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2016-02 Modifications to CIP Standards | IROL Modifications to CIP-002 SAR

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Start Date: 06/14/2018
End Date: 07/13/2018

Associated Ballots:

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Electric Reliability Council of Texas, Inc. encourages coordination between the standards drafting teams for Projects 2015-09 and 2016-02 in order to ensure revisions achieve their intended purpose.

Brandon Gleason, On Behalf of: Brandon Gleason, , Segments 2

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For 2.6

1)      Recommend that there be a Requirement for the Planning Coordinator / Transmission Planner to notify the TOP/TO/GOP/GO that their location has been so designated.

2)      Recommend changing “identified” to “notified”.

 

For 2.9

Request clarification on how the TOP/TO/GOP/GO knows their RAS has been so designated. Does PRC-012-2 help clarify?

 

We recommend that the proposed criteria language be removed from the SAR to provide the SDT maximum flexibility.

 

We recommend that associated Guideline and Technical Basis “Technical Rationale” criterion information should be revised accordingly for changes made to the Impact Rating Criteria.

RSC no Dominion, Segment(s) 10, 2, 4, 5, 7, 1, 3, 6, 0, 7/13/2018

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Other Answers

Russell Martin II, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

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It is not necessary to change CIP-002 with the retirement of FAC-010. Identifying IROLs is still required in FAC-011-3 R1.3 and R3.7. The SAR does not refer to retirement of FAC-011-3 R1.3 and R3.7 nor retirement of the IROL definition in the NERC glossary. Therefore it is not necessary nor efficient to replace “IROL(s)” with its definition in the CIP-002 criteria 2.6 and 2.9.

Terry Harbour, On Behalf of: Berkshire Hathaway Energy - MidAmerican Energy Co., , Segments 1, 3

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faranak sarbaz, On Behalf of: Los Angeles Department of Water and Power, , Segments 1, 3, 5, 6

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Based on its Version 5 implementation experience, AEP believes planners are trained and have the experience necessary to evaluate BES Elements and Facilities for the risks to the BES from System instability, Cascading or uncontrolled separation. They are not, however, in the best position to evaluate Cyber risk. The following should be substituted in the Requested Information Section to relay the intent: “The Project 2015-09 SDT developed draft language to replace the reference to such IROLs in Criterion 2.6 and Criterion 2.9” with other language that would allow Planning Coordinators and Transmission Planners to identify Facilities that meet the stated criteria in the proposed modifications. Project 2015-09 SDT should work with the Project 2016-02 SDT to write explicit requirements in Planning Standards for Planning Authorities to work with Responsible Entities to evaluate BES facilities for the above risks and provide for a formal appeals process.

The drafters of the FAC standards should clearly obligate, through additional or modified requirement language, for the planning authorities to provide information regarding the impact to those facilities to Generation Owners and Transmission Owners.

In the Reliability Principals Section, only item# 8 should be checked, as CIP-002 is not a planning standard.

It appears that these two proposed SARs would be applied to the project along with the existing SAR, bringing the total number of SARs for this project to three. AEP is not aware of any precedent of multiple, concurrent SARs governing a NERC project at a single point in time. A SAR helps set a project’s direction and scope, and while a project’s SAR may be revised over time, AEP does not believe Appendix 3A (Standards Process Manual) provides an allowance for multiple, concurrent SARs to govern a single NERC project. Rather, the SPM allows a project’s existing SAR to be revised to accommodate any changes believed to be necessary.

Thomas Foltz, On Behalf of: AEP, , Segments 3, 5

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It is not necessary to change CIP-002 with the retirement of FAC-010. Identifying IROLs is still required in FAC-011-3 R1.3 and R3.7. The SAR does not refer to retirement of FAC-011-3 R1.3 and R3.7 nor retirement of the IROL definition in the NERC glossary. Therefore it is not necessary nor efficient to replace “IROL(s)” with its definition in the CIP-002 criteria 2.6 and 2.9.

Marty Hostler, On Behalf of: Northern California Power Agency, , Segments 5, 6

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It is not necessary to change CIP-002 with the retirement of FAC-010. Identifying IROLs is still required in FAC-011-3 R1.3 and R3.7. The SAR does not refer to retirement of FAC-011-3 R1.3 and R3.7 nor retirement of the IROL definition in the NERC glossary. Therefore it is not necessary nor efficient to replace “IROL(s)” with its definition in the CIP-002 criteria 2.6 and 2.9.

Dennis Sismaet, On Behalf of: Northern California Power Agency, , Segments 5, 6

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The SDT should review all SOL/IROL related standards and evaluate if all references to IROLs should be removed with regards to applicability and requirements  specific to the planning horizon.  

AECI, Segment(s) 1, 3, 6, 5, 4/30/2018

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Reclamation recommends simplifying the Impact Rating Criteria using the methodology described below.

 

BES Cyber Systems are to be rated as high, medium, or low impact as follows:

  1. A high impact BES Cyber System has one or more of the following characteristics:

1.1 Is used to operate transmission lines of 500kV or above

1.2 Supports a sum greater than 2500kV of transmission lines above 230kV

1.3 Supports generation with an aggregate capacity greater than 3000MW

1.4 Is identified as supporting an IROL or is necessary to avoid an Adverse Reliability Impact

 

2. A medium impact BES Cyber System has one or more of the following characteristics:

2.1 Supports generation with the aggregate capacity between 1500 – 3000MW

2.2 Supports a sum between 1500 – 2500kV of transmission lines above 230kV

2.3 Supports a RAS that could negatively affect an IROL or that can perform automatic Load shedding of 300MW or more

 

3. A low impact BES Cyber System has one or more of the following characteristics:

3.1 Supports a sum less than 1500kV of transmission lines above 230kV

3.2 Supports transmission only between 110 – 230kV

3.3 Supports generation with an aggregate capacity between 75 – 1500MW

3.4 Supports any single generator greater than 20MW not already identified as a Medium Impact BES Cyber System

3.5 Supports any Facilities that are designated a blackstart resource

3.6 Supports any other RAS not already identified as a medium impact BES Cyber System

Wendy Center, On Behalf of: U.S. Bureau of Reclamation, , Segments 1, 5

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Douglas Johnson, On Behalf of: Douglas Johnson, , Segments 1

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FirstEnergy Corporation, Segment(s) 4, 1, 3, 5, 6, 4/11/2017

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David Ramkalawan, On Behalf of: David Ramkalawan, , Segments 5

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First, City Light appreciates the efforts made by the drafting teams for NERC projects 2015-09 and 2016-02 to align work such that CIP-002-5.1 is revised only by one drafting team. The proposed SAR achieves this specific goal, but does not address the larger objective of consistency of effort. The issue in this case is that the same language about IROLs that is part of CIP-002 also is incorporated in CIP-014-2 (see Section 4.1.1.3). To ensure consistency, the IROL replacement language in both CIP-002 and CIP-014 should be handled by the same drafting team. The existing SAR for project 2016-02 does not include CIP-014 in its scope. As a result, it may be best to leave the IROL replacement language work for CIP-002 within project 2015-09, to ensure consistency between CIP-002 and CIP-014.

Second, City Light is concerned that the IROL replacement language proposed in the IROL SAR does not represent an administrative replacement of more-or-less equivalent terms, but rather has a different meaning that introduces potential for expanded scope and unintended consequences. Expanded scope because under the language as proposed, any contingency studied in a Planning Assessment that shows BES Cascading, Uncontrolled Separation, or Instability--even if the contingency is an extra-extreme case, well beyond anything considered in the traditional study of IROLs, a case examined only for exploratory purposes—thus triggers inclusion of associated Elements within scope for CIP protections. Unintended consequences because as different extra-extreme cases are studied in successive years, Elements may go in and out of scope for CIP protections on an annual basis. Unintended consequences also because to avoid these situations, Planners may choose to limit their Planning Assessments only to those contingencies required by the applicable Planning Standards and thus limit the study of grid behavior under unusual, unexpected cases. As such, City Light recommends that the proposed IROL replacement language be struck from the SAR. This change will allow the applicable drafting team, whichever it is, full flexibility to address the IROL replacement language. A reference to the proposed language might be included in the SAR, but in terms of one possible approach and not as the presumptive solution.

Thank you for your consideration.

Seattle City Light Ballot Body, Segment(s) 1, 4, 6, 5, 3, 12/2/2016

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Andrew Gallo, On Behalf of: Andrew Gallo, , Segments 1, 3, 4, 5, 6

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MRO NSRF, Segment(s) 3, 4, 5, 6, 1, 2, 7/19/2017

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Duke Energy is concerned with the process implications that could occur by going forward with the FAC SDT’s recommendations to CIP-002 at this time. Potential exists for industry confusion if one project gets ahead of the other. For example, what if the FAC project is stalled, or never fully approved by FERC? The revisions being proposed in CIP-002 then would no longer be acceptable. Going ahead with implementing the revisions suggested by another Project SDT while that Project has not been approved, and is still in active development is premature. We suggest that any revisions be put on hold until after the FAC project has been approved by FERC.

Duke Energy , Segment(s) 1, 5, 6, 4/10/2014

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None

Aaron Cavanaugh, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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While APS agrees with the need to modify Criteria 2.6 and 2.9 and understands the goal of efficiency this SAR is intended to achieve, APS has significant concerns regarding the consolidation of the IROL-related efforts into a CIP-focused drafting team.  The criteria set forth at 2.6 and 2.9 are inherently technical and require engineering and operational expertise beyond the information technology aspects of the majority of CIP-002.  More specifically, because these criteria will be premised upon the processes, assessments, and deliverables resulting from engineering analyses, APS respectfully asserts that the value the SDT is intending to recognize through the proposed transfer and consolidation is outweighed by the potential drawbacks that will result from the loss of engineering and operational expertise represented on the previous 2015-09 SDT.

Vivian Moser, On Behalf of: Vivian Moser, , Segments 1, 3, 5, 6

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PSEG supports the proposed CIP-002-5.1a SAR because it provides sufficient scope and direction for the SDT to implement changes to CIP-002 required by retiring FAC-010-3.

PSEG REs, Segment(s) 5, 6, 3, 1, 11/2/2017

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While I do agree with the need to revise criterion 2.6 and 2.9 in Attachment 1 of CIP-002, I am concerned the language proposed by the SOL SDT may not be sufficiently clear (a "bright line") to prevent varying interpretations of what indicates System instability, Cascading and/or uncontrolled separation and thus properly identifying Medium Impact BES Cyber Systems. The Planning Assessments for TPL-001 include many different Contingency events that may indicate some level of System instability, Cascading and/or uncontrolled separation. However, they may not justify a medium impact rating for the associated BES Cyber Systems. Therefore, I suggest keeping the IROL designation and relying on the RC and its methodology for identification. See comments from FMPA for a possible solution.

John Allen, On Behalf of: City Utilities of Springfield, Missouri, , Segments 1, 3, 4

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 FMPA appreciates the SDTs efforts with Project 2016-02 and CIP-002.  We disagree with the changes being proposed for sections 2.6 and 2.9 of Attachment 1.  We propose the following language for 2.6:

2.6. Generation at a single plant location or Transmission Facilities at a single station or substation location that are identified by its Reliability Coordinator, Planning Coordinator, or Transmission Planner as critical to the derivation of Interconnection Reliability Operating Limits (IROLs) and their associated contingencies.

FAC-011-3 applies to the Reliability Coordinator (RC) and requires the RC to have a documented methodology for developing SOLs and specifically (R1.3) the subset of SOLs that are IROLs.  In this way the language “as critical to the derivation of Interconnection Reliability Operating Limits (IROLs) and their associated contingencies” can be left in the standard instead of replaced as the SDT proposes.  The replacement language proposed by the SDT is not clear and could possibly bring Facilities that are currently and appropriately out of scope, into scope.  For example, what does “an element of each Contingency event” mean?  Would it apply if it were an element of only one event, or does it have to be an element of each event studied?  We recommend our proposed language above.

We see no reason to change the language for Section 2.9.  The issues raised in the SAR do not point to a necessity to change Section 2.9.

FMPA, Segment(s) , 10/23/2017

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ACES Standards Collaborators, Segment(s) 1, 3, 4, 5, 7/2/2018

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SPP Standards Review Group, Segment(s) 2, 4, 1, 3, 5, 6, 7/13/2018

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Hot Answers

Brandon Gleason, On Behalf of: Brandon Gleason, , Segments 2

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RSC no Dominion, Segment(s) 10, 2, 4, 5, 7, 1, 3, 6, 0, 7/13/2018

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Other Answers

Russell Martin II, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

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Terry Harbour, On Behalf of: Berkshire Hathaway Energy - MidAmerican Energy Co., , Segments 1, 3

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faranak sarbaz, On Behalf of: Los Angeles Department of Water and Power, , Segments 1, 3, 5, 6

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Thomas Foltz, On Behalf of: AEP, , Segments 3, 5

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Marty Hostler, On Behalf of: Northern California Power Agency, , Segments 5, 6

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Dennis Sismaet, On Behalf of: Northern California Power Agency, , Segments 5, 6

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AECI, Segment(s) 1, 3, 6, 5, 4/30/2018

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Wendy Center, On Behalf of: U.S. Bureau of Reclamation, , Segments 1, 5

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Douglas Johnson, On Behalf of: Douglas Johnson, , Segments 1

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FirstEnergy Corporation, Segment(s) 4, 1, 3, 5, 6, 4/11/2017

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David Ramkalawan, On Behalf of: David Ramkalawan, , Segments 5

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Seattle City Light Ballot Body, Segment(s) 1, 4, 6, 5, 3, 12/2/2016

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Andrew Gallo, On Behalf of: Andrew Gallo, , Segments 1, 3, 4, 5, 6

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MRO NSRF, Segment(s) 3, 4, 5, 6, 1, 2, 7/19/2017

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N/A

Duke Energy , Segment(s) 1, 5, 6, 4/10/2014

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None

Aaron Cavanaugh, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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Vivian Moser, On Behalf of: Vivian Moser, , Segments 1, 3, 5, 6

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PSEG REs, Segment(s) 5, 6, 3, 1, 11/2/2017

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John Allen, On Behalf of: City Utilities of Springfield, Missouri, , Segments 1, 3, 4

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None that we are aware of.

FMPA, Segment(s) , 10/23/2017

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ACES Standards Collaborators, Segment(s) 1, 3, 4, 5, 7/2/2018

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SPP Standards Review Group, Segment(s) 2, 4, 1, 3, 5, 6, 7/13/2018

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Hot Answers

Brandon Gleason, On Behalf of: Brandon Gleason, , Segments 2

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We recommend that the Guidelines and Technical Basis “Technical Rationale” for Criterion 2.3 be revised to reference TPL-001-4, instead of TPL-003.

RSC no Dominion, Segment(s) 10, 2, 4, 5, 7, 1, 3, 6, 0, 7/13/2018

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Other Answers

Is the modified language in 2.6 correct? For example, an entity performs a Planning Assessment and has 20 contingency events that result in System instability, Cascading, or uncontrolled separation. Generator X is an element in 19 of those 20 contingency events. From the modified language in 2.6, the BES Cyber Systems associated with generator X would not have a medium impact rating in accordance with 2.6 because generator X was not an element of each of the 20 contingency events. Is this the intent of this language?

Russell Martin II, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

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See Question 1 comments

Terry Harbour, On Behalf of: Berkshire Hathaway Energy - MidAmerican Energy Co., , Segments 1, 3

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faranak sarbaz, On Behalf of: Los Angeles Department of Water and Power, , Segments 1, 3, 5, 6

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Thomas Foltz, On Behalf of: AEP, , Segments 3, 5

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Marty Hostler, On Behalf of: Northern California Power Agency, , Segments 5, 6

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Dennis Sismaet, On Behalf of: Northern California Power Agency, , Segments 5, 6

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AECI, Segment(s) 1, 3, 6, 5, 4/30/2018

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Reclamation recommends that impact ratings apply to all BES Cyber Systems regardless of a Responsible Entity’s functional registration (Transmission or generation).

 

Reclamation also recommends that if the SDT modifies the Control Center definition, at least one member with CIP expertise and at least one member with O&P expertise should be on the team.

Wendy Center, On Behalf of: U.S. Bureau of Reclamation, , Segments 1, 5

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Douglas Johnson, On Behalf of: Douglas Johnson, , Segments 1

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FirstEnergy Corporation, Segment(s) 4, 1, 3, 5, 6, 4/11/2017

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David Ramkalawan, On Behalf of: David Ramkalawan, , Segments 5

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Seattle City Light Ballot Body, Segment(s) 1, 4, 6, 5, 3, 12/2/2016

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Andrew Gallo, On Behalf of: Andrew Gallo, , Segments 1, 3, 4, 5, 6

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MRO NSRF, Segment(s) 3, 4, 5, 6, 1, 2, 7/19/2017

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Duke Energy is unclear on the language, and the necessity of bringing the Elements in as they are proposed in this standard. First, the terms System instability, Cascading, or uncontrolled separation may be interpreted differently depending on the PC/TP.  The proposed criteria introduce a level of subjectivity that was intentionally eliminated from Version 5.  Second,  the term “Planning Assessment” is used which includes evaluation of Extreme Events under TPL-001.  Providing a Medium impact classification to Facilities that are only identified during an Extreme Event is inappropriate.  Third, with respect to generation, criterion 2.3 currently addresses a generation Facility that has been designated to avoid an Adverse Reliability Impact.  The proposed criterion 2.6 is potentially duplicative with respect to generation.  Fourth and most importantly, TP/PC identified SOLs/IROLs are proposed to be removed from the FAC standards.   We are unclear why identification would be unnecessary in FAC-010, but those same Facilities that would have been identified are important enough to be labeled as Medium impact in this CIP standard.

Duke Energy , Segment(s) 1, 5, 6, 4/10/2014

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None

Aaron Cavanaugh, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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APS has interpreted the intent of the SAR to be a simple transference of the proposed language drafted by the Project 2015-09 STD to the Project 2016-02, to incorporate into Draft 3 of CIP-002-6 thereby consolidating the drafting and comment processes.  APS is concerned that this consolidation could adversely impact the iterative comment and balloting process that normally accompanies the standards drafting process.  Further, and importantly, the scope, objectives, and context around the drafting of these revisions have been shifting throughout the course of these SDTs’ efforts.  For this reason, APS recommends that the SAR be modified to indicate that the commenting periods shall occur as necessary based on the comments and feedback received from industry.  As currently written, it appears that the SAR contemplates only one comment period, which APS believes is likely inadequate to re-calibrate the revisions and industry input.

APS is not in agreement with the proposed modifications to Criteria 2.6 as written by the Project 2025-09 STD.  Not all events that result in system instability, cascading, or controlled separation would result in an IROL.  This could pull in “extreme events” as defined in TPL-001-4, which is too broad.  APS proposes the following language for Criterion 2.6 in order to clarify that it is not applicable to Extreme Events that are also studied within the Planning Assessment:

2.6 Generation at a single plant location or Transmission Facilities at a single station or substation location that are identified by its Planning Coordinator or Transmission Planner as an element of each P0 – P7 Contingency event included in the Planning Assessment that result in System instability, Cascading or uncontrolled separation.   

Vivian Moser, On Behalf of: Vivian Moser, , Segments 1, 3, 5, 6

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PSEG REs, Segment(s) 5, 6, 3, 1, 11/2/2017

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John Allen, On Behalf of: City Utilities of Springfield, Missouri, , Segments 1, 3, 4

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Is transferring the SAR the same as subdividing it? From the Standards Process Manual: “ If a SAR is subdivided and assigned to more than one drafting team, each drafting team will have a clearly defined portion of the work such that there are no overlaps and no gaps in the work to be accomplished.” My concern is does transferring the SAR from one Project to another stay within the process outlined in the Standards Process Manual?  FMPA appreciates the challenge the SDTs have of incorporating changes made to other families of standard requirements with the CIP requirements.

FMPA, Segment(s) , 10/23/2017

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ACES Standards Collaborators, Segment(s) 1, 3, 4, 5, 7/2/2018

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The SPP Standards Review Group (“SSRG”) offers that the language proposed by Project 2015-09 SDT could be interpreted as overly broad, and could expand the list of facilities that would be identified as Medium Impact BES Cyber Systems.  The SSRG recommends that the Standard Drafting Team exclude contingent elements that are classified as Extreme Events from consideration for Criterion 2.6.   If Extreme Events from the Planning Assessment are included in Criterion 2.6, the list of identified facilities could grow to include facilities that would otherwise be Low Impact BES Cyber Systems.  This could create confusion amongst the industry how to account for those assets. The SSRG has included proposed language for your consideration (shown as a blackline against the draft proposal): 

2.6.         Generation at a single plant location or Transmission Facilities at a single station or substation location that are identified by its Planning Coordinator or Transmission Planner as a contingent element of Planning event (P1-P7) included in the Planning Assessment that result in System instability, for conditions such as Cascading, voltage instability, or uncontrolled islanding and cannot be adequately mitigated with a Corrective Action Plan or System adjustment.  

2.9.         Each Special Protection System (SPS), Remedial Action Scheme (RAS) or automated switching System that operates BES Elements, that, if destroyed, degraded, misused, or otherwise rendered unavailable, would result in System instability, for conditions such as Cascading, voltage instability, or uncontrolled islanding and cannot be adequately mitigated with a Corrective Action Plan or System adjustment.

SPP Standards Review Group, Segment(s) 2, 4, 1, 3, 5, 6, 7/13/2018

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