time
Assessment and Real-time monitoring data is not clearly identified in the provided data specification, the
Responsible Entity should document the methodology used and all actions taken to identify the Real-time
Assessment and Real-time monitoring data.
Identification of Security Protection
Entities have latitude to identify and choose which security protection is used to mitigate the risks of posed by
unauthorized disclosure or and unauthorized modification of Real-time Assessment and Real-time monitoring
data while being transmitted between Control Centers.
This security protection could consist of logical protection, physical protection, or some combination of both. To
determine security protection, the requirement specifies that it must mitigate the risks posed byof unauthorized
disclosure or and unauthorized modification of applicable data.
Security protection implementation can be demonstrated in many ways. If a Responsible Entity uses physical
protection, it may demonstrate implementation through review of an applicable Control Center floor plan with
details subsequently confirmed through visual inspection, which identifies the physical security measures in
place protecting the communication link. If the Responsible Entity uses logical protection, it may demonstrate
implementation through an export of the device configuration which applies the security protection.
Alternatively, a Responsible Entity may demonstrate implementation through security control monitoring, using
an automated monitoring tool to generate reports on the encryption service used to protect a communications
link. Where the operational obligations of an entire communication link, including both endpoints, belong to the
Control Center of another Responsible Entity, the Responsible Entity without operational obligations for the
communication link may demonstrate compliance by ensuring the communications link endpoint is within its
Control Center, which could be limited to including the communication link endpoint within a PSP or where
other physical protection is applied.

NERC | DRAFT CIP-012-1 Implementation Guidance | AugustMay 2018
5

Identification of Where Security Protection is Applied by the Responsible Entity
A Responsible Entity should consider its environment when identifying where security protections should be
applied. One approach is to implement security within the Control Center itself to ensure that data
confidentiality and integrity is protected throughout the transmission. The Responsible Entity can identify where
security protection is applied using a logical or physical location The application of security in accordance with
CIP-012 requirements does not add additional assets to the scope of the CIP Reliability Standards. Locations of
applied security protection may vary based on many factors such as impact levels of the Control Center,
different technologies, or infrastructures. Where the operational obligations of an entire communication link,
including both endpoints, belong to the Control Center of another Responsible Entity, the Responsible Entity
without operational obligations for the communication link may demonstrate compliance by ensuring the
communications link endpoint is within its Control Center, which could be limited to including the
communication link endpoint within a PSP. or where other physical protection is applied.
Identification of where a Responsible Entity applies security protection could be demonstrated with a list or a
Control Center diagram showing either physical or logical security controls. Physical diagrams may require visual
confirmation of these controls. These diagrams or a list could be included within the plan developed for R1. A
Responsible Entity could also use labels to identify on-site devices where CIP-012 security protection is applied.
When exchanging data between two entities, if a Responsible Entity only manages one end of a communication
link, the Responsible Entity is not responsible for identifying where the security protection is applied by the
neighboring entity with which it is exchanging data. However, if a Responsible Entity has taken responsibility for
both ends of the communication link (such as by placing a router within the neighboring entity’s data center),
then the Responsible Entity shall identify where the security protection is applied at both ends of the link.
Similarly, if a Responsible Entity owns and operates both Control Centers which are exchanging data (such as in
the case of a primary and backup Control Center), then the Responsible Entity shall identify where security
protection is applied at both ends of the link.
Identification of Responsibilities when the Control Centers are Owned or Operated by Different
Responsible Entities

The Technical Rationale and Justification for CIP-012-1 identifies key considerations in the Control Center
Ownership section when communications between Control Centers with different owners or operators. Many
operational relationships between Responsible Entities are unique. Consequently, there is no single way to
identify responsibilities for applying security protection to the transmission of Real-time Assessment and Realtime monitoring data between Control Centers.
Implementation of responsibilities could also be demonstrated in many ways. Some examples include a joint
procedure, a memorandum of understanding, or meeting minutes between the two parties where
responsibilities are defined. These responsibilities should be included in both Responsible Entities’ plans
satisfying requirement pPart 1.3.
Where the operational obligations of an entire communication link, including both endpoints, belong to the
Control Center of another Responsible Entity, the Responsible Entity without operational obligations for the
communication link may demonstrate compliance by ensuring the communications link endpoint is within its
Control Center, which could be limited to including the communication link endpoint within a PSP or where
other physical protection is applied. These responsibilities should be included in both Responsible Entities’ plans
satisfying requirement part 1.3.

NERC | DRAFT CIP-012-1 Implementation Guidance | AugustMay 2018
6

Reference Model
For this Implementation Guidance, the SDT uses a basic reference model of Primary and Backup Control Centers
(Entity Alpha) to illustrate approaches to demonstrating compliance. These Control Centers communicate to
each other and to a neighboring entity’s Control Center (Entity Beta) in configurations outlined by the diagrams
in this section. The SDT recognizes that the reference model does not contain many of the complexities of a real
Control Center. For this Implementation Guidance, the registration or functions performed in the reference
model Control Center are also not considered. A high level block diagram of the basic reference model is shown
below in Figure 1. This Implementation Guidance is developed from the perspective of Entity Alpha.

Entity Alpha’s Primary
Control Center

Communication between Entity Alpha’s
Primary and Backup Control Center

Communication between Entity Alpha’s
Primary Control Center and Entity Beta’s Control Center

Entity Alpha’s Backup
Control Center

Communication between Entity Alpha’s
Backup Control Center and Entity Beta’s Control Center

Entity Beta’s Control
Center

Figure 1: High Level Block Diagram of Reference Model Control Centers

Reference Model Discussion
Requirement R1 requires the implementation of a documented plan. To comply with requirement R1, one
approach to a plan is to first determine which communications are in scope of CIP-012-1. There are multiple
ways to identify an entity’s scope in R1. For example, Entity Alpha in the reference model may first identify the
Control Centers with which it communicates. Entity Alpha would determine that there are three: Entity Alpha’s
Primary Control Center, Entity Alpha’s Backup Control Center, and Entity Beta’s Control Center. Entity Alpha
does not need to consider whether Entity Beta further shares its data with another Entity. That is the
responsibility of Entity Beta and is outside of Entity Alpha’s purview. Additionally, Entity Alpha does not need to
consider any communications to other non-Control Center facilities such as generating plants or substations.
These communications are out of scope for CIP-012-1.
Now that Entity Alpha has identified the Control Centers with which it communicates, Entity Alpha identifies
either: (1) the Real-time Assessment and Real-time monitoring data; or (2) communication links which are used
to transmit Real-time Assessment and Real-time monitoring data between Control Centers. In either case, Entity
Alpha should refer to the data specification for Real-time Assessment and Real-time monitoring data identified
NERC | DRAFT CIP-012-1 Implementation Guidance | AugustMay 2018
7

in TOP-003-3 and IRO-010-2. For this reference model scenario, identifying the communication links used to
transmit Real-time Assessment and Real-time monitoring data may be the most straightforward approach.
Through an evaluation of communication links between Control Centers and an evaluation of how it transmits
and receives Real-time Assessment and Real-time monitoring data, Entity Alpha determined that it
communicates applicable data between its primary and backup Control Centers across a single communication
link. Entity Alpha also determined that it communicates applicable data to and from Entity Beta’s Control Center
across one of two links that originate from either Entity Alpha’s primary or backup Control Center using the
Inter-Control Center Communications Protocol (ICCP).
With an identified scope of communications links, Entity Alpha now considers the three required elements of its
required communications between Control Centers for its plan.
Identification of Security Protection

2

•

Entity Alpha must ensure that protection is applied where identified in its CIP-012-1 plan. The protection
must also meet the security objective of mitigating the risks of posed by unauthorized disclosure or and
unauthorized modification of applicable data while in transit between Control Centers. The
identification of security protection could be demonstrated by a network diagram similar to that shown
in Figure 2 or Figure 3.

•

In a simple case where the security protection is applied sufficiently close to the Control Center, such as
within the Physical Security Perimeter of the Control Center, Entity Alpha may use a single security
protection method to meet the security objective. For this case, shown in Figure 2, Entity Alpha
implements a Virtual Private Network (VPN) connection across a private leased communication circuit
for each of its three in-scope communication links. To meet the security objective, Entity Alpha further
states that its VPN uses Internet Protocol security (IPsec) with encryption.

•

For more complex scenarios, Entity Alpha may need to use a combination of security controls. For
instance, in Figure 3, Entity Alpha uses a combination of physical security controls (physical access
control) and logical security controls (encrypted communications consistent with the first scenario
above) to meet the security objective. The SDT notes that the same technical architecture could exist
where the responsibilities of the registered entities are different. Therefore as shown in Figure 2 & 3, in
the scenario where entity Alpha owns and operationally manages the communication link and endpoint
equipment, Entity Beta is responsible for ensuring the communication endpoint of the communication
link is within a Control Center. Entity Beta ensures Entity Alpha’s communication link endpoint
equipment is within a Control Center by including the communication endpoint within a Control Center
PSP. The physical controls for the PSP are described in CIP-006 documentation and do not need to be
repeated for this requirement. This satisfies Entity Beta’s obligation for Part 1.1 and 1.2.

•

While these scenarios are all specific to communication links, it is possible that Entity Alpha and Entity
Beta achieve the security objective by applying protection to the data rather than the communication
links. In this scenario, the application enabling the data exchange between Control Centers may be
capable of applying security controls directly to the data. These security controls mitigate the risks of
posed by unauthorized disclosure or and unauthorized modification of applicable data rather than
relying on lower level network services to provide this security. For instance, Entity Alpha and Entity
Beta may apply security protection at the application layer by using Secure ICCP to exchange applicable
data. According to a report released by Sandia National Labs 2, Secure ICCP provides “data integrity
indirectly by providing a cryptographic checksum. Secure ICCP provides data confidentiality by
encrypting ICCP data exchanges.” Methods other than Secure ICCP could also be used to apply security
protection to the data at the application layer.

https://energy.gov/sites/prod/files/oeprod/DocumentsandMedia/19-Secure_ICCP_Integration.pdf
NERC | DRAFT CIP-012-1 Implementation Guidance | AugustMay 2018
8

•

It is theoretically possible that Entity Alpha and Entity Beta could exchange Real-time Assessment data
between Control Centers by email. In that scenario, one approach may be for Entity Alpha to email the
applicable data to Entity Beta’s Control Center in a protected container such as an encrypted zip file.
Entity Alpha and Entity Beta can then exchange the password to that encrypted container through
another method, such as by phone. While the notional example of protecting data exchanged by email
is a useful illustration of how to achieve the security objective of CIP-012-1, it is extremely unlikely to be
used in practice. The characteristics of email communication are inconsistent with the requirements of
Real-time data exchange.

Identification of Where Security Protection is Applied by the Responsible Entity

Similar to the identification of security protection above, the identification of where security protection is
applied can also be demonstrated by a network diagram similar to those found in Figures 2 and 3.
•

Figure 2 shows the identification where CIP-012-1 security protection is applied for the Entity Alpha
reference model when a single encrypted tunnel is used to implement the required protection. Entity
Alpha has identified that security protection is applied at each of its Control Centers on the external
Ethernet interface on the WAN router. While the diagram depicts where Entity Beta has applied
security protection for illustrative purposes, Entity Alpha is not responsible for identifying where Entity
Beta has applied security protection.

•

In order to understand the application of security protection in context of who controls the
communication link, it may be helpful to identify both where CIP-012-1 security protection is applied
and the location of the telecommunications carrier (telco) demarcation point. Figure 3 provides such an
example where the telco demarcation point may not be within the Control Center and based the facts
and circumstances surrounding this scenario, Entity Alpha has implemented a combination of security
controls to comply with CIP-012-1. In this scenario, Entity Alpha identifies that it has applied physical
security protection for its PSP and continuing for its WAN router and that it has applied logical security
protection (encryption) at the WAN router. Entity Alpha has also identified the telco demarcation point
at a point in the telecommunications cabling connecting to Entity Alpha’s WAN router, perhaps at a
punch down block for example. In Figure 3, the telco demarcation point is inside the same room as the
WAN router. The telco demarcation points are referenced in the drawing for clarity, but are not part of
the plan.

•

Figures 2 & 3 provide an example of where the operational obligations of an entire communications link,
including both endpoints, belong to Entity Alpha. In this case, Entity Beta may be responsible for
ensuring the communications endpoint of the communications link is within their Control Center. Entity
Beta ensures Entity Alpha’s communication link endpoint equipment is within a Control Center by
including the communication endpoint within a Control Center PSP. The documentation provided for
Part 1.1 by Entity Beta fulfils this obligation.

•

The data-centric scenario described above is less intuitive for identifying where security protection is
applied by Entity Alpha. If security protection is applied at the application layer (such as Secure ICCP),
Entity Alpha could reasonably identify the application or service applying the security (such as the
Secure ICCP service) as the location of where security protection is applied.

Identification of Responsibilities when the Control Centers are Owned or Operated by Different
Responsible Entities

Entity Alpha and Entity Beta may determine they each are responsible for one end of the VPN configuration on
their respective WAN routers. Entity Alpha and Entity Beta have agreed to a 30 character pre-shared key for
IPSec authentication.

NERC | DRAFT CIP-012-1 Implementation Guidance | AugustMay 2018
9

Rather than use a pre-shared key, Entity Alpha and Entity Beta may decide to use digital certificates for the IPSec
authentication using a trusted certificate authority. In that scenario, Entity Alpha and Entity Beta would agree on
who is the party responsible for managing the certificate authority.
In the example where the communication link and endpoint equipment are owned by Entity Alpha, both entities
should include ownership responsibilities in their plans satisfying requirement 1.3. Examples include but are not
limited to, a letter indicating ownership or responsibility, a copy of a contract indicating ownership or
responsibilities, an excerpt from an operational agreement or manual indicating ownership or responsibility.

Entity Alpha’s Primary
Control Center

Entity Alpha’s CIP-012
security protection applied
at the external interface of
the WAN router

Entity Alpha’s CIP-012
security protection applied
at the external interface of
the WAN router

Entity Alpha’s Backup
Control Center

WAN Router

WAN Router

ESP Firewall

ESP Firewall

Operator Application Database
Workstations Server
Server

ICCP
Server

Operator Application Database
Workstations Server
Server

ICCP
Server

Communications Carrier
Entity Beta’s CIP-012
security protection applied
at the external interface of
the WAN router

Entity Beta’s
Control Center
WAN Router

ESP Firewall

Operator Application Database
Workstations Server
Server

In the case where Entity Alpha owns
and operationally manages the
communication link and endpoint
equipment, Entity Beta ensures
Entity Alpha’s endpoint equipment
is within the Control Center. Entity
Alpha includes any logical security
protection applied to the
communication link in their plan

ICCP
Server

Figure 2: Network diagram and identification of where security protection is applied

NERC | DRAFT CIP-012-1 Implementation Guidance | AugustMay 2018
10

Entity Alpha’s CIP-012
physical security
protection applied

Physically secured area

Physically secured area

Entity Alpha’s Primary
Control Center

WAN Router
Entity Alpha’s CIP-012
logical security
protection applied

ESP Firewall

Entity Alpha’s Backup
Control Center

WAN Router
Telco
Demarcation
Point

Telco
Demarcation
Point

Entity Alpha’s CIP-012
physical security
protection applied

Entity Alpha’s CIP-012
logical security
protection applied

ESP Firewall

Encrypted
Communications
Operator Application Database
Workstations Server
Server

ICCP
Server

Operator Application Database
Workstations Server
Server

ICCP
Server

Communications Carrier
Entity Beta’s CIP-012
security protection
applied

Entity Beta’s
Control Center
WAN Router

ESP Firewall

Operator Application Database
Workstations Server
Server

In the case where Entity Alpha owns
and operationally manages the
communication link and endpoint
equipment, Entity Beta ensures
Entity Alpha’s endpoint equipment
is within the Control Center. Entity
Alpha includes any logical security
protection applied to the
communication link in their plan

ICCP
Server

Figure 3: Network diagram using a combination of controls for CIP-012-1

NERC | DRAFT CIP-012-1 Implementation Guidance | AugustMay 2018
11

References
Mitre Common Weakness Enumeration (CWE™) list of software weakness types
https://cwe.mitre.org/data/definitions/327.html
Cryptographic Standards and Guidelines
https://csrc.nist.gov/Projects/Cryptographic-Standards-and-Guidelines
NIST Special Publication 800-175B
Guideline for Using Cryptographic Standards in the Federal Government: Cryptographic Mechanisms
http://nvlpubs.nist.gov/nistpubs/SpecialPublications/NIST.SP.800-175B.pdf
Guide to Cryptography
https://www.owasp.org/index.php/Guide_to_Cryptography#Symmetric_Cryptography

NERC | DRAFT CIP-012-1 Implementation Guidance | AugustMay 2018
12

Standards Announcement

Project 2016-02 Modifications to CIP Standards
Final Ballot Open through August 13, 2018
Now Available

The final ballot for CIP-012-1 – Cyber Security - Communications between Control Centers is open
through 8 p.m. Eastern, Monday, August 13, 2018.
Balloting

In the final ballot, votes are counted by exception. Votes from the previous ballot are automatically carried
over in the final ballot. Only members of the applicable ballot pools can cast a vote. Ballot pool members
who previously voted have the option to change their vote in the final ballot. Ballot pool members who did
not cast a vote during the previous ballot can vote in the final ballot.
Members of the ballot pool associated with this project can log in and submit their votes here. If you
experience issues navigating the Standards Balloting & Commenting System (SBS), contact Wendy Muller.
•

If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential error
messages, or system lock-out, contact NERC IT support directly at https://support.nerc.net/ (Monday
– Friday, 8 a.m. - 5 p.m. Eastern).

•

Passwords expire every 6 months and must be reset.

•

The SBS is not supported for use on mobile devices.

•

Please be mindful of ballot and comment period closing dates. We ask to allow at least 48 hours for
NERC support staff to assist with inquiries. Therefore, it is recommended that users try logging into
their SBS accounts prior to the last day of a comment/ballot period.

Next Steps

The voting results will be posted and announced after the ballot closes. If approved, the standard will be
submitted to the Board of Trustees for adoption and then filed with the appropriate regulatory authorities.
Standards Development Process

For more information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Standards Developer, Jordan Mallory (via email) or at (404)
446-2589.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Index - NERC Balloting Tool

NERC Balloting Tool (/)

Page 1 of 17

Dashboard (/)

Users

Ballots

Comment Forms

Login (/Users/Login) / Register (/Users/Register)

BALLOT RESULTS
Ballot Name: 2016-02 Modifications to CIP Standards CIP-012-1 FN 5 ST
Voting Start Date: 8/3/2018 10:27:31 AM
Voting End Date: 8/13/2018 8:00:00 PM
Ballot Type: ST
Ballot Activity: FN
Ballot Series: 5
Total # Votes: 252
Total Ballot Pool: 309
Quorum: 81.55
Weighted Segment Value: 72.55
Negative
Fraction
w/
Comment

Negative
Votes
w/o
Comment

Abstain

No
Vote

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Segment:
1

80

1

44

0.677

21

0.323

0

3

12

Segment:
2

7

0.6

5

0.5

1

0.1

0

1

0

Segment:
3

73

1

43

0.754

14

0.246

0

3

13

Segment:
4

17

1

9

0.692

4

0.308

0

2

2

Segment:
5

73

1

31

0.608

20

0.392

0

2

20

Segment:
6

46

1

23

0.657

12

0.343

0

3

8

Segment:
7

2

0

0

0

0

0

0

1

1

Segment:
8

3

0.2

2

0.2

0

0

0

0

1

Segment:
9

1

0.1

1

0.1

0

0

0

0

0

1

0.1

0

0

0

Segment

Segment: 7
0.7
6
0.6
10
© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB01

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9/10/2018

Index - NERC Balloting Tool

Page 2 of 17

Segment

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Totals:

309

6.6

164

4.789

73

Negative
Fraction
w/
Comment

Negative
Votes
w/o
Comment

Abstain

No
Vote

1.811

0

15

57

BALLOT POOL MEMBERS
Show All

Segment

 entries

Organization

Search: Search

Voter

Designated
Proxy

Ballot

NERC
Memo

1

AEP - AEP Service Corporation

Dennis Sauriol

Affirmative

N/A

1

Allete - Minnesota Power, Inc.

Jamie Monette

Abstain

N/A

1

American Transmission
Company, LLC

Douglas Johnson

Affirmative

N/A

1

APS - Arizona Public Service
Co.

Michelle
Amarantos

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

John Shaver

None

N/A

1

Associated Electric
Cooperative, Inc.

Ryan Ziegler

Affirmative

N/A

1

Austin Energy

Thomas Standifur

None

N/A

1

Balancing Authority of Northern
California

Kevin Smith

Affirmative

N/A

1

Basin Electric Power
Cooperative

David Rudolph

None

N/A

1

BC Hydro and Power Authority

Patricia
Robertson

Affirmative

N/A

1

Berkshire Hathaway Energy MidAmerican Energy Co.

Terry Harbour

Negative

N/A

Negative

N/A

1
Bonneville Power
Kammy Rogers© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB01
Administration
Holliday

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Joe Tarantino

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 3 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Brazos Electric Power
Cooperative, Inc.

Tony Kroskey

Negative

N/A

1

Cedar Falls Utilities

Adam Peterson

None

N/A

1

CenterPoint Energy Houston
Electric, LLC

Daniela
Hammons

Affirmative

N/A

1

Central Electric Power
Cooperative (Missouri)

Michael Bax

Affirmative

N/A

1

Central Hudson Gas & Electric
Corp.

Frank Pace

Affirmative

N/A

1

City Utilities of Springfield,
Missouri

Michael Buyce

Affirmative

N/A

1

CMS Energy - Consumers
Energy Company

James Anderson

Negative

N/A

1

Con Ed - Consolidated Edison
Co. of New York

Dermot Smyth

Affirmative

N/A

1

Dominion - Dominion Virginia
Power

Larry Nash

Affirmative

N/A

1

Duke Energy

Laura Lee

Negative

N/A

1

Edison International - Southern
California Edison Company

Steven Mavis

Affirmative

N/A

1

Entergy - Entergy Services, Inc.

Oliver Burke

Affirmative

N/A

1

Eversource Energy

Quintin Lee

Affirmative

N/A

1

Exelon

Chris Scanlon

Affirmative

N/A

1

FirstEnergy - FirstEnergy
Corporation

Julie Severino

Affirmative

N/A

1

Great Plains Energy - Kansas
City Power and Light Co.

James McBee

Affirmative

N/A

1

Great River Energy

Gordon Pietsch

None

N/A

1

Hydro One Networks, Inc.

Payam
Farahbakhsh

Affirmative

N/A

1

Hydro-Qu?bec TransEnergie

Nicolas Turcotte

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Laura Nelson

Negative

N/A

Douglas Webb

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Segment

Organization

Page 4 of 17

Voter

1

Imperial Irrigation District

Jesus Sammy
Alcaraz

1

International Transmission
Company Holdings Corporation

Michael Moltane

1

Lincoln Electric System

1

Designated
Proxy

Ballot

NERC
Memo

None

N/A

Negative

N/A

Danny Pudenz

Negative

N/A

Long Island Power Authority

Robert Ganley

Affirmative

N/A

1

Los Angeles Department of
Water and Power

faranak sarbaz

None

N/A

1

Lower Colorado River Authority

William Sanders

Affirmative

N/A

1

M and A Electric Power
Cooperative

William Price

Affirmative

N/A

1

Manitoba Hydro

Mike Smith

None

N/A

1

MEAG Power

David Weekley

Affirmative

N/A

1

Memphis Light, Gas and Water
Division

Allan Long

None

N/A

1

Minnkota Power Cooperative
Inc.

Theresa Allard

Negative

N/A

1

Muscatine Power and Water

Andy Kurriger

Negative

N/A

1

N.W. Electric Power
Cooperative, Inc.

Mark Ramsey

Affirmative

N/A

1

National Grid USA

Michael Jones

Affirmative

N/A

1

Nebraska Public Power District

Jamison Cawley

Negative

N/A

1

New York Power Authority

Salvatore
Spagnolo

None

N/A

1

NextEra Energy - Florida Power
and Light Co.

Mike ONeil

Affirmative

N/A

1

NiSource - Northern Indiana
Public Service Co.

Steve Toosevich

Affirmative

N/A

1

Northeast Missouri Electric
Power Cooperative

Kevin White

Affirmative

N/A

1

OGE Energy - Oklahoma Gas
and Electric Co.

Terri Pyle

Negative

N/A

Stephanie
Burns

Scott Miller

Andy Fuhrman

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Segment

Organization

Page 5 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Ohio Valley Electric
Corporation

Scott
Cunningham

Affirmative

N/A

1

Omaha Public Power District

Doug Peterchuck

Negative

N/A

1

Oncor Electric Delivery

Lee Maurer

Negative

N/A

1

OTP - Otter Tail Power
Company

Charles Wicklund

Negative

N/A

1

Peak Reliability

Scott Downey

Affirmative

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Laurie Williams

Affirmative

N/A

1

PPL Electric Utilities
Corporation

Brenda Truhe

Affirmative

N/A

1

PSEG - Public Service Electric
and Gas Co.

Joseph Smith

Affirmative

N/A

1

Public Utility District No. 1 of
Chelan County

Jeff Kimbell

Affirmative

N/A

1

Public Utility District No. 1 of
Snohomish County

Long Duong

Abstain

N/A

1

Puget Sound Energy, Inc.

Theresa
Rakowsky

Affirmative

N/A

1

Sacramento Municipal Utility
District

Arthur Starkovich

Affirmative

N/A

1

Salt River Project

Steven Cobb

Negative

N/A

1

Santee Cooper

Chris Wagner

Negative

N/A

1

SCANA - South Carolina
Electric and Gas Co.

Tom Hanzlik

Abstain

N/A

1

Seattle City Light

Pawel Krupa

None

N/A

1

Seminole Electric Cooperative,
Inc.

Mark Churilla

None

N/A

1

Sempra - San Diego Gas and
Electric

Martine Blair

Affirmative

N/A

1

Sho-Me Power Electric
Cooperative

Peter Dawson

Affirmative

N/A

Tho Tran

Joe Tarantino

Jeff Johnson

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Segment

Organization

Page 6 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Southern Company - Southern
Company Services, Inc.

Katherine Prewitt

Affirmative

N/A

1

Southern Indiana Gas and
Electric Co.

Steve Rawlinson

Affirmative

N/A

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

Negative

N/A

1

Tennessee Valley Authority

Howell Scott

Affirmative

N/A

1

Tri-State G and T Association,
Inc.

Tracy Sliman

Negative

N/A

1

U.S. Bureau of Reclamation

Richard Jackson

Negative

N/A

1

Westar Energy

Allen Klassen

Affirmative

N/A

1

Western Area Power
Administration

sean erickson

Negative

N/A

1

Xcel Energy, Inc.

Dean Schiro

Affirmative

N/A

2

California ISO

Richard Vine

Abstain

N/A

2

Electric Reliability Council of
Texas, Inc.

Brandon Gleason

Affirmative

N/A

2

Independent Electricity System
Operator

Leonard Kula

Affirmative

N/A

2

ISO New England, Inc.

Michael Puscas

Affirmative

N/A

2

Midcontinent ISO, Inc.

Terry BIlke

Negative

N/A

2

New York Independent System
Operator

Gregory Campoli

Affirmative

N/A

2

PJM Interconnection, L.L.C.

Mark Holman

Affirmative

N/A

3

AEP

Leanna
Lamatrice

Affirmative

N/A

3

AES - Indianapolis Power and
Light Co.

Bette White

None

N/A

3

APS - Arizona Public Service
Co.

Vivian Vo

Affirmative

N/A

3

Arkansas Electric Cooperative
Corporation

Mark Gann

Affirmative

N/A

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Segment

Organization

Page 7 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Associated Electric
Cooperative, Inc.

Todd Bennett

Affirmative

N/A

3

Austin Energy

W. Dwayne
Preston

Affirmative

N/A

3

Basin Electric Power
Cooperative

Jeremy Voll

Affirmative

N/A

3

BC Hydro and Power Authority

Hootan Jarollahi

Affirmative

N/A

3

Berkshire Hathaway Energy MidAmerican Energy Co.

Annette Johnston

Negative

N/A

3

Bonneville Power
Administration

Rebecca Berdahl

Negative

N/A

3

Central Electric Power
Cooperative (Missouri)

Adam Weber

Affirmative

N/A

3

City of Farmington

Linda JacobsonQuinn

Abstain

N/A

3

City of Leesburg

Chris Adkins

None

N/A

3

City of Vero Beach

Ginny Beigel

Negative

N/A

3

City Utilities of Springfield,
Missouri

Scott Williams

Affirmative

N/A

3

Cleco Corporation

Michelle Corley

Affirmative

N/A

3

Con Ed - Consolidated Edison
Co. of New York

Peter Yost

Affirmative

N/A

3

Cowlitz County PUD

Russell Noble

None

N/A

3

Duke Energy

Lee Schuster

Negative

N/A

3

Edison International - Southern
California Edison Company

Romel Aquino

Affirmative

N/A

3

Empire District Electric Co.

Kalem Long

None

N/A

3

Eversource Energy

Sharon Flannery

Affirmative

N/A

3

Exelon

John Bee

Affirmative

N/A

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

Affirmative

N/A

Darnez
Gresham

Brandon
McCormick

Louis Guidry

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Segment

Organization

Page 8 of 17

Voter

3

Georgia System Operations
Corporation

Scott McGough

3

Great Plains Energy - Kansas
City Power and Light Co.

Jessica Tucker

3

Great River Energy

3

Designated
Proxy

Ballot

NERC
Memo

Affirmative

N/A

Affirmative

N/A

Brian Glover

Negative

N/A

Hydro One Networks, Inc.

Paul Malozewski

None

N/A

3

KAMO Electric Cooperative

Ted Hilmes

Affirmative

N/A

3

Lincoln Electric System

Jason Fortik

Negative

N/A

3

M and A Electric Power
Cooperative

Stephen Pogue

Affirmative

N/A

3

Manitoba Hydro

Karim Abdel-Hadi

None

N/A

3

MEAG Power

Roger Brand

Scott Miller

Affirmative

N/A

3

Modesto Irrigation District

Jack Savage

Nick Braden

Affirmative

N/A

3

Muscatine Power and Water

Seth Shoemaker

Negative

N/A

3

National Grid USA

Brian Shanahan

Affirmative

N/A

3

Nebraska Public Power District

Tony Eddleman

Negative

N/A

3

New York Power Authority

David Rivera

None

N/A

3

NiSource - Northern Indiana
Public Service Co.

Aimee Harris

Affirmative

N/A

3

North Carolina Electric
Membership Corporation

doug white

Affirmative

N/A

3

Northeast Missouri Electric
Power Cooperative

Skyler Wiegmann

Affirmative

N/A

3

NW Electric Power
Cooperative, Inc.

John Stickley

Affirmative

N/A

3

Ocala Utility Services

Neville Bowen

None

N/A

3

OGE Energy - Oklahoma Gas
and Electric Co.

Donald Hargrove

Affirmative

N/A

3

OTP - Otter Tail Power
Company

Wendi Olson

Negative

N/A

3

Owensboro Municipal Utilities

Thomas Lyons

Affirmative

N/A

Affirmative

N/A

© 2018
Machine
Name:
ERODVSBSWB01
3 - NERC Ver 4.2.1.0
Platte River
Power
Authority
Jeff Landis

https://sbs.nerc.net/BallotResults/Index/276

Douglas Webb

Shelly Dineen

Scott Brame

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 9 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

3

PNM Resources - Public
Service Company of New
Mexico

Lynn Goldstein

Affirmative

N/A

3

Portland General Electric Co.

Angela Gaines

Affirmative

N/A

3

PPL - Louisville Gas and
Electric Co.

Charles Freibert

Affirmative

N/A

3

PSEG - Public Service Electric
and Gas Co.

James Meyer

Affirmative

N/A

3

Public Utility District No. 1 of
Chelan County

Joyce Gundry

Affirmative

N/A

3

Puget Sound Energy, Inc.

Tim Womack

Affirmative

N/A

3

Rutherford EMC

Tom Haire

None

N/A

3

Sacramento Municipal Utility
District

Nicole Looney

Affirmative

N/A

3

Salt River Project

Robert
Kondziolka

Negative

N/A

3

Santee Cooper

James Poston

Negative

N/A

3

SCANA - South Carolina
Electric and Gas Co.

Scott Parker

None

N/A

3

Seattle City Light

Tuan Tran

Affirmative

N/A

3

Seminole Electric Cooperative,
Inc.

James Frauen

Abstain

N/A

3

Sempra - San Diego Gas and
Electric

Bridget Silvia

Affirmative

N/A

3

Sho-Me Power Electric
Cooperative

Jeff Neas

Affirmative

N/A

3

Silicon Valley Power - City of
Santa Clara

Val Ridad

None

N/A

3

Snohomish County PUD No. 1

Holly Chaney

Abstain

N/A

3

Southern Company - Alabama
Power Company

Joel Dembowski

Affirmative

N/A

3

Southern Indiana Gas and
Electric Co.

Fred Frederick

Affirmative

N/A

Joe Tarantino

© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB01

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 10 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Tacoma Public Utilities
(Tacoma, WA)

Marc Donaldson

Negative

N/A

3

TECO - Tampa Electric Co.

Ronald Donahey

None

N/A

3

Tennessee Valley Authority

Ian Grant

Affirmative

N/A

3

Tri-State G and T Association,
Inc.

Janelle Marriott
Gill

None

N/A

3

WEC Energy Group, Inc.

Thomas Breene

Negative

N/A

3

Westar Energy

Bryan Taggart

Negative

N/A

3

Xcel Energy, Inc.

Michael Ibold

Affirmative

N/A

4

American Public Power
Association

Jack Cashin

None

N/A

4

Arkansas Electric Cooperative
Corporation

Alice Wright

Affirmative

N/A

4

Austin Energy

Esther Weekes

Affirmative

N/A

4

City of Clewiston

Lynne Mila

Negative

N/A

4

City Utilities of Springfield,
Missouri

John Allen

Affirmative

N/A

4

FirstEnergy - FirstEnergy
Corporation

Aubrey Short

Affirmative

N/A

4

Georgia System Operations
Corporation

Andrea Barclay

Affirmative

N/A

4

Indiana Municipal Power
Agency

Jack Alvey

None

N/A

4

National Rural Electric
Cooperative Association

Barry Lawson

Affirmative

N/A

4

North Carolina Electric
Membership Corporation

John Lemire

Affirmative

N/A

4

Public Utility District No. 1 of
Snohomish County

John Martinsen

Abstain

N/A

4

Sacramento Municipal Utility
District

Beth Tincher

Affirmative

N/A

4

Seattle City Light

Hao Li

Affirmative

N/A

Brandon
McCormick

Scott Berry

Scott Brame

Joe Tarantino

© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB01

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9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 11 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

4

Seminole Electric Cooperative,
Inc.

Charles
Wubbena

Abstain

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

Negative

N/A

4

Utility Services, Inc.

Brian EvansMongeon

Negative

N/A

4

WEC Energy Group, Inc.

Anthony
Jankowski

Negative

N/A

5

Acciona Energy North America

George Brown

None

N/A

5

AEP

Thomas Foltz

Affirmative

N/A

5

Ameren - Ameren Missouri

Sam Dwyer

Negative

N/A

5

APS - Arizona Public Service
Co.

Kelsi Rigby

Affirmative

N/A

5

Arkansas Electric Cooperative
Corporation

Moses Harris

Affirmative

N/A

5

Associated Electric
Cooperative, Inc.

Brad Haralson

Affirmative

N/A

5

Austin Energy

Shirley Mathew

Affirmative

N/A

5

Avista - Avista Corporation

Glen Farmer

Affirmative

N/A

5

Basin Electric Power
Cooperative

Mike Kraft

Affirmative

N/A

5

BC Hydro and Power Authority

Helen Hamilton
Harding

Affirmative

N/A

5

Boise-Kuna Irrigation District Lucky Peak Power Plant
Project

Mike Kukla

Affirmative

N/A

5

Bonneville Power
Administration

Scott Winner

Negative

N/A

5

BP Wind Energy North America
Inc.

Carla Holly

None

N/A

5

Choctaw Generation Limited
Partnership, LLLP

Rob Watson

Affirmative

N/A

5

Cleco Corporation

Stephanie
Huffman

Affirmative

N/A

Louis Guidry

© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB01

https://sbs.nerc.net/BallotResults/Index/276

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 12 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

5

CMS Energy - Consumers
Energy Company

David
Greyerbiehl

Negative

N/A

5

Colorado Springs Utilities

Jeff Icke

None

N/A

5

Con Ed - Consolidated Edison
Co. of New York

William Winters

Affirmative

N/A

5

Dairyland Power Cooperative

Tommy Drea

None

N/A

5

Dominion - Dominion
Resources, Inc.

Lou Oberski

Affirmative

N/A

5

Duke Energy

Dale Goodwine

Negative

N/A

5

Edison International - Southern
California Edison Company

Selene Willis

Affirmative

N/A

5

EDP Renewables North
America LLC

Heather Morgan

None

N/A

5

Entergy

Jamie Prater

Affirmative

N/A

5

Exelon

Ruth Miller

Negative

N/A

5

FirstEnergy - FirstEnergy
Solutions

Robert Loy

Affirmative

N/A

5

Great Plains Energy - Kansas
City Power and Light Co.

Harold Wyble

Affirmative

N/A

5

Great River Energy

Preston Walsh

Negative

N/A

5

Gridforce Energy Management,
LLC

David Blackshear

None

N/A

5

Hydro-Qu?bec Production

Junji Yamaguchi

None

N/A

5

JEA

John Babik

None

N/A

5

Kissimmee Utility Authority

Mike Blough

Negative

N/A

5

Lakeland Electric

Jim Howard

Negative

N/A

5

Lincoln Electric System

Kayleigh
Wilkerson

Negative

N/A

5

Los Angeles Department of
Water and Power

Donald
Sievertson

Affirmative

N/A

5

Manitoba Hydro

Yuguang Xiao

None

N/A

Alyson Slanover

Douglas Webb

Brandon
McCormick

© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB01

https://sbs.nerc.net/BallotResults/Index/276

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 13 of 17

Voter

5

Massachusetts Municipal
Wholesale Electric Company

David Gordon

5

MEAG Power

Steven Grego

5

Muscatine Power and Water

5

Designated
Proxy

Ballot

NERC
Memo

Affirmative

N/A

Affirmative

N/A

Neal Nelson

Negative

N/A

NB Power Corporation

Laura McLeod

None

N/A

5

Nebraska Public Power District

Don Schmit

Negative

N/A

5

New York Power Authority

Erick Barrios

None

N/A

5

NextEra Energy

Allen Schriver

Affirmative

N/A

5

NiSource - Northern Indiana
Public Service Co.

Kathryn Tackett

Affirmative

N/A

5

North Carolina Electric
Membership Corporation

Robert Beadle

Affirmative

N/A

5

Northern California Power
Agency

Marty Hostler

Negative

N/A

5

OGE Energy - Oklahoma Gas
and Electric Co.

John Rhea

Negative

N/A

5

Omaha Public Power District

Mahmood Safi

Negative

N/A

5

Ontario Power Generation Inc.

David
Ramkalawan

Affirmative

N/A

5

OTP - Otter Tail Power
Company

Cathy Fogale

Negative

N/A

5

Portland General Electric Co.

Ryan Olson

None

N/A

5

PPL - Louisville Gas and
Electric Co.

JULIE
HOSTRANDER

Affirmative

N/A

5

PSEG - PSEG Fossil LLC

Tim Kucey

Affirmative

N/A

5

Public Utility District No. 1 of
Chelan County

Meaghan Connell

Abstain

N/A

5

Public Utility District No. 1 of
Snohomish County

Sam Nietfeld

Abstain

N/A

5

Puget Sound Energy, Inc.

Eleanor Ewry

Affirmative

N/A

5

Sacramento Municipal Utility
District

Susan Oto

Affirmative

N/A

Negative

N/A

© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB01
5
Salt River Project
Kevin Nielsen

https://sbs.nerc.net/BallotResults/Index/276

Scott Miller

Scott Brame

Joe Tarantino

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 14 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Santee Cooper

Tommy Curtis

Negative

N/A

5

SCANA - South Carolina
Electric and Gas Co.

Alyssa Hubbard

None

N/A

5

Seattle City Light

Faz Kasraie

None

N/A

5

Seminole Electric Cooperative,
Inc.

Brenda Atkins

None

N/A

5

Sempra - San Diego Gas and
Electric

Daniel Frank

None

N/A

5

Silicon Valley Power - City of
Santa Clara

Sandra Pacheco

None

N/A

5

Southern Company - Southern
Company Generation

William D. Shultz

Affirmative

N/A

5

SunPower

Bradley Collard

None

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Negative

N/A

5

Talen Generation, LLC

Matthew
McMillan

None

N/A

5

TECO - Tampa Electric Co.

Frank L Busot

None

N/A

5

Tennessee Valley Authority

M Lee Thomas

Affirmative

N/A

5

U.S. Bureau of Reclamation

Wendy Center

Negative

N/A

5

WEC Energy Group, Inc.

Linda Horn

Negative

N/A

5

Xcel Energy, Inc.

Gerry Huitt

Affirmative

N/A

6

APS - Arizona Public Service
Co.

Nicholas Kirby

Affirmative

N/A

6

Arkansas Electric Cooperative
Corporation

Bruce Walkup

Affirmative

N/A

6

Austin Energy

Andrew Gallo

Affirmative

N/A

6

Basin Electric Power
Cooperative

Paul Huettl

Affirmative

N/A

6

Berkshire Hathaway PacifiCorp

Sandra Shaffer

Negative

N/A

Bonneville Power
Andrew Meyers
Administration
© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB01

Negative

N/A

6

https://sbs.nerc.net/BallotResults/Index/276

Andrey
Komissarov

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 15 of 17

Voter

6

Cleco Corporation

Robert Hirchak

6

Con Ed - Consolidated Edison
Co. of New York

6

Designated
Proxy

NERC
Memo

Affirmative

N/A

Christopher
Overberg

Affirmative

N/A

Dominion - Dominion
Resources, Inc.

Sean Bodkin

Affirmative

N/A

6

Duke Energy

Greg Cecil

Negative

N/A

6

Edison International - Southern
California Edison Company

Kenya Streeter

None

N/A

6

Entergy

Julie Hall

Affirmative

N/A

6

Exelon

Becky Webb

Negative

N/A

6

FirstEnergy - FirstEnergy
Solutions

Ann Ivanc

Affirmative

N/A

6

Florida Municipal Power Pool

Tom Reedy

Brandon
McCormick

Negative

N/A

6

Great Plains Energy - Kansas
City Power and Light Co.

Jim Flucke

Douglas Webb

Affirmative

N/A

6

Lincoln Electric System

Eric Ruskamp

Negative

N/A

6

Los Angeles Department of
Water and Power

Anton Vu

Affirmative

N/A

6

Luminant - Luminant Energy

Brenda Hampton

Abstain

N/A

6

Manitoba Hydro

Blair Mukanik

None

N/A

6

Modesto Irrigation District

James McFall

Affirmative

N/A

6

Muscatine Power and Water

Ryan Streck

Negative

N/A

6

NextEra Energy - Florida Power
and Light Co.

Silvia Mitchell

None

N/A

6

NiSource - Northern Indiana
Public Service Co.

Joe O'Brien

Affirmative

N/A

6

Northern California Power
Agency

Dennis Sismaet

Negative

N/A

6

OGE Energy - Oklahoma Gas
and Electric Co.

Sing Tay

Affirmative

N/A

6

Omaha Public Power District

Joel Robles

None

N/A

Affirmative

N/A

© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB01
6
Portland General Electric Co.
Daniel Mason

https://sbs.nerc.net/BallotResults/Index/276

Louis Guidry

Ballot

Nick Braden

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 16 of 17

Voter

Designated
Proxy

Ballot

NERC
Memo

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

Affirmative

N/A

6

Public Utility District No. 1 of
Chelan County

Davis Jelusich

Affirmative

N/A

6

Public Utility District No. 2 of
Grant County, Washington

LeRoy Patterson

None

N/A

6

Sacramento Municipal Utility
District

Jamie Cutlip

Affirmative

N/A

6

Salt River Project

Bobby Olsen

Negative

N/A

6

Santee Cooper

Michael Brown

Negative

N/A

6

Seattle City Light

Charles Freeman

Affirmative

N/A

6

Seminole Electric Cooperative,
Inc.

Trudy Novak

Abstain

N/A

6

Snohomish County PUD No. 1

Franklin Lu

Abstain

N/A

6

Southern Company - Southern
Company Generation and
Energy Marketing

Jennifer Sykes

Affirmative

N/A

6

Southern Indiana Gas and
Electric Co.

Brad Lisembee

None

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Rick Applegate

Negative

N/A

6

Talen Energy Marketing, LLC

Jennifer
Hohenshilt

None

N/A

6

TECO - Tampa Electric Co.

Benjamin Smith

None

N/A

6

Tennessee Valley Authority

Marjorie Parsons

Affirmative

N/A

6

WEC Energy Group, Inc.

David Hathaway

Negative

N/A

6

Westar Energy

Megan Wagner

Affirmative

N/A

6

Xcel Energy, Inc.

Carrie Dixon

Affirmative

N/A

7

Exxon Mobil

Jay Barnett

None

N/A

7

Luminant Mining Company LLC

Stewart Rake

Abstain

N/A

8

David Kiguel

David Kiguel

Affirmative

N/A

None

N/A

8
Massachusetts Attorney
Frederick Plett
© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB01
General

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Joe Tarantino

Douglas Webb

9/10/2018

Index - NERC Balloting Tool

Segment

Organization

Page 17 of 17

Voter

Designated
Proxy

NERC
Memo

Ballot

8

Roger Zaklukiewicz

Roger
Zaklukiewicz

Affirmative

N/A

9

Commonwealth of
Massachusetts Department of
Public Utilities

Donald Nelson

Affirmative

N/A

10

Midwest Reliability
Organization

Russel Mountjoy

Affirmative

N/A

10

New York State Reliability
Council

ALAN ADAMSON

Affirmative

N/A

10

Northeast Power Coordinating
Council

Guy V. Zito

Affirmative

N/A

10

ReliabilityFirst

Anthony
Jablonski

Affirmative

N/A

10

SERC Reliability Corporation

Drew Slabaugh

Affirmative

N/A

10

Texas Reliability Entity, Inc.

Rachel Coyne

Affirmative

N/A

10

Western Electricity
Coordinating Council

Steven Rueckert

Negative

N/A

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9/10/2018

Exhibit I
Standard Drafting Team Roster

Standard Drafting Team Roster
Project 2016-02 Modifications to CIP Standards
Name

Entity

Co-Chair

David Revill

Georgia System Operations Corporation
(GSOC)

Co-Chair

Jay Cribb

Southern Company

Members

Steven Brain

Dominion Energy

Jake Brown

ERCOT

Gerald Freese

NIPSCO

Tom Foster

PJM Interconnection

Scott Klauminzer

Tacoma Public Utilities, Tacoma Power

Matthew Hyatt

Tennessee Valley Authority

Forrest Krigbaum

Bonneville Power Administration

Heather Morgan

EDP Renewables

Mark Riley

Calpine

Abdo Y. Saad

Consolidated Edison Company of New York,
Inc.

Ken Lanehome

Bonneville Power Administration

Kirk Rosener

CPS Energy

Jordan Mallory – Standards
Developer

North American Electric Reliability
Corporation

Shamai Elstein – Senior Counsel

North American Electric Reliability
Corporation

Marisa Hecht – Counsel

North American Electric Reliability
Corporation

PMOS Liaisons

NERC Staff