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Project 2015-09 Establish and Communicate System Operating Limits

Description:

Start Date: 06/19/2020
End Date: 08/26/2020

Associated Ballots:

Ballot Name Project Standard Pool Open Pool Close Voting Start Voting End
2015-09 Establish and Communicate System Operating Limits FAC-011-4 AB 3 ST 2015-09 Establish and Communicate System Operating Limits FAC-011-4 09/29/2017 07/20/2020 07/24/2020 08/26/2020
2015-09 Establish and Communicate System Operating Limits FAC-014-3 AB 3 ST 2015-09 Establish and Communicate System Operating Limits FAC-014-3 09/29/2017 07/20/2020 07/24/2020 08/26/2020
2015-09 Establish and Communicate System Operating Limits Implementation Plan AB 3 OT 2015-09 Establish and Communicate System Operating Limits Implementation Plan 09/29/2017 07/20/2020 07/24/2020 08/26/2020
2015-09 Establish and Communicate System Operating Limits CIP-014-3 AB 2 ST 2015-09 Establish and Communicate System Operating Limits CIP-014-3 08/24/2018 07/20/2020 07/24/2020 08/26/2020
2015-09 Establish and Communicate System Operating Limits FAC-003-5 AB 2 ST 2015-09 Establish and Communicate System Operating Limits FAC-003-5 08/24/2018 07/20/2020 07/24/2020 08/26/2020
2015-09 Establish and Communicate System Operating Limits FAC-013-3 AB 2 ST 2015-09 Establish and Communicate System Operating Limits FAC-013-3 08/24/2018 07/20/2020 07/24/2020 08/26/2020
2015-09 Establish and Communicate System Operating Limits PRC-002-3 AB 2 ST 2015-09 Establish and Communicate System Operating Limits PRC-002-3 08/24/2018 07/20/2020 07/24/2020 08/26/2020
2015-09 Establish and Communicate System Operating Limits PRC-023-5 AB 2 ST 2015-09 Establish and Communicate System Operating Limits PRC-023-5 08/24/2018 07/20/2020 07/24/2020 08/26/2020
2015-09 Establish and Communicate System Operating Limits PRC-026-2 AB 2 ST 2015-09 Establish and Communicate System Operating Limits PRC-026-2 08/24/2018 07/20/2020 07/24/2020 08/26/2020
2015-09 Establish and Communicate System Operating Limits IRO-008-3 IN 1 ST 2015-09 Establish and Communicate System Operating Limits IRO-008-3 06/19/2020 07/20/2020 07/24/2020 08/26/2020
2015-09 Establish and Communicate System Operating Limits TOP-001-6 IN 1 ST 2015-09 Establish and Communicate System Operating Limits TOP-001-6 06/19/2020 07/20/2020 07/24/2020 08/26/2020

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Hot Answers

See SEE, EEI and MISO comments.

Maurice Paulk, On Behalf of: Cleco Corporation, , Segments 1, 3, 5, 6

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Ray Jasicki, 8/24/2020

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Other Answers

I agree SOL exceedances should be determined using the TOP and IRO standards and not an FAC standard. However, the standards need to be results-based and define a clear and measurable expected outcome for all Registered Entities. Otherwise it becomes more of a guideline that is difficult to enforce. It appears each Reliability Coordinator has some flexibility to develop it’s own method for identifying SOL exceedances in its SOL methodology. If so, then what is going to prevent two adjacent Reliability Coordinators from arriving at different conclusions and having disagreements during Real-time operations? What is going to prevent two adjacent Transmission Operators in different Reliability Coordinator Areas from having disagreements? What is going to prevent disagreements between Registered Entities and their Regional Entity? How are those disagreements resolved? The purpose of the SOL Whitepaper was to establish a common understanding of SOL exceedances across North America. Hopefully these requirements are not detrimental to that effort and the purpose of this project.

John Allen, City Utilities of Springfield, Missouri, 4, 7/15/2020

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Michael Courchesne, On Behalf of: Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2

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Laura Nelson, 7/24/2020

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NCPA supports John Allen's, City Utilities of Springfield, Missouri, comments.

Marty Hostler, On Behalf of: Northern California Power Agency, , Segments 3, 4, 5, 6

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Matthew Nutsch, On Behalf of: Seattle City Light, WECC, Segments 1, 3, 4, 5, 6

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Thomas Foltz, AEP, 5, 7/27/2020

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Bruce Reimer, Manitoba Hydro , 1, 7/27/2020

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Jennie Wike, On Behalf of: John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6

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These comments represent the MRO NSRF membership as a whole but would not preclude members from submitting individual comments”.

 The MRO-NSRF agrees with revisions made by the SDT in FAC-011-4, FAC-014-3, TOP-001-6 and IRO-008-3 with regard to SOL exceedance use and determinations. The MRO-NSRF supports the proposed revisions to FAC-011-4, Requirement 6, which while providing a consistent framework for defining a SOL Exceedance within the RC methodology, also provides some flexibility to each RC in the application of the framework within its footprint.

However, the MRO NSRF does recommend a change to FAC-011-4 R6.4 language. Specifically, the proposed language reads, "planned manual load shedding is acceptable only after all available System adjustments have been made." Although the MRO NSRF understands the intent of this language (i.e. load shed is a last resort solution), we don't believe it is the SDT's intention to require every System adjustment to actually be implemented in a study or model prior to determining that manual load shed is the best planned response. We believe the intent is to ensure all available adjustments have been appropriately assessed before deciding on the solution of last resort. We recommend changing the language to, "planned manual load shedding is acceptable only after all available System adjustments have been assessed."

The MRO NSRF notes there remains the potential for differences between adjacent Reliability Coordinators over the methods used to identify SOL exceedances.

MRO NSRF, Segment(s) 3, 4, 5, 6, 1, 2, 1/29/2020

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In consideration of past confusion related to whether an SOL exceedance is a regulatory violation, LES suggests the following changes to better clarify R6:

R6.2.1 Steady State post-Contingency flow through Facilities within applicable Emergency Ratings. [Remove: Steady state post-Contingency flow through a Facility must not be above the Facility’s highest Emergency Rating.]

R6.2.3 Predetermined stability limits are not exceeded. [Remove: The stability performance criteria defined in the Reliability Coordinator’s SOL methodology are met.]

Lincoln Electric System, Segment(s) 5, 6, 3, 1, 4/17/2018

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Richard Jackson, U.S. Bureau of Reclamation, 1, 7/29/2020

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R6.1: The way this is worded is awkward and confusing. Why are you using the language “no contingencies” instead of “pre-contingency state”?

 

Vince Ordax, Florida Reliability Coordinating Council – Member Services Division , 8, 7/29/2020

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BC Hydro, Segment(s) 3, 5, 1, 12/18/2018

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Amy Casuscelli, On Behalf of: Michael Ibold, Xcel Energy, Inc., 1,3,5; Michael Ibold, Xcel Energy, Inc., 1,3,5; Michael Ibold, Xcel Energy, Inc., 1,3,5

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Duke Energy agrees with the revisions but due to the numerous methodologies, procedures, processes, tools, and training impacts associated with this Project, suggest extending implemenation period from 12 months to 30 months.

Duke Energy, Segment(s) 1, 5, 6, 4/11/2019

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Alliant Energy supports the comments submitted by the MRO NSRF.

Larry Heckert, Alliant Energy Corporation Services, Inc., 4, 7/30/2020

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MEC supports the MRO NSRF comments. 

The MRO-NSRF agrees with revisions made by the SDT in FAC-011-4, FAC-014-3, TOP-001-6 and IRO-008-3 with regard to SOL exceedance use and determinations. The MRO-NSRF supports the proposed revisions to FAC-011-4, Requirement 6, which while providing a consistent framework for defining a SOL Exceedance within the RC methodology, also provides some flexibility to each RC in the application of the framework within its footprint.

However, the MRO NSRF does recommend a change to FAC-011-4 R6.4 language. Specifically, the proposed language reads, "planned manual load shedding is acceptable only after all available System adjustments have been made." Although the MRO NSRF understands the intent of this language (i.e. load shed is a last resort solution), we don't believe it is the SDT's intention to require every System adjustment to actually be implemented in a study or model prior to determining that manual load shed is the best planned response. We believe the intent is to ensure all available adjustments have been appropriately assessed before deciding on the solution of last resort. We recommend changing the language to, "planned manual load shedding is acceptable only after all available System adjustments have been assessed."

The MRO NSRF notes there remains the potential for differences between adjacent Reliability Coordinators over the methods used to identify SOL exceedances.

Terry Harbour, Berkshire Hathaway Energy - MidAmerican Energy Co., 1, 7/30/2020

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MEC Supports NSRF Comments

Darnez Gresham, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 7/30/2020

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Please see our comments in Q#2 and Q#4

Leonard Kula, Independent Electricity System Operator, 2, 7/30/2020

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Detailed comments are in the attached file with special formatting for clarity and emphasis where needed (strike-through, highlighting, etc.).

Southern Company, Segment(s) 1, 3, 5, 6, 12/13/2019

2015-09_Unofficial_Comment_Form_202006 - SOCO Comments Final.pdf

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FE Voter, Segment(s) 1, 3, 5, 6, 4, 7/31/2020

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FAC-014-3   No

The FAC-014-3 R6 language opens the door for the Reliability Coordinator (RC) to dictate to the Transmission Planner (TP), through the RC's SOL methodology, the following items used in planning assessments: facility ratings, voltage criteria, and stability criteria. Establishment of facility ratings are the responsibility of the TO under FAC-008, while establishment of voltage and stability criteria are the responsibility of the TP under TPL-001-4. These responsibilities should not be ceded to another party. Long term implications are that the RC, through control of such items as facility ratings, voltage and stability limits, could force a TO to enter into corrective action plans and associated capital expenditures that they otherwise would not.

Joe O'Brien, NiSource - Northern Indiana Public Service Co., 6, 7/31/2020

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Dominion Energy supports comments submitted by EEI. Dominion agrees that the implmentation period should be extended to allow entities the appropriate time to make changes to complex systems and processes.

Dominion, Segment(s) 3, 5, 1, 9/19/2019

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Anthony Jablonski, ReliabilityFirst , 10, 7/31/2020

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Maryanne Darling-Reich, On Behalf of: Black Hills Corporation - MRO, WECC - Segments 1, 3, 5, 6

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Glenn Barry, Los Angeles Department of Water and Power, 5, 7/31/2020

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OGE agrees with MRO-NSRF’s comments on replacing IROL definition language with “Adverse Reliability Impact” as shown below:

Proposed Language:

FAC-011-4, Parts 6.1.4 and 6.2.4. Adverse Reliability Impacts do not occur. 1

            Footnote 1, page 5: Stability evaluations and assessments of Adverse Reliability Impacts can be performed using real-time stability assessments, predetermined stability limits or other offline analysis techniques.

FAC-011-4, Part 6.3. System performance for applicable Contingencies identified in Part 5.2 demonstrates that Adverse Reliability Impacts do not occur.

FAC-011-4, Part 7.1.3. Post-contingency SOL exceedances that are identified to have a validated risk of Adverse Reliability Impacts

OKGE, Segment(s) 6, 1, 3, 5, 4/10/2019

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PPL NERC Registered Affiliates, Segment(s) 1, 3, 5, 6, 9/6/2018

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MPC supports comments submitted by the MRO NERC Standards Review Forum.

Andy Fuhrman, On Behalf of: Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1

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FMPA supports John Allen's, City Utilities of Springfield, Missouri, comments.

Truong Le, On Behalf of: Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Chris Gowder, Florida Municipal Power Agency, 3,4,5,6; Chris Gowder, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Richard Montgomery, Florida Municipal Power Agency, 3,4,5,6; Richard Montgomery, Florida Municipal Power Agency, 3,4,5,6; Carol Chinn, Florida Municipal Power Agency, 3,4,5,6; Carol Chinn, Florida Municipal Power Agency, 3,4,5,6; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3

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ATC appreciates the changes made by the SDT to address industry concerns and we are supportive of the current revisions to these standards. We do recommend one change to FAC-011-4 R6.4 language. Specifically, the proposed language reads, "planned manual load shedding is acceptable only after all available System adjustments have been made." Although we understand the intent of this language (i.e. load shed is a last resort solution), we don't believe it is the SDT's intention to require every System adjustment to actually be implemented in a study or model prior to determining that manual load shed is the best planned response. We believe the intent is to ensure all available adjustments have been appropriately assessed before deciding on the solution of last resort. We recommend changing the language to, "planned manual load shedding is acceptable only after all available System adjustments have been assessed."

LaTroy Brumfield, American Transmission Company, LLC, 1, 8/3/2020

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We agree with the revisions but offer the following for consideration and improvement.

a.       Requirement R7 – plural word “communications” needs to be changed to be singular.

b.       The proposed modification to IRO-008 requirement R6 effectively requires the RC to notify TOPs and BAs when SOL exceedances have been mitigated or prevented in accordance with its SOL Methodology; however, there is no specific requirement in proposed FAC-011-4 that requires the SOL methodology to address notification of SOL exceedance mitigation or prevention. It only specifically requires the SOL methodology to addresses notification of SOL exceedances. While it is true that proposed FAC-011-4 requirement R7 can be interpreted to include not only notification of SOL exceedances, but also notification of SOL exceedance mitigation or prevention, it might be clearer to enhance FAC-011-4 requirement R7 by specifically addressing notification of SOL exceedance mitigation and prevention. If this modification is not made, RCs might not know that their SOL methodology is supposed to address notification of SOL exceedance mitigation and prevention if they don’t happen to read proposed IRO-008 requirement R6. Potential language enhancement could be “Each Reliability Coordinator shall include in its SOL methodology a risk-based approach for determining how SOL exceedances (and associated exceedance mitigation) identified as part of Real-time monitoring and Real-time Assessments must be communicated…”

Steven Rueckert, Western Electricity Coordinating Council, 10, 8/3/2020

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BPA suggests the proposed TOP-001-6 requirement R25 be removed.  BPA believes the requirement that the TOP use the RC SOL methodology for establishing SOLs in the Operations horizon is already covered in FAC-014 R2.  The proposed FAC-011-4 R6 will require the RC SOL Methodology to explicitly include applicability to “Real-time monitoring, Real-time Assessments, and Operational Planning Analysis”.  (Using the RC West SOL Methodology as an example, the applicability of the methodology to these sub-horizons is already explicit in the document.)  BPA believes the proposed TOP-001-6 R25 is redundant and simply adds to the burden of compliance documentation.

BPA has no concerns with the proposed revisions to IRO-008-3 R5/R6.

Cain Braveheart, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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Mark Holman, 8/3/2020

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Sandra Shaffer, 8/3/2020

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Texas RE appreciates the standard drafting team’s (SDT) efforts to clarify System Operating Limit (SOL) exceedance use and determination.  As Texas RE understands it, proposed FAC-011-4 Requirement R6 establishes the required system performance framework in an RC’s SOL methodology for determining SOL exceedances in the RC’s Real-time monitoring, Real-time Assessment (RTA) and Operation Planning Analyses (OPA) activities.  Texas RE remains concerned, however, that proposed FAC-011-4 could be read to permit the broader use of less conservative Facility Ratings in identifying and responding to SOL exceedances by permitting entities to operate the system without identifying an SOL and implementing an Operating Plan when: (1) pre-contingency steady state flows are within Emergency Ratings in circumstances in which System adjustments to return the flow to within a Facility’s Normal Rating could be executed and completed within the applicable time duration of the Emergency Ratings; and (2) post-contingency flows through Facilities are within the Facility’s highest Emergency Rating. 

 

Regarding post-contingency flows in particular, Texas RE is concerned that entities would not be required to identify post-contingency flows and voltages above a Facility’s two-hour Emergency Rating as an SOL.  Texas RE notes that the “highest Emergency Rating” is usually an extreme limit associated with a very short duration to mitigate an exceedance of the Emergency Rating.  For example, ERCOT ISO utilizes a 15-minute rating (along with 2-hour and continuous) that is defined as shown below:

 

“The 15-minute MVA rating of a Transmission Element, including substation terminal equipment in series with a conductor or transformer, at the applicable ambient temperature and with a step increase from a prior loading up to 90% of the Normal Rating.  The Transmission Element can operate at this rating for 15 minutes, assuming its pre-contingency loading up to 90% of the Normal Rating limit at the applicable ambient temperature, without violation of NESC clearances or equipment failure.  This rating takes advantage of the time delay associated with heating of a conductor or transformer following a sudden increase in current.”

 

As Texas RE reads the proposed FAC-011-4, R 6.2.1 language, SOL methodologies could be designed to permit post-contingency flows above a Facility’s two-hour Emergency Rating but below the highest 15-minute rating.  By possibly not requiring entities to identify this instance as an SOL exceedance in its OPA or RTA, an entity would correspondingly not be required to create an Operating Plan to mitigate the exceedance and would not be required to take pre-emptive steps to address such post-contingency flows identified in Real-time.  In turn, if an Operating Plan is not created, the entity potentially would not know the adjustments needed to address the exceedance and the duration in which these adjustments can be completed. 

 

Texas RE observes that the proposed NERC System Operating Limit Definition and Exceedance Clarification provides: “Normal voltage limits are typically applicable for the pre-Contingency state while emergency voltage limits are normally applicable for the post-Contingency state. SOL exceedance with respect to these voltage limits occurs when either actual bus voltage is outside acceptable pre-Contingency (normal) bus voltage limits, or when Real-time Assessments indicate that bus voltages are expected to fall outside acceptable emergency limits in response to a Contingency event.” 

 

Texas RE supports this approach, but believes additional clarity is necessary in the Standard Requirement language itself to require entities more proactive action to address post-contingency identified Emergency Rating exceedances rather than only requiring entities to develop Operating Plans when exceedances of the highest Emergency Rating are identified.

Additionally, Texas RE recommends the SDT consider the following:

  • In Part 6.1, rephrase “System performance for no Contingencies demonstrates the following to “System performance where there are no applied Contingencies demonstrates the following”.  Alternatively, “applied” could be moved to be after “Contingencies”.

  • In Part 6.1.2, there is typically no time duration associated with voltage limits, nor is there a reference to time duration in the proposed definition of System Voltage Limits.  Based on this language it should or a SOL exceedance for a System Voltage Limit may not occur based on this language.  The reliability of the grid could suffer by never returning to “normal” System Voltage Limits because no time duration is specified.

  • In Part 6.2.1 “Steady State” is capitalized (and also capitalized in the rationale document in several places), but there is no current or proposed definition in the NERC Glossary.  Texas RE has experienced entities asking about a definition during recent engagements. 

  • Additionally, within Part 6.2, there may need to be a reference regarding “Predetermined stability limits are not exceeded”.  It would appear that the omission would allow a “predetermined stability limit” to be exceeded for a single contingency and thus meet system performance, which seems to contradict an N-1 approach to reliable operations.

  • Part 6.1.2 states “System Voltage Limits may be used when System adjustments to return the voltage within its normal System Voltage Limits could be executed and completed within the specified time duration of those emergency System Voltage Limits.”  The proposed definition of System Voltage Limit does not define a time period.  So there nothing to describe what the “specified time duration of those emergency System Voltage Limits” is.  Texas RE recommends the System Voltage definition include a time duration to be more effective, reliable, and applicable.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 8/3/2020

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AEPC believes that the revisions made by the SDT will improve the reliability with regard to SOL exceedance. However, it does not provide consistent framework for defining SOL exceedances for all registered entities. Therefore, two adjacent Reliability Coordinators can reach different conclusions to address a common event during real-time operations.

Jennifer Bray, Arizona Electric Power Cooperative, Inc., 1, 8/3/2020

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Joshua Andersen, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

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Daniela Atanasovski, APS - Arizona Public Service Co., 1, 8/3/2020

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CenterPoint Energy Houston Electric, LLC supports the comments as submitted by EEI.

Larisa Loyferman, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

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Dennis Chastain, On Behalf of: Tennessee Valley Authority - SERC - Segments 1, 3, 5, 6

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Teresa Krabe, Lower Colorado River Authority, 5, 8/3/2020

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NV Energy supports the comments provided by EEI:

While the latest modifications are an improvement over the previously proposed modifications, EEI does not support certain changes made to FAC-011-04, FAC-014-3, TOP-001-6 and IRO-008-3 with regard to SOL exceedance use and determinations.  Specifically, the proposed FAC-011-4 modifications contain requirements related to the establishment of limits, contingency events, and performance framework that eliminate a necessary level of flexibility and clarity that currently exists in the FAC-011-3 Reliability Standard.  Requirement 6, subpart 6.1/6.1.3 of FAC-011-4 affords entities little flexibility when determining stability performance for system conditions with no contingencies by requiring “predetermined stability limits” to not be exceeded. (R6.1)  This seems to be in contrast with the flexibility afforded for single contingency conditions, which require the “stable performance criteria defined in the Reliability Coordinator’s SOL methodology” to be met, based on predetermined stability limits or adjusted with real-time or offline analysis techniques. (R6.2).  EEI suggest that R6.1.3 be removed or revised to more closely aligned with R6.2.

Additionally, the implementation plan proposed by the SDT should be extended to account for the extensive work that may be required by responsible entities to document and track what is expected to be a significantly larger numbers of documented exceedances under the proposed new FAC-011-04 and associated TOP-001-6 Reliability Standards.  Many entities may need to make certain enhancements to systems such as their energy management systems (EMS) and/or Real-time Contingency Analysis (RTCA) tools to accurately track and validate exceedances.  New servers and other associated hardware, as well as software modifications may be necessary to meet these new logging requirements to track exceedances of very short duration and to record mitigation responses for every SOL exceedance regardless of the duration.  This situation is further complicated for those entities using dynamic line ratings (e.g., ambient temperature ratings or wind speed adjusted ratings).  To address this issue, the industry will need time to make these adjustments.  Consequently, the 12 month implementation timeframe should be extended to a minimum of 24 months.

Kevin Salsbury, Berkshire Hathaway - NV Energy, 5, 8/3/2020

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On behalf of Exelon, Segments 1, 3, 5, & 6

Exelon concurs with the comments submitted by the EEI. 

Daniel Gacek, Exelon, 1, 8/3/2020

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We believe the future for SOL communication will require automation for exceedances to be logged and reported, as based on RC and TOP methodology.  We have concerns with an increase in data logging requirements and ask the SDT to look at TOP-001 and we question whether it is the best place for specifications for determining real-time assessments? Perhaps it is better in TOP-002?  Also we believe an SOL needs to be clearly defined and not open to interpretation from region to region.  In addition, we believe that a 12 month implementation plan wouldn't allow enough time to incorporate these new changes, to procure hardware and software, and therefore we ask that a 30 month implementation plan be implemented.

David Jendras, Ameren - Ameren Services, 3, 8/3/2020

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Scott Langston, Tallahassee Electric (City of Tallahassee, FL), 1, 8/3/2020

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Carl Pineault, Hydro-Qu?bec Production, 5, 8/3/2020

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Michael Jones, National Grid USA, 1, 8/3/2020

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Please consider a 24 calendar month implementation plan, instead of 12 calendar months.  Additional tracking, validation, and documentation of exceedances will be necessary.  Enhancements to existing tracking tools may be required.

NPCC Regional Standards Committee, Segment(s) 10, 2, 4, 7, 3, 1, 5, 6, 7/8/2020

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While the latest modifications are an improvement over the previously proposed modifications, EEI does not support certain changes made to FAC-011-04, FAC-014-3, TOP-001-6 and IRO-008-3 with regard to SOL exceedance use and determinations.  Specifically, the proposed FAC-011-4 modifications contain requirements related to the establishment of limits, contingency events, and performance framework that eliminate a necessary level of flexibility and clarity that currently exists in the FAC-011-3 Reliability Standard.  Requirement 6, subpart 6.1/6.1.3 of FAC-011-4 affords entities little flexibility when determining stability performance for system conditions with no contingencies by requiring “predetermined stability limits” to not be exceeded. (R6.1)  This seems to be in contrast with the flexibility afforded for single contingency conditions, which require the “stable performance criteria defined in the Reliability Coordinator’s SOL methodology” to be met, based on predetermined stability limits or adjusted with real-time or offline analysis techniques. (R6.2).  EEI suggest that R6.1.3 be removed or revised to more closely aligned with R6.2.

Additionally, the implementation plan proposed by the SDT should be extended to account for the extensive work that may be required by responsible entities to document and track what is expected to be a significantly larger numbers of documented exceedances under the proposed new FAC-011-04 and associated TOP-001-6 Reliability Standards.  Many entities may need to make certain enhancements to systems such as their energy management systems (EMS) and/or Real-time Contingency Analysis (RTCA) tools to accurately track and validate exceedances.  New servers and other associated hardware, as well as software modifications may be necessary to meet these new logging requirements to track exceedances of very short duration and to record mitigation responses for every SOL exceedance regardless of the duration.  This situation is further complicated for those entities using dynamic line ratings (e.g., ambient temperature ratings or wind speed adjusted ratings).  To address this issue, the industry will need time to make these adjustments.  Consequently, the 12 month implementation timeframe should be extended to a minimum of 24 months.

Mark Gray, On Behalf of: Edison Electric Institute, NA - Not Applicable, Segments NA - Not Applicable

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Please consider a 24 calendar month implementation plan, instead of 12 calendar months.  Additional tracking, validation, and documentation of exceedances will be necessary.  Enhancements to existing tracking tools may be required.

Eversource Group, Segment(s) 3, 1, 4/12/2019

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ITC supports the direction of the changes made to FAC-011-04, FAC-014-3, TOP-001-6 and IRO-008-3 with regard to SOL exceedance use and determinations.  However, the implementation plan should be extended to account for the additional work by responsible entities to document and track what is expected to be a significantly larger number of documented exceedances under the proposed new FAC-011-04 and associated TOP-001-6 Reliability Standards.  Companies will need to make certain enhancements to systems such as their energy management systems (EMS) and/or Real-time Contingency Analysis (RTCA) tools to track accurately exceedances and validate exceedances.  Consequently, the 12 month implementation timeframe would be insufficient to implement the new requirements and therefore request that the SDT extend the implementation plan to at least 24 months.

 

ITC believes however that in a similar way that industry responded to FAC-015, the same concerns exist for FAC-014-3 R7.  Transmission Planners refer to TPL-001-4 (-5).  It seems misplaced to have a requirement concerning the Near Term Assessment and its results in a FAC-014 standard.

Allie Gavin, On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1

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Robert Hirchak, Cleco Corporation, 6, 8/3/2020

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The Evergy companies support, and incorporate by reference, Edison Electric Institute’s response to Question No. 1. 

 

Westar-KCPL, Segment(s) 1, 3, 5, 6, 12/18/2018

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SPP Standards Review Group, Segment(s) 2, 8/3/2020

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IPL offers no further comments.

 

Colleen Campbell, AES - Indianapolis Power and Light Co., 3, 8/3/2020

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Oncor supports EEI comments.

Lee Maurer, Oncor Electric Delivery, 1, 8/3/2020

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The ISO/RTO Council Standards Review Committee (IRC SRC) supports the changes made by the SDT to FAC-011-4, FAC-014-3, TOP-001-6 and IRO-008-3 with regard to SOL exceedance use and determination.

 

That said, the IRC SRC offers the following comment for SDT consideration. While the IRC SRC agrees with the SDT that planned manual load shedding is a last resort, we believe a slight modification to the wording of FAC-011-4, Part 6.4 is warranted to reflect that planned manual load shedding should only be implemented after all available System adjustments have been assessed and determined that no other available System adjustments can be accomplished in the time available to return the flow within limits without the risk of unplanned load shedding. 

Proposed revision to FAC-011-4, Part 6.4: “planned manual load shedding is acceptable only after all available System adjustments have been assessed (delete made).”  

 

Note: SPP was not party to the comment for Question #1.

ISO/RTO Standards Review Committee, Segment(s) 2, 8/3/2020

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MISO supports the comments filed by the IRC SRC.

The ISO/RTO Council Standards Review Committee (IRC SRC) supports the changes made by the SDT to FAC-011-4, FAC-014-3, TOP-001-6 and IRO-008-3 with regard to SOL exceedance use and determination.

 

That said, the IRC SRC offers the following comment for SDT consideration. While the IRC SRC agrees with the SDT that planned manual load shedding is a last resort, we believe a slight modification to the wording of FAC-011-4, Part 6.4 is warranted to reflect that planned manual load shedding should only be implemented after all available System adjustments have been assessed and determined that no other available System adjustments can be accomplished in the time available to return the flow within limits without the risk of unplanned load shedding. 

Proposed revision to FAC-011-4, Part 6.4: “planned manual load shedding is acceptable only after all available System adjustments have been assessed.”  

 

Bobbi Welch, Midcontinent ISO, Inc., 2, 8/3/2020

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Aaron Staley, Orlando Utilities Commission, 1, 8/3/2020

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Mickey Bellard, On Behalf of: Seminole Electric Cooperative, Inc., SERC, Segments 1, 5

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James Baldwin, Lower Colorado River Authority, 1, 8/3/2020

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FAC-014-3 The statement “any  instability identified in its Planning Assessment of the Near-Term Transmission…” seems unclear.  I think an improvement and more clear statement might be, “any stability criteria violation identified in its Planning Assessment of the Near-Term Transmission…”.

 

The revision that Oncor is proposing also seems to better align with the deliverables outlined in R7.1 – R7.5, and in particular, R7.3: The associated stability criteria violation requiring the Corrective Action Plan (e.g. violation of transient voltage response criteria or damping rate criteria).

 

Tammy Porter, On Behalf of: Tammy Porter - - Segments

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None.

Brandon Gleason, Electric Reliability Council of Texas, Inc., 2, 8/3/2020

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ACES believes that the revisions made by the SDT will improve the reliability with regard to SOL exceedance. However, it does not provide consistent framework for defining SOL exceedances for all registered entities. Therefore, two adjacent Reliability Coordinators can reach different conclusions to address a common event during real-time operations.

ACES Standard Collaborations, Segment(s) 1, 8/3/2020

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California ISO agrees with comments submitted by the ISO/RTO Counsel (IRC) Standards Review Committee.

Jamie Johnson, California ISO, 2, 8/3/2020

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Denise Sanchez, On Behalf of: Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Tino Zaragoza, Imperial Irrigation District, 1,3,5,6; Tino Zaragoza, Imperial Irrigation District, 1,3,5,6; Diana Torres, Imperial Irrigation District, 1,3,5,6; Diana Torres, Imperial Irrigation District, 1,3,5,6; Glen Allegranza, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6

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Oncor supports the comments submitted by EEI.

Gul Khan, On Behalf of: Oncor Electric Delivery - Texas RE - Segments 1

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Support the MRO-NSRF comments.

Wayne Guttormson, SaskPower, 1, 8/3/2020

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Please see comments submitted by Edison Electric Institute

Kenya Streeter, Edison International - Southern California Edison Company, 6, 8/3/2020

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WAPA partially agrees with the SDT revisions that address how SOL exceedances are determined and used in FAC-011-4, FAC-014-3, TOP-001-6 and IRO-008-3.  The flexibility afforded to each Reliability Coordinator to determine its own framework based upon its SOL methodology is an absolute must, but the concept of “a risk-based approach for determining how SOL exceedances identified as part of Real-time monitoring and Real-time Assessments” is problematic and vague.  It is noted that the concept of a “risk-based approach” does not carry over into the actual selection of single or multiple Contingency events which is a core tenet of the existing FAC-011-3.  Incorporating aspects of risk are essential to the establishment of SOL exceedances (e.g., defining credible multiple contingencies) and should be addressed in each Reliability Coordinators SOL methodology, but this perpetuates the confusion that has plagued the existing FAC-011-4 and elsewhere.

sean erickson, Western Area Power Administration, 1, 8/3/2020

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FAC-011-4 contains quite a number of required changes to the RC’s SOL Methodology to try to align it more for use with Planning Horizon studies.  The changes generally seem appropriate, but questions remain about the details of implementation – have all differences between Planning and Operations been adequately considered?  A detailed parsing of each RC’s existing SOL Methodology versus a draft modified according to this standard may be needed to fully grasp the potential for issues related to these changes. 

PG&E has no concerns with the applicable use of TOP-001-6 for SOL exceedance and determinations.

Pamalet Mackey, On Behalf of: Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5

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FAC-011-4 contains quite a number of required changes to the RC’s SOL Methodology to try to align it more for use with Planning Horizon studies.  The changes generally seem appropriate, but questions remain about the details of implementation – have all differences between Planning and Operations been adequately considered?  A detailed parsing of each RC’s existing SOL Methodology versus a draft modified according to this standard may be needed to fully grasp the potential for issues related to these changes. 

PG&E has no concerns with the applicable use of TOP-001-6 for SOL exceedance and determinations.

Marco Rios, Pacific Gas and Electric Company, 1, 8/3/2020

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While FAC-011-4 requires the RC to Provide Planning Coordinators and Transmission Planners with the RC Methodology, FAC-014-3 does not allow the Planning Coordinators and Transmission Planners to respond to the RC established SOLs and requirese the Planning Coordinators and Transmission Planners to establish their own SOLs that are equally limiting or more limiting than the RC established SOLs.

What if there is a technical problem with the RC established SOLs. There is not listed recourse in FAC-014-3 for the PC or the TP to provide comments on technical problems with the RC established SOLs and a requirement that the RC address those problems.

Clark Public Utilities is a small utility and as a TP, it doubts that the RC West is going to be very concerned about Clark's small area of 115 kV transmission. RC West has already informed Clark by email that it will only be in direct contact with its BA and TOP members and Clark need to go through its TOP (Bonneville Power Administration) to deliver its annual Transmission Planning Assessment. FAC-011 and FAC-014 need to address the changed relationship between non-BA and non-TOP entities in the West that are part of the RC West Reliability Coordinator footprint.

RC West's relationship with non-BAs and non-TOPs is different that the Peak RC relationship, RC West seems only to want to deal directly with the larger organizations. While this may only be a situation in the West, NERC should look closer at what the RC to other entity relations should be so the overall compliance can be more efficient and so that smaller entities are not creating work that is not going to be used. That is just paper pushing to make sure a compliance box is checked off and is not doing anything to assure reliability.

Clark believes that the relationship heirarchy for the Operating Horizon should be from the RC to the Planning Coordinator to the Transmission Planner. The Planning Coordinator should develop its SOL Methodology using the RC Methodology and RC Contingincies for the Operating Horizon and its own methodology and its own contingencies for the Planning Horizon. The PC should distribute its methodology and contingency list to Transmission Planners in its footprint. TPs then should have the ability to coordinate their own contingincies with the PC provided contingincy list. Once that is done (i.e. the TP and PC agree on the contingencies to be used in studies) the TP should then establish its SOLs for the Operating Horizon and Planning Horizion and provide those to its PC for comments and revision or approval. The PC should provide its consoldated SOLs for the Operating Horizon and Planning Horizion to the RC for comments and revision or approval. Then the RC should provide the final approved list of SOLs for all PCs and TPs in its footprint to all TOPs in its footprint.

Jack Stamper, Clark Public Utilities, 3, 8/21/2020

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Hot Answers

See SEE, EEI and MISO comments

Maurice Paulk, On Behalf of: Cleco Corporation, , Segments 1, 3, 5, 6

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Ray Jasicki, 8/24/2020

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Other Answers

Besides the concerns expressed in response to question 1, what is the purpose of communicating SOL exceedances to the Reliability Coordinator? If the purpose is for the Reliability Coordinator’s Real-time monitoring and/or Real-time Assessments, then the data specification concept is a more effective and efficient method and should be maintained in IRO-010-2 where each Reliability Coordinator has the flexibility to determine the items that need reported, the method and a timeframe based on their individual operating environment. Having this requirement detached in FAC-011 could lead to misunderstanding of context, expectations and/or compliance failures, which is contrary to ongoing work by the Standards Efficiency Review project to simplify data exchange requirements, reduce administrative burdens and remove redundancies. If not used for the Reliability Coordinator’s Real-time monitoring and/or Real-time Assessments, then please explain the purpose and the corresponding obligation by the Reliability Coordinator to use the information? Otherwise, it potentially becomes an administrative compliance exercise that distract our operations personnel and doesn’t benefit reliability. 

R7.2.2. Please explain the rationale for 30 minutes for this one specific item when (according to R6.1 and further explained in the System Operating Limit Definition and Exceedance Clarification whitepaper) pre-contingency exceedances of much shorter timeframes are an indication of unacceptable system performance? This requirement seems to imply the risk of high voltage is minimal for all registered entities and their equipment.

John Allen, City Utilities of Springfield, Missouri, 4, 7/15/2020

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Michael Courchesne, On Behalf of: Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2

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Laura Nelson, 7/24/2020

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NCPA supports John Allen's, City Utilities of Springfield, Missouri, comments.

Marty Hostler, On Behalf of: Northern California Power Agency, , Segments 3, 4, 5, 6

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Matthew Nutsch, On Behalf of: Seattle City Light, WECC, Segments 1, 3, 4, 5, 6

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Thomas Foltz, AEP, 5, 7/27/2020

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Bruce Reimer, Manitoba Hydro , 1, 7/27/2020

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Jennie Wike, On Behalf of: John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6

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“These comments represent the MRO NSRF membership as a whole but would not preclude members from submitting individual comments”.

The MRO NSRF agrees with the changes proposed by the SDT to FAC-011-4, TOP-001-6 and IRO-008-3. That said, MISO requests the SDT acknowledge that momentary errors or other specified short-term excursions above Emergency Limits will occur and be dispositioned in accordance with the RC’s SOL methodology. We would like to see this clarification in either the measures in the standard, the RSAW or Compliance Guidance

In addition, MRO NSRF requests the SDT consider implementing the clarifications below. Note that each request is presented independently for ease of review; however, when viewed collectively, there some requirements which would benefit from multiple clarifications that are additive:

Proposed Language (to clarify the description, if our interpretation of the SDT’s intent is correct):

FAC-011-4, R6. Each Reliability Coordinator shall include the following performance framework in its SOL methodology to determine SOLs exceedances when performing Real-time monitoring, Real-time Assessments, and Operational Planning Analyses

Proposed Language (to clarify what is intended; as currently written, exceeding the normal low System Voltage Limit could be interpreted as operating at a higher voltage than the minimum [i.e. exceeding the limit] which would not necessarily have adverse impacts unless the operating voltage was also exceeding the high System Voltage Limit):

FAC-011-4, R7.1.5. Pre-contingency operating conditions outside SOL exceedances of normal low System Voltage Limits.”

FAC-011-4, R7.2.1. Post-contingency operating conditions outside SOL exceedances of Facility Ratings and emergency System Voltage limits, and

Proposed Language (to add clarity by adding a reference to the corresponding description under FAC-011, requirement R6, if our interpretation of the SDT’s intent is correct):

FAC-011-4, 7.1.4 “Facility Ratings as described in Part 6.1.1”

FAC-011-4, 7.2.1 “Facility Ratings as described in Part 6.2.1”

Proposed Language (to eliminate the potential interpretation that both parts 7.1.4 and 7.1.5 need to be true before the communication threshold is reached):

FAC-011-4, 7.1.4 “Pre-contingency SOL exceedances of Facility Ratings; and”

Proposed Language (to eliminate potential interpretation that use of the word “and” indicates both parts need to be true):

FAC-011-4, 7.2.1 “Post-contingency SOL exceedances of Facility Ratings; and emergency System Voltage limits, and“

7.2.2. Post-contingency SOL exceedances of emergency System Voltage Limits;

7.2.3. Pre-contingency SOL exceedances of normal high System Voltage Limits

MRO NSRF, Segment(s) 3, 4, 5, 6, 1, 2, 1/29/2020

Project 2015-09_SOLs Comment_Form-Final.docx

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LES feels that the sub-requirements listed in R7 may cause confusion as they relate to the performance criteria of R6. Suggest changing the word "of" to "based on", which will allow for a distinct correlation between what is and isn't a SOL exceedance. For example, 7.1.4 could be read as an independent check against Facility Ratings, which would raise the question whether it relates to Normal or Emergency Ratings. SOL exceedances should only be declared based on the performance criteria.

Lincoln Electric System, Segment(s) 5, 6, 3, 1, 4/17/2018

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Richard Jackson, U.S. Bureau of Reclamation, 1, 7/29/2020

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Vince Ordax, Florida Reliability Coordinating Council – Member Services Division , 8, 7/29/2020

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BC Hydro, Segment(s) 3, 5, 1, 12/18/2018

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Amy Casuscelli, On Behalf of: Michael Ibold, Xcel Energy, Inc., 1,3,5; Michael Ibold, Xcel Energy, Inc., 1,3,5; Michael Ibold, Xcel Energy, Inc., 1,3,5

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Duke Energy agrees with the revisions but due to the numerous methodologies, procedures, processes, tools, and training impacts associated with this Project, suggest extending implemenation period from 12 months to 30 months.

Duke Energy, Segment(s) 1, 5, 6, 4/11/2019

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Alliant Energy supports the comments submitted by the MRO NSRF.

Larry Heckert, Alliant Energy Corporation Services, Inc., 4, 7/30/2020

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MEC supports MRO NSRF comments.  The MRO NSRF agrees with the changes proposed by the SDT to FAC-011-4, TOP-001-6 and IRO-008-3. That said, MISO requests the SDT acknowledge that momentary errors or other specified short-term excursions above Emergency Limits will occur and be dispositioned in accordance with the RC’s SOL methodology. We would like to see this clarification in either the measures in the standard, the RSAW or Compliance Guidance

In addition, MRO NSRF requests the SDT consider implementing the clarifications below. Note that each request is presented independently for ease of review; however, when viewed collectively, there some requirements which would benefit from multiple clarifications that are additive:

Proposed Language (to clarify the description, if our interpretation of the SDT’s intent is correct):

FAC-011-4, R6. Each Reliability Coordinator shall include the following performance framework in its SOL methodology to determine SOLs exceedances when performing Real-time monitoring, Real-time Assessments, and Operational Planning Analyses

Proposed Language (to clarify what is intended; as currently written, exceeding the normal low System Voltage Limit could be interpreted as operating at a higher voltage than the minimum [i.e. exceeding the limit] which would not necessarily have adverse impacts unless the operating voltage was also exceeding the high System Voltage Limit):

FAC-011-4, R7.1.5. Pre-contingency operating conditions outside SOL exceedances of normal low System Voltage Limits.”

FAC-011-4, R7.2.1. Post-contingency operating conditions outside SOL exceedances of Facility Ratings and emergency System Voltage limits, and

Proposed Language (to add clarity by adding a reference to the corresponding description under FAC-011, requirement R6, if our interpretation of the SDT’s intent is correct):

FAC-011-4, 7.1.4 “Facility Ratings as described in Part 6.1.1”

FAC-011-4, 7.2.1 “Facility Ratings as described in Part 6.2.1”

Proposed Language (to eliminate the potential interpretation that both parts 7.1.4 and 7.1.5 need to be true before the communication threshold is reached):

FAC-011-4, 7.1.4 “Pre-contingency SOL exceedances of Facility Ratings; and”

Proposed Language (to eliminate potential interpretation that use of the word “and” indicates both parts need to be true):

FAC-011-4, 7.2.1 “Post-contingency SOL exceedances of Facility Ratings; and emergency System Voltage limits, and“

7.2.2. Post-contingency SOL exceedances of emergency System Voltage Limits;

7.2.3. Pre-contingency SOL exceedances of normal high System Voltage Limits

Terry Harbour, Berkshire Hathaway Energy - MidAmerican Energy Co., 1, 7/30/2020

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MEC Supports NSRF Comments

Darnez Gresham, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 7/30/2020

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1.       The construct in the proposed FAC-0114 (and Requirement R6) maintains how System Operators generally define IROLs today, and the long-standing operating practice where the loss of small or radial portions of the system is acceptable provided the performance requirements are not violated for the remaining bulk power system. 

 

The IESO suggests that the footnote to Requirement R6, sub-requirement 6.2.4 be expanded to include this industry practice, as follows: 

 

Sub-requirement R 6.2.4:

“ Instability, Cascading or uncontrolled separation that adversely impact the reliability of the Bulk Electrice System does not occur”[Footnote 1}

 

[Footnote 1] Stability evaluations and assessments of instability, Cascading, and uncontrolled separation can be performed using real-time stability assessments, predetermined stability limits or other offline analysis techniques. Loss of small or radial portions of the system is acceptable provided the performance requirements are not violated for the remaining bulk power system.

 

 

2.      The IESO seek clarification as to what is meant by  “expected to produce more severe System impacts” in R4 Sub-requirement 4.2?

Leonard Kula, Independent Electricity System Operator, 2, 7/30/2020

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Southern Company supports the inclusion of Requirement R7, which provides the industry with a risk-based approach for determining how SOL exceedances are identified, and how they are communicated, including timeframes, however; this does not fully address Southern Company’s specific concerns noted in Question 1 on the requirement revisions related to the establishment of limits, contingency events, and performance framework in FAC-011-4. 

Southern Company, Segment(s) 1, 3, 5, 6, 12/13/2019

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FE Voter, Segment(s) 1, 3, 5, 6, 4, 7/31/2020

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Joe O'Brien, NiSource - Northern Indiana Public Service Co., 6, 7/31/2020

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Dominion, Segment(s) 3, 5, 1, 9/19/2019

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ReliabilityFirst offers the following comments on FAC-011-4 for the SDT’s consideration.  In the clean version of FAC-011-4, in the “New or Modified Term(s) Used in NERC Reliability Standards” section of the Standard, it states: “None.” The term “System Operating Limit” has been modified and “System Voltage Limit” is newly defined.

 

Requirement R6 part 6.1.4, part 6.2.4, and part 6.3 references: “Instability, Cascading or uncontrolled separation that adversely impact the reliability of the Bulk Electric System does not occur.” What is the meaning of “that adversely impact the reliability of the Bulk Electric System does not occur?” Is it possible for instability, Cascading, or uncontrolled separation to NOT adversely impact the reliability of the BES? What is the criteria for determining if instability, Cascading, or uncontrolled separation do or do not adversely impact the reliability of the BES? These parts of Requirement R6 are open to interpretation, and therefore does not promote the reliability of the BES. Note that the NERC approved definition of IROL also uses the term “… that adversely impact the reliability of the Bulk Electric System.”

Requirement R7 does not specify which entities (TOPs? BAs? DPs?, etc.) are to be the receivers of the referenced communications of SOL exceedances. The “timeframe that communications must occur” are left to the discretion of the RC. The Requirement should be revised to clarify  which entities the RC must communicate SOL exceedances to, and to specify a timeframe for the communication (of SOL exceedances) to occur.

 

FAC-011-4 requires the RC to have a SOL methodology and to provide the methodology to other entities (including TOPs within the RC area). TOPs are required (per FAC-014) to establish SOLs consistent with the RC’s SOL methodology. The RC’s SOL methodology typically specifies that the model to be used covers the entire RC footprint, as well as at least portions of adjacent RC’s footprints. TOPs should not be required to follow an RC’s SOL methodology to include a model that covers the entire RC (and portions of adjacent RC’s) footprint. TOPs don’t typically have models this large.

Anthony Jablonski, ReliabilityFirst , 10, 7/31/2020

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Maryanne Darling-Reich, On Behalf of: Black Hills Corporation - MRO, WECC - Segments 1, 3, 5, 6

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Glenn Barry, Los Angeles Department of Water and Power, 5, 7/31/2020

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OKGE, Segment(s) 6, 1, 3, 5, 4/10/2019

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PPL NERC Registered Affiliates, Segment(s) 1, 3, 5, 6, 9/6/2018

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MPC supports comments submitted by the MRO NERC Standards Review Forum.

Andy Fuhrman, On Behalf of: Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1

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Truong Le, On Behalf of: Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Chris Gowder, Florida Municipal Power Agency, 3,4,5,6; Chris Gowder, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Richard Montgomery, Florida Municipal Power Agency, 3,4,5,6; Richard Montgomery, Florida Municipal Power Agency, 3,4,5,6; Carol Chinn, Florida Municipal Power Agency, 3,4,5,6; Carol Chinn, Florida Municipal Power Agency, 3,4,5,6; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3

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ATC believes the existing language of R7 may be adequate. However, we think some additional clarity on two specific requirements (R7.1.4 and R7.2.1) would benefit the industry. Both items relate back to how FAC-011-4 Requirement 7 does or does not tie back to the language of Requirement 6. In these two requirements, the clarification requested is, which Facility Ratings are in view as explained below.

New Requirement R7.1.4 states, “Pre-contingency SOL exceedances of Facility Ratings”. Based on our reading of the draft standard, we believe the SDT is referring to the thermal Facility Ratings described in requirement R6.1.1 (i.e. Normal and Emergency Ratings). R6.1.1 reads, “Steady state flow through Facilities are within Normal Ratings; however, Emergency Ratings may be used when System adjustments to return the flow within its Normal Rating could be executed and completed within the specified time duration of those Emergency Ratings.”

Similarly, requirement R7.2.1 reads, “Post-contingency SOL exceedances of Facility Ratings and emergency System Voltage limits”. We believe the SDT intends for “Facility Ratings” to correspond to the Facility Ratings described in R6.2.1 (“Steady State post-Contingency flow through Facilities are within applicable Emergency Ratings., provided that System adjustments could be executed and completed within the specified time duration of those Emergency Ratings. Steady state post-Contingency flow through a Facility must not be above the Facility’s highest Emergency Rating.”)

Regardless as to whether or not ATC’s interpretation is correct, we believe the industry will benefit in the future from greater clarity. For example, if ATC’s interpretation is correct, the SDT could add wording such as, “Facility Ratings as described in R6.1.1” for R7.1.4 and “Facility Ratings as described in R6.2.1” for R7.2.1.

ATC also has one minor comment on the formatting of R7.1 and R7.2 requirements. The word “and” appears in different sub-requirements, as shown below. We request the SDT review if “and” is correct wording to use, since a reader may interpret that all these items may need to be simultaneously true before the threshold is reached for communicating. The clearest example is R7.2.1. ATC believes that removing “and” and splitting up R7.2.1 as follows may be beneficial:

7.1.4. Pre-contingency SOL exceedances of Facility Ratings; and

7.1.5. Pre-contingency SOL exceedances of normal low System Voltage Limits.

7.2.1. Post-contingency SOL exceedances of Facility Ratings and

7.2.2 Post-contingency SOL exceedances of emergency System Voltage limits, and

7.2.3. Pre-contingency SOL exceedances of normal high System Voltage Limits.

LaTroy Brumfield, American Transmission Company, LLC, 1, 8/3/2020

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Steven Rueckert, Western Electricity Coordinating Council, 10, 8/3/2020

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BPA believes the proposed FAC-011-4 R7 is both too prescriptive and belongs in a TOP standard and Reliability Coordinator procedures developed under IRO-010. IRO-010 requires the Reliability Coordinator to document the information it needs to perform real-time monitoring, and this level of detail would be better left to that documentation. In addition to RC documentation, BPA believes the drafting team’s objective of minimizing burdensome notifications can be achieved through the following proposed edit to TOP-001 R15 (bold, italic text added):

R15. Each Transmission Operator shall inform its Reliability Coordinator of SOL exceedances determined by its Reliability Coordinator’s business procedures to merit notification.

Cain Braveheart, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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Mark Holman, 8/3/2020

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Sandra Shaffer, 8/3/2020

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Texas RE has the following recommendations regarding communication as described in proposed FAC-011-4 Requirement R7. 

  • Specify to whom the SOL exceedances must be communicated.

  • Add language to specify that communication of SOL exceedances includes prevention and mitigation (IRO-008-3 R6) and actions taken to return the System to within limits when a SOL has been exceeded (TOP-001-6 R15). Even if Part 7.1 SOL exceedance is mitigated within timeframes identified for communication of SOL exceedances, this information should be communicated. 

  • Add language to communicate post-Contingency SOL exceedances of “normal minimum System Voltage Limits” or “normal maximum System Voltage Limits”.  An exceedance could occur for an extended amount of time with no communication which may jeopardize the reliability of the System when the next Contingency occurs.

  • Specify the time duration for IROL exceedances to be communicated in Part 7.1.1. The NERC Glossary definition states that IROL Tv should not exceed 30 minutes.  Texas RE recommends the SDT consider adding language that the RC should communicate IROL exceedances within 30 minutes rather than its discretion. 

  • Remove “Outages” after “Cascading” in Part 7.1.3 since “Cascading Outages” is not a defined term per the NERC Glossary.

  • Capitalize “contingency” in Part 7.1.3 wherever used since it is a defined term in the NERC Glossary.  This includes “pre-“ and “post-“ usages.

  • Include a description of what “validated risk” in Part 7.1.3 means or when the risk should be validated. The case could exist where there could be “post-contingency SOL exceedances” identified but there is no defined duration (time period) for an RC to “validate” the risk.  An RC could take hours to validate that a contingency could occur that violated an Emergency Rating (time duration in minutes perhaps) and not communicate that issue in a timeframe that supports reliable operations (and 7.2 does not alleviate the concern.) 

 

Additionally, Texas RE inquires as to whether a post-contingency operating state is identified to have a validated risk of instability, Cascading Outages, and uncontrolled separation, but it is determined the instability, Cascading or uncontrolled separation that adversely impact the reliability of the Bulk Electric System, would this be required to be identified and communicated since it may not be an SOL exceedance per Part 6.4?

  • Use the terms “normal minimum” and “normal high” in Part 7.1.5 to be consistent with the proposed definition of System Voltage Limit. 

  • Specify a timeframe for the RC to communicate SOL exceedances that are not resolved within 30 minutes in Parts 7.1 and 7.2.  If the SOL exceedance is not communicated timely, multiple entities could be working to mitigate the issue and the actions could potentially conflict with each other.  Affected entities should be coordinating so they know what is being done and will not affect each other.  They should confirm what each is doing to mitigate the SOL exceedance.  For example, the RC could be taking certain measures at the same time an LCC is taking different measures.  If they are not communicating, this could lead to adverse effects.

  • Capitalize “limits” in Part 7.1.2 since it is part of the proposed term System Voltage Limits.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 8/3/2020

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Jennifer Bray, Arizona Electric Power Cooperative, Inc., 1, 8/3/2020

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Joshua Andersen, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

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Daniela Atanasovski, APS - Arizona Public Service Co., 1, 8/3/2020

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CenterPoint Energy Houston Electric, LLC supports the comments as submitted by EEI.

Larisa Loyferman, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

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Dennis Chastain, On Behalf of: Tennessee Valley Authority - SERC - Segments 1, 3, 5, 6

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Teresa Krabe, Lower Colorado River Authority, 5, 8/3/2020

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NV Energy supports the following comments provided by EEI:

EEI supports the inclusion of Requirement R7, which provides the industry with a risk-based approach for determining how SOL exceedances are identified, and how they are communicated, including timeframes.  However, the implementation timeframe should be increased to allow for the increased burden of both identifying and validating exceedances.  The SDT should modify the implementation plan to provide at least 24 months to allow the industry to address the proposed changes.

Kevin Salsbury, Berkshire Hathaway - NV Energy, 5, 8/3/2020

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On behalf of Exelon, Segments 1, 3, 5, & 6

Exelon concurs with the comments submitted by the EEI. 

Daniel Gacek, Exelon, 1, 8/3/2020

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In our opinion a 30 month implementation would be better because an entity may need to purchase new servers, or hardware, and software to meet logging obligations.  We are concerned with the burden of providing exceedances due to the level of detail required from our ISO that will also become our responsibility. We believe that a large amount of work will be required to document and log what is expected to be a much larger number of exceedances under the proposed new FAC-011-04 and TOP-001-6 Reliability Standards.

 

David Jendras, Ameren - Ameren Services, 3, 8/3/2020

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Scott Langston, Tallahassee Electric (City of Tallahassee, FL), 1, 8/3/2020

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Carl Pineault, Hydro-Qu?bec Production, 5, 8/3/2020

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Michael Jones, National Grid USA, 1, 8/3/2020

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Please consider a 24 calendar month implementation plan, instead of 12 calendar months. Additional tracking, validation, and documentation of exceedances will be necessary. Enhancements to existing tracking tools may be required.

NPCC Regional Standards Committee, Segment(s) 10, 2, 4, 7, 3, 1, 5, 6, 7/8/2020

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EEI supports the inclusion of Requirement R7, which provides the industry with a risk-based approach for determining how SOL exceedances are identified, and how they are communicated, including timeframes.  However, the implementation timeframe should be increased to allow for the increased burden of both identifying and validating exceedances.  The SDT should modify the implementation plan to provide at least 24 months to allow the industry to address the proposed changes.

Mark Gray, On Behalf of: Edison Electric Institute, NA - Not Applicable, Segments NA - Not Applicable

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No Comment

Eversource Group, Segment(s) 3, 1, 4/12/2019

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Requirement R7 of FAC-011-4 as currently written only provides the ability for a “risk based approach for determining how SOL exceedances identified as part of Real-time monitoring and Real-time Assessments must be communicated”, it does not seem to provide a risk based approach to how SOL exceedances are identified. If the intent is to provide the ability to use a risk based approach to determine how SOL exceedances are identified the language should be modified to make this clear. Requirement R7 could be reworded to say:

 

“Each Reliability Coordinator shall include in its SOL methodology a risk-based approach for determining how SOL exceedances are identified as part of Real-time monitoring and Real-time Assessments and how they must be communicated and if so, the timeframe that communications must occur.”

 

If it is not the intent of the SDT to allow the identification of SOL exceedances to be risk based, requirement R7 may provide some relief from communication requirements that could be burdensome depending on the Reliability Coordinators’s SOL methodology, however it does not change that fact that Requirement 6 now makes any post contingent flow projected above a Facilities highest Emergency Rating an SOL exceedance. Some existing SOL methodologies allow for post contingent mitigation actions to be developed within 30 minutes in order to prevent this situation from becoming an SOL exceedance. It does seem appropriate that post contingent flow above the highest emergency rating would be an SOL exceedance, however this would be more stringent than what some have today and require more tracking, documentation, and communication. Consequently, the 12 month implementation timeframe would be insufficient to implement the new requirements and therefore request that the SDT extend the implementation plan to at least 24 months.  

Allie Gavin, On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1

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Robert Hirchak, Cleco Corporation, 6, 8/3/2020

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The Evergy companies do not support the proposed revision to FAC-011-4, TOP-001-6 and IRO-008-3 to address compliance risk and administrative logging. 

The revisions are ambiguous and proposed requirements unsustainable.  

There is inconsistency between R6.2 and R6.2.1, with the proposed language being confusing.  

Moreover, having both Normal Ratings and Emergency Ratings calculated under FAC-008, and, also, entities being required to use both Normal Ratings and Emergency Ratings, is concerning:  The revision would require operating at an Emergency Rating for a specified amount of time “under a no contingency scenario” rather than the current practice of operating up to an emergency rating indefinitely. 

Finally, the Evergy companies support, and incorporate by reference, Edison Electric Institute’s response to Question No. 2. 

 

Westar-KCPL, Segment(s) 1, 3, 5, 6, 12/18/2018

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FAC-011-4 R7

FAC-011-4 R7 implies the use of a “risk-based” approach for the communication aspects of R7.1.1 through R7.2.2.

“Risk-based” approach terminology is rare outside of FAC vegetation. As written, this terminology could result in compliance misinterpretation or misunderstanding by operations staff.

FAC Standards address the methodology of determining SOLs, COM Standards address the communication protocol between operations, and IRO Standards address interconnected operations of the Bulk Electric System (BES) including coordination with external entities.

The SPP Standards Review Group asks the SDT’s consideration that R7 should not be a Requirement in the FAC Standards, instead, included with the IRO Standards where it would be intuitive for operations staff to reference.

IRO-008-3 R5

IRO-008-3 R5 provides expectations of operations staff in real-time communication requirements needed to facilitate reliability. This Standard is intentionally, and properly, non-prescriptive in specific aspects of real-time or anticipated SOL risks, and does not introduce “risk-based” prescriptive actions for specific SOL events.

The SPP Standards Review Group considers IRO-008-3 R5 sufficient in requiring coordination and communication between entities that take place during SOL and IROL events. If necessary to document SOL methodologies that include the communication and coordination during such events, the SPP Standards Review Group recommends the methodologies should not be more descriptive than IRO-008-3 R5.

 

SPP Standards Review Group, Segment(s) 2, 8/3/2020

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IPL feels the industry needs more time with the implementation schedule to address coordination adjustments between RCs & TOPs to integrate the revisions of the RC’s SOL methodology based on the updated framework.  This could involve monitoring and system updates for efficient data transfers (automatic logging and reporting) to make these additional reporting requirements manageable for System Operators and Compliance Staff, and of course keeping the compliance records between the TOP and RC in lock-step.

The implementation plan document states that the “TOP-001-6” and “IRO-008-3” versions will be retired.  IPL believes these are typos (meant to list the older versions of TOP-001-5/IRO-008-2), the SDT will need to revise this document to provide the plan for TOP-001-6 and IRO-008-3.

Colleen Campbell, AES - Indianapolis Power and Light Co., 3, 8/3/2020

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Oncor supports EEI comments.

Lee Maurer, Oncor Electric Delivery, 1, 8/3/2020

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The IRC SRC agrees with the changes proposed by the SDT to FAC-011-4, TOP-001-6 and IRO-008-3. That said, the IRC SRC requests the SDT acknowledge that momentary errors or other specified short-term excursions above Emergency Limits will occur and be dispositioned in accordance with the RC’s SOL methodology. We would like to see this clarification in either the measures in the standard, the RSAW or Compliance Guidance.

 

In addition, the IRC SRC requests the SDT consider implementing the following clarifications:

 

Proposed Language (if our interpretation of the SDT’s intent is correct):

FAC-011-4, 7.1.4 “Facility Ratings as described in Part 6.1.1

FAC-011-4, 7.2.1 “Facility Ratings as described in Part 6.2.1

 

Proposed Language (to eliminate the potential interpretation that both parts 7.1.4 and 7.1.5 need to be true by removing the word 'and'):

FAC-011-4, 7.1.4 “Pre-contingency SOL exceedances of Facility Ratings; (delete and)

 

Proposed Language (to eliminate potential interpretation that use of the word “and” indicates both parts need to be true):

FAC-011-4, 7.2.1 “Post-contingency SOL exceedances of Facility Ratings;(Delete - and emergency System Voltage limits,  and)“

7.2.2. Post-contingency SOL exceedances of emergency System Voltage Limits;

7.2.3. Pre-contingency SOL exceedances of normal high System Voltage Limits

ISO/RTO Standards Review Committee, Segment(s) 2, 8/3/2020

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MISO supports the comments filed by the IRC SRC.

The IRC SRC agrees with the changes proposed by the SDT to FAC-011-4, TOP-001-6 and IRO-008-3. That said, the IRC SRC requests the SDT acknowledge that momentary errors or other specified short-term excursions above Emergency Limits will occur and be dispositioned in accordance with the RC’s SOL methodology. We would like to see this clarification in either the measures in the standard, the RSAW or Compliance Guidance.

 

In addition, the IRC SRC requests the SDT consider implementing the following clarifications:

Proposed Language (if our interpretation of the SDT’s intent is correct):

FAC-011-4, 7.1.4 “Facility Ratings as described in Part 6.1.1”

FAC-011-4, 7.2.1 “Facility Ratings as described in Part 6.2.1”

 

Proposed Language (to eliminate the potential interpretation that both parts 7.1.4 and 7.1.5 need to be true):

FAC-011-4, 7.1.4 “Pre-contingency SOL exceedances of Facility Ratings;”

 

Proposed Language (to eliminate potential interpretation that use of the word “and” indicates both parts need to be true):

FAC-011-4, 7.2.1 Post-contingency SOL exceedances of Facility Ratings;

7.2.2. Post-contingency SOL exceedances of emergency System Voltage Limits;

7.2.3. Pre-contingency SOL exceedances of normal high System Voltage Limits

Bobbi Welch, Midcontinent ISO, Inc., 2, 8/3/2020

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Aaron Staley, Orlando Utilities Commission, 1, 8/3/2020

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Mickey Bellard, On Behalf of: Seminole Electric Cooperative, Inc., SERC, Segments 1, 5

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James Baldwin, Lower Colorado River Authority, 1, 8/3/2020

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Tammy Porter, On Behalf of: Tammy Porter - - Segments

- 0 - 0

ERCOT is concerned that the meaning of “communicated” in Requirement R7 is not sufficiently clear.  ERCOT suggests that Requirement R7 be revised in order to clarify that communications may be electronic.  Similar to the measures accompanying IRO-008, Requirement R5, and TOP-001, Requirement R15, Requirement R7 should be revised to expressly permit electronic communications.  Moreover, ERCOT believes “electronic” communications should be defined to include the mere electronic posting of data that enables entities to access/view SOL exceedances.

 

ERCOT further notes that it intends to vote in favor of FAC-011-4, provided Requirement R7 is clarified to provide that communications may be electronic.

Brandon Gleason, Electric Reliability Council of Texas, Inc., 2, 8/3/2020

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ACES Standard Collaborations, Segment(s) 1, 8/3/2020

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California ISO agrees with comments submitted by the ISO/RTO Counsel (IRC) Standards Review Committee.

Jamie Johnson, California ISO, 2, 8/3/2020

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Denise Sanchez, On Behalf of: Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Tino Zaragoza, Imperial Irrigation District, 1,3,5,6; Tino Zaragoza, Imperial Irrigation District, 1,3,5,6; Diana Torres, Imperial Irrigation District, 1,3,5,6; Diana Torres, Imperial Irrigation District, 1,3,5,6; Glen Allegranza, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6

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Gul Khan, On Behalf of: Oncor Electric Delivery - Texas RE - Segments 1

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Support the MRO-NSRF comments.

Wayne Guttormson, SaskPower, 1, 8/3/2020

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Please see comments submitted by Edison Electric Institute

Kenya Streeter, Edison International - Southern California Edison Company, 6, 8/3/2020

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WAPA partially agrees with the SDT revisions that address how SOL exceedances are identified and communicated, but we do not agree with how the definitions of SOL versus SOL exceedances have been confused in FAC-011-4, specifically in Requirement R6 to include a performance framework in the Reliability Coordinator SOL methodology to determine SOLs exceedances when performing Real-time monitoring, Real-time Assessments, and Operational Planning Analyses.  We request that the SDT reconsider that the constraints that define how SOLs are established are categorically different than how exceedances are defined, identified in the Operations Horizon, and communicated.  

sean erickson, Western Area Power Administration, 1, 8/3/2020

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Generally, PG&E has no objections to the revisions, but has some concerns with implementation for FAC-011-4.

Pamalet Mackey, On Behalf of: Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5

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Generally, PG&E has no objections to the revisions, but has some concerns with implementation for FAC-011-4.

Marco Rios, Pacific Gas and Electric Company, 1, 8/3/2020

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No. FAC-014 is administratively burdonsome on small entites by requiring it to accept RC established SOLs without any recourse to address technical problems with the RC established SOLs. It the RC is going to establish and communicate SOLS to a PC or a TP, there should be the ability for the PC or the TP to provide comments and a requirement for the RC to address those comments.

A better approach is discribed in Clark's answer to Question 1. Pay more attention to the changes that are occuring in the west (and maybe elsewhere). The RC is more eficient when dealing with larger entities (BAs, TOPs, and PCs). PCs should be the driving entity for work performed by TPs in the PC footprint. PCs establish the SOL Methodology (using the RC methodology for the Operings Horizon) used by its TPs,and would then consolidate its planning study results with the approved TP planning study results. The PC would then provide the consolidated results to the RC who would in turn provide the approved final SOL list to its TOPs'

Jack Stamper, Clark Public Utilities, 3, 8/21/2020

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Hot Answers

Maurice Paulk, On Behalf of: Cleco Corporation, , Segments 1, 3, 5, 6

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Ray Jasicki, 8/24/2020

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Other Answers

The standards need to be results-based and define a clear and measurable expected outcome for all Registered Entities. By adding “that adversely impact the reliability of the Bulk Electric System” implies that some instability, Cascading or uncontrolled separation is acceptable. Who determines that threshold? The Reliability Coordinator in its SOL methodology? How do we ensure a consistent expectation and application for all Registered Entities?

John Allen, City Utilities of Springfield, Missouri, 4, 7/15/2020

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Michael Courchesne, On Behalf of: Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2

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Laura Nelson, 7/24/2020

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NCPA supports John Allen's, City Utilities of Springfield, Missouri, comments.

Marty Hostler, On Behalf of: Northern California Power Agency, , Segments 3, 4, 5, 6

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Matthew Nutsch, On Behalf of: Seattle City Light, WECC, Segments 1, 3, 4, 5, 6

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Thomas Foltz, AEP, 5, 7/27/2020

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The changes to these standards place a considerable reporting requirement on SOL exceedance. Manitoba Hydro is requesting 30 month implementation period rather than, normal 12 months implementation period to work out SOL reporting methodology with the RC.

Bruce Reimer, Manitoba Hydro , 1, 7/27/2020

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Jennie Wike, On Behalf of: John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6

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“These comments represent the MRO NSRF membership as a whole but would not preclude members from submitting individual comments”.

Please note that the NSRF has concerns that if the Implementation Plan is not adjusted to atleast 24 months that this may impact our Final Ballot of the Standards within this Project.

1. Extend the implementation timeframe - The MRO NSRF respectfully requests the SDT extend the timeframe for implementation from 12 to at least 24 calendar months to support the changes needed to comply with FAC-011-4, FAC-014-3, TOP-001-6 and IRO-008-3. Some entities will need to enhance existing tools to accurately track, validate and reconcile what is expected to be a significantly larger number of documented SOL exceedances; particularly in those instances where the Reliability Coordinator (RC) is not also the Transmission Operator (TOP). To support this change, it is anticipated that companies will need to make certain enhancements to systems such as their energy management systems (EMS) and/or Real-time Contingency Analysis (RTCA) tools in order to accurately track and validate SOL exceedances.  While many entities may already utilize these same tools to identify and track SOL exceedances, most will have to further enhance these tools if they use dynamic line ratings (e.g., ambient temperature ratings or wind speed adjusted ratings).  It is our understanding that most EMS and RTCA systems are not currently set up to distinguish the validity of exceedances in these situations.

Aside from tools, implementation of the new standards will also require collaboration between the RC and its respective TOPs to revise the SOL methodology and associated processes and procedures and provide relevant training to system operators. Additionally, a 24-month implementation timeframe would provide the time needed to budget, design, develop, test, implement and train on new processes and tools prior to placing them into production, particularly in light of the ongoing operational challenges associated with the COVID-19 pandemic and the anticipated demand this will place on EMS vendors as entities compete for limited resources. For these reasons, MRO NSRF is requesting the SDT consider extending the implementation timeframe to at least 24 months.

For this approach to be successful, the effective dates of FAC-011-4, FAC-014-3, TOP-001-6 and IRO-008-3 need to be synchronized so they coincide.

2. Coordinate common SOLs - The MRO NSRF respectfully requests the SDT to consider coordination of all common SOLs similar to what is proposed in FAC-011-4, Part 3.5 which requires the SOL methodology to define the method for determining common System Voltage Limits between the RC and its TOPs, between adjacent TOPs, and between adjacent RCs within an interconnection. 

3. Replace IROL language with “Adverse Reliability Impact” - The MRO NSRF respectfully requests the SDT replace language excerpted from the current IROL definition with the current definition of “Adverse Reliablity Impact” to indicate that no amount of instability, Cascading or uncontrolled separation is acceptable:

Proposed Language

FAC-011-4, Parts 6.1.4 and 6.2.4. Instability, Cascading or uncontrolled separation that adversely impact the reliability of the Bulk Electrice System Adverse Reliability Impacts does not occur. 

 Footnote 1, page 5: Stability evaluations and assessments of instability, Cascading, and uncontrolled separation Adverse Reliability Impacts can be performed using real-time stability assessments, predetermined stability limits or other offline analysis techniques

FAC-011-4, Part 6.3. System performance for applicable Contingencies identified in Part 5.2 demonstrates that: instability, Cascading or uncontrolled separation that adversely impact the reliability of the Bulk Electrice System Adverse Reliability Impacts does not occur

FAC-011-4, Part 7.1.3. Post-contingency SOL exceedances that are identified to have a validated risk of instability, Cascading Outages, and uncontrolled separation Adverse Reliability Impacts

MRO NSRF, Segment(s) 3, 4, 5, 6, 1, 2, 1/29/2020

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Lincoln Electric System, Segment(s) 5, 6, 3, 1, 4/17/2018

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None

Richard Jackson, U.S. Bureau of Reclamation, 1, 7/29/2020

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R4.6: Please clarify. Consider adding language to clarify the intent of this requirement as stated in the rationale.

R4.7: Please clarify. Consider adding language to clarify the intent of this requirement as stated in the rationale. Consider adding "for post-contingency mitigation" are not allowed....

Vince Ordax, Florida Reliability Coordinating Council – Member Services Division , 8, 7/29/2020

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BC Hydro agrees with the proposed FAC-011-4 R6 provides clarity on SOL exceedances that may alleviate the need for a glossary definition and offers the following comments and suggestions:

FAC-011-4 R6.2.1

The addition of “Steady state-post-Contingency flow through a Facility must not be above the Facility’s highest Emergency Rating” to “Steady State post-Contingency flow through Facilities within applicable Emergency Ratings” in Requirement 6.2.1 appears redundant and can possibly create confusion.

Please consider the following wording:

“Steady state-post-Contingency flow through a Facility must not be above the Facility’s highest applicable Emergency Rating”

Rationale for “applicable” is to reflect that Emergency Ratings must also observe the time duration requirement in the RC’s SOL Methodology, and also that the highest Emergency rating can change seasonally.

The currently proposed language in requirements R6.2.1 and R6.2.2 appears to imply a more nuanced post-contingency performance requirement for flow vs. voltage. As requirements R6.2.1 and R6.2.2 are conceptually the same, so BC Hydro suggest that the use of similar wording.

 

FAC-011-3 R3.4 “Identify the lowest allowable System Voltage Limit”

If RC is required to identify a specific low voltage limit across its entire RC area, this will likely be a theoretical limit, which may not address the reliability issues that exist in specific areas of the RC Area. Rather than prescribing a specific limit applicable across the system, a list of qualitative considerations for establishing voltage stability based SOLs could be included instead. These considerations  may include under voltage load shedding schemes design, voltage instability, loss of synchronism etc), and other prescriptions in support of accurate modeling of post contingency powerflow (e.g. low voltage limit not lower than value that could cause load trip due to process controls or motor contactors dropping etc.).

BC Hydro, Segment(s) 3, 5, 1, 12/18/2018

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Amy Casuscelli, On Behalf of: Michael Ibold, Xcel Energy, Inc., 1,3,5; Michael Ibold, Xcel Energy, Inc., 1,3,5; Michael Ibold, Xcel Energy, Inc., 1,3,5

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None.

Duke Energy, Segment(s) 1, 5, 6, 4/11/2019

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Alliant Energy supports the comments submitted by the MRO NSRF.

Larry Heckert, Alliant Energy Corporation Services, Inc., 4, 7/30/2020

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MEC supports MRO NSRF comments.  Please note that the NSRF has concerns that if the Implementation Plan is not adjusted to atleast 24 months that this may impact our Final Ballot of the Standards within this Project.months that this may impact our Final Ballot of the Standards within this Project.

1. Extend the implementation timeframe - The MRO NSRF respectfully requests the SDT extend the timeframe for implementation from 12 to at least 24 calendar months to support the changes needed to comply with FAC-011-4, FAC-014-3, TOP-001-6 and IRO-008-3. Some entities will need to enhance existing tools to accurately track, validate and reconcile what is expected to be a significantly larger number of documented SOL exceedances; particularly in those instances where the Reliability Coordinator (RC) is not also the Transmission Operator (TOP). To support this change, it is anticipated that companies will need to make certain enhancements to systems such as their energy management systems (EMS) and/or Real-time Contingency Analysis (RTCA) tools in order to accurately track and validate SOL exceedances.  While many entities may already utilize these same tools to identify and track SOL exceedances, most will have to further enhance these tools if they use dynamic line ratings (e.g., ambient temperature ratings or wind speed adjusted ratings).  It is our understanding that most EMS and RTCA systems are not currently set up to distinguish the validity of exceedances in these situations. 

Aside from tools, implementation of the new standards will also require collaboration between the RC and its respective TOPs to revise the SOL methodology and associated processes and procedures and provide relevant training to system operators. Additionally, a 24-month implementation timeframe would provide the time needed to budget, design, develop, test, implement and train on new processes and tools prior to placing them into production, particularly in light of the ongoing operational challenges associated with the COVID-19 pandemic

and the anticipated demand this will place on EMS vendors as entities compete for limited resources. For these reasons, MRO NSRF is requesting the SDT consider extending the implementation timeframe to at least 24 months.

For this approach to be successful, the effective dates of FAC-011-4, FAC-014-3, TOP-001-6 and IRO-008-3 need to be synchronized so they coincide.

Terry Harbour, Berkshire Hathaway Energy - MidAmerican Energy Co., 1, 7/30/2020

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MEC Supports NSRF Comments

Darnez Gresham, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 7/30/2020

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Leonard Kula, Independent Electricity System Operator, 2, 7/30/2020

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In addition to the specific concerns noted in Question 1, Southern Company offers the following comments on the SOL exceedance determination, use, and communications in FAC-011-4:  

1) Requirement 6.4 of FAC-011-4 should have additional clarity that the limitation on manual load shedding only refers to firm load consistent with FERC Order 693. Specifically, the following changes should be made

6.4 In determining the System’s response to any Contingency identified in Requirement R5, planned manual FIRM load shedding is acceptable only after all other available System adjustments have been made.

 

2) Additionally, the SOL whitepaper, of which the implementation of FAC-011-4 is largely based, appears to mistakenly refer to TOP-001-3 instead of TOP-001-6 on page 6

 

3) Lastly, the NERC timehorizon and the SOL whitepaper should add an additional time horizon of “Day-Ahead Operations” that can be used to clearly delineate the horizon in which SOLs are established and applicable in FAC-011-4. Ideally, Operations Planning horizon would be slightly modified to prevent overlap, but as this may impact other standards, it would be acceptable to leave more broad if necessary. Specifically, the new horizon would be termed “Day-Ahead Operations – operating and resource plans within the day-ahead timeframe” and replace the Operations Planning Horizon applicability of R5 through R9.

 

Detailed comments are in the attached file with special formatting for clarity and emphasis where needed (strike-through, highlighting, etc.).

Southern Company, Segment(s) 1, 3, 5, 6, 12/13/2019

2015-09_Unofficial_Comment_Form_202006 - SOCO Comments Final.pdf

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N/A

FE Voter, Segment(s) 1, 3, 5, 6, 4, 7/31/2020

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NIPSCO believes the Implementation Plan Effective Date is short and should be increased from twelve (12) calendar months to thirty-six (36) calendar months.

We will work with the EMS vendor to create a process for related logging. In addition to developing new processes, related training will need to be developed and delivered. Furthermore, MISO will develop and implement new methodology and protocols. This will all require additional time.

Joe O'Brien, NiSource - Northern Indiana Public Service Co., 6, 7/31/2020

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Dominion, Segment(s) 3, 5, 1, 9/19/2019

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Anthony Jablonski, ReliabilityFirst , 10, 7/31/2020

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Maryanne Darling-Reich, On Behalf of: Black Hills Corporation - MRO, WECC - Segments 1, 3, 5, 6

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Glenn Barry, Los Angeles Department of Water and Power, 5, 7/31/2020

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OGE supports MRO-NSRF’s recommendation to extend the timeframe for implementation from 12 to 24 calendar months.

OKGE, Segment(s) 6, 1, 3, 5, 4/10/2019

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PPL NERC Registered Affiliates, Segment(s) 1, 3, 5, 6, 9/6/2018

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MPC supports comments submitted by the MRO NERC Standards Review Forum.

Andy Fuhrman, On Behalf of: Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1

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Truong Le, On Behalf of: Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Chris Gowder, Florida Municipal Power Agency, 3,4,5,6; Chris Gowder, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Richard Montgomery, Florida Municipal Power Agency, 3,4,5,6; Richard Montgomery, Florida Municipal Power Agency, 3,4,5,6; Carol Chinn, Florida Municipal Power Agency, 3,4,5,6; Carol Chinn, Florida Municipal Power Agency, 3,4,5,6; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3

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ATC supports the changes proposed for the FAC-011, FAC-014, IRO-008 and TOP-001 standards. However, the 12 month implementation timeframe should be extended to 30 months. This additional time is needed to allow for the following sequential actions:

First, the RC will need to update its methodology (in the case of MISO, this will be through a stakeholder process).

Second, the TOP will need to update its operating practices and procedures to follow the revised RC methodology.

Finally, likely in parallel, the RC and TOP will need train staff to adhere to the new requirements and methodology and create new processes to ensure documentation is developed, either automatically or manually, as new SOL exceedances are managed as evidence of compliance.

LaTroy Brumfield, American Transmission Company, LLC, 1, 8/3/2020

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Some industry stakeholders believe the implementation plan should be 18 months as opposed to 12 months.

Steven Rueckert, Western Electricity Coordinating Council, 10, 8/3/2020

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Cain Braveheart, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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R4.2 A portion of the redline language, “applicable to the establishment of stability limits” is redundant to the language that starts the requirement.  The existing language “to meet the criteria specified in Part 4.1” already addresses the “that are expected to produce more severe System impacts”.  Only focusing on “its portion of the BES” could permit an RC or TOP to ignore addressing impacts to their neighboring TOP/RC, and as such should be expanded or dropped.

 

Given the intent is to indicate that not all the contingencies captured within R5 are applicable and/or required in order to establish stability limits, the following suggested language mirrors similar clarifying contingency language proposed by the SDT for  FAC-011-4 R6.3:

Proposed Language: Require that stability limits are established to meet the criteria specified in Part 4.1 for applicable Contingencies identified in Requirement R5.

 

R6.2.4 Instability, Cascading or uncontrolled separation that adversely impact the reliability of the Bulk Electric System does not occur.

Given that 6.2.4 is applicable only to System performance following contingencies, suggest that “does not” be replace with “would not”.

·      Proposed Language: Instability, Cascading or uncontrolled separation that adversely impact the reliability of the BES would not occur.

R7 The proposed language in R7 does not solely provide, as the rationale states, “a performance framework for determining SOL exceedances in the RC’s SOL methodology.”  Rather, it provided a communication framework around those SOL exceedances deemed reportable.  However, R7 does not indicate any requirement around the communication (from whom & to whom) beyond it being directed to take place by the RC’s methodology, which could include an RC communicating internally to itself.  The proposed language below proscribes a direction of communication.  If the SDT would prefer the RC’s methodology to spell out the communication path, then that need should be included in a sub-requirement of R7.

·      Proposed Language: Each Reliability Coordinator shall include in its SOL methodology a risk-based approach for determining which SOL exceedances identified as part of Real-time monitoring and Real-time Assessments must be communicated by the Transmission Operator or the Reliability Coordinator to impacted Transmission Operators or Reliability Coordinators, and if so, the timeframe that communications must occur. The approach shall include:

Mark Holman, 8/3/2020

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Sandra Shaffer, 8/3/2020

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Texas RE has the following additional comments for proposed FAC-011-4:

  • Stability is a defined term in the NERC Glossary, but is used throughout FAC-011 (e.g. stability limits, stability performance, steady-state voltage stability, angular stability) and is not capitalized. Texas RE recommends the SDT take steps to incorporate the defined term into the Standards, update the definition, or retire the definition as appropriate.

  • The language of Requirement R2 could imply that the RC owns Facilities, which is not typical. 

  • Texas RE recommends revising Requirement R2 to match the language in the rationale.  It should be revised to “…such that the Transmission Operators and their Reliability Coordinator(s) use common Facility Ratings.”

  • Requirement R3.1 shows System Voltage Limit(s) as both singular and plural.   Please review for correct grammar.

  • Texas RE recommends including a minimum bar for stability performance criteria in Requirement R4. As written, the RC has unlimited discretion to determine performance criteria that is used to establish stability limits, which can lead to action not being taken unless there is an Emergency.

  • Texas RE is concerned with the vague language in Part 4.2.  The current language indicates an entity will be expected to clearly demonstrate how stability limits are “expected” to produce more “severe” System impacts, but there is no threshold provided for what “severe” is. This language could result in an entity indicating all impacts are the same and there are no stability limits needed.
  • In Part 4.3, Texas RE recommends the SDT consider adding “or other Reliability Coordinators Areas within its Interconnection” unless it has an understanding that there is a need to confirm stability limits used in operations between RCs in different Interconnections.  Part 4.5 is similar: “other Reliability Coordinator Areas within its Interconnection.”

  • Part 5.3 only requires the RC to “[d]escribe the method(s) for identifying which, if any, of the Contingency events provided by the Planning Coordinator or Transmission Planner in accordance with FAC-014-3, Requirement R7, to use in determining stability limits.”  Texas RE recommends including language within FAC-011 or FAC-014 to require the RC to provide justification when Contingency events provided per FAC-014-3 R7 are not used in determining stability limits.

  • Texas RE noticed there is no discussion of thermal limits in FAC-011.  Does the SDT agree that thermal Facility Ratings are thermal SOLs?

     

Rachel Coyne, Texas Reliability Entity, Inc., 10, 8/3/2020

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Requirement 6 lists language stating “that adversely impact the reliability of the BES” without detailing what is considered “adverse impact.” This introduces inconsistences among the industry.

Jennifer Bray, Arizona Electric Power Cooperative, Inc., 1, 8/3/2020

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Joshua Andersen, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

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AZPS does not consider the intent of R4.2 to be clear.  The language “more servere” is broad and open to interpretation.  AZPZ requests that the STD add additional clarifying language to R4.2.

 

R4.2  Required that stability limits are established to meet the criteria specified in Part 4.1 for the contingencies identified in requirement R5 applicable to the establishment of stability limits that are expected to produce more severe system impacts on its portion of the BES.  

 

Additionally, AZPS supports the comments submitted by EEI regarding the need to extend the implementation dates for Requirements FAC-011-4 and  TOP-001-6.  AZPS agrees that entities will see an addition in workload to document and track what is expected to be a significantly larger number of documented exceedances under the proposed new FAC-011-04 and associated TOP-001-001-6.  Companies will need to make certain enhancements to systems such as their energy management systems (EMS) and/or Real-time Contingency Analysis (RTCA) tools to accurately track and validate exceedances.  While many entities may already utilize these tools to track exceedances, most will have to further enhance those tools if they are using dynamic line ratings (e.g., ambient temperature ratings or wind speed adjusted ratings).  It is our understanding that most of the EMS and RTCA systems are not currently set up to distinguish the validity of exceedances in these situations.  To address this issue, the industry will need time to make these adjustments.  Consequently, the 12 month implementation timeframe would be insufficient to implement the new requirements and therefore request that the SDT extend the implementation plan to at least 24 months.  

Daniela Atanasovski, APS - Arizona Public Service Co., 1, 8/3/2020

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The changes to this standard would place a considerable reporting requirement on SOL exceedance. Therefore, the implementation period of 12 months for the Reliability Coordinators and Transmission Operators/Transmission Owners to work out SOL reporting methodology should be extended to at least 24 months. Additionally, the changes to this standard places the obligation ont the Reliability Coordinator  to communicate SOL exceedance; however, if the information is not used by the Reliability Coordinators for Real-time monitoring and/or Real-time Assessments, it could potentially become an administrative compliance exercise that distracts Real Time Operations

Larisa Loyferman, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

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Dennis Chastain, On Behalf of: Tennessee Valley Authority - SERC - Segments 1, 3, 5, 6

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Teresa Krabe, Lower Colorado River Authority, 5, 8/3/2020

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NV Energy supports the following comments provided by EEI:

As stated in our comments for question 1 (above), changes to FAC-011-4 place a considerable reporting obligation on SOL exceedance. Therefore, the implementation period of 12 months for the Reliability Coordinators and Transmission Operators/Transmission Owners to develop new SOL reporting methodology and associated system enhancements merit extending the implementation period to at least 24 months. While this standard places the obligation on the Reliability Coordinator  to communicate SOL exceedance; if the information is not used by the Reliability Coordinators for Real-time monitoring and/or Real-time Assessments, it could become potentially an administrative compliance exercise that distracts Real Time Operations personnel from focusing on reliability. These new obligations also could be inconsistent with the ongoing work of the NERC Standards Efficiency Review project.

Kevin Salsbury, Berkshire Hathaway - NV Energy, 5, 8/3/2020

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On behalf of Exelon, Segments 1, 3, 5, & 6

Exelon concurs with the comments submitted by the EEI. 

Daniel Gacek, Exelon, 1, 8/3/2020

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David Jendras, Ameren - Ameren Services, 3, 8/3/2020

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Scott Langston, Tallahassee Electric (City of Tallahassee, FL), 1, 8/3/2020

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Carl Pineault, Hydro-Qu?bec Production, 5, 8/3/2020

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Michael Jones, National Grid USA, 1, 8/3/2020

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The addition of R4.7 in FAC-011-4 will have an impact on interconnection with lower system inertia such as the Québec Interconnection. 

 

Because of its unique characteristics (main generation centers located in the north, remote from the main load centers in the south), The QI has no potential viable BES Island in underfrequency conditions.  Therefore, the use of the UFLS Program does not relate to system separation.

The Quebec Variance in the NERC Standard PRC-006-3 reflects that situation.

 

As mentioned in the rationale box for PRC-006-3 requirement D.A.3, the UFLS Program is part of the Hydro-Québec TransÉnergie defense plan to cover extreme contingencies along with two other RAS.  Therefore, taking into account the reality of the QI, the use of the UFLS Program would relate more to R4.6 rather than R4.7.

 

We respectfully request the SDT extend the timeframe for implementation from 12 to at least 24 calendar months to support the changes needed to comply with FAC-011-4, FAC-014-3, TOP-001-6, and IRO-008-3. Some entities will need to enhance existing tools to accurately track, validate, and reconcile SOL exceedances; particularly in those instances where the Reliability Coordinator (RC) is not also the Transmission Operator (TOP). In addition to tools, implementation of the new standards will require collaboration between the RC and its respective TOPs to revise the SOL methodology and associated processes and procedures and provide relevant training to system operators. Additionally, a 24-month implementation timeframe would provide the time needed to budget, design, develop, test, implement and train on new processes and tools prior to placing them into production, particularly in light of the ongoing operational challenges associated with the COVID-19 pandemic and the anticipated demand this will place on EMS vendors as entities compete for limited resources. For these reasons, we are requesting the SDT consider extending the implementation timeframe to at least 24 months.

 

We would also like to suggest that additional clarity could be achieved by adding the additional phrase to FAC-011-4 R2, ‘ which type of owner-provided Facility Ratings are to be used...’.

 

The definition of SOL includes thermal, voltage, stability, and frequency (BAL) Operating Limits. FAC-011-4 explicitly talks about voltage and stability but is silent on thermal. We don’t believe the facility rating discussion addresses SOLs for thermal limitations. We believe it would provide more clarity if the term Thermal Operation Limit was used in place of Facility Limit.

NPCC Regional Standards Committee, Segment(s) 10, 2, 4, 7, 3, 1, 5, 6, 7/8/2020

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As stated in our comments for question 1 (above), changes to FAC-011-4 place a considerable reporting obligation on SOL exceedance. Therefore, the implementation period of 12 months for the Reliability Coordinators and Transmission Operators/Transmission Owners to develop new SOL reporting methodology and associated system enhancements merit extending the implementation period to at least 24 months. While this standard places the obligation on the Reliability Coordinator  to communicate SOL exceedance; if the information is not used by the Reliability Coordinators for Real-time monitoring and/or Real-time Assessments, it could become potentially an administrative compliance exercise that distracts Real Time Operations personnel from focusing on reliability. These new obligations also could be inconsistent with the ongoing work of the NERC Standards Efficiency Review project.

Mark Gray, On Behalf of: Edison Electric Institute, NA - Not Applicable, Segments NA - Not Applicable

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No Comment

Eversource Group, Segment(s) 3, 1, 4/12/2019

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Requirement R3.5 implies that adjacent Transmission Operators need to have common System Voltage Limits. While theoretically this might seem appropriate, it should be up to the adjacent Transmission Operators to determine acceptable System Voltage Limits for their systems.  The voltage limits of adjacent Transmission Operators don’t necessarily need to be common, however ITC agrees that Reliability Coordinators should be utilizing the same System Voltage Limits as the Transmission Operators. We also believe that adjacent Transmission Operators should coordinate their individual System Voltage Limits rather than requiring common System Voltage Limits.  The intent of the requirement should be reflected in the language.

 

Another option would be to modify Requirement R3.5 to say:

 

“Define the method for ensuring that System Voltage Limits are coordinated between Reliability Coordinators and Transmission Operators, and between adjacent Reliability Coordinators within an Interconnection.”

 

Requirement R5 seems to imply that all single contingency events listed in Requirement R5.1.1 should be included in the set of contingency events for use in determining stability limits. However Requirement R4.2 indicates that stability limits are established for only the contingencies that are expected to produce more severe system impacts. Requirement R4.2 is more appropriate as it would be unduly burdensome to expect that stability simulations be performed for all of the contingencies listed in Requirement R5.1.1. Requirement R5 should be split to make it clear that only the contingencies that are expected to produce more severe system impacts need to be considered for determining stability limits while all single contingencies (identified in Requirement R5.1.1) should be considered when perfomring Operational Planning Analysis and Real-time Assessments.

 

Implementation of these modifications to the standards will require collaboration between some Reliability Coordinators and their respective Transmission Operators to revise the SOL methodology and associated processes and procedures and provide relevant training to system operators. The implementation timeframe should be extended to at least 24 months in order to provide more time to budget, design, develop, test, implement and train on new processes and tools prior to placing them into production.

Allie Gavin, On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1

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Implementation plan of 12 months is too short to develop operator tools to track.See MISO and EEI comments.

Robert Hirchak, Cleco Corporation, 6, 8/3/2020

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The Evergy companies support, and incorporate by reference, Edison Electric Institute’s response to Question No. 3. 

 

Westar-KCPL, Segment(s) 1, 3, 5, 6, 12/18/2018

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The SPP Standards Review Group offers the following “non-content” considerations for SDT review:

1.         Implementation of the “blue box” concept, as in previous standards development processes, which could give industry insight on       proposed revisions.

 

2.         Consideration of the concept could assist in a seamless transfer of information to the future Guideline and Technical Basis        documentation.

SPP Standards Review Group, Segment(s) 2, 8/3/2020

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Colleen Campbell, AES - Indianapolis Power and Light Co., 3, 8/3/2020

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Oncor supports EEI comments.

Lee Maurer, Oncor Electric Delivery, 1, 8/3/2020

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The IRC SRC respectfully requests the SDT extend the timeframe for implementation from 12 to at least 24 calendar months to support the changes needed to comly with FAC-011-4, FAC-014-3, TOP-001-6 and IRO-008-3. Some entities will need to enhance existing tools to accurately track, validate and reconcile SOL exceedances; particularly in those instances where the Reliability Coordinator (RC) is not also the Transmisison Operator (TOP). In addition to tools, implementation of the new standards will require collaboration between the RC and its respective TOPs to revise the SOL methodology and associated processes and procedures and provide relevant training to system operators. Additionally, a 24-month implementation timeframe would provide the time needed to budget, design, develop, test, implement and train on new processes and tools prior to placing them into production, particularly in light of the ongoing operational challenges associated with the COVID-19 pandemic and the anticipated demand this will place on EMS vendors as entities compete for limited resources. For these reasons, the IRC SRC is requesting the SDT consider extending the implementation timeframe to at least 24 months.

 

The IRC/SRC would also like to suggest that additional clarity could be achieved by adding the additional phrase to FAC-011-4 R2, ‘ which type of owner-provided Facility Ratings are to be used...’.

 

The definition for SOL includes thermal, voltage, stability and frequency (BAL) Operating Limits. FAC-011-4 explicitly talks about voltage and stability but is silent on thermal. We don’t believe the facility rating discussion addresses SOLs for thermal limitations. We believe it would provide more clarity if the term Thermal Operation Limit was used in place of Facility Limit.

 

Requirement R5 is looking for a set of contingency for stability, RTA and OPA analysis. A set of contingencies can be a dynamic list based on system configuration (outages) that can change throughout the day or it’s simply the list of all BES elements in the footprint. We believe it would add clarity if the requirement said, ‘for a type of contingency for…’.

ISO/RTO Standards Review Committee, Segment(s) 2, 8/3/2020

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MISO supports the comments filed by the IRC SRC.

The IRC SRC respectfully requests the SDT extend the timeframe for implementation from 12 to at least 24 calendar months to support the changes needed to comly with FAC-011-4, FAC-014-3, TOP-001-6 and IRO-008-3. Some entities will need to enhance existing tools to accurately track, validate and reconcile SOL exceedances; particularly in those instances where the Reliability Coordinator (RC) is not also the Transmisison Operator (TOP). In addition to tools, implementation of the new standards will require collaboration between the RC and its respective TOPs to revise the SOL methodology and associated processes and procedures and provide relevant training to system operators. Additionally, a 24-month implementation timeframe would provide the time needed to budget, design, develop, test, implement and train on new processes and tools prior to placing them into production, particularly in light of the ongoing operational challenges associated with the COVID-19 pandemic and the anticipated demand this will place on EMS vendors as entities compete for limited resources. For these reasons, the IRC SRC is requesting the SDT consider extending the implementation timeframe to at least 24 months.

The IRC/SRC would also like to suggest that additional clarity could be achieved by adding the additional phrase to FAC-011-4 R2, ‘ which type of owner-provided Facility Ratings are to be used...’.

The definition for SOL includes thermal, voltage, stability and frequency (BAL) Operating Limits. FAC-011-4 explicitly talks about voltage and stability but is silent on thermal. We don’t believe the facility rating discussion addresses SOLs for thermal limitations. We believe it would provide more clarity if the term Thermal Operation Limit was used in place of Facility Limit.

Requirement R5 is looking for a set of contingency for stability, RTA and OPA analysis. A set of contingencies can be a dynamic list based on system configuration (outages) that can change throughout the day or it’s simply the list of all BES elements in the footprint. We believe it would add clarity if the requirement said, ‘for a type of contingency for…’.

Bobbi Welch, Midcontinent ISO, Inc., 2, 8/3/2020

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Aaron Staley, Orlando Utilities Commission, 1, 8/3/2020

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Mickey Bellard, On Behalf of: Seminole Electric Cooperative, Inc., SERC, Segments 1, 5

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James Baldwin, Lower Colorado River Authority, 1, 8/3/2020

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Tammy Porter, On Behalf of: Tammy Porter - - Segments

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ERCOT suggests the implementation period be extended from 12 to 24 months in order to allow sufficient time to make necessary system changes.

Brandon Gleason, Electric Reliability Council of Texas, Inc., 2, 8/3/2020

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Requirement 6 lists language stating “that adversely impact the reliability of the BES” without detailing what is considered “adverse impact.” This introduces inconsistences among the industry.

ACES Standard Collaborations, Segment(s) 1, 8/3/2020

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California ISO agrees with comments submitted by the ISO/RTO Counsel (IRC) Standards Review Committee.

Jamie Johnson, California ISO, 2, 8/3/2020

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Denise Sanchez, On Behalf of: Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Tino Zaragoza, Imperial Irrigation District, 1,3,5,6; Tino Zaragoza, Imperial Irrigation District, 1,3,5,6; Diana Torres, Imperial Irrigation District, 1,3,5,6; Diana Torres, Imperial Irrigation District, 1,3,5,6; Glen Allegranza, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6

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n/a

Gul Khan, On Behalf of: Oncor Electric Delivery - Texas RE - Segments 1

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Support MRO-NSRF comments for:

1. Extend the implementation timeframe

2. Coordinate common SOLs

Wayne Guttormson, SaskPower, 1, 8/3/2020

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Please see comments submitted by Edison Electric Institute

Kenya Streeter, Edison International - Southern California Edison Company, 6, 8/3/2020

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Certainly in FAC-011-4 Requirement R6, but also in the proposed PRC-023-5, CIP-014-3, and FAC-014-3, the pairing of “expected to result in instances of instability, Cascading, or uncontrolled separation” with “that adversely impacts the reliability of the Bulk Electric System” is unnecessarily redundant given that the Glossary of Terms definition of Adverse Reliability Impact is frequency-related instability; unplanned tripping of load or generation; or uncontrolled separation or cascading outages that affects a widespread area of the Interconnection.  It is not clear if the SDT intends for this language to mean anything other than “expected to result in instances of instability, Cascading, or uncontrolled separation.”  Additionally, the SDT is perpetuating the industry-wide ambiguity of the term “widespread” by invoking the reference (without capitalization) to “adversely impacts the reliability.”  A simple, logical change is to simply retain “expected to result in instances of instability, Cascading, or uncontrolled separation” and stop there

sean erickson, Western Area Power Administration, 1, 8/3/2020

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PG&E has no additional comments

Pamalet Mackey, On Behalf of: Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5

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PG&E has no additional comments.

Marco Rios, Pacific Gas and Electric Company, 1, 8/3/2020

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Jack Stamper, Clark Public Utilities, 3, 8/21/2020

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Hot Answers

See SEE, EEI and MISO comments

Maurice Paulk, On Behalf of: Cleco Corporation, , Segments 1, 3, 5, 6

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Ray Jasicki, 8/24/2020

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Other Answers

R6. This requirement is out of place in FAC-014 and should already be covered in the data provided via MOD-032-1 and model building effort via TPL-001-4 R1, which specifies that models “shall represent projected System conditions”. Therefore, why wouldn’t the models already contain Facility Ratings, System steady-state voltage limits and stability criteria that are equally limiting or more limiting than those used by the Reliability Coordinator? If there are significant differences between how the system is being planned and how it’s being operated, then that should be within the scope for auditing TPL-001-4 R1 today. Having this requirement detached in FAC-014 could lead to misunderstanding of context, expectations and/or compliance failures, which is not effective or efficient and contrary to ongoing work by the Standards Efficiency Review project.

Additionally, the two bulleted items are problematic since the development of Facility Ratings is the responsibility of the Transmission Owner in accordance with FAC-008. To allow the Planning Coordinator or Transmission Planner to develop a “less limiting” (higher) Facility Rating could lead to unrealistic and/or invalid Planning Assessments. The Planning Coordinator and/or Transmission Planner should not be allowed on their own to overrule the Transmission Owner’s ability to maintain conservative Facility Ratings in accordance with manufacture recommendations to protect its personnel and equipment. However, if the Planning Coordinators and Transmission Planners want to adjust system models with a higher Facility Rating based on a proposed system upgrade, then that is already allowed via TPL-001-4 R1, Part 1.1.3. (New planned Facilities and changes to existing Facilities).

R7. This requirement is out of place in FAC-014 and should be covered in TPL-001-4 R8 where the requirement for the Planning Coordinator and Transmission Planner to share information on their annual Planning Assessment resides. Having this requirement detached in FAC-014 could lead to misunderstanding of context, expectations and/or compliance failures, which is not effective or efficient and contrary to ongoing work by the Standards Efficiency Review project. Therefore, the list of entities in TPL-001-4 R8 should be enhanced to allow Reliabilty Coordinators and Transmission Operators the ability to request and receive this information. 

R8. This requirement is out of place in FAC-014 and should be covered in TPL-001-4 R8 where the requirement for the Planning Coordinator and Transmission Planner to share information on their annual Planning Assessment resides. Having this requirement detached in FAC-014 could lead to misunderstanding of context, expectations and/or compliance failures, which is not effective or efficient and contrary to ongoing work by the Standards Efficiency Review project. It also appears in the rationale document for FAC-014 the sole purpose of this requirement is to facilitate compliance administration needs for the Transmission Owners and Generator Owners. Therefore, the list of entities in TPL-001-4 R8 should be expanded to allow Transmission Owners and Generator Owners the ability to request and receive this information. 

John Allen, City Utilities of Springfield, Missouri, 4, 7/15/2020

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Michael Courchesne, On Behalf of: Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2

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Laura Nelson, 7/24/2020

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NCPA supports John Allen's, City Utilities of Springfield, Missouri, comments.

Marty Hostler, On Behalf of: Northern California Power Agency, , Segments 3, 4, 5, 6

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Matthew Nutsch, On Behalf of: Seattle City Light, WECC, Segments 1, 3, 4, 5, 6

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AEP disagrees with incorporating R6-R8 into FAC-014 as currently proposed. It is not clear exactly what the SDT believes the benefits would be of such an approach. FAC-014 and its obligations have historically been centric to the Operations Planning Time Horizon, not the Near/Long Term Planning Horizon as currently proposed in these most recent revisions. To do so would change the original intent and purpose of FAC-014 into something more reminiscent of TPL-001. We believe the SDT needs to clarify their strategies and intentions regarding the “mixing” of these time horizons, and for them to further consider the unintentional impacts of making such changes. The “planning assessments” proposed in FAC-014 seem redundant to that which is already required under TPL-001. We believe the SDT needs to be clear as to the intent of R6-R8 with regard to the Time Horizon. SOLs applied to support Operations Planning Time Horizon will be different than those applied to the Long-Term Planning Time Horizon. If the intent is to ensure SOLs applied in the Operations Planning Time Horizon are incorporated in any Planning Assessments performed, the existing language does not accomplish this. An RC’s stability limits may become obsolete and thus inapplicable in the planning time horizon as new generation is added.  When this happens, it is rather the TP’s and PC’s stability limits that ought to be communicated to the RC so the RC knows what to expect in the future. If industry and the SDT believe that the obligations proposed in R6-R8 are indeed worth pursuing, it may be worth considering including them within a new FAC standard of their own.

The revised FAC-014 R6, R7, and R8 apply directly to the conduct and communication of planning assessments. While we recognize that TPL-001 is not within scope of the project’s SAR, we believe such obligations are already captured as part of TPL-001.

FAC-014 R6 states “Each Planning Coordinator and each Transmission Planner shall implement a documented process”, but it is not clear exactly where the creation of this documented process is/was originally required.

Thomas Foltz, AEP, 5, 7/27/2020

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Bruce Reimer, Manitoba Hydro , 1, 7/27/2020

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Jennie Wike, On Behalf of: John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6

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“These comments represent the MRO NSRF membership as a whole but would not preclude members from submitting individual comments”.

R6 Concerns

The NSRF does not support incorporating R6 into FAC-014 for the following reasons:

Duplicative. Proposed R6 is covered by the data required under MOD-032-1 and TPL-001-4 R1 model building which specifies that models “shall represent projected System conditions.

Questions for SDT Consideration

1. Wouldn’t the models already evaluate System conditions against Facility Ratings, System steady-state voltage limits and stability criteria that are equally limiting or more limiting than those used by the RC?

2. Today, if there are differences, they should fall within the TPL-001-4 R1 audit scope.

Adds Reliability Risk. Transmission Owners are required to develop Facility Ratings under FAC-008. The proposed two bulleted subparts permit the Planning Coordinator or Transmission Planner to develop “less limiting” (higher) Facility Ratings. Inconsistencies between FAC-008 Facility Ratings and ratings developed under the R6 bulleted subparts can lead to unrealistic Planning Assessments or invalidate Planning Assessments, altogether.

The proposed bulleted subparts seek to address the described reliability risk by requiring PCs or TPs to submit a technical rationale to affected TPs, TOs, and RCs. The proposed revision to FAC-014-3 does not consider the possibility TPs, TOs, RCs not wanting to accept a risk posed by the technical rationale. As such, the PCs or TPs could effectively reject TP, TO, or RC concerns raised by the technical rationale and proceed to operate at the less limiting Facility Ratings, regardless of those concerns; for example, the Transmission Owner needing to maintain conservative Facility Ratings in accordance with manufacture recommendations to protect its personnel and equipment.

We would note, however, if the Planning Coordinators and Transmission Planners want to adjust system models with a higher Facility Rating based on a proposed system upgrade, there is a path to do so under TPL-001-4 R1, Part 1.1.3. (New planned Facilities and changes to existing Facilities).

R7 Concerns

The NSRF does not support incorporating R7 into FAC-014 for the following reasons:

Duplicative. The information sharing under proposed R7 is already addressed under TPL-001-4 R8, which establishes the Planning Coordinator and Transmission Planner are required to share information as part of their annual Planning Assessment.

Recommendation. Revise TPL-001-4 R8 to permit Reliability Coordinators and Transmission Operators to request and receive the CAPs information as reflected in proposed FAC-014 R7.

R8 Concerns 

The NSRF does not support incorporating R8 into FAC-014 for the following reasons:

Duplicative. The information sharing under proposed R8 is already addressed under TPL-001-4 R8, which establishes the Planning Coordinator and Transmission Planner are required to share information as part of their annual Planning Assessment.

Recommendation. Revise TPL-001-4 R8 to permit Transmission Owners and Generator Owners to request and receive the information in proposed FAC-014 R8, e.g. instability info, cascading and uncontrolled separation.

Clarification. It looks as if the rationale document for FAC-014 infers the sole purpose of this requirement is to facilitate compliance administration needs for the Transmission Owners and Generator Owners since they do not operate the system. If that is the intent, it would be helpful to clarify and unambiguously state that for purposes of transparency.

R6 R7 R8 Shared Concerns

Compliance Ambiguity. As stated, above, incorporating R6, R7, and R8 into FAC-014 creates inconsistencies within the context of the Standard, providing unclear performance expectations and ambiguity around potential noncompliance. As such, the proposed revisions are incompatible with the Standards Efficiency Review project’s effort to reduce ambiguity around compliance.

MRO NSRF, Segment(s) 3, 4, 5, 6, 1, 2, 1/29/2020

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Lincoln Electric System, Segment(s) 5, 6, 3, 1, 4/17/2018

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Richard Jackson, U.S. Bureau of Reclamation, 1, 7/29/2020

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Vince Ordax, Florida Reliability Coordinating Council – Member Services Division , 8, 7/29/2020

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BC Hydro, Segment(s) 3, 5, 1, 12/18/2018

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Amy Casuscelli, On Behalf of: Michael Ibold, Xcel Energy, Inc., 1,3,5; Michael Ibold, Xcel Energy, Inc., 1,3,5; Michael Ibold, Xcel Energy, Inc., 1,3,5

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Duke Energy recommends that FAC-014-3 R7 be modified to include the phrase “during the planning events” as an added measure of clarity.  For example: R7. Each Planning Coordinator and each Transmission Planner shall annually communicate the following information for Corrective Action Plans developed to address any instability identified “during the planning events” in its Planning Assessment of the Near-Term Transmission Planning Horizon to each impacted Transmission Operator and Reliability Coordinator.

Additionally, due to the numerous methodologies, procedures, processes, tools, and training impacts associated with this Project, suggest extending implementation period from 12 months to 30 months.

 

Duke Energy, Segment(s) 1, 5, 6, 4/11/2019

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Alliant Energy supports the comments submitted by the MRO NSRF.

Larry Heckert, Alliant Energy Corporation Services, Inc., 4, 7/30/2020

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MEC supports MRO NSRF comments. 

R6 Concerns

The NSRF does not support incorporating R6 into FAC-014 for the following reasons:

Duplicative. Proposed R6 is covered by the data required under MOD-032-1 and TPL-001-4 R1 model building which specifies that models “shall represent projected System conditions.

Questions for SDT Consideration

1. Wouldn’t the models already evaluate System conditions against Facility Ratings, System steady-state voltage limits and stability criteria that are equally limiting or more limiting than those used by the RC?

2. Today, if there are differences, they should fall within the TPL-001-4 R1 audit scope.

Adds Reliability Risk. Transmission Owners are required to develop Facility Ratings under FAC-008. The proposed two bulleted subparts permit the Planning Coordinator or Transmission Planner to develop “less limiting” (higher) Facility Ratings. Inconsistencies between FAC-008 Facility Ratings and ratings developed under the R6 bulleted subparts can lead to unrealistic Planning Assessments or invalidate Planning Assessments, altogether.

The proposed bulleted subparts seek to address the described reliability risk by requiring PCs or TPs to submit a technical rationale to affected TPs, TOs, and RCs. The proposed revision to FAC-014-3 does not consider the possibility TPs, TOs, RCs not wanting to accept a risk posed by the technical rationale. As such, the PCs or TPs could effectively reject TP, TO, or RC concerns raised by the technical rationale and proceed to operate at the less limiting Facility Ratings, regardless of those concerns; for example, the Transmission Owner needing to maintain conservative Facility Ratings in accordance with manufacture recommendations to protect its personnel and equipment.

We would note, however, if the Planning Coordinators and Transmission Planners want to adjust system models with a higher Facility Rating based on a proposed system upgrade, there is a path to do so under TPL-001-4 R1, Part 1.1.3. (New planned Facilities and changes to existing Facilities).

R7 Concerns

The NSRF does not support incorporating R7 into FAC-014 for the following reasons:

Duplicative. The information sharing under proposed R7 is already addressed under TPL-001-4 R8, which establishes the Planning Coordinator and Transmission Planner are required to share information as part of their annual Planning Assessment.

Recommendation. Revise TPL-001-4 R8 to permit Reliability Coordinators and Transmission Operators to request and receive the CAPs information as reflected in proposed FAC-014 R7.

 

R8 Concerns 

The NSRF does not support incorporating R8 into FAC-014 for the following reasons:

Duplicative. The information sharing under proposed R8 is already addressed under TPL-001-4 R8, which establishes the Planning Coordinator and Transmission Planner are required to share information as part of their annual Planning Assessment.

Recommendation. Revise TPL-001-4 R8 to permit Transmission Owners and Generator Owners to request and receive the information in proposed FAC-014 R8, e.g. instability info, cascading and uncontrolled separation.

Clarification. It looks as if the rationale document for FAC-014 infers the sole purpose of this requirement is to facilitate compliance administration needs for the Transmission Owners and Generator Owners since they do not operate the system. If that is the intent, it would be helpful to clarify and unambiguously state that for purposes of transparency.

R6 R7 R8 Shared Concerns

Compliance Ambiguity. As stated, above, incorporating R6, R7, and R8 into FAC-014 creates inconsistencies within the context of the Standard, providing unclear performance expectations and ambiguity around potential noncompliance. As such, the proposed revisions are incompatible with the Standards Efficiency Review project’s effort to reduce ambiguity around compliance.

Terry Harbour, Berkshire Hathaway Energy - MidAmerican Energy Co., 1, 7/30/2020

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MEC Supports NSRF Comments

Darnez Gresham, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 7/30/2020

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1.      The IESO is concerned that there is  no requirement for the affected RC to provide feedback on the technical rationale provided by the PC or TP for using less limiting ratings.  The IESO proposes to add a sub-requirement to establish this feedback loop between the affected entities and the PC or TP.  The proposed requirement would mirror Requirement R8, sub-requirement 8.1.  of Reliability Standard TPL-001-4 which allows the  recipient of the Planning Assessment results to provide documented comments on the results,  and the respective PC or TP to provide a documented response to that recipient within 90 calendar days of receipt of those comments:

 

Proposed Requirement R6, Sub-requirement 6.1:

“The  recipient of the technical rationale may provide documented comments on the results,  and the respective PC or TP to provide a documented response to that recipient within 90 calendar days of receipt of those comments”

 

Alternatively, the IESO would like to clarify if Requirement R8., subrequirement 8.1 is the feedback loop that can be used to address the lack of input from the affected entities on the technical rationale provided by the PC or TP on the use of less limiting ratings (this is based on the assumption that the technical rationale would be part of the Planning Assessment results). 

 

2.       Similar with the Reliability Standard TPL-001-4 where an RC can provide input on the Planning Assessment criteria, the IESO believes that the PC and TP should be afforded the reciprocal opportunity to provide input to its RC’s methodology and have the RC provide a document response. 

 

The IESO proposes to add Sub-requirement R9.3 to FAC-011-4 as follows:

 “9.3. If a recipient of the Reliability Coordinator SOL methodology provides documented comments on the methodology, the respective Reliability Coordinator shall provide a documented response to that recipient within 90 calendar days of receipt of those comments.”

 

3.      We find that Requirements R7 and R8 are duplicative of existing communication requirements within other Reliability Standards.  Specifically,

{C}o   Requirement R7 requires the PC and TP to communicate, annually any CAP identified in its Planning Assessments to the RC.  Requirement 8 in TPL-001-4 requires the PC and TP to provide its Planning Asssessment results to affected entities, which include any CAP developed in R2 Sub-requirements 2.7 of TPL-001-4; and

{C}o   Similarly, Requirement R8 requires the PC and TP to communicate, annually , any instability, Cascading or uncontrolled separation that adversely impacts the reliability of the BES in its Planning Assessment of the Near‐Term Transmission Planning Horizon to TOs and GOs.  All Planning Assessments performed by PCs and TPs are governed by other standards (TPL-001, PRC-012, PRC-023 etc.) and the processes required by those standards already include provisions for the communication of those results to the entities that have a reliability need.

 

We suggest that Requirements R7 and R8 be removed to avoid duplication with existing communication obligations for the PC and TP.

 

 

Leonard Kula, Independent Electricity System Operator, 2, 7/30/2020

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While Southern Company supports the removal of FAC-015-1, retirement of FAC-010, and inclusion of the requirements as contemplated in R6 through R8 of the proposed FAC-014-3, these requirements are best located in TPL-001, not FAC-014. The proposed FAC-014-3 “Establish and Communicate System Operating Limits” should cover the responsibilities related to SOLs, which no longer apply to near/long-term planning horizons. The communication of planning information by the TP and PCs should be appropriately housed in the TPL standard family to prevent confusion and cross pollination of standards.

 

Southern Company also suggests a modification to R7 of the proposed FAC-014-3 that will help focus the communication of any instabilities identified in the Planning Assessment to include only those contingency events which are the most impactful, as follows:

R7 Each Planning Coordinator and each Transmission Planner shall annually communicate the following information for Corrective Action Plans developed to address any instability identified in its Planning Assessment of the near-Term Transmission Planning Horiozon, using planning event contingencies only, to each impacted Reliability Coordinator. 

FAC – 014 R7 and R8 could result in burdensome communication even if there isn’t any identified issues per the Planning Assessment to communicate.  As such, we suggest the following language modifications:

 

Modify the last sentence of FAC-014 R7 from “This communication shall include:” to “This communication, which is required if any information in Part 7.1 – Part7.5 is identified, shall include:”

 

Modify the first sentence of FAC-014 R8 from “shall annually communicate any instability…” to “shall annually communicate if there is any identified instability…….”

Southern Company, Segment(s) 1, 3, 5, 6, 12/13/2019

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FE Voter, Segment(s) 1, 3, 5, 6, 4, 7/31/2020

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Joe O'Brien, NiSource - Northern Indiana Public Service Co., 6, 7/31/2020

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While the intent of the requirements in FAC-014 does not appear to be reflected in the actual words. These requirements are confusing and create ambiguity that could result in incomsistent results, especially with auditors.

Dominion, Segment(s) 3, 5, 1, 9/19/2019

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Anthony Jablonski, ReliabilityFirst , 10, 7/31/2020

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Maryanne Darling-Reich, On Behalf of: Black Hills Corporation - MRO, WECC - Segments 1, 3, 5, 6

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Glenn Barry, Los Angeles Department of Water and Power, 5, 7/31/2020

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OGE supports the concerns expressed by MRO-NSRF on the proposed FAC-014 R6, R7 and R8. OGE believes that the proposed R6, R7 and R8 are duplicative of requirements in TPL-001-4.

OKGE, Segment(s) 6, 1, 3, 5, 4/10/2019

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PPL NERC Registered Affiliates, Segment(s) 1, 3, 5, 6, 9/6/2018

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MPC supports comments submitted by the MRO NERC Standards Review Forum.

Andy Fuhrman, On Behalf of: Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1

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Truong Le, On Behalf of: Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Chris Gowder, Florida Municipal Power Agency, 3,4,5,6; Chris Gowder, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Richard Montgomery, Florida Municipal Power Agency, 3,4,5,6; Richard Montgomery, Florida Municipal Power Agency, 3,4,5,6; Carol Chinn, Florida Municipal Power Agency, 3,4,5,6; Carol Chinn, Florida Municipal Power Agency, 3,4,5,6; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3

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LaTroy Brumfield, American Transmission Company, LLC, 1, 8/3/2020

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Steven Rueckert, Western Electricity Coordinating Council, 10, 8/3/2020

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BPA agrees with the withdrawal of FAC-015-1 and consolidating the requirements into FAC-014-3.  However, BPA offers the following comments on the new Requirements.

FAC-014-3 Requirement R6: Facility Ratings are modeling data, as developed and reported in Standards FAC-008 and MOD-032. System steady-state voltage limits and stability criteria used in Planning Assessments are criteria developed and documented in annual system assessments required by Standard TPL-001. 

BPA suggests including the following language (bold. italic text added) to add clarity to R6: 

R6. Each Planning Coordinator and each Transmission Planner shall ensure that, when developing its steady-state modeling data requirements, Facility Ratings used in its Planning Assessment of the Near-Term Transmission Planning Horizon are equally limiting or more limiting than the criteria for Facility Ratings described in its respective Reliability Coordinator’s SOL methodology.  In addition, each Planning Coordinator and each Transmission Planner shall ensure that criteria developed and documented for System steady state voltage limits and stability performance for its Planning Assessment of the Near-Term Transmission Planning Horizon are equally limiting or more limiting than the criteria for System Voltage Limits and stability described in its respective Reliability Coordinator’s SOL methodology.

FAC-014-3 Requirement 7: BPA believes it should only be necessary to communicate information for Corrective Action Plans to impacted Transmission Operators and Reliability Coordinators that adversely impact the reliability of the Bulk Electric System.  This is also consistent with the SDT’s response to comments from the previous posting. 

BPA suggests including the following language (bold, italic text added) to add clarity to R7.

R7. Each Planning Coordinator and each Transmission Planner shall annually communicate the following information for Corrective Action Plans developed to address any instability identified in its Planning Assessment of the Near-Term Transmission Planning Horizon that adversely impacts the reliability of the Bulk Electric System to each impacted transmission Operator and Reliability Coordinator.

Cain Braveheart, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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Mark Holman, 8/3/2020

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Sandra Shaffer, 8/3/2020

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Rachel Coyne, Texas Reliability Entity, Inc., 10, 8/3/2020

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Jennifer Bray, Arizona Electric Power Cooperative, Inc., 1, 8/3/2020

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Joshua Andersen, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

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Daniela Atanasovski, APS - Arizona Public Service Co., 1, 8/3/2020

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The proposed FAC-014-3 Requirements R6 through R8 obligate the Planning Coordinator and Transmission Planner to share information on their annual Transmission Planning Assessments. The proposed requirements are redundant because Planning Coordinators and Transmission Planners are already required to share planning assessments under TPL-001-4, Requirement R8.  Requirement R8 states: “Each Planning Coordinator and Transmission Planner shall distribute its Planning Assessment results to adjacent Planning Coordinators and adjacent Transmission Planners within 90 calendar days of completing its Planning Assessment, and to any functional entity that has a reliability related need and submits a written request for the information within 30 days of such a request.” The proposed requirements would be inefficient, increase administrative compliance responsibilities, and would be contrary to ongoing work of the NERC Standards Efficiency Review project.

Alternatively, if the SDT does not withdraw Requirements R6 through R8, the intent  with regard to the Time Horizon must be clarified. SOLs applied to support the Operations Planning Time Horizon will be different than those applied to the Long-Term Planning Time Horizon. Stability limits identified by the Reliability Coordinator may become invalid in the Planning Time Horizon as new generation is potentially added in future power flow models.  When this occurs, it is the Transmission Planner’s and Planning Coordinator’s stability limits that must be communicated to the Reliability Coordinator so that the Reliability Coordinator knows what to expect.

Also, the two bulleted items in the newly proposed Requirement R6 are troubling. The development of Facility Ratings is the responsibility of the Transmission Owner, per FAC-008. To allow the Planning Coordinator and Transmission Planner to develop a “less limiting” Facility Rating could result in inaccurate Operational and Transmission Planning Assessments. The Planning Coordinator or Transmission Planner should not be allowed to independently overrule the Transmission Owner’s responsibility to develop  Facility Ratings.  

Larisa Loyferman, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

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The proposed Requirements R6-R8 in FAC-014-3 all require actions associated with the PC and TP annual Planning Assessment, which is required by TPL-001.  If not already sufficiently addressed by the Requirements in TPL-001, we believe it would be better to address any additional actions associated with the annual Planning Assessment in a revision to TPL-001 to avoid requirement fragmentation between TPL-001 and FAC-014.

Dennis Chastain, On Behalf of: Tennessee Valley Authority - SERC - Segments 1, 3, 5, 6

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Teresa Krabe, Lower Colorado River Authority, 5, 8/3/2020

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NV Energy does not agree with the proposed requirement R6 of FAC-014-3. The proposed requirement requires additional clarity on the potential opportunity of a RC creating a Facility Rating based upon its own SOL methodology, and removing the ownership provided to Entities through FAC-008-3. FAC-014-3 requirement R6, currently reads that each Planning Coordinator and Transmission Planner shall implement a process to use Facility Ratings…that are equally limiting or more limiting than the criteria for Facility Ratings…as described in its RC’s SOL methodology.  NV Energy currently interprets this this as the RC can create a Facility Rating based on its own SOL methodology. Under this interpretation of the requirement, NV Energy cannot approve the current draft of the requirement R6..

Additionally, the remainder of the Standard, FAC-014-3, states that the PC and TP may use less limiting Facility Ratings, if the Entity provides a technical rationale.  NV Energy interprets the intention of this language that the TP can use a less limiting element (higher facility rating) than what the RC provides, but that isn’t entirely clear in the requirement’s current draft.

Kevin Salsbury, Berkshire Hathaway - NV Energy, 5, 8/3/2020

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On behalf of Exelon, Segments 1, 3, 5, & 6

Exelon concurs with the comments submitted by the EEI. 

Daniel Gacek, Exelon, 1, 8/3/2020

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In our opinion we need to be careful that there is only one methodology for SOL's going forward.  We agree with the proposed requirements but also suggests that the team consider instead adding these requirements within TPL-001, which deals with the Planning Assessment and correspondence/communication of the Planning Study to affected entities. 

David Jendras, Ameren - Ameren Services, 3, 8/3/2020

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Scott Langston, Tallahassee Electric (City of Tallahassee, FL), 1, 8/3/2020

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Carl Pineault, Hydro-Qu?bec Production, 5, 8/3/2020

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FAC-014-3 Requirements (R6 – R8) are not well aligned for inclusion in a FAC Standard and there are already similar requirements in TPL-001-4.  Requirement R8 in FAC-014-3, which requires annual communication of any instability, Cascading or uncontrolled separation that adversely impact the reliability of the Bulk Electric System identified in its Planning Assessment, appears to already be covered by requirement R8 in TPL-001-4.  In addition, FAC-014-3 Requirements (R6 - R8) are only related to the Near‐Term Transmission Planning Time Horizon. There appears to be a need for further clarification regarding the relevant Time Horizon(s) which reference: "Time Horizon: Long-term Planning."     

Michael Jones, National Grid USA, 1, 8/3/2020

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We have an overall concern with the term Facility Rating as applied in these FAC Standards and the confusion with those used in the MOD Standards. Does the SDT really mean Thermal Operation Limits as developed from the Facility Ratings? This set of standards talks about Steady State Voltage Limits, Stability Limits, but us silent on Thermal Operation Limits. We believe it would provide more clarity if the term Thermal Operation Limit was used in place of Facility Limit.

NPCC Regional Standards Committee, Segment(s) 10, 2, 4, 7, 3, 1, 5, 6, 7/8/2020

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While EEI is supportive of the general concepts for Requirements R6 through R8, the language lacks sufficient clarity to address what results or outcomes are expected.  Given this ambiguity, the outcomes could result in inconsistent application across the various regions.  Moreover, the current language in these three requirements do not adequately conform to the tenant of a Results Based Standard.  For these reasons, we cannot support the currently proposed draft of FAC-014-3 at this time.    

Mark Gray, On Behalf of: Edison Electric Institute, NA - Not Applicable, Segments NA - Not Applicable

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No Comment

Eversource Group, Segment(s) 3, 1, 4/12/2019

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The proposed requirements R7 and R8 in FAC-014-3 are unnecessary. Requirement R5 ensures that the Reliability Coordinators provide the Plannning Coordinators and Transmission Planners the SOLs for their respective areas. If instability is  identified in the Planning Assessments which drives an SOL, it would be provided to the TOPs through instabilitie identified by requirement R5. If the identified instability does not require an SOL then providing that information to TOPs could lead to uncertantity as to what to do with the information.   Many of the instabilities identified by Planning should be items strictly for the Planning Horizon, as Planning should be addressing them with Corrective Action Plans prior to them making it to become a Real Time Operating Horizon SOL issue. 

 

FAC-014 Requirement R6 is more appropriately placed in the TPL-001 standard to avoid possible confusion in completing the task in finalizing the completion of the models needed for performing the Near Term Assessments.  All of the other requirements for the models are identified in this standard.

Allie Gavin, On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1

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Robert Hirchak, Cleco Corporation, 6, 8/3/2020

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The Evergy companies support, and incorporate by reference, Edison Electric Institute’s response to Question No. 4. 

Evergy would further respond: 

Proposed Revisions Add Reliability Risk. Transmission Owners are required to develop Facility Ratings under FAC-008. The proposed two bulleted subparts permit the Planning Coordinator or Transmission Planner to use “less limiting” (higher) Facility Ratings. Inconsistencies between FAC-008 Facility Ratings and ratings developed under the R6 bulleted subparts can lead to unrealistic Planning Assessments or invalidate Planning Assessments, altogether.  

The proposed bulleted subparts seek to address the described reliability risk by requiring PCs or TPs to submit a technical rationale to affected TPs, TOs, and RCs. The proposed revision to FAC-014-3 does not consider the possibility TPs, TOs, RCs not wanting to accept a risk posed by the technical rationale. As such, the PCs or TPs could effectively reject TP, TO, or RC concerns raised by the technical rationale and proceed to operate at the less limiting Facility Ratings, regardless of those concerns; for example, the Transmission Owner needing to maintain conservative Facility Ratings in accordance with manufacture recommendations to protect its personnel and equipment. 

Westar-KCPL, Segment(s) 1, 3, 5, 6, 12/18/2018

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FAC-014-3 R6

The SPP Standards Review Group asks the SDTs consideration that coverage of FAC-014-3 is included in the data provided in MOD-032-1, and in the model building in TPL-001-4 R1, where the models contain Facility Ratings, System steady-state voltage limits, and stability criteria that are equally limiting or more limiting than the ones utilized by the Reliability Coordinator (RC).

The SPP Standards Review Group asks the SDTs consideration of these differences in the scope for TPL-001-4 R1.

The development of Facility Ratings is the responsibility of the Transmission Owner (TO) in accordance with FAC-008-3. To allow the Planning Coordinator (PC) or Transmission Planner (TP) to develop a “less limiting”, “higher” Facility Rating, could lead to unrealistic and/or invalid Planning Assessments.

The PC and/or the TP should not have the ability to overrule the TOs capability to maintain conservative Facility Ratings in accordance with manufacturer recommendations to protect its personnel and equipment.

If the PCs and TPs want to adjust system models with a higher Facility Rating based on a proposed system upgrade, that is included in TPL-001-4 R1, Part 1.1.3.

FAC-014-3 R6, as written, could lead to the misunderstanding of the context, the expectations, and/or the compliance failures. 

FAC-014-3 R7

 

The SPP Standards Review Group asks the SDTs consideration that TPL-001-4 R8 is for the PC and TP to share information on their annual Planning Assessments.

 

The SPP Standards Review Group recommends that the list of entities in TPL-001-4 R8 include RCs and TOPs the ability to request and receive the information. 

FAC-014-3 R7, as written, could lead to the misunderstanding of the context, the expectations, and/or the compliance failures. 

FAC-014-3 R8

The SPP Standards Review Group considers existing coverage of FAC-014-3 R8 in TPL-001-4 R8.

The SPP Standards Review Group recommends that the list of entities in FAC-014-3 R8 include TOs and Generator Owners (GOs) the ability to request and receive the information.  

FAC-014-3 R8, as written, could lead to the misunderstanding of the context, the expectations, and/or the compliance failures.  

SPP Standards Review Group, Segment(s) 2, 8/3/2020

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IPL offers no further comment.

Colleen Campbell, AES - Indianapolis Power and Light Co., 3, 8/3/2020

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Oncor supports EEI comments.

Lee Maurer, Oncor Electric Delivery, 1, 8/3/2020

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The IRC SRC believes the three requirements (R6-R8) proposed for FAC-014-3 are all misplaced and are duplicative of other existing NERC requirements in the following NERC standards: IRO-017, MOD-032 and TPL-001 as described below. For these reasons, we believe that FAC-010 can still be retired even if FAC-015 is withdrawn.

 

FAC-014-3

We have an overall concern with the term Facility Rating as applied in these FAC Standards and the confusion with those used in the MOD Standards. Does the SDT really mean Thermal Operation Limits as developed from the Factility Ratings? This set of standards talks about Steady State Voltage Limits, Stability Limits, but is silent on Thermal Operation Limits. We believe it would provide more clarity if the term Thermal Operation Limit was used in place of Facility Rating.

FAC-014-3, R6

We believe FAC-014-3, R6, i.e. to implement a documented process for Facility Ratings, voltage limits and stability criteria, is duplicative of existing NERC Standard MOD-032-1 (R2) and TPL-001-4, R1 which require each Planning Coordinator and Transmission Planner to maintain models that represent projected System conditions. If the SDT believes additional detail is required, we suggest MOD-032 or TPL-001-4 be updated so that all related requirements are located together. Keeping “like” requirements together will retain the overall context of the requirements, increase efficiency, minimize opportunities for confusion and support the efforts of the Standards Efficiency Review project

 

If FAC-014-3, requirement R6 is not retired, the IRC SRC requests that it be modified to acknowledge that the determination of Facility Ratings is the responsibility of Generator Owners (GO) and Transmission Owners (TO) under FAC-008-3 as follows:

Proposed Language:

FAC-014-3, R6. Each Planning Coordinator and each Transmission Planner shall implement a documented process to use Facility Ratings, System steady-state voltage limits and stability criteria in its Planning Assessment of Near Term Transmission Planning Horizon that represent projected System Operating Limits that are equally limiting or more limiting than the (delete - criteria for) Facility Ratings, System steady-state Voltage Limits and stability criteria as determined by the Transmission Owners and Generator Owners in accordance with FAC-008 and provided to the PC via MOD-032, R2 and in accordance with their respective RC’s SOL methodology (FAC-011-4, R9).

Likewise, the requirement for the PC to notify impacted entities and provide a technical rationale for the use of a less limiting Facility Rating in its Planning Assessment (under FAC-014-3, R6) is misplaced. Instead, the IRC SRC recommends FAC-008-3 be revised (see requirement R8) and expanded to require GOs and TOs notify applicable entities, including the PC, of planned upgrades that will increase a Facility Rating and modify FAC-014-3 to recognize this.

·       The Planning Coordinator may use less limiting Facility Ratings as provided by the GO or TO (in accordance with FAC-008-3, R8), to recognize planned upgrades in the Near Term Transmisison Planning Horizon, System steady-state voltage limits and stability criteria if it provides a technical rationale to each affected Transmission Planner, Transmission Operator and Reliability Coordinator

Alternatively, MOD-032, R3 could be updated to reflect this detail as MOD-032-1, R3, Part 3.1 already requires Balancing Authorities, Generator Owners, Load Serving Entities, Resource Planners, Transmission Owners and Transmission Service Providers to provide an explanation with a technical basis for the data.

FAC-014-3, R7

We believe FAC-014-3, R7 is duplicative of existing NERC Standard IRO-017-1, R3 which obligates each Planning Coordinator and Transmission Planner to provide its Planning Assessment to impacted Reliability Coordinators. In addition, TPL-001-4, R8 allows any functional entity that has a reliability related need need to request this information. If the SDT believes additional detail is required, we suggest IRO-017-1, R3 be updated so that this type of request is located in a single requirement or standard. Keeping “like” requirements together will retain the overall context of the requirements, increase effiiciency, minimize opportunities for confusion and support the efforts of the Standards Efficiency Review project.

 

FAC-014-3, R8

We believe FAC-014-3, R8 is duplicative of existing NERC Standard TPL-001-4, requirements R6 and R8 and IRO-017-1, R4 which collectively include the obligation for the Planning Coordinator and Transmission Planner to define and document when the Planning Assessment indicates the inability of the system to meet the performance requirements, including System instability for conditions such as Cascading, voltage instability, or uncontrolled islanding and to provide its Planning Assessment to impacted Reliability Coordinators. In addition, TPL-001-4, R8 allows any functional entity that has a reliability related need need to request this information. If the SDT believes additional detail is required, we suggest that IRO-017-1, R3 be updated so that this type of request is located in a single requirement or standard. Keeping “like” requirements together will retain the overall context of the requirements, increase efficiency, minimize opportunities for confusion and support the efforts of the Standards Efficiency Review project. 

ISO/RTO Standards Review Committee, Segment(s) 2, 8/3/2020

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MISO supports the comments filed by the IRC SRC.

The IRC SRC believes the three requirements (R6-R8) proposed for FAC-014-3 are all misplaced and are duplicative of other existing NERC requirements in the following NERC standards: IRO-017, MOD-032 and TPL-001 as described below. For these reasons, we believe that FAC-010 can still be retired even if FAC-015 is withdrawn.

 

FAC-014-3

We have an overall concern with the term Facility Rating as applied in these FAC Standards and the confusion with those used in the MOD Standards. Does the SDT really mean Thermal Operation Limits as developed from the Factility Ratings? This set of standards talks about Steady State Voltage Limits, Stability Limits, but is silent on Thermal Operation Limits. We believe it would provide more clarity if the term Thermal Operation Limit was used in place of Facility Rating.

FAC-014-3, R6

We believe FAC-014-3, R6, i.e. to implement a documented process for Facility Ratings, voltage limits and stability criteria, is duplicative of existing NERC Standard MOD-032-1 (R2) and TPL-001-4, R1 which require each Planning Coordinator and Transmission Planner to maintain models that represent projected System conditions. If the SDT believes additional detail is required, we suggest MOD-032 or TPL-001-4 be updated so that all related requirements are located together. Keeping “like” requirements together will retain the overall context of the requirements, increase efficiency, minimize opportunities for confusion and support the efforts of the Standards Efficiency Review project.

If FAC-014-3, requirement R6 is not retired, the IRC SRC requests that it be modified to acknowledge that the determination of Facility Ratings is the responsibility of Generator Owners (GO) and Transmission Owners (TO) under FAC-008-3 as follows:

 

Proposed Language:

FAC-014-3, R6. Each Planning Coordinator and each Transmission Planner shall implement a documented process to use Facility Ratings, System steady-state voltage limits and stability criteria in its Planning Assessment of Near Term Transmission Planning Horizon that represent projected System Operating Limits that are equally limiting or more limiting than the Facility Ratings, System steady-state Voltage Limits and stability criteria as determined by the Transmission Owners and Generator Owners in accordance with FAC-008 and provided to the PC via MOD-032, R2 and in accordance with their respective RC’s SOL methodology (FAC-011-4, R9).

Likewise, the requirement for the PC to notify impacted entities and provide a technical rationale for the use of a less limiting Facility Rating in its Planning Assessment (under FAC-014-3, R6) is misplaced. Instead, the IRC SRC recommends FAC-008-3 be revised (see requirement R8) and expanded to require GOs and TOs notify applicable entities, including the PC, of planned upgrades that will increase a Facility Rating and modify FAC-014-3 to recognize this.

 

  • The Planning Coordinator may use less limiting Facility Ratings as provided by the GO or TO (in accordance with FAC-008-3, R8), to recognize planned upgrades in the Near Term Transmisison Planning Horizon, System steady-state voltage limits and stability criteria if it provides a technical rationale to each affected Transmission Planner, Transmission Operator and Reliability Coordinator

 

Alternatively, MOD-032, R3 could be updated to reflect this detail as MOD-032-1, R3, Part 3.1 already requires Balancing Authorities, Generator Owners, Load Serving Entities, Resource Planners, Transmission Owners and Transmission Service Providers to provide an explanation with a technical basis for the data.

FAC-014-3, R7

We believe FAC-014-3, R7 is duplicative of existing NERC Standard IRO-017-1, R3 which obligates each Planning Coordinator and Transmission Planner to provide its Planning Assessment to impacted Reliability Coordinators. In addition, TPL-001-4, R8 allows any functional entity that has a reliability related need need to request this information. If the SDT believes additional detail is required, we suggest IRO-017-1, R3 be updated so that this type of request is located in a single requirement or standard. Keeping “like” requirements together will retain the overall context of the requirements, increase effiiciency, minimize opportunities for confusion and support the efforts of the Standards Efficiency Review project.

 

FAC-014-3, R8

We believe FAC-014-3, R8 is duplicative of existing NERC Standard TPL-001-4, requirements R6 and R8 and IRO-017-1, R4 which collectively include the obligation for the Planning Coordinator and Transmission Planner to define and document when the Planning Assessment indicates the inability of the system to meet the performance requirements, including System instability for conditions such as Cascading, voltage instability, or uncontrolled islanding and to provide its Planning Assessment to impacted Reliability Coordinators. In addition, TPL-001-4, R8 allows any functional entity that has a reliability related need need to request this information. If the SDT believes additional detail is required, we suggest that IRO-017-1, R3 be updated so that this type of request is located in a single requirement or standard. Keeping “like” requirements together will retain the overall context of the requirements, increase efficiency, minimize opportunities for confusion and support the efforts of the Standards Efficiency Review project. 

Bobbi Welch, Midcontinent ISO, Inc., 2, 8/3/2020

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Aaron Staley, Orlando Utilities Commission, 1, 8/3/2020

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Mickey Bellard, On Behalf of: Seminole Electric Cooperative, Inc., SERC, Segments 1, 5

FAC-014 SBS Comments 8-3-2020.docx

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James Baldwin, Lower Colorado River Authority, 1, 8/3/2020

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FAC-014-3 The statement “any  instability identified in its Planning Assessment of the Near-Term Transmission…” seems unclear.  I think an improvement and more clear statement might be, “any stability criteria violation identified in its Planning Assessment of the Near-Term Transmission…”. 

 

The revision that Oncor is proposing also seems to better align with the deliverables outlined in R7.1 – R7.5, and in particular, R7.3: The associated stability criteria violation requiring the Corrective Action Plan (e.g. violation of transient voltage response criteria or damping rate criteria).

 

Tammy Porter, On Behalf of: Tammy Porter - - Segments

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With respect to Requirement R6, ERCOT believes the language contained in the prior draft of FAC-015 should be utilized.  The current draft of FAC-014 seems to suggest that responsible entities must provide a technical rationale to each Transmission Planner, Transmission Operator, and Reliability Coordinator in the event of the utilization of a higher rating than was provided for an upgraded circuit.  Accordingly, ERCOT suggests replacing the proposed language of Requirement R6 with the language previously utilized in Requirements R1, R2, and R3 of FAC-015.

 

With respect to Requirement R8, ERCOT believes the Planning Coordinator (PC) and Transmission Planner should communicate only the limited information each Transmission Owner and Generator Owner (GO) needs to know, not necessarily the full details regarding the nature of the instability, Cascading, or uncontrolled separation.  ERCOT suggest the use of the following language in Requirement R8:

 

Each Planning Coordinator and each Transmission Planner shall provide an annual communication to Transmission Owners and Generation Owners that own Facilities that meet the following conditions:

 

1. The Facility is part of a planning event contingency that the Planning Coordinator or Transmission Planner has identified in its annual Planning Assessment would cause instability, uncontrolled separation or Cascading outages that adversely impact the reliability of the BES if a limit is exceeded; or

 

2. The Facility is part of a contingency associated with an established IROL or stability limit, which was provided to the Planning Coordinator or Transmission Planner under Requirement R5, Part 5.2.4.

 

ERCOT also suggests modifying the standards that utilize such information, which are part of this ballot/comment period, to  include “Facilities identified in FAC-014” or “FAC-014-3, Requirement R8” as appropriate so that the facilities that must meet those requirements include part 2 suggested above.

 

ERCOT further notes that it intends to vote in favor of FAC-014-3, provided the foregoing suggested modifications are incorporated.

Brandon Gleason, Electric Reliability Council of Texas, Inc., 2, 8/3/2020

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ACES Standard Collaborations, Segment(s) 1, 8/3/2020

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In addtion to comments submitted by the ISO/RTO Counsel (IRC) Standards Review Committee the CAISO has the following comments:

CAISO believes the three requirements (R6-R8) proposed for FAC-014-3 are all misplaced and are duplicative of other existing NERC requirements in the following NERC standards: IRO-017, MOD-032 and TPL-001 as described below. Keeping “like” requirements together in one standard will retain the overall context of the requirements, increase efficiency, minimize opportunities for confusion, avoid undue regulatory burden and support the efforts of the Standards Efficiency Review project. For these reasons, we believe that FAC-010 can still be retired even if FAC-015 is withdrawn without adding Requirements R6 to R8 in FAC-014-3. Accordingly, we recommend:

  • Requirements R6 to R8 be removed from FAC-014-3

  • The phrase “ and that Planning Assessment performance criteria is coordinated with these methodologies.” be removed from the Purpose (Section 3) of FAC-014-3

  • The Planning Coordinator and the Transmission Planner be removed from the Applicablity Section.

FAC-014-3

We have an overall concern with the term Facility Rating as applied in these FAC Standards and the confusion with those used in the MOD Standards. Does the SDT really mean Thermal Operation Limits as developed from the Factility Ratings? This set of standards talks about Steady State Voltage Limits, Stability Limits, but is silent on Thermal Operation Limits. We believe it would provide more clarity if the term Applicable Facility Ratings Duration Criteria was used in place of Facility Rating.

FAC-014-3, R6

We believe FAC-014-3, R6, i.e. to implement a documented process for Facility Ratings, voltage limits and stability criteria, is duplicative of existing NERC Standard MOD-032-1 (R2),  whose purpose is “To establish consistent modeling data requirements and reporting procedures [for each Transmission Owner, Transmission Service Provider, Generation owner, Resources Planner, and  Balancing Authority]. TPL-001-4, R1  requires each Planning Coordinator and Transmission Planner to maintain models that use data consistent with that provided in accordance with the MOD-032 Standard that represent projected System conditions. TPL-001-5 further requires that Applicable Facility Ratings shall not be exceeded and that system adjustments are allowed to mitigate rating exceedances if such adjustments are executable within the time duration applicable to the Facility Ratings. If the SDT believes additional detail, such as a criteria regarding which of the Facility Ratings (30 min, 4 hour, continuous, etc.) are applicable under normal and emergency conditions is required, we suggest TPL-001-4 be updated to include those details/criteria so that all related requirements are located together. TPL 001-5 also requires the Planning Coordinator and Transmission Planner to establish system steady state voltages, post-Contingency voltage deviation and transient voltage response. Instead of making the RC’s SOL methodology, which is typically developed entirely from the operations perspective without involvement of the PC(s) and TPs, binding on PCs and TPs, TPL-001-5 can be modified so that the RC is a party in the development of the criteria, possibly through a process that is led by Regional Reliability Organizations such as WECC.

As we noted above, keeping “like” requirements together will retain the overall context of the requirements, increase efficiency, minimize opportunities for confusion and support the efforts of the Standards Efficiency Review project.

In addition, reading the proposed Requirement 6.2 of FAC-011-4, it doesn’t appear that there is a material risk for the PC and TP to use less restrictive criteria than the RC that makes including Requirement R6 in FAC-014-3 necessary.[1] 

[1] The system performance standards FAC-011-4 requires the RC to include in its SOL methodology are:

Ø  System performance for no contingencies demonstrates flows and voltages are within normal ratings but emergency limits may be used when System adjustments to return the flow within its Normal Rating could be executed and completed within the specified time duration of those Emergency Ratings.

Ø  System performance for single contingencies demonstrates flow through facilities and voltages are within applicable Emergency Ratings and System Voltgae Limits.  Steady steate post-Contingency flow through a facility must not be above the Facilitiy’s highest Emergency Rating.

If FAC-014-3, requirement R6 is not retired, the IRC SRC requests that it be modified to either: (1) actually include the desired criteria, including the Applicable Facility Ratings Duration Criteria,  in FAC-014-3 possibly using similar language as used in Requirement R6 of FAC-011-4 while maintaining consistency with the requirements in TPL-001-5 mentioned above, rather than leaving it to the RC’s SOL methodology,  or (2) to acknowledge that the determination of Facility Ratings is the responsibility of Generator Owners (GO) and Transmission Owners (TO) under FAC-008-3 as follows:

Proposed Language:

FAC-014-3, R6. Each Planning Coordinator and each Transmission Planner shall implement a documented process to use Facility Ratings criteria, System steady-state voltage limits and stability criteria in its Planning Assessment of Near Term Transmission Planning Horizon that represent projected System Operating Limits that are equally limiting or more limiting than the Facility Ratings, System steady-state Voltage Limits and stability criteria as determined by the Transmission Owners and Generator Owners in accordance with FAC-008 and provided to the PC via MOD-032, R2 and in accordance with their respective RC’s SOL methodology (FAC-011-4, R9).

Likewise, the requirement for the PC to notify impacted entities and provide a technical rationale for the use of a less limiting Facility Rating in its Planning Assessment (under FAC-014-3, R6) is misplaced. Instead, the IRC SRC recommends FAC-008-3 be revised (see requirement R8) and expanded to require GOs and TOs notify applicable entities, including the PC, of planned upgrades that will increase a Facility Rating and modify FAC-014-3 to recognize this.

  • The Planning Coordinator may use less limiting Facility Ratings as provided by the GO or TO (in accordance with FAC-008-3, R8), to recognize planned upgrades in the Near Term Transmisison Planning Horizon, System steady-state voltage limits and stability criteria if it provides a technical rationale to each affected Transmission Planner, Transmission Operator and Reliability Coordinator

Alternatively, MOD-032, R3 could be updated to reflect this detail as MOD-032-1, R3, Part 3.1 already requires Balancing Authorities, Generator Owners, Load Serving Entities, Resource Planners, Transmission Owners and Transmission Service Providers to provide an explanation with a technical basis for the data.

If on the other hand it can be assumed that the SDT is referring to Applicable Facility Ratings Duration Criteria rather than individual Facility Ratings, System voltage limits rather than Facility specific voltage limits and system stability limits then the provision of technical rationale be limited to the Regional Reliability Organization (RRO) as part of the established compliance monitoring process rather than to multiple entities to avoid putting additional regulatory burden on PCs and TPs.

FAC-014-3, R7

We believe FAC-014-3, R7 is duplicative of existing NERC Standard IRO-017-1, R3 which obligates each Planning Coordinator and Transmission Planner to provide its Planning Assessment to impacted Reliability Coordinators. In addition, TPL-001-4, R8 allows any functional entity that has a reliability related need need to request this information. If the SDT believes additional detail is required, we suggest IRO-017-1, R3 or Requirement R8 of TPL-001-5 be updated so that this type of request is located in a single requirement or standard. Keeping “like” requirements together will retain the overall context of the requirements, increase effiiciency, minimize opportunities for confusion,  avoid undue regulatory burden, and support the efforts of the Standards Efficiency Review project.

We believe FAC-014-3, R8 is duplicative of existing NERC Standard TPL-001-4, requirements R6 and R8 and IRO-017-1, R3 which collectively include the obligation for the Planning Coordinator and Transmission Planner to define and document when the Planning Assessment indicates the inability of the system to meet the performance requirements, including System instability for conditions such as Cascading, voltage instability, or uncontrolled islanding and to provide its Planning Assessment to impacted Reliability Coordinators. In addition, TPL-001-4, R8 allows any functional entity that has a reliability related need to request this information. If the SDT believes additional detail is required, we suggest that IRO-017-1, R3 or TPL-001-5, R8 be updated so that this type of request is located in a single requirement or standard. Keeping “like” requirements together will retain the overall context of the requirements, increase efficiency, minimize opportunities for confusion, avoid placing undue regulatory burden on entities and support the efforts of the Standards Efficiency Review project.  We strongly oppose the requirement to inform multiple entities including generator owners because, that could take planning engineers away from their core job. The existing FAC-014 limits such communication to the affected RC. We recommend that arrangement remain unchanged.

Jamie Johnson, California ISO, 2, 8/3/2020

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Denise Sanchez, On Behalf of: Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Tino Zaragoza, Imperial Irrigation District, 1,3,5,6; Tino Zaragoza, Imperial Irrigation District, 1,3,5,6; Diana Torres, Imperial Irrigation District, 1,3,5,6; Diana Torres, Imperial Irrigation District, 1,3,5,6; Glen Allegranza, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6

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Gul Khan, On Behalf of: Oncor Electric Delivery - Texas RE - Segments 1

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Understand the good-faith intent of the SDT, but fundamentally the proposed requirements are TPL 001 based (and perhaps even FAC 008 based) and should be placed in the applicable standard if deemed acceptable.  The draft standard appears to mandate the Facility Ratings, System steady-state voltage limits and stability criteria to be used by the PC/TP, as set by the RC/TOP methodology.  It would probably be more effective to rewrite the drafted FAC-014 standard for the RC's/TOP's to provide their associated technical rationales (beyond a methodology) for the defined operating limits to the PC/TP for input into the TPL assessments. 

In general, having standards placing requirements for other standards (as a standards setting practice) risks creating confusion.  Also support the MRO-NSRF comments.

 

 

 

          

Wayne Guttormson, SaskPower, 1, 8/3/2020

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Please see comments submitted by Edison Electric Institute

Kenya Streeter, Edison International - Southern California Edison Company, 6, 8/3/2020

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WAPA agrees with removing the redundancy of the proposed FAC-015-1 and part of the shift of those requirements to the revised FAC-014-3.  However, the proposed FAC-014-3 Requirement R6 remains redundant to existing obligations of MOD-032-1 and TPL-001-4 (soon -5) Requirement R1.  The proposed Requirement R6 establishes a significant Compliance risk to planning entities who seek to plan the future transmission System for expansion and load growth, and ignores that Facility Ratings of the moment may not exist in the future planned System.  In the proposed Requirement R7, it is unclear what reliability objective is accomplished that is not redundant to the existing IRO-017-1 Requirements R3 and R4.  Furthermore, if there is a need to modify TPL-001-4 (soon -5) Requirement R8 to address annual Planning Assessment distribution, it should be revised there.  Finally, to reiterate the comment above, FAC-014-3 Requirement R8 is not clear about requiring Planning Coordinators to communicate that “big-3” impacts during a particular planning event (e.g. see Cascading during simulation of a P6 event) were observed versus that “big-3” impacts caused a failure to meet System performance requirements.  Here, the SDT is making a different interpretation than most planning entities make regarding TPL-001-4 (soon -5).  It is not simply that “big-3” impacts were observed; it is that the “big-3” impact required a Corrective Action Plan (CAP) because the Contingency caused a failure to meet System performance requirements of Table 1.  In other words, for a P6 event that yields Cascading, the Table 1 performance requirements may allow shedding Non-Consequential Load as part of the allowable mitigations such that System performance requirements are met (and no CAP).   WAPA requests that the SDT reconsider the incorporation of the planning entity requirements into FAC-014-3 and, if retained, clearly state the intended reliability objective to retaining them there.

sean erickson, Western Area Power Administration, 1, 8/3/2020

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In concept, the proposed requirements for FAC-014-3 R6 to R8 are good, but the details need to be further developed.  For instance, for R6, the RC can change their methodology at any time and the Transmission Planner will then be responsible to ensure that any more stringent criteria are then reflected in Planning studies, but the RC is required by FAC-011-4 R9 to provide its SOL methodology to PCs and TPs, so there should be adequate notification which would allow the TP to implement such changes in their next reliability assessment.  The greatest concern, then, appears to be possible disconnects between Operating and Planning criteria that make it difficult to ensure compliance with R6 and leave certain aspects up to interpretation, such as differences in Facility Ratings used in Operations vs. Planning.  The standard as currently written does not require the RC to accept and respond to feedback from other entities if the methodology is unclear, but R6 will require the PC and TP to correctly interpret the methodology for ratings, limits, and criteria.  For R7 and R8, the concept of notification to TOPs/RCs (R7) and TOs/GOs (R8) is sound, but the implementation may not be straightforward.  In R7, for instance, “instability” must be communicated – does this include small generators that lose synchronism for P1 events?  How does an entity differentiate bad models from instability when compliance directly depends on notifications of such issues?  Clear definitions of the terms involved here would be a significant improvement.

Pamalet Mackey, On Behalf of: Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5

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In concept, the proposed requirements for FAC-014-3 R6 to R8 are good, but the details need to be further developed.  For instance, for R6, the RC can change their methodology at any time and the Transmission Planner will then be responsible to ensure that any more stringent criteria are then reflected in Planning studies, but the RC is required by FAC-011-4 R9 to provide its SOL methodology to PCs and TPs, so there should be adequate notification which would allow the TP to implement such changes in their next reliability assessment.  The greatest concern, then, appears to be possible disconnects between Operating and Planning criteria that make it difficult to ensure compliance with R6 and leave certain aspects up to interpretation, such as differences in Facility Ratings used in Operations vs. Planning.  The standard as currently written does not require the RC to accept and respond to feedback from other entities if the methodology is unclear, but R6 will require the PC and TP to correctly interpret the methodology for ratings, limits, and criteria.  For R7 and R8, the concept of notification to TOPs/RCs (R7) and TOs/GOs (R8) is sound, but the implementation may not be straightforward.  In R7, for instance, “instability” must be communicated – does this include small generators that lose synchronism for P1 events?  How does an entity differentiate bad models from instability when compliance directly depends on notifications of such issues?  Clear definitions of the terms involved here would be a significant improvement.

Marco Rios, Pacific Gas and Electric Company, 1, 8/3/2020

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FAC-015 seems as an attempt to provide for the PC to TP heirarchy that should exist. However, it appears that there is a lack of coordination between FAC-011, FAC-014, and FAC-015. The goal should be to keep establishment of the Operating and Planning Horizon planning assessment with the closest entity (i.e. the Transmission Planner) and have the results go up the chain (subject to review and approval) from the TP to the PC to the RC and down to the TOP.

The existing combination appears to include would that will not be used and is therefore wasting time and not accomplishing reliability.

Jack Stamper, Clark Public Utilities, 3, 8/21/2020

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Hot Answers

Maurice Paulk, On Behalf of: Cleco Corporation, , Segments 1, 3, 5, 6

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Ray Jasicki, 8/24/2020

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Other Answers

R3. What is the purpose of the Transmission Operator providing its SOLs to the Reliability Coordinator? If it’s for the Reliability Coordinator’s Operational Planning Analyses, Real-time monitoring and Real-time assessments, then keeping this requirement is redundant with the data specification in IRO-010-2 and contrary to ongoing work by the Standards Efficiency Review project to simplify data exchange requirements, reduce administrative burdens and remove redundancies. If not used for the Reliability Coordinator’s Operational Planning Analyses, Real-time monitoring and/or Real-time Assessments, then please explain the purpose and the corresponding obligation by the Reliability Coordinator to use the information? Otherwise, it potentially becomes an administrative compliance exercise that distracts our operations personnel and isn’t benefiting reliability. 

Furthermore, by definition SOLs change continuously based on “a specified system configuration”.  Therefore, does the SDT expect the Transmission Operator to continuously provide the Reliability Coordinator with updated SOLs for each system configuration within the timeframe of each Operational Planning Analysis, Real-time monitoring and/or Real-time Assessment? This is another reason why the information/data exchange activity needs to remain within IRO-010-2, where each Reliability Coordinator can determine the items that need reported, the method and a timeframe based on their individual operating environment.

R5.1 and R5.2. If one purpose of Project 2015-09 is to eliminate planning-based SOLs and IROLs, then what is the purpose of the Reliability Coordinator providing them to the Planning Coordinator and Transmission Planners in this requirement? If it’s for the purpose of better aligning planning and operations, then where is the requirement for the Planning Coordinator or Transmission Planner to use them in the models for the Planning Assessments? If there isn’t a corresponding obligation, then it potentially becomes an administrative compliance exercise that isn’t benefiting reliability.  Additionally, the model building topic is covered in MOD-032-1 and if the intent is to use additional information identified during operations in the models for TPL-001-4 Planning Assessments, then MOD-032-1 should be enhanced and the Reliability Coordinator should be added to the applicability. Having it dispersed in other standards could lead to misunderstanding of context, expectations and/or compliance failures, which is not effective or efficient.

R5.3 and R5.4. What is the purpose of the Reliability Coordinator providing IROL information to the Transmission Operators? If it’s for the Transmission Operator’s Operational Planning Analyses, Real-time monitoring and Real-time assessments, then the data specification concept should be maintained and TOP-003-3 should be enhanced to allow the Transmission Operator to request and receive information from its Reliability Coordinator. To keep these requirements detached in FAC-014 is not effective or efficient and contrary to ongoing work by the Standards Efficiency Review project to simplify data exchange requirements, reduce administrative burdens and remove redundancies. If not used for the Transmission Operator’s Operational Planning Analyses, Real-time monitoring and/or Real-time Assessments, then please explain the purpose and the corresponding obligation by the Transmission Operator to use the information? Otherwise, it potentially becomes an administrative compliance exercise that distracts our operations personnel and isn’t benefiting reliability. 

John Allen, City Utilities of Springfield, Missouri, 4, 7/15/2020

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Michael Courchesne, On Behalf of: Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2

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Laura Nelson, 7/24/2020

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NCPA supports John Allen's, City Utilities of Springfield, Missouri, comments.

Marty Hostler, On Behalf of: Northern California Power Agency, , Segments 3, 4, 5, 6

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Matthew Nutsch, On Behalf of: Seattle City Light, WECC, Segments 1, 3, 4, 5, 6

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If retained, we believe FAC-014 should be revised as “Each Reliability Coordinator shall establish stability limits to be used in operations when *an instability* impacts adjacent Reliability Coordinator Areas or more than one Transmission Operator in its Reliability Coordinator Area in accordance with its SOL methodology.”

Thomas Foltz, AEP, 5, 7/27/2020

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It is also important that RC and/or TO provide technical rationale to PC if they are

using less restrictive SOLs than PC’s SOLs.

Bruce Reimer, Manitoba Hydro , 1, 7/27/2020

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Jennie Wike, On Behalf of: John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6

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“These comments represent the MRO NSRF membership as a whole but would not preclude members from submitting individual comments”.

R3 Issues

A. Transmission Operators providing their SOLs to the Reliability Coordinator raises some questions for consideration by the SDT:

1. Is SOL data sharing being used for the Reliability Coordinator’s Operational Planning Analyses, Real-time monitoring and Real-time assessments?

If that is the case, R3 is redundant with the data specification in IRO-010-2 and could be a candidate for deactivation under the Standards Efficiency Review project.

2. If SOL data sharing is not used by the RC for OPA, RTM and RTAs, what is the purpose of the data sharing, and the corresponding obligation by the Reliability Coordinator, to use the information?

Concern. Without a clear purpose and specific benefit to reliability of BPS, R3 saddles operations personnel with an administrative compliance burden that provides little reliability benefit.

B. SOLs, by definition, continuously change based on “a specified system configuration”. 

1. Is the expectation for the Transmission Operator to continuously provide the Reliability Coordinator with updated SOLs for each system configuration within the timeframe of each Operational Planning Analysis, Real-time monitoring and/or Real-time Assessment?

This highlights why the information/data exchange topic probably needs to remain within IRO-010-2 where Reliability Coordinators can determine items that need to be reported, the method and a timeframe based on the RCs’ specific operating environment.

R5 Issues

A. Reliability Coordinators providing planning-based SOLs and IROLS to the Planning Coordinator and Transmission Planner raises some questions for consideration by the SDT:

1. What is the purpose of the Reliability Coordinator providing SOLs and IROLS to the Planning Coordinator and Transmission Planners?

If the purpose is to better align planning and operations, we are unaware of any requirement for the Planning Coordinator or Transmission Planner to use SOLs and IROLS in models for the Planning Assessments.

Concern. Without a clear requirement for the Planning Coordinator or Transmission Planner to use SOLs and IROLS in models for the Planning Assessments, R5 loads operations personnel with an administrative compliance burden that provides little reliability benefit. 

2. Is the intent to use additional information--like SOLs and IROLs--identified during operations in the models for TPL-001-4 Planning Assessments?

If that is the case, MOD-032-1, the model building Standard, should be revised to expand the Applicability to include the Reliability Coordinator.

Compliance Challenge. Scattering model building Requirements across multiple Standards is inefficient, creating the opportunity for discord between Requirements, even difficulties agreeing on the guiding Requirement for purposes of compliance and enforcement. Clarity as to the expected or desired performance under a Requirement better serves BPS reliability.

B. Reliability Coordinators providing IROL information to the Transmission Operators raises some questions for consideration by the SDT:

1. Is IROL data sharing being used for the Transmission Operator’s Operational Planning Analyses, Real-time monitoring and Real-time assessments?

If that is the case, then the data specification concept should be maintained and TOP-003-3 revised to allow the Transmission Operator to request and receive the information from its Reliability Coordinator.

2. If IROL data is not used by the RC for OPA, RTM and RTAs, what is the purpose of the data sharing, and the corresponding obligation by the Reliability Coordinator, to use the information?

Concern. Without a clear purpose and specific benefit to BPS reliability, R5 encumbers operations personnel with an administrative compliance burden that provides little reliability benefit.

3. The NSRF does not support incorporating R5 into FAC-014. As outlined, above, the revision may be inconsistent with the Standards Efficiency Review project goals of simplifying data exchange requirements and addressing redundancies.

Purpose Statement Issue

The NSRF does not support adding the phrase, “…and that Planning Assessment performance criteria is coordinated with these methodologies,” to the proposed FAC-014-3 Purpose statement.

As already discussed in our previous responses, we believe consolidating the four FAC-015 requirements into proposed FAC-014-3 R6, R7 and R8 creates redundant Requirements; the planning aspects of the proposed Requirements are represented within other Standards. As such, the proposed revision to the FAC-014-3 Purpose statement is unnecessary.

MRO NSRF, Segment(s) 3, 4, 5, 6, 1, 2, 1/29/2020

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Lincoln Electric System, Segment(s) 5, 6, 3, 1, 4/17/2018

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None

Richard Jackson, U.S. Bureau of Reclamation, 1, 7/29/2020

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R5.5: This language is awkward. Please clarify and reword to capture intent.

Vince Ordax, Florida Reliability Coordinating Council – Member Services Division , 8, 7/29/2020

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BC Hydro, Segment(s) 3, 5, 1, 12/18/2018

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Amy Casuscelli, On Behalf of: Michael Ibold, Xcel Energy, Inc., 1,3,5; Michael Ibold, Xcel Energy, Inc., 1,3,5; Michael Ibold, Xcel Energy, Inc., 1,3,5

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None.

Duke Energy, Segment(s) 1, 5, 6, 4/11/2019

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Alliant Energy supports the comments submitted by the MRO NSRF.

Larry Heckert, Alliant Energy Corporation Services, Inc., 4, 7/30/2020

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MEC supports MRO NSRF comments. 

R3 Issues

A. Transmission Operators providing their SOLs to the Reliability Coordinator raises some questions for consideration by the SDT:

1. Is SOL data sharing being used for the Reliability Coordinator’s Operational Planning Analyses, Real-time monitoring and Real-time assessments?

If that is the case, R3 is redundant with the data specification in IRO-010-2 and could be a candidate for deactivation under the Standards Efficiency Review project.

2. If SOL data sharing is not used by the RC for OPA, RTM and RTAs, what is the purpose of the data sharing, and the corresponding obligation by the Reliability Coordinator, to use the information?

Concern. Without a clear purpose and specific benefit to reliability of BPS, R3 saddles operations personnel with an administrative compliance burden that provides little reliability benefit.

 

B. SOLs, by definition, continuously change based on “a specified system configuration”. 

1. Is the expectation for the Transmission Operator to continuously provide the Reliability Coordinator with updated SOLs for each system configuration within the timeframe of each Operational Planning Analysis, Real-time monitoring and/or Real-time Assessment?

This highlights why the information/data exchange topic probably needs to remain within IRO-010-2 where Reliability Coordinators can determine items that need to be reported, the method and a timeframe based on the RCs’ specific operating environment.

R5 Issues

A. Reliability Coordinators providing planning-based SOLs and IROLS to the Planning Coordinator and Transmission Planner raises some questions for consideration by the SDT:

1. What is the purpose of the Reliability Coordinator providing SOLs and IROLS to the Planning Coordinator and Transmission Planners?

If the purpose is to better align planning and operations, we are unaware of any requirement for the Planning Coordinator or Transmission Planner to use SOLs and IROLS in models for the Planning Assessments.

Concern. Without a clear requirement for the Planning Coordinator or Transmission Planner to use SOLs and IROLS in models for the Planning Assessments, R5 loads operations personnel with an administrative compliance burden that provides little reliability benefit. 

2. Is the intent to use additional information--like SOLs and IROLs--identified during operations in the models for TPL-001-4 Planning Assessments?

If that is the case, MOD-032-1, the model building Standard, should be revised to expand the Applicability to include the Reliability Coordinator.

Compliance Challenge. Scattering model building Requirements across multiple Standards is inefficient, creating the opportunity for discord between Requirements, even difficulties agreeing on the guiding Requirement for purposes of compliance and enforcement. Clarity as to the expected or desired performance under a Requirement better serves BPS reliability.

B. Reliability Coordinators providing IROL information to the Transmission Operators raises some questions for consideration by the SDT:

1. Is IROL data sharing being used for the Transmission Operator’s Operational Planning Analyses, Real-time monitoring and Real-time assessments?

If that is the case, then the data specification concept should be maintained and TOP-003-3 revised to allow the Transmission Operator to request and receive the information from its Reliability Coordinator.

2. If IROL data is not used by the RC for OPA, RTM and RTAs, what is the purpose of the data sharing, and the corresponding obligation by the Reliability Coordinator, to use the information?

Concern. Without a clear purpose and specific benefit to BPS reliability, R5 encumbers operations personnel with an administrative compliance burden that provides little reliability benefit.

3. The NSRF does not support incorporating R5 into FAC-014. As outlined, above, the revision may be inconsistent with the Standards Efficiency Review project goals of simplifying data exchange requirements and addressing redundancies.

Purpose Statement Issue

The NSRF does not support adding the phrase, “…and that Planning Assessment performance criteria is coordinated with these methodologies,” to the proposed FAC-014-3 Purpose statement.

As already discussed in our previous responses, we believe consolidating the four FAC-015 requirements into proposed FAC-014-3 R6, R7 and R8 creates redundant Requirements; the planning aspects of the proposed Requirements are represented within other Standards. As such, the proposed revision to the FAC-014-3 Purpose statement is unnecessary.

Terry Harbour, Berkshire Hathaway Energy - MidAmerican Energy Co., 1, 7/30/2020

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MEC Supports NSRF Comments

Darnez Gresham, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 7/30/2020

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Leonard Kula, Independent Electricity System Operator, 2, 7/30/2020

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Detailed comments are in the attached file with special formatting for clarity and emphasis where needed (strike-through, highlighting, etc.).

Southern Company, Segment(s) 1, 3, 5, 6, 12/13/2019

2015-09_Unofficial_Comment_Form_202006 - SOCO Comments Final.pdf

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N/A

FE Voter, Segment(s) 1, 3, 5, 6, 4, 7/31/2020

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None

Joe O'Brien, NiSource - Northern Indiana Public Service Co., 6, 7/31/2020

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Dominion, Segment(s) 3, 5, 1, 9/19/2019

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Anthony Jablonski, ReliabilityFirst , 10, 7/31/2020

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Maryanne Darling-Reich, On Behalf of: Black Hills Corporation - MRO, WECC - Segments 1, 3, 5, 6

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Glenn Barry, Los Angeles Department of Water and Power, 5, 7/31/2020

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OKGE, Segment(s) 6, 1, 3, 5, 4/10/2019

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PPL NERC Registered Affiliates, Segment(s) 1, 3, 5, 6, 9/6/2018

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MPC supports comments submitted by the MRO NERC Standards Review Forum.

Andy Fuhrman, On Behalf of: Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1

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Truong Le, On Behalf of: Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Chris Gowder, Florida Municipal Power Agency, 3,4,5,6; Chris Gowder, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Richard Montgomery, Florida Municipal Power Agency, 3,4,5,6; Richard Montgomery, Florida Municipal Power Agency, 3,4,5,6; Carol Chinn, Florida Municipal Power Agency, 3,4,5,6; Carol Chinn, Florida Municipal Power Agency, 3,4,5,6; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3

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LaTroy Brumfield, American Transmission Company, LLC, 1, 8/3/2020

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Measure M3, the phrase “in accordance with its Reliability Coordinator’s SOL methodology” should be stricken since it is stricken in the requirement. Proposed language “in accordance with requirement R3” would suffice.

Steven Rueckert, Western Electricity Coordinating Council, 10, 8/3/2020

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Cain Braveheart, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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R3 - The new language provides no suggested timeline beyond the Time Horizon of Operations Planning.  Many SOLs, the limit itself, not the basis for the limit which can include Facility Ratings, at minimum, are derived/determined in the Real-time horizon.  The Rationale gives several options/examples of how this might transpire which are not governed by the requirement language, which drops the suggested option of “in accordance with its Reliability Coordinators SOL methodology”.  As such, the proposed SDT language for R3 is ambiguous and either allows the TOP to indicate an SOL as they see fit, or continuously.

 

Yet, the measurement indicates that evidence demonstrating the TOP provided its SOLs in accordance with its RC’s SOL methodology.  Which seems appropriate.

 

R5 - RC’s have Facility Ratings.  RC’s have stability limits.  RC’s have criteria for the determination of IROLs.  The value of the SOL, which could include, for example a single temperature set rating for a given facility, is of minimal benefit to a PC or TP and is an incomplete set.

·      The methodology and ratings sets that can lead to potential SOLs would be of value to the PC or TP.

 

As written, this requirement and many of its subparts serve minimal reliability value and is highly administrative in nature; and is not an improvement over the current FAC-014-2 R5.  Requiring the formalized exchange of such information is not necessarily a determination that it is of value to the recipient.

 

Suggest R5 be rewritten to align with R6 and provided the criteria, methodology and supporting data (including Facility Ratings) that may be both relevant and beneficial to a TP or PC.  Alternatively, providing a list of SOL exceedances and/or trends may also be of some value to the PC or TP.  A long list of SOLs with no additional context is an overlap of other requirements/obligations set on the TO/GOs in other standards.

Mark Holman, 8/3/2020

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Sandra Shaffer, 8/3/2020

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Texas RE recommends the SDT consider the following:

  • In Requirement R4, add “adjacent Reliability Coordinators Areas within its Interconnection or” unless it has an understanding that there is a need to confirm stability limits used in operations between RCs in different Interconnections.

  • Revise Part 5.4 from “each established stability limit or each IROL” to “each established stability limit and each IROL applicable to the impacted Transmission Operator”.  Both the stability limit and the IROL should be provided to each impacted Transmission Operator.

  • In Requirement R6, the term “System steady-state voltage limits” is not defined.  Is this term intended to be different than the proposed term “System Voltage Limit,” which was introduced in this project?    

  • Include a check and balance for use of the less limiting parameter in Requirement R6.  This requirement allows for any criteria to be used (i.e. less limiting Facility Rating, etc) as it simply states a “technical rationale” has to be provided to any entity affected by a “less limiting” parameter.

  • Requirement R6 uses “affected Transmission Planner, Transmission Operator and Reliability Coordinator,” while R7 references “impacted Transmission Operator and Reliability Coordinator” and R8 references “impacted Transmission Owner and Generation Owner.”  Unless there is a specific reason for difference in verbiage, Texas RE recommends being consistent to avoid confusion and potential interpretation attempts at differences in language in the Requirements.

  • Requirement R7 appears to exclude any CAP for Cascading or uncontrolled separation.  Please provide the rationale for the exclusion.

  • Provide more clarity in Requirement R8.  In the phrase “any Facilities critical to the instability, Cascading or uncontrolled separation identified,” it is not clear what would constitute “Facilities critical to the instability, Cascading or uncontrolled separation identified,” and how these are different than “Facilities that comprise the Contingency(ies) (planning events only).”
  • Requirement R8 requires the PC and TP to communicate “Facilities that comprise the Contingency(ies) (planning events only) and any Facilities critical to the instability, Cascading or uncontrolled separation identified.” Many of the updated Standards (e.g. CIP-014-3, FAC-003-5) use the applicability language “Facilities that if lost or degraded are expected to result in instances of instability, Cascading, or uncontrolled separation, that adversely impacts the reliability of the Bulk Electric System for planning events”. It would be helpful if the information provided by the PC and TP directly maps to the applicability section of these other Standards. Texas RE recommends requiring that communication to the TO and GO include “Facilities that if lost or degraded are expected to result in instances of instability, Cascading, or uncontrolled separation, that adversely impacts the reliability of the Bulk Electric System for planning events” instead of “Facilities that comprise the Contingency(ies) (planning events only) and any Facilities critical to the instability, Cascading or uncontrolled separation identified.”

  • Requirement R8 uses the phrase “planning events only.”  Texas RE recommends including an explanation that these events refer to the events in Table 1 of TPL-001.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 8/3/2020

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N/A

Jennifer Bray, Arizona Electric Power Cooperative, Inc., 1, 8/3/2020

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The time horizon in R6-R8 are currently identified as “Long-Term Planning Horizon” While this aligns with the horizon of the TPL-001-4 standard where issues would be identified, it is specifically the Near-Term Planning horizon that these issues point to. We recommend adjusting the time horizon assocoaited with R6-R8 to more accurately reflect the portion of the TPL-001-4 assessment they are intended to align to.

Joshua Andersen, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

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None

Daniela Atanasovski, APS - Arizona Public Service Co., 1, 8/3/2020

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Larisa Loyferman, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

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Dennis Chastain, On Behalf of: Tennessee Valley Authority - SERC - Segments 1, 3, 5, 6

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Teresa Krabe, Lower Colorado River Authority, 5, 8/3/2020

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NV Energy would like to communicate its additional concern over FAC-014-3, with the retirement of FAC-010-3. With the retirement of FAC-10-3, Transmission Planners will not be able to use their IROL methodology for the Planning Horizon anymore, and as stated, will be forced to adjust to their respective RC’s SOL Methodology and definition of an IROL.  NV Energy’s concern with using a respective RC’s IROL definition is the potential for the RC to identify an IROL for a more conservative loss than what a Transmission Planner would determine. NV Energy understands the need for a secure BES with the establishment of an IROL in an Interconnection; however, the ramifications of an IROL declaration stretch into multiple Standards that require a substantial amount of work for compliance implementation (i.e. CIP Standard suite), as well as the equipment modifications for facilities to monitor the flows on Elements within an IROL. NV Energy still believes their should still be a responsibility of defining IROLs with the Transmission Planner.

Kevin Salsbury, Berkshire Hathaway - NV Energy, 5, 8/3/2020

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Daniel Gacek, Exelon, 1, 8/3/2020

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David Jendras, Ameren - Ameren Services, 3, 8/3/2020

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Scott Langston, Tallahassee Electric (City of Tallahassee, FL), 1, 8/3/2020

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Carl Pineault, Hydro-Qu?bec Production, 5, 8/3/2020

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Michael Jones, National Grid USA, 1, 8/3/2020

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NERC Standard IRO-17 obligates each Planning Coordinator and Transmission Planner to provide its Planning Assessment to impacted Reliability Coordinators.  NERC TPL-001 includes the obligation that when the analysis indicates the inability of the system to meet the performance requirements.  We believe FAC-014-3 R7 basically includes/requires the same if not similar information. If this additional detail is required, we suggest that IRO-017 be updated so that this type of request is located in a single requirement or standard.

NPCC Regional Standards Committee, Segment(s) 10, 2, 4, 7, 3, 1, 5, 6, 7/8/2020

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Mark Gray, On Behalf of: Edison Electric Institute, NA - Not Applicable, Segments NA - Not Applicable

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No Comment

Eversource Group, Segment(s) 3, 1, 4/12/2019

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Allie Gavin, On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1

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Robert Hirchak, Cleco Corporation, 6, 8/3/2020

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Westar-KCPL, Segment(s) 1, 3, 5, 6, 12/18/2018

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The SPP Standards Review Group offers the following “non-content” considerations for SDT review:

1.         Implementation of the “blue box” concept, as in previous standards development processes, which could give industry insight on proposed revisions.

2.         Consideration of the concept could assist in a seamless transfer of information to the future Guideline and Technical Basis documentation.

SPP Standards Review Group, Segment(s) 2, 8/3/2020

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Colleen Campbell, AES - Indianapolis Power and Light Co., 3, 8/3/2020

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Lee Maurer, Oncor Electric Delivery, 1, 8/3/2020

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The IRC SRC would like to note that discrepancies may be introduced when applying Facility Ratings derived in accordance with the RC’s SOL methodology to the Near Term Transmission Planning Horizon because system topology may change from the time the Facility Ratings are developed in the current year to the time when the limit is applied in the Planning Assessment of the Near Term Transmission Planning Horizon; a study of anticipated system performance one (1) to five (5) years in the future. Therefore, it is preferable to retain the process under TPL-001-4 “as is.”

ISO/RTO Standards Review Committee, Segment(s) 2, 8/3/2020

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MISO supports the comments filed by the IRC SRC.

The IRC SRC would like to note that discrepancies may be introduced when applying Facility Ratings derived in accordance with the RC’s SOL methodology to the Near Term Transmission Planning Horizon because system topology may change from the time the Facility Ratings are developed in the current year to the time when the limit is applied in the Planning Assessment of the Near Term Transmission Planning Horizon; a study of anticipated system performance one (1) to five (5) years in the future. Therefore, it is preferable to retain the process under TPL-001-4 “as is.”

Bobbi Welch, Midcontinent ISO, Inc., 2, 8/3/2020

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Aaron Staley, Orlando Utilities Commission, 1, 8/3/2020

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Mickey Bellard, On Behalf of: Seminole Electric Cooperative, Inc., SERC, Segments 1, 5

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James Baldwin, Lower Colorado River Authority, 1, 8/3/2020

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Tammy Porter, On Behalf of: Tammy Porter - - Segments

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None.

Brandon Gleason, Electric Reliability Council of Texas, Inc., 2, 8/3/2020

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N/A

ACES Standard Collaborations, Segment(s) 1, 8/3/2020

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In addtion to comments submitted by the ISO/RTO Counsel (IRC) Standards Review Committee the CAISO has the following comments:

The SDT proposal to retire FAC-010 and the requirement to establish SOLs and IROLs for the planning horizon appear to be the result of the following two misconceptions:

  • The “new” TPL 001-4 standard eliminates the need for developing SOLs and IROLs for the planning horizon, which is incorrect and

  • SOLs are not useful for the reliable planning of the BES, which is also incorrect.

TPL 001-4 standard does not replace the need for developing SOLs and IROLs for the planning horizon and eliminate the need for the existing FAC-010 and Requirement R3 and R4 of the existing FAC-014. This is because TPL-001-4 is all about ensuring reliable service to firm load and firm transmission services. It does not require planning entities to stress tranfers on any part of the system to determine its limit.  Also,  since TPL-001-4 studies do not require stressing the system they are less suited to identifiying contingencies the lead to system instability, cascading and uncontrolled separation compared to SOL and IROL Studies performed under FAC-014 R3 and R4.  Even if, TPL 001-4 studies identify contingencies that lead to such adverse impacts, they would be mitigated, which means there would be no planning contingencies with such adverse impacts.

SOLs are useful  in the reliable planning of the system. For example, in the Western Interconnection (accepted) path ratings, which California ISO deems to be SOLs and are typically developed in the planning horizon, are used in the reliable planning of the system. In all its studies including the annual reliability assessment and local capacity studies, the CAISO ensures these SOLs are not exceeded. For example, reliability assessments and local capacity studies performed use this SOL information.

Jamie Johnson, California ISO, 2, 8/3/2020

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Denise Sanchez, On Behalf of: Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Tino Zaragoza, Imperial Irrigation District, 1,3,5,6; Tino Zaragoza, Imperial Irrigation District, 1,3,5,6; Diana Torres, Imperial Irrigation District, 1,3,5,6; Diana Torres, Imperial Irrigation District, 1,3,5,6; Glen Allegranza, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6

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n/a

Gul Khan, On Behalf of: Oncor Electric Delivery - Texas RE - Segments 1

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Support the MRO-NSRF comments.

Wayne Guttormson, SaskPower, 1, 8/3/2020

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Please see comments submitted by Edison Electric Institute

Kenya Streeter, Edison International - Southern California Edison Company, 6, 8/3/2020

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No. Thank you

sean erickson, Western Area Power Administration, 1, 8/3/2020

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PG&E has no additional comments.

Pamalet Mackey, On Behalf of: Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5

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PG&E has no additional comments.

Marco Rios, Pacific Gas and Electric Company, 1, 8/3/2020

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Jack Stamper, Clark Public Utilities, 3, 8/21/2020

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Hot Answers

Maurice Paulk, On Behalf of: Cleco Corporation, , Segments 1, 3, 5, 6

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Ray Jasicki, 8/24/2020

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Other Answers

IRO-008 R5. What is the purpose of the Reliability Coordinator notifying the Transmission Operator of SOL/IROL exceedances? If it’s for the Transmission Operator’s Real-time monitoring and Real-time assessments, then the data specification concept should be maintained and TOP-003-3 should be enhanced to allow the Transmission Operator to request and receive this information from its Reliability Coordinator based on its individual operating environment. To keep this requirement detached in IRO-008 is not effective or efficient and contrary to ongoing work by the Standards Efficiency Review project to simplify data exchange requirements, reduce administrative burdens and remove redundancies. If not used for the Transmission Operator’s Real-time monitoring and Real-time assessments, then please explain the purpose and the corresponding obligation by the Transmission Operator to use the information? Otherwise, it potentially becomes an administrative compliance exercise that distracts our operations personnel and isn’t benefiting reliability.

IRO-008 R6. What is the purpose of the Reliability Coordinator notifying the Transmission Operator when SOL/IROL exceedances are prevented or mitigated? If it’s for the Transmission Operator’s Real-time monitoring and Real-time assessments, then the data specification concept should be maintained and TOP-003-3 should be enhanced to allow the Transmission Operator to request and receive information from its Reliability Coordinator. To keep this requirement detached in IRO-008 is contrary to ongoing work by the Standards Efficiency Review project to simplify data exchange requirements, reduce administrative burdens and remove redundancies. If not used for the Transmission Operator’s Real-time monitoring and Real-time assessments, then please explain the purpose and the corresponding obligation by the Transmission Operator to use the information? Otherwise, it potentially becomes an administrative compliance exercise that distracts our operations personnel and isn’t benefiting reliability. 

John Allen, City Utilities of Springfield, Missouri, 4, 7/15/2020

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Michael Courchesne, On Behalf of: Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2

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Laura Nelson, 7/24/2020

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NCPA supports John Allen's, City Utilities of Springfield, Missouri, comments.

Marty Hostler, On Behalf of: Northern California Power Agency, , Segments 3, 4, 5, 6

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Why R25 couldn’t have just been incorporated into R14?  R25 basically stating a TOP has to use its RC’s methodology, which indirectly implies it has to be in each TOP operating plan for the identified SOL exceedances for R14?

Matthew Nutsch, On Behalf of: Seattle City Light, WECC, Segments 1, 3, 4, 5, 6

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Thomas Foltz, AEP, 5, 7/27/2020

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The changes to these standards place a considerable reporting requirement on SOL

exceedance. Manitoba Hydro is requesting 30 month implementation period rather than, normal

12 months implementation period to work out SOL reporting methodology with the RC.

Bruce Reimer, Manitoba Hydro , 1, 7/27/2020

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Jennie Wike, On Behalf of: John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6

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“These comments represent the MRO NSRF membership as a whole but would not preclude members from submitting individual comments”.

IRO-008 R5. What is the purpose of the Reliability Coordinator notifying the Transmission Operator of SOL exceedances? If it’s for the Transmission Operator’s Real-time monitoring and Real-time assessments, then the data specification concept should be maintained and TOP-003-3 should be enhanced to allow the Transmission Operator to request and receive this information from its Reliability Coordinator based on its individual operating environment. To keep this requirement detached in IRO-008 is contrary to ongoing work by the Standards Efficiency Review project to simplify data exchange requirements and remove redundancies. If not used for the Transmission Operator’s Real-time monitoring and Real-time assessments, then please explain the purpose and the corresponding obligation by the Transmission Operator to use the information? Otherwise, it potentially becomes an administrative compliance exercise that distracts our operations personnel and isn’t benefiting reliability.

IRO-008 R6. What is the purpose of the Reliability Coordinator notifying the Transmission Operator when SOL exceedances are prevented or mitigated? If it’s for the Transmission Operator’s Real-time monitoring and Real-time assessments, then the data specification concept should be maintained and TOP-003-3 should be enhanced to allow the Transmission Operator to request and receive information from its Reliability Coordinator. To keep this requirement detached in IRO-008 is contrary to ongoing work by the Standards Efficiency Review project to simplify data exchange requirements and remove redundancies. If not used for the Transmission Operator’s Real-time monitoring and Real-time assessments, then please explain the purpose and the corresponding obligation by the Transmission Operator to use the information? Otherwise, it potentially becomes an administrative compliance exercise that distracts our operations personnel and isn’t benefiting reliability.

MRO NSRF, Segment(s) 3, 4, 5, 6, 1, 2, 1/29/2020

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Lincoln Electric System, Segment(s) 5, 6, 3, 1, 4/17/2018

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None

Richard Jackson, U.S. Bureau of Reclamation, 1, 7/29/2020

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Vince Ordax, Florida Reliability Coordinating Council – Member Services Division , 8, 7/29/2020

- 0 - 0

BC Hydro, Segment(s) 3, 5, 1, 12/18/2018

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Amy Casuscelli, On Behalf of: Michael Ibold, Xcel Energy, Inc., 1,3,5; Michael Ibold, Xcel Energy, Inc., 1,3,5; Michael Ibold, Xcel Energy, Inc., 1,3,5

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None.

Duke Energy, Segment(s) 1, 5, 6, 4/11/2019

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Alliant Energy supports the comments submitted by the MRO NSRF.

Larry Heckert, Alliant Energy Corporation Services, Inc., 4, 7/30/2020

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MEC supports MRO NSRF comments. 

RO-008 R5. What is the purpose of the Reliability Coordinator notifying the Transmission Operator of SOL exceedances? If it’s for the Transmission Operator’s Real-time monitoring and Real-time assessments, then the data specification concept should be maintained and TOP-003-3 should be enhanced to allow the Transmission Operator to request and receive this information from its Reliability Coordinator based on its individual operating environment. To keep this requirement detached in IRO-008 is contrary to ongoing work by the Standards Efficiency Review project to simplify data exchange requirements and remove redundancies. If not used for the Transmission Operator’s Real-time monitoring and Real-time assessments, then please explain the purpose and the corresponding obligation by the Transmission Operator to use the information? Otherwise, it potentially becomes an administrative compliance exercise that distracts our operations personnel and isn’t benefiting reliability.

IRO-008 R6. What is the purpose of the Reliability Coordinator notifying the Transmission Operator when SOL exceedances are prevented or mitigated? If it’s for the Transmission Operator’s Real-time monitoring and Real-time assessments, then the data specification concept should be maintained and TOP-003-3 should be enhanced to allow the Transmission Operator to request and receive information from its Reliability Coordinator. To keep this requirement detached in IRO-008 is contrary to ongoing work by the Standards Efficiency Review project to simplify data exchange requirements and remove redundancies. If not used for the Transmission Operator’s Real-time monitoring and Real-time assessments, then please explain the purpose and the corresponding obligation by the Transmission Operator to use the information? Otherwise, it potentially becomes an administrative compliance exercise that distracts our operations personnel and isn’t benefiting reliability.

Terry Harbour, Berkshire Hathaway Energy - MidAmerican Energy Co., 1, 7/30/2020

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MEC Supports NSRF Comments

Darnez Gresham, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 7/30/2020

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Leonard Kula, Independent Electricity System Operator, 2, 7/30/2020

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Detailed comments are in the attached file with special formatting for clarity and emphasis where needed (strike-through, highlighting, etc.).

Southern Company, Segment(s) 1, 3, 5, 6, 12/13/2019

2015-09_Unofficial_Comment_Form_202006 - SOCO Comments Final.pdf

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N/A

FE Voter, Segment(s) 1, 3, 5, 6, 4, 7/31/2020

- 0 - 0

None

Joe O'Brien, NiSource - Northern Indiana Public Service Co., 6, 7/31/2020

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Dominion, Segment(s) 3, 5, 1, 9/19/2019

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Considering that "Consistent with SOL methodology" is mentioned throughout the Standard, suggest referencing "SOL expectations outlined in FAC-011-3" somewhere within the Standard.

Anthony Jablonski, ReliabilityFirst , 10, 7/31/2020

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Maryanne Darling-Reich, On Behalf of: Black Hills Corporation - MRO, WECC - Segments 1, 3, 5, 6

- 0 - 0

Glenn Barry, Los Angeles Department of Water and Power, 5, 7/31/2020

- 0 - 0

OKGE, Segment(s) 6, 1, 3, 5, 4/10/2019

- 0 - 0

PPL NERC Registered Affiliates, Segment(s) 1, 3, 5, 6, 9/6/2018

- 0 - 0

MPC supports comments submitted by the MRO NERC Standards Review Forum.

Andy Fuhrman, On Behalf of: Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1

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Truong Le, On Behalf of: Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Chris Gowder, Florida Municipal Power Agency, 3,4,5,6; Chris Gowder, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Richard Montgomery, Florida Municipal Power Agency, 3,4,5,6; Richard Montgomery, Florida Municipal Power Agency, 3,4,5,6; Carol Chinn, Florida Municipal Power Agency, 3,4,5,6; Carol Chinn, Florida Municipal Power Agency, 3,4,5,6; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3

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LaTroy Brumfield, American Transmission Company, LLC, 1, 8/3/2020

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Need to add the word "its" to the modified portion of Requirement R6.

Steven Rueckert, Western Electricity Coordinating Council, 10, 8/3/2020

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Cain Braveheart, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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Mark Holman, 8/3/2020

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Sandra Shaffer, 8/3/2020

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Texas RE has the following comments for proposed IRO-008-3:

  • In Requirement R1, revise Interconnection Operating Reliability Limits to Interconnection Reliability Operating Limits.

  • In Requirement R5, “exceedance” is added after SOL but is not in Requirement R6.  It was added in the VSL/VRF matrix for Requirement 5 and parts of Requirement R6.  Requirement R6 VSL/VRF only has “exceedance” added within the first statement and not the second statements (after the “OR” in Lower, Moderate, and High VSL columns on page 12 of 15).  Since the language appears to be so similar, Texas RE recommends consistency in where exceedance is added. 

  • Requirement R7, as well as the measure, capitalizes “Real-time Monitoring.”  Real-time Monitoring is not a defined term in the NERC Glossary and monitoring should not be capitalized.

  • Texas RE noticed the Data Retention section does not include Requirement R7.  Texas RE recommends Requirement R7’s data retention match Measures M1 - M3, Measure M5, and Measure M6 at a minimum.

  • Texas RE noticed the Guidelines and Technical Basis has been removed from this standard, but it is still in place for other standards, such as PRC-026.  Texas RE recommends following the Technical Rationale Transition Plan and determine whether the Guidelines and Technical Basis is Technical Rationale or Implementation Guidance.

  • Texas RE recommends the IRO-008-3 mapping document include the BA since it is included in the standard.

  • Texas RE has the following comments for proposed TOP-001-6:

  • The term “Real-Time System Operators” is used in several places in the rationale document.  Since it is not a defined term in NERC Glossary, Texas RE recommends using the term System Operator, which is defined.

  • In Requirement R15, it is unclear as to whether the phrase “in accordance with its Reliability Coordinator’s SOL methodology” is referring to the “exceeded” SOL or the need to “inform”.  The VSL/VRF matrix language structure places the phrase after “inform”.  Texas RE recommends reviewing the sentence and make clarifying changes as necessary. 

  • Requirement R25, as well as the measure, capitalizes “Real-time Monitoring”.  Real-time Monitoring is not a defined term in the NERC Glossary and monitoring should not be capitalized.  It is also capitalized in the VSL/VRF matrix and the Evidence Retention sections of the standard.

  • Texas RE requests justification for revising the Evidence Retention requirement for Requirement R14.  This justification for the change could be captured in the mapping document for TOP-001-6.
  • The mapping document appears to contain guidance on how to comply with TOP-001-6, in the statement “communication could range from simply RC and TOP sharing via ICCP output from the real time monitoring and RTCA output”.  This is not a method to inform the RC of “actions taken”.  ICCP reflects results of actions but does not necessarily reflect the action(s) actually taken.  The mapping document is not an appropriate place for putting guidance on how to comply with the standard and the process for developing Implementation Guidance can be utilized if the SDT would like to provide guidance on complying with the standard.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 8/3/2020

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N/A

Jennifer Bray, Arizona Electric Power Cooperative, Inc., 1, 8/3/2020

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Joshua Andersen, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

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None

Daniela Atanasovski, APS - Arizona Public Service Co., 1, 8/3/2020

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Larisa Loyferman, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

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Dennis Chastain, On Behalf of: Tennessee Valley Authority - SERC - Segments 1, 3, 5, 6

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Teresa Krabe, Lower Colorado River Authority, 5, 8/3/2020

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NV Energy agrees with the requirement language provided for TOP-001-6 R14, but has concerns with the language provided for the measures for R14. NV Energy has concerns with the phrase “successfully mitigated”, and it not being appropriate, even if it is just for suggested evidence. Requirement R14 states only to show a Plan that was initiated to mitigate SOLs, not to prove mitigation. While success is obviously the desired outcome, it is not the only possible outcome, and this language addition to the measures for R14 seems to extend beyond the intent of the requirement.

Kevin Salsbury, Berkshire Hathaway - NV Energy, 5, 8/3/2020

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Daniel Gacek, Exelon, 1, 8/3/2020

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David Jendras, Ameren - Ameren Services, 3, 8/3/2020

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Scott Langston, Tallahassee Electric (City of Tallahassee, FL), 1, 8/3/2020

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Carl Pineault, Hydro-Qu?bec Production, 5, 8/3/2020

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Michael Jones, National Grid USA, 1, 8/3/2020

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NPCC Regional Standards Committee, Segment(s) 10, 2, 4, 7, 3, 1, 5, 6, 7/8/2020

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Mark Gray, On Behalf of: Edison Electric Institute, NA - Not Applicable, Segments NA - Not Applicable

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No Comment

Eversource Group, Segment(s) 3, 1, 4/12/2019

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Allie Gavin, On Behalf of: Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1; Michael Moltane, International Transmission Company Holdings Corporation, 1

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Robert Hirchak, Cleco Corporation, 6, 8/3/2020

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Westar-KCPL, Segment(s) 1, 3, 5, 6, 12/18/2018

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SPP Standards Review Group, Segment(s) 2, 8/3/2020

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IPL offers no further comment.

Colleen Campbell, AES - Indianapolis Power and Light Co., 3, 8/3/2020

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Lee Maurer, Oncor Electric Delivery, 1, 8/3/2020

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ISO/RTO Standards Review Committee, Segment(s) 2, 8/3/2020

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MISO supports the comments filed by the IRC SRC.

The IRC SRC respectfully requests the SDT extend the timeframe for implementation from 12 to at least 24 calendar months to support the changes needed to comly with FAC-011-4, FAC-014-3, TOP-001-6 and IRO-008-3. Some entities will need to enhance existing tools to accurately track, validate and reconcile SOL exceedances; particularly in those instances where the Reliability Coordinator (RC) is not also the Transmisison Operator (TOP). In addition to tools, implementation of the new standards will require collaboration between the RC and its respective TOPs to revise the SOL methodology and associated processes and procedures and provide relevant training to system operators. Additionally, a 24-month implementation timeframe would provide the time needed to budget, design, develop, test, implement and train on new processes and tools prior to placing them into production, particularly in light of the ongoing operational challenges associated with the COVID-19 pandemic and the anticipated demand this will place on EMS vendors as entities compete for limited resources. For these reasons, the IRC SRC is requesting the SDT consider extending the implementation timeframe to at least 24 months.

 

Bobbi Welch, Midcontinent ISO, Inc., 2, 8/3/2020

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Aaron Staley, Orlando Utilities Commission, 1, 8/3/2020

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Mickey Bellard, On Behalf of: Seminole Electric Cooperative, Inc., SERC, Segments 1, 5

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James Baldwin, Lower Colorado River Authority, 1, 8/3/2020

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Tammy Porter, On Behalf of: Tammy Porter - - Segments

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ERCOT suggests the implementation period be extended from 12 to 24 months in order to allow sufficient time to make necessary system changes.

Brandon Gleason, Electric Reliability Council of Texas, Inc., 2, 8/3/2020

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N/A

ACES Standard Collaborations, Segment(s) 1, 8/3/2020

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California ISO agrees with comments submitted by the ISO/RTO Counsel (IRC) Standards Review Committee.

Jamie Johnson, California ISO, 2, 8/3/2020

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Denise Sanchez, On Behalf of: Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Tino Zaragoza, Imperial Irrigation District, 1,3,5,6; Tino Zaragoza, Imperial Irrigation District, 1,3,5,6; Diana Torres, Imperial Irrigation District, 1,3,5,6; Diana Torres, Imperial Irrigation District, 1,3,5,6; Glen Allegranza, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6; Jesus Sammy Alcaraz, Imperial Irrigation District, 1,3,5,6

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n/a

Gul Khan, On Behalf of: Oncor Electric Delivery - Texas RE - Segments 1

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Support the MRO-NSRF comments.

Wayne Guttormson, SaskPower, 1, 8/3/2020

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Please see comments submitted by Edison Electric Institute

Kenya Streeter, Edison International - Southern California Edison Company, 6, 8/3/2020

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No. Thank you.

sean erickson, Western Area Power Administration, 1, 8/3/2020

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PG&E has no additional comments.

Pamalet Mackey, On Behalf of: Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Sandra Ellis, Pacific Gas and Electric Company, 1,3,5; Ed Hanson, Pacific Gas and Electric Company, 1,3,5

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PG&E has no additional comments.

Marco Rios, Pacific Gas and Electric Company, 1, 8/3/2020

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These standards appear to be fine.

One general comment on various FAC standards is the use of the term "impacted." It is used as a non-capitalized term however, how is an entity supposed to determine if another entity is impacted or not?

If Clark is suposed to do something or say something to an impacted RC, what criteria is it to use to determine whether RC West is just an RC or an impacted RC?

Jack Stamper, Clark Public Utilities, 3, 8/21/2020

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Hot Answers

See SEE, EEI and MISO comments

Maurice Paulk, On Behalf of: Cleco Corporation, , Segments 1, 3, 5, 6

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Ray Jasicki, 8/24/2020

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Other Answers

The standards need to be results-based and define a clear and measurable expected outcome for all Registered Entities. By adding “that adversely impact the reliability of the Bulk Electric System” implies that some instability, Cascading or uncontrolled separation is acceptable. Who determines that threshold? The Reliability Coordinator in its SOL methodology? How do we ensure a consistent expectation and application for all Registered Entities?

John Allen, City Utilities of Springfield, Missouri, 4, 7/15/2020

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Michael Courchesne, On Behalf of: Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2; Michael Puscas, ISO New England, Inc., 2

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Laura Nelson, 7/24/2020

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NO.

NCPA supports John Allen's, City Utilities of Springfield, Missouri, comments.

Additionally, NERC has a SER project.  Project 2015-09, Establish and Communicate, System Operating Limits, proposals create more redunancies; counter to the purpose of the SER project.

 

Marty Hostler, On Behalf of: Northern California Power Agency, , Segments 3, 4, 5, 6

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Regarding the changes to CIP-014, Seattle City Light has five areas of concern. The first three relate to revised Section 4.1.1.3 and the fourth and fifth address impacts to existing R1.

First, the changes to Section 4.1.1.3 to replace the reference to IROL Facilities identified by an entity’s Reliability Coordinator, Planning Coordinator, or Transmission Planner with Facilities associated with instability, Cascading, or uncontrolled separation, that also adversely impact BES reliability for planning events, is inconsistent with Criteria 2.6 of CIP-002 Attachment 1, from which Section 4.1.1.3 was taken. The applicability CIP-014 is designed to conform to the criteria of CIP-002 for Medium impact Transmission Facilities. For consistency among the CIP Standards, Seattle suggests that CIP-002 Attachment 1, Criteria 2.6, also be changed along with CIP-014.

Second, the changes to Section 4.1.1.3 are confusing and perhaps redundant. As proposed, the criteria to identify applicable Facilities has two components: (i) loss that creates instability, Cascading, or uncontrolled separation, (ii) that adversely impacts BES reliability for planning events. So far as Seattle is aware, nowhere else in the NERC Standards are the “big three” bad events (instability, Cascading, uncontrolled separation) qualified in this way; they are presumed by their existence to create adverse BES impacts. In addition, the language “adverse impact for planning events” adds another layer of confusion. What is an adverse impact for a planning event? Considerable effort has been spent by NERC and industry over the years to qualify “adverse BES impact” for CIP-002, yet this new language introduces a different new concept that expands adverse impact to new territory. Additional clarity is required. As a simpler solution, Seattle suggests that the qualifier phrase “that adversely impacts…” be dropped from the proposed change to Section 4.1.1.3.

Third, the changes to Section 4.1.1.3 add a new burden on entities that was not previously present. For IROLs, there exist established processes to inform entities of the existence of IROLs and document those Facilities critical to their derivation. The “IROL Cards” and IROL website used in the Western Interconnection are examples of these processes. As a result, it is easy for entities to apply existing Section 4.1.1.3 criteria (as well as those of CIP-002 Criteria 2.6) and crystal clear to document conclusions at audit. For the proposed changes, there is no established mechanism or consistent process for Planning Coordinators or Transmission Planners to share with entities information about Facilities related to BES instability, Cascading, or uncontrolled separation, nor is there established language about how to identify such Facilities. Presumably such information is shared in some fashion as a matter of good practice, but absent any established means to do so and consistent approach to documentation, the change creates a new burden on entities to track down such information from others and to clarify findings in unequivocal, crystal clear language to satisfy any auditor. As a solution, Seattle suggests that somewhere in the body of changes introduced by Project 2015-09, there be a new requirement for Planning Coordinators and Transmission Planners to inform subject entities, in a standardized manner, of Facilities related to to BES instability, Cascading, or uncontrolled separation.

Fourth, the changes to Section 4.1.1.3 cause redundancy for CIP-014 R1. Specifically, R1 requires a transmission planning study to identify Facilities associated with instability, Cascading, or uncontrolled separation. These are the identical criteria that cause a Facility to be applicable in 4.1.1.3. As proposed, the requirement would require a transmission study on Facilities identified to be associated with instability, Cascading, or uncontrolled separation to determine if they are associated with instability, Cascading, or uncontrolled separation. Ridiculous! As a possible solution, Seattle suggests CIP-014 R1 be rewritten to exempt from evaluation any Facility meeting Section 4.1.1.3 (because it already has been so evaluated), and revise R2 to require a third party evaluation of the entity’s R1 study and the Section 4.1.1.3 evaluation of the applicable Planning Coordinator/Transmission Planner.

Fifth, the different qualifiers used in Section 4.1.1.3 and R1 create unnecessary confusion. Section 4.1.1.3 qualifies applicability based on “adversely impacting the reliability of the BES reliability for planning events” whereas R1 qualifies applicability “within an Interconnection.” It is not clear how these different qualifiers impact identified instances of identified instability, Cascading, or uncontrolled separation. There’s enough confusion and auditor dissent for CIP-014 about how to apply the “within an Interconnection” qualifier; no new confusion is needed. As suggested above, Seattle recommends that the Section 4.1.1.3 “adverse impact” qualifier be removed, which would also address R1 confusion as discussed here. If qualifying language is desired, Seattle recommends that the same language be used in Section 4.1.1.3 and R1. 

Matthew Nutsch, On Behalf of: Seattle City Light, WECC, Segments 1, 3, 4, 5, 6

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AEP continues to have concerns regarding 4.2.2, Transmission Facilities, within FAC-003. Proposing new requirements in FAC-014 to ensure a Transmission Planner is performing a “planning assessment” does not automatically ensure such efforts will naturally flow to FAC-003 simply because they are in the same standard family. The SDT may be making some assumptions regarding communication in that regard.  It should not be assumed that communication between a Transmission Planning function and a Transmission Owner (a Forestry department, for example) would be a naturally occurring activity. If these changes are indeed pursued, the SDT will need to give consideration on how to ensure this communication is taking place. It should also be noted however that while more insight is needed on ensuring this communication takes place, care should also be taken to ensure no restrictions or limitations be unnecessarily placed on the parties involved.

These proposed revisions could unintentionally lead to a line not being properly identified. Any  planning event causing instability that is identified in planning assessments, whether the contingency is above or below 200 kV, would have a corrective action plan which may possibly include generation redispatch. If generation redispatch is applied in the operation time-frame, as might be assumed in planning, there is no instability for a planning event and no lines will be identified. We are not certain whether or not the SDT realizes this could be applicable to CAPs of any nature. Could the SDT provide insight as to whether these proposed revisions are requiring that the identification of lines below 200 kV take place pre-CAP or instead post-CAP? In any event, we disagree with the proposed revisions, which we believe changes from identifying lines in a practical way, to doing so in a less practical manner using planning studies.

As stated in the previous comment period, we believe additional text is needed here to ensure no lines are unintentionally excluded by a) the timing of their being identified as part of an IROL and b) the timing of any facilities identified, which could lead to instability, Cascading, or uncontrolled separation within associated planning assessments. The SDT’s response from the previous comment period gives the impression that they may possibly be unaware of the guidance provided in the original Errata which was eventually incorporated into the GTB. The team provided an example of a line identified as an IROL and then incorporated into FAC-003 and that “it could be months or years before the vegetation management caught up with the designation, providing no practical benefit.” The SDT may wish to further review the GTB of this standard to ensure they are aware such guidance has already been provided in this standard regarding how soon after a line is identified that it becomes incorporated into the vegetation management program. With this in mind, AEP once again recommends that this section be clarified in the following manner… “Each overhead transmission line operated below 200kV, identified by the Planning Coordinator or Transmission Planner, per its Planning Assessment of the Near-Term Transmission Planning Horizon or its Transfer Capability Assessment (Planning Coordinator only) as a Facility that if lost or degraded are expected to result in instances of instability, Cascading, or uncontrolled separation or overhead transmission line operated below 200kV that have been established as part of an IROL by the Reliability Coordinator per IRO-014-3 R1.” 

 

Proposed Implementation Plan: The changes proposed are very expansive and involve many individuals across a number of Functional Entities. In addition, new cross-functional procedures and processes would need to developed and established to meet the proposed obligations. As a result, we believe 36 months would be more appropriate.

We believe the references to planning events in CIP-14 Applicability Section 4.1.1.3 and FAC-003 Applicability Sections 4.2.2 and 4.3.1.2 could be more clearly stated. We recommend that CIP-014 Applicability Section 4.1.1.3 be revised to state “Transmission Facilities at a single station or substation location that are identified by the Planning Coordinator, or Transmission Planner, per its Planning Assessment of the NearTerm Transmission Planning Horizon as Facilities that if lost or degraded *due to planning events* are expected to result in instances of instability, Cascading, or uncontrolled separation, that adversely impacts the reliability of the Bulk Electric System.”

AEP would like to make a suggestion and encouragement regarding how the standards drafting team provides redlined documents for industry review. While redlined documents using the previously proposed revision as a baseline do provide a very beneficial way for the reader to identify only the most-recently proposed changes, we believe that they cannot be the only redlined document provided during these comment and balloting periods. These particular redlines are simply a “delta” between the current and previous draft revision and do NOT show all the proposed additions and deletions that have been retained-to-date. This could result in the reader misunderstanding or misinterpreting the content in the draft. For example, text shown in black could be a) text currently included in the version under enforcement or b) new text that was proposed in a previous comment period but “no longer considered new text” in the current comment period. In addition, text shown as deleted could be a) text that has been newly proposed for deletion in the current comment period or b) text that was proposed for addition in a previous comment period draft but then later struck from consideration in a latter comment period. As a result, when multiple revisions are proposed over time, the reader would have to review each and every draft proposed to date and somehow determine for themselves all the changes retained to date. A balloter is not voting on only the most recently proposed changes, they are voting on all the proposed changes that have been retained-to-date. As a result, we recommend drafts showing only most recent changes also be accompanied by an additional redlined document which shows *all the proposed revisions retained to date*, and using the version under enforcement as a baseline.

Thomas Foltz, AEP, 5, 7/27/2020

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We agree with the retirement of planning based IROLs.  We also agree with  the

changes made to the CIP-014 and PRC-023 standards.  However we don’t agree with the use of a

 general statement to  say that the retirement of FAC-10 will eliminate all planning based SOLs.

Planing coordinator can still use their SOLs with valid  technical rationale.

Bruce Reimer, Manitoba Hydro , 1, 7/27/2020

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Jennie Wike, On Behalf of: John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; John Merrell, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Terry Gifford, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Hien Ho, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6; Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 1,3,4,5,6

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“These comments represent the MRO NSRF membership as a whole but would not preclude members from submitting individual comments”.

The MRO NSRF agrees with the changes to FAC-003, FAC-013, PRC-002, PRC-023 and PRC-026 (subject to the recommendations made in questions 1 to 6), but disagrees with changes to CIP-014 at this time.

CIP-014 Applicability Section 4.1.1.3 comes from CIP-002-5.1a Medium Impact Rating criterion 2.6. The SDT for Project 2016-02 considered and rejected this proposed change for CIP-002-6, which just passed industry ballot without any change to criteria 2.6 and 2.9, both of which continue to reference IROLs, a NERC Glossary-defined term.

 

The proposal would lower the threshold from Interconnection instability to any instability affecting the BES, representing a potentially substantial increase in scope for CIP-014, and sundering the connection to and synergy with CIP-002, creating disparate populations.

Deference should be given to the SDT for Project 2016-02 with respect to any conforming changes to CIP-002 and CIP-014, which need to be addressed concurrently and consistently.

The MRO-NSRF suggests the SDT coordinate with Project 2018-03 which shows FAC-013 and TOP-001 R22 scheduled to be retired by FERC.

MRO NSRF, Segment(s) 3, 4, 5, 6, 1, 2, 1/29/2020

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LES supports comments provided by the MRO NSRF related to CIP-014.

Lincoln Electric System, Segment(s) 5, 6, 3, 1, 4/17/2018

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Richard Jackson, U.S. Bureau of Reclamation, 1, 7/29/2020

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Vince Ordax, Florida Reliability Coordinating Council – Member Services Division , 8, 7/29/2020

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BC Hydro agrees with the changes to CIP-014, FAC-003, FAC-013 and PRC-023. However, on FAC-013, PRC-023 and PRC-026, BC Hydro offers the following comments and suggestions.

FAC-013-3         Project 2018-03 Standards Efficiency Review Retirements drafting team recommended the retirement of FAC-013-2. As stated in their June 7, 2019 petition to FERC, NERC determined that the standard is not needed for BES reliability, and should therefore be retired. BC Hydro suggest that a revision of FAC-013-2 is no longer warranted.

PRC-023-5        Through the inclusion of the Transmission Planner (TP) in Attachment B, Criterion B2, the proposed revision indicates TP’s responsibilities of selecting the circuits subject to requirements R1 through R5. BC Hydro recommends that the TP functional entity be included in the Applicability section of the standard and the TP’s responsibilities clarified in the language of the requirement.

PRC-026-2          Requirement 1 mandates that the Planning Coordinator (PC) use Near-Term Planning Assessment results to identify stability constraints associated BES elements. However, the Near-Term Planning Assessment would be conducted by Transmission Planners (TPs) and coordinated by their PC. If a TP fails to provide its PC the list of stability related BES elements, PC could be held non-compliant to PRC-026-2.  The proposed draft does not identify the Transmission Planners (TPs) as a responsible entity. BC Hydro recommends that the Transmission Planner’s role to timely provide its PC with the BES Elements meeting R1 criteria be reflected within the requirement, and TP functional entity be added to the Applicability section of the standard.

BC Hydro, Segment(s) 3, 5, 1, 12/18/2018

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Xcel Energy recommends a longer implementation plan due to the coordination and potential tools required.

Amy Casuscelli, On Behalf of: Michael Ibold, Xcel Energy, Inc., 1,3,5; Michael Ibold, Xcel Energy, Inc., 1,3,5; Michael Ibold, Xcel Energy, Inc., 1,3,5

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Connditionally Yes - Request clarification of the phrase “adversely impacts” for impacted Standards.  For example, the first FAC-003 instance reads: 4.3.1.2 Facility that if lost or degraded are expected to result in instances of instability, Cascading, or uncontrolled separation that "adversely impacts" the reliability of the Bulk Electric System for a planning event…  Please confirm the phrase “adversely impacts” has the exact meaning as the NERC Reliability Standards Glossary defined phrase “Adverse Reliability Impact”; if different, please define phrase "adversely impacts".

Additionally, due to the numerous methodologies, procedures, processes, tools, and training impacts associated with this Project, suggest extending implementation period from 12 months to 30 months.

Duke Energy, Segment(s) 1, 5, 6, 4/11/2019

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Alliant Energy supports the comments submitted by the MRO NSRF.

Larry Heckert, Alliant Energy Corporation Services, Inc., 4, 7/30/2020

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MEC supports MRO NSRF comments. 

The MRO NSRF agrees with the changes to FAC-003, FAC-013, PRC-002, PRC-023 and PRC-026 (subject to the recommendations made in questions 1 to 6), but disagrees with changes to CIP-014 at this time.

CIP-014 Applicability Section 4.1.1.3 comes from CIP-002-5.1a Medium Impact Rating criterion 2.6. The SDT for Project 2016-02 considered and rejected this proposed change for CIP-002-6, which just passed industry ballot without any change to criteria 2.6 and 2.9, both of which continue to reference IROLs, a NERC Glossary-defined term.

The proposal would lower the threshold from Interconnection instability to any instability affecting the BES, representing a potentially substantial increase in scope for CIP-014, and sundering the connection to and synergy with CIP-002, creating disparate populations.

Deference should be given to the SDT for Project 2016-02 with respect to any conforming changes to CIP-002 and CIP-014, which need to be addressed concurrently and consistently.

The MRO-NSRF suggests the SDT coordinate with Project 2018-03 which shows FAC-013 and TOP-001 R22 scheduled to be retired by FERC.

Terry Harbour, Berkshire Hathaway Energy - MidAmerican Energy Co., 1, 7/30/2020

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MEC Supports NSRF Comments

Darnez Gresham, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 7/30/2020

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Leonard Kula, Independent Electricity System Operator, 2, 7/30/2020

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Southern Company does not support adjusting the applicable entity in PRC 002 [R5] from TP/PC to RC for the Eastern Interconnect. TP/PCs are appropriately positioned to identify where dynamic Disturbance recording (DDR) data is required based upon their wide area view of reliability needs, particularly as it pertains to changing system conditions that can be best gauged in the near term planning horizon. Furthermore, this time horizon is more aptly suited for determining equipment installation requirements due to the lead-time associated with the installation of any BES equipment. Lastly, there are potentially significant implementation plan and timing concerns with shifting the applicability of existing requirements to another functional entity, that could correspondingly shift the location and amount of DDR coverage required. These implementation considerations would need to be addressed.

 

Southern Company, Segment(s) 1, 3, 5, 6, 12/13/2019

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FirstEnergy disagrees with the proposed changes to CIP-014 as the changes proposed are not also being applied to NERC Reliability Standard CIP-002 - Attachment 1, criteria 2.6.  The four (4) sub-parts of Applicability Section 4.1.1 in the current approved CIP-014 standard are based on a subset of the NERC CIP-002 Attachment 1 criteria.  The proposed change to CIP-014 section 4.1.1.3 would bring inconsistency with the CIP-002 - Attachment 1, criteria 2.  While we do not necessarily oppose the proposed revision, the SDT should also ensure the change is made to CIP-002 for consistency and the proposed changes would need to be more carefully considered for impact within the CIP-002 standard before we can fully support.

FE Voter, Segment(s) 1, 3, 5, 6, 4, 7/31/2020

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Joe O'Brien, NiSource - Northern Indiana Public Service Co., 6, 7/31/2020

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Dominion has the same concerns with the term instability that we have previously shared both here and in regards to prvious versions of CIP-002. The current use of the term, without clarification that it is intended to be applied to wide area issues, could lead to misinterpretation of the intent and lead to inconsistent application of the standard.

Dominion, Segment(s) 3, 5, 1, 9/19/2019

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ReliabilityFirst offers the following comments for consideration.

  1. PRC-026-2

    1. The revised Standard uses the capitalized term “Near-Term Planning Horizon,” but this term is not in the NERC Glossary. The term defined in the NERC Glossary is “Near-Term Transmission Planning Horizon.”

    2. The revised Standard uses the capitalized term “Near-Term Planning Horizon” but this term is not in the NERC Glossary.

  2. PRC-023-5

    1. Attachment B criteria B2 added the term in bold: “… instances of instability, Cascading, or uncontrolled separation, that adversely impact the reliability of the Bulk Electric System for planning events.” The bolded term is also used in FAC-011-4, and our comments are nearly the same: What is the meaning of “that adversely impact the reliability of the Bulk Electric System?” Is it possible for instability, Cascading, or uncontrolled separation to NOT adversely impact the reliability of the BES? What is the criteria for determining if instability, Cascading, or uncontrolled separation do or do not adversely impact the reliability of the BES? Attachment B criteria B2 is open to interpretation, and therefore does not promote the reliability of the BES. Note that the NERC approved definition of IROL also uses the term “… that adversely impact the reliability of the Bulk Electric System.”

    2. There are references in R6 to version 4 of the Standard (PRC-023-4) that should be changed to reference the new PRC-023-5 Standard

    3. Recommend update to the new format with the measurements placed under each requirement.

  3. FAC-003-5

    1. While RF disagrees with the removal of IROL lines as a whole due to reduction of lines falling under the compliance standards regarding maintenance, the noted red-lined changes are recommended for approval as stated.

  4. CIP-014-3

    1. For all these, references to planning events needs to be more clearly stated as being the planning events in TPL-001 Table 1.

       

      CIP-014-03  R4.1.1.3   This needs to be made clearer.  I am reading this revision in several different ways, none of which I believe to be then intent of the change.   I think the reference to planning events needs to be changed to single station or single station location event.

       

      Here are the two ways that I read the standard as proposed.

       

      1) What are the planning events?  Are they the subset of TPL-001 Table 1 P1 through P7 events that could cause the loss of the single station or substation location, or all facilities at a single voltage level in a station or substation?   If so, the CIP standard should provide more detail on what assumptions must be made for the planning events, that differ from the same events when studied per TPL requirements.  

       

      2) Are the planning events additional contingencies after system adjustments, and with the single station or substation still out of service?  If so, this is a significant change the severity of events that this standard addresses.  Is this a requirement to study the station outage concurrent with a planning event? 

Anthony Jablonski, ReliabilityFirst , 10, 7/31/2020

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BHE does not agree with the changes to CIP-014

BHE agrees with the changes to FAC-013

BHE agrees with the changes to PRC-002

BHE agrees with the changes to PRC-023

BHE agrees with the changes to PRC-026

BHE agrees with EEI’s response to this question. The EEI response conveys that the proposed changes to the CIP-014 Aplicability Section would break the alignment between CIP-014 and CIP-002.

Maryanne Darling-Reich, On Behalf of: Black Hills Corporation - MRO, WECC - Segments 1, 3, 5, 6

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Some changes seem to be minor and some require revisiting the methodology and more coordination. Unless there is a fatal flaw with the existing, the proposed changes create a more complicated process that impacts several Standards.

Glenn Barry, Los Angeles Department of Water and Power, 5, 7/31/2020

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OGE has similar concerns expressed by MRO-NSRF on CIP-014 changes.  The proposed CIP-014 change would lower the threshold from Interconnection instability to any instability affecting the BES, representing a potentially substantial increase in scope for CIP-014. OGE recommends the SDT to ensure any changes made to CIP-014 conforms with CIP-002.

 

OKGE, Segment(s) 6, 1, 3, 5, 4/10/2019

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PPL NERC Registered Affiliates support the proposed revisions to FAC-003. However, the revised language is somewhat ambiguous, and we would appreciate the Drafting Team providing clarification on how the revisions apply to lines under 200kV described in 4.2.2. The conditions described in the revised FAC-003 affecting lines under 200 kV would not occur without being in violation of planning requirements of TPL-001-5 and TPL-001-4, which require looking to the future and mitigating where a single outage may result in a stability issue. 

PPL NERC Registered Affiliates, Segment(s) 1, 3, 5, 6, 9/6/2018

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MPC supports comments submitted by the MRO NERC Standards Review Forum.

Andy Fuhrman, On Behalf of: Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1; Theresa Allard, Minnkota Power Cooperative Inc., 1

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Truong Le, On Behalf of: Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Tom Reedy, Florida Municipal Power Pool, 6; Chris Gowder, Florida Municipal Power Agency, 3,4,5,6; Chris Gowder, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Dale Ray, Florida Municipal Power Agency, 3,4,5,6; Richard Montgomery, Florida Municipal Power Agency, 3,4,5,6; Richard Montgomery, Florida Municipal Power Agency, 3,4,5,6; Carol Chinn, Florida Municipal Power Agency, 3,4,5,6; Carol Chinn, Florida Municipal Power Agency, 3,4,5,6; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Neville Bowen, Ocala Utility Services, 3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3; Don Cuevas, Beaches Energy Services, 1,3

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ATC Supports the comments of the MRO NSFR and EEI.

CIP-014 Applicability Section 4.1.1.3 comes from CIP-002-5.1a Medium Impact Rating criterion 2.6. The SDT for Project 2016-02 considered and rejected this proposed change for CIP-002-6, which just passed industry ballot without any change to criteria 2.6 and 2.9, both of which continue to reference IROLs, a NERC Glossary-defined term.

The proposal would lower the threshold from Interconnection instability to any instability affecting the BES, representing a potentially substantial increase in scope for CIP-014, and sundering the connection to and synergy with CIP-002, creating disparate populations.

Deference should be given to the SDT for Project 2016-02 with respect to any conforming changes to CIP-002 and CIP-014, which need to be addressed concurrently and consistently.

 

 

LaTroy Brumfield, American Transmission Company, LLC, 1, 8/3/2020

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Steven Rueckert, Western Electricity Coordinating Council, 10, 8/3/2020

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With regards to standards revisions or deletions to FAC-010-3, FAC-011-3, and FAC-014-2  requirements for determining and communicating SOLs used in the reliable planning and operation of the BES, BPA agrees with the associated changes to FAC-003, FAC-013, PRC-002, PRC-023, and PRC-026.

Regarding CIP-014-3, it is unclear how the Planning Assessment performed by the Planning Coordinator or the Transmission Planner in Applicability criteria 4.1.1.3 relates to the risk assessment performed by the Transmission Owner in Standard Requirement R1.

BPA suggests the following edits to criteria 4.1.1.3 to help clarify.

4.1.1.3. “Transmission Facilities that are identified by the Planning Coordinator or Transmission Planner through its Annual Planning Assessment of the Near-Term Transmission Planning Horizon, at a single station or substation location that if lost or degraded are expected to result in instances of instability, Cascading, or uncontrolled separation, that adversely impacts the reliability of the Bulk Electric System for planning events.”

Cain Braveheart, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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Mark Holman, 8/3/2020

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PacifiCorp does not agree with the changes to CIP-014 and supports EEI and MRO NSRF with their comments.  The CIP-014 Applicability Section 4.1.1.3 comes from language in CIP-002-5.1a Medium Impact Rating criterion 2.6. The SDT for Project 2016-02 filed CIP-002-6 with FERC for approval, which passed industry ballot without any change to criteria 2.6 and 2.9, both of which continue to reference IROLs, a NERC Glossary-defined term.

 

The proposal would lower the threshold from Interconnection instability to any instability affecting the BES, representing a potentially substantial increase in scope for CIP-014, and changing the connection and synergy with CIP-002.

 

Deference should be given to the SDT for Project 2016-02 with respect to any conforming changes to CIP-002 and CIP-014, which need to be addressed concurrently and consistently.

Sandra Shaffer, 8/3/2020

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Texas RE is concerned with removing the Reliability Coordinator (RC) in the applicability of proposed CIP-014-3.  The RC, as specified in the proposed FAC-014 standard, establishes Interconnection Reliability Operating Limits (IROLs) in accordance with its SOL methodology.  Once identified in the operational horizon, however, the RC will likely adopt more conservative operational criteria to avoid instability, Cascading or uncontrolled separation.  As Texas RE reads the current FAC-014 requirements, the Planning Coordinator (PC) and Transmission Planner (TP) will be required to plan using at least these more conservative Facility Rating, voltage limits, and stability criteria.  The use of these more conservative limits in the Planning Assessment could potentially make it less likely that the TP and PC will ultimately identify instability, Cascading, or uncontrolled separations that adversely impact the reliability of the Bulk Electric System.  As such, facilities currently subject to the CIP-014 requirements today would be potentially excluded from the scope of the proposed CIP-014.

 

Texas RE understands that the SDT’s intent in revising the CIP-014 was not to change the substantive scope of the CIP-014 requirements.  To ensure there is no inadvertent changes to the facilities subject to CIP-014, Texas RE recommends that facilities identified by the RC as causing instability, Cascading, or uncontrolled separations that adversely impact the reliability of the Bulk Electric System be retained in the scope of the CIP-014 requirements.

Texas RE has the following comments regarding proposed FAC-003-5:

 

  • It is unclear how planning events that involve multiple elements (e.g. TPL-001-4 P6 event) would fall into the applicability of FAC-003-5. The applicability section of FAC-003-4 made it clear using the language of “Each overhead transmission line operated below 200kV identified as an element of an IROL…” FAC-003-5, however, simply uses the language “a Facility that if lost or degraded are expected to result in instances of instability, Cascading, or uncontrolled separation that adversely impacts the reliability of the Bulk Electric System for a planning event.” It is not clear whether each element that comprises the planning event or only a single line “that if lost or degraded are expected to result in instances of instability, Cascading, or uncontrolled separation, that adversely impacts the reliability of the Bulk Electric System”.

  • The asterisk on Table 2 appears to be inconsistent with FAC-014.  The asterisk is applicable only “if PC has determined such per FAC-014.”  FAC-014 includes both of the PC and TP in Requirements R6-R8.  The footnote as written excludes the TP so it is unclear whether TP Facilities, determined per FAC-014 R8, are subject to vegetation management.  This could leave a gap in the reliable operations of the grid if the list of Facilities derived by the PC and TP are different.  Texas RE recommends adding “and TP” to the footnote in FAC-003-5.

Texas RE noticed that the rationale for PRC-002-3 includes a reference to PRC-002-2 in Requirement R6. The Guidelines and Technical Basis Section also contain references to PRC-002-2 (e.g. Introduction Section, Guideline for Requirement R6, R7).

 

Texas RE has the following comments for proposed PRC-023-5.

Texas RE recommends Transmission Planner be added to Requirement R6 and the Applicabi