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2015-09 Establish and Communicate System Operating Limits | FAC-014-3

Description:

Start Date: 02/19/2021
End Date: 04/05/2021

Associated Ballots:

Ballot Name Project Standard Pool Open Pool Close Voting Start Voting End
2015-09 Establish and Communicate System Operating Limits FAC-014-3 AB 5 ST 2015-09 Establish and Communicate System Operating Limits FAC-014-3 09/29/2017 07/20/2020 03/26/2021 04/05/2021

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Hot Answers

See comments from Southern Company.

Rob Watson, Choctaw Generation Limited Partnership, LLLP, 5, 4/5/2021

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Southern Company believes it is more appropriate to provide information initially and then provide information within a certain prescribed timeframe as the information changes. Several changes could occur within the annual period and users would not have the most up to date information. Additionally, the annual update is unnecessary if the information does not change.

 

The addition of the “Time Horizon” in R5.1-R5.6 does not provide useful clarification as R5 already indicates the applicable time horizons. Not only does this introduce un-necessary confusion for the RC in addressing the requirements, it appears to limit the flexibility in providing the SOL/IROL information the RC deems appropriate.  For instance, it appears the RC is limited in R5.1 and R5.2 to only provide SOLs/IROLs identified in the Operations Planning time fame. Southern recommends removing the addition of the “Time Horizons” in R5.1-R5.6.

Southern Company, Segment(s) 1, 3, 6, 5, 1/14/2021

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Other Answers

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

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Bruce Reimer, Manitoba Hydro , 1, 3/10/2021

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Tacoma Power, Segment(s) 1, 3, 4, 5, 6, 3/9/2021

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

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Thomas Foltz, AEP, 5, 3/17/2021

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In reviewing the language for requirement R5.4, the focus is on the Operational Planning Analysis, which NERC defines as a next day analysis. Given the NERC time horizon defintions (https://www.nerc.com/pa/Stand/Resources/Documents/Time_Horizons.pdf), the only applicable time horizon appears to be Operations Planning since Same-day Operations applies to “the timeframe of a day” and Real-time Operations applies to “one hour or less”. In the alternative, if the drafting team believes these time horizons do apply, we recommend that the team update the rationale requirements document to explain how these other time horizons apply to the OPA.

LaTroy Brumfield, American Transmission Company, LLC, 1, 3/24/2021

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none

Richard Jackson, U.S. Bureau of Reclamation, 1, 3/25/2021

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Laura Nelson, 3/26/2021

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FE Voter, Segment(s) 1, 3, 5, 6, 4, 2/23/2021

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Evergy incorporates by reference and supports Edison Electric Institute's response to Question 1. 

Douglas Webb, 3/30/2021

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Michael Jones, National Grid USA, 1, 3/31/2021

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MRO NSRF, Segment(s) 2, 4, 1, 6, 3, 5, 3/31/2021

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

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

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DTE Energy - DTE Electric, Segment(s) 5, 4, 3, 1/24/2020

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Regarding the annual reporting requirement, Southern thinks it would be more appropriate to provide the information initially and then provide information as it changes, such as “within 90 days of a change.”  Southern suggests that would be true for all of R5, not just R5.6.

Scott Miller, On Behalf of: David Weekley, MEAG Power, 1,3; Roger Brand, MEAG Power, 1,3

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Steven Taddeucci, NiSource - Northern Indiana Public Service Co., 3, 4/1/2021

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The standard is not results-based.

Unfortunately, this project is six years old and needs to end.

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

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N/A.

Leonard Kula, Independent Electricity System Operator, 2, 4/1/2021

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ACES Standard Collaborations, Segment(s) 1, 3, 4/1/2021

- 0 - 0

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

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Jamie Monette, Allete - Minnesota Power, Inc., 1, 4/2/2021

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James Baldwin, Lower Colorado River Authority, 1, 4/5/2021

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Gladys DeLaO, CPS Energy, 1, 4/5/2021

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Rachel Coyne, Texas Reliability Entity, Inc., 10, 4/5/2021

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Support the MRO NSRF comments.

Wayne Guttormson, SaskPower, 1, 4/5/2021

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sean erickson, Western Area Power Administration, 1, 4/5/2021

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Robert Stevens, On Behalf of: CPS Energy, , Segments 1, 3, 5

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Teresa Krabe, Lower Colorado River Authority, 5, 4/5/2021

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Daniela Atanasovski, APS - Arizona Public Service Co., 1, 4/5/2021

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Truong Le, 4/5/2021

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Ameren agrees with and supports EEI comments.

David Jendras, Ameren - Ameren Services, 3, 4/5/2021

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

Jamie Johnson, California ISO, 2, 4/5/2021

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Alliant Energy supports the comments submitted by the MRO NSRF.

Larry Heckert, Alliant Energy Corporation Services, Inc., 4, 4/5/2021

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EEI supports the inclusion of “at least once every 12 months” to Requirement R5, Part 5.6, as well as the addition of Time Horizons to the various parts of Requirement R5.

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

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Aidan Gallegos, 4/5/2021

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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, 4/5/2021

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We support the revisions made by the SDT to FAC-014-3.

NPCC Regional Standards Committee, Segment(s) 10, 2, 4, 7, 3, 1, 5, 6, 4/5/2021

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The IRC SRC appreciates the clarification made by the SDT to the language and applicable Time Horizons in Part 5.6 to specify “at least once every twelve calendar months.” This timeframe should allow sufficient analysis to document IROLs that will persist and need monitoring by the Reliability Coordinator and any necessary action by asset owners, per CIP standards.

ISO/RTO Standards Review Committee, Segment(s) 2, 4/5/2021

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

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None.

Brandon Gleason, 4/5/2021

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Hot Answers

Rob Watson, Choctaw Generation Limited Partnership, LLLP, 5, 4/5/2021

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Southern Company, Segment(s) 1, 3, 6, 5, 1/14/2021

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Other Answers

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

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We agree that the CIP-002.5.1a criterion 2.6 can be retained without changes, but the Guidelines and Technical Basis as part of CIP-002-5.1a standard will need to be updated to reflect and align with FAC-014 R5 changes (see references cited for Criterion 2.6 at the bottom of page 25 and page 28 of CIP-002.5.1a). Without this linkage, Generator Owners or Transmission Owner receiving information pursuant to FAC-014-3 for the first time may fail to make the correlation to CIP-002-5.1a resulting in missing the identification of medium impct BES Facilities.

Bruce Reimer, Manitoba Hydro , 1, 3/10/2021

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Tacoma Power, Segment(s) 1, 3, 4, 5, 6, 3/9/2021

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

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Thomas Foltz, AEP, 5, 3/17/2021

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LaTroy Brumfield, American Transmission Company, LLC, 1, 3/24/2021

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none

Richard Jackson, U.S. Bureau of Reclamation, 1, 3/25/2021

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Laura Nelson, 3/26/2021

- 0 - 0

FE Voter, Segment(s) 1, 3, 5, 6, 4, 2/23/2021

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Evergy incorporates by reference and supports Edison Electric Institute's response to Question 2.

Douglas Webb, 3/30/2021

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Michael Jones, National Grid USA, 1, 3/31/2021

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MRO NSRF, Segment(s) 2, 4, 1, 6, 3, 5, 3/31/2021

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

- 0 - 0

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

- 0 - 0

DTE Energy - DTE Electric, Segment(s) 5, 4, 3, 1/24/2020

- 0 - 0

Scott Miller, On Behalf of: David Weekley, MEAG Power, 1,3; Roger Brand, MEAG Power, 1,3

- 0 - 0

Steven Taddeucci, NiSource - Northern Indiana Public Service Co., 3, 4/1/2021

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CIP-002.5.1.a was already revised, vetted by industry and by NERC, approved by all, then submitted to FERC.  Recently NERC withdrew it. 

The CIP virtualization project is also modifying it.  Very confusing.  Please no more changes.

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

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N/A.

Leonard Kula, Independent Electricity System Operator, 2, 4/1/2021

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ACES Standard Collaborations, Segment(s) 1, 3, 4/1/2021

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

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Jamie Monette, Allete - Minnesota Power, Inc., 1, 4/2/2021

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James Baldwin, Lower Colorado River Authority, 1, 4/5/2021

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Gladys DeLaO, CPS Energy, 1, 4/5/2021

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Texas RE does not agree with not revising CIP-002-5.1.  First, Texas RE notes that while PCs and TPs were removed from identifying IROLs in FAC-014, CIP-002 and CIP-014 still reference the PCs and TPs identifying Interconnection Reliability Operating Limits (IROLs).  Second, since the RC does not have a timeframe for identifying SOLs, there could be a gap in that CIP protections may not occur for up to 24 months in accordance with the CIP-002-5.1 Implementation Plan.

 

Section 2.6 of the Impact Criteria of CIP-002-5.1, states that the PC and TP identify generation that is critical to the derivation of IROLs.  Section 4.1.1.3 of the Applicability section of CIP-014-2 does this as well.  However, FAC-014-3 removed the requirements for the PC and TP to establish IROLs.  While the SDT indicates that PCs and TPs may continue to conduct planning assessments and provide Corrective Action Plans (CAPs) to address identified system deficiencies to their RCs,  there ultimately is no definitive obligation within the NERC Reliability Standards for PCs and TPs to explicitly identify generation critical to the derivation of IROLs.  From Texas RE’s perspective, this results in reliability gaps because the TPL-001 planning assessment process does not explicitly incorporate the specific IROL derivation reliability task.

 

Texas RE believes that this gap has important consequences for the timing of the identification of IROLs and the corresponding implementation of CIP controls.  Given that the TPs and PCs were removed from establishing IROLs in FAC-014-3, no identity is explicitly responsible for identifying IROLs in the planning horizon.  Texas RE recommends explicitly keeping the TPs and PCs involved with this process in CIP-002 and CIP-014.  Having the PCs and TPs conduct this analysis in the planning horizon many months or years prior to the IROL being established allows time for the generation and Transmission Facilities to establish CIP protections on the IROL.

 

Since FAC-014-3 does not include a time-frame specified for the RC to establish IROLs and no studies are required by the RC until a day prior to Real-time operations (OPA), the RC may not identify these Facilities before that point.  Since the implementation plan for CIP-002-5.1 allows for an implementation period of 12 or 24 months depending on the scenario, this could result in a Facility that is determined to be critical to the derivation of an IROL not having adequate cyber and physical security controls for a period of up to 24 months.

 

This could be resolved by revising the impact criteria in CIP-002 and the applicability in CIP-014.  In section 2.6 of the impact criteria for CIP-002, Texas RE recommends removing the reference to PCs and TPs, as they are no longer involved with identifying IROLs per FAC-14-3.  Texas RE further recommends adding an additional criterion with the following verbiage:  Facilities 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. This verbiage is consistent with the applicability section of FAC-003-5.

 

In CIP-014, Texas RE recommends revising section 4.1.1.3 of the Applicability to: Facilities 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.

 

These changes would explicitly allow for the PC and TPs to be involved with identifying Facilities that if lost or degraded are expected to result in instances of instability, Cascading, or uncontrolled separation.  Doing this in the planning horizon will allow for the identified Facilities to establish CIP protections much earlier in the process, reducing the potential reliability issues posed by such critical Facilities.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 4/5/2021

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Support the MRO NSRF comments.

Wayne Guttormson, SaskPower, 1, 4/5/2021

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sean erickson, Western Area Power Administration, 1, 4/5/2021

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Robert Stevens, On Behalf of: CPS Energy, , Segments 1, 3, 5

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Teresa Krabe, Lower Colorado River Authority, 5, 4/5/2021

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Daniela Atanasovski, APS - Arizona Public Service Co., 1, 4/5/2021

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Support Texas RE's comments.

Truong Le, 4/5/2021

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Ameren agrees with and supports EEI comments.

David Jendras, Ameren - Ameren Services, 3, 4/5/2021

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

Jamie Johnson, California ISO, 2, 4/5/2021

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Alliant Energy supports the comments submitted by the MRO NSRF.

Larry Heckert, Alliant Energy Corporation Services, Inc., 4, 4/5/2021

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EEI supports the arguments contained in the Technical Rationale document titled “Technical Rationale for Exclusion of CIP Criteria Modifications by Project 2015-09” which addresses why there are no reliability gaps resulting from the retirement of FAC-010.  

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

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Aidan Gallegos, 4/5/2021

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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, 4/5/2021

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We support the SDT not revising CIP-002-5.1a.

NPCC Regional Standards Committee, Segment(s) 10, 2, 4, 7, 3, 1, 5, 6, 4/5/2021

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ISO/RTO Standards Review Committee, Segment(s) 2, 4/5/2021

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

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None.

Brandon Gleason, 4/5/2021

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Hot Answers

See comments from Southern Company.

Rob Watson, Choctaw Generation Limited Partnership, LLLP, 5, 4/5/2021

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A new NERC time-horizon should be created, termed “Day-Ahead Operations” – operating and resource plans within the day ahead timeframe, to replace the Operations Planning Horizon applicability of R1 through R5 consistent with the intended horizon of SOL exceedance determinations.

Southern Company, Segment(s) 1, 3, 6, 5, 1/14/2021

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Other Answers

Nothing to add

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

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Bruce Reimer, Manitoba Hydro , 1, 3/10/2021

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Tacoma Power, Segment(s) 1, 3, 4, 5, 6, 3/9/2021

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None.

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

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AEP has expressed its concerns in previous comment periods regarding the proposed revisions to FAC-014. A majority of those concerns and comments still stand and will not be restated again in their entirety in this current comment period. We would, however, like to offer the following thoughts and suggestions for consideration.

AEP thanks the drafting team for clarification on the meaning of “stability criteria” within R6. However, we find no reason why stability criteria consisting of acceptable power swing damping level, transient voltage dip and recovery durations, the necessity for the system to remain stable, and contingency definitions used in studies to evaluate stability would be any different in operations versus planning time-frames. We believe that the practical effect of including stability criteria in R6 will be to produce unnecessary administrative paperwork.

While we are somewhat encouraged that future consideration might be given to moving R6, R7 and R8 into TPL-001, we do remained concerned by the inference that this “move” might not happen until *after* these three requirements are first placed within FAC-014. We believe efforts to pursue such changes should be dealt with *only* as part of revising TPL-001, rather than *moving* them from FAC-014 to TPL-001 sometime in the future. As previously stated, rather than pursuing such changes within FAC-014, AEP recommends removing “stability criteria” from the proposed R6 and transferring the proposed R6, R7 and R8 over to a TPL-001 Standards Drafting Team. While well intentioned, we believe the Project 2015-09 Standards Drafting Team is unintentionally encroaching on the TPL domain by proposing such requirements be placed within FAC-014. These requirements are best served if drafted and reviewed from a Transmission Planner perspective, as these individuals would be in the best position to properly evaluate their necessity in view of the potential for nullification, or by possible reliance on operational actions and system adjustments not considered corrective action plans.

In closing, while AEP has once again chosen to vote negative as driven by the concerns stated above, we appreciate the efforts of the standards drafting team, and we envision potentially supporting such an effort provided a) “stability criteria” is removed from the proposed R6 and b) by dealing with R6, R7, and R8 solely within a project to revise TPL-001.

Thomas Foltz, AEP, 5, 3/17/2021

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LaTroy Brumfield, American Transmission Company, LLC, 1, 3/24/2021

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Richard Jackson, U.S. Bureau of Reclamation, 1, 3/25/2021

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Laura Nelson, 3/26/2021

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N/A

FE Voter, Segment(s) 1, 3, 5, 6, 4, 2/23/2021

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Evergy incorporates by reference and supports Edison Electric Institute's response to Question 3.

Douglas Webb, 3/30/2021

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RE: R5.2.4 The associated critical Contingency(ies):  We request the Standard Drafting Team clarify the use of the word “critical” to describe Contingency(ies)” noting that “critical Contingency(ies)” is undefined and opens Requirement R5, subpart 5.2.4 to interpretation.


Please consider revising the subparts of 5.2 (Requirement R5) as follows:
5.2.1 The value of the stability limit or IROL;
5.2.2 The associated IROL Tv for any IROL;
5.2.3 Identification of the Facilities that are critical to the derivation of the stability limit or the IROL and the associated Contingency(ies);
5.2.4 A description of system conditions associated with the stability limit or IROL; and
5.2.5 The type of limitation represented by the stability limit or IROL (e.g., voltage collapse, angular stability).

Michael Jones, National Grid USA, 1, 3/31/2021

- 0 - 0

Comments:

  • ·        Suggest the coordination of methodologies, limits, criteria, etc, by the RC with the PC/TP should occur earlier in the RC’s                 process. 
  • ·        Suggest the RC should be requesting review and comments from the PC/TP.   

o   The RC should align as much as possible with the PC/TP’s criteria as the PC/TP determines what adequate investment into the system is.

MRO NSRF, Segment(s) 2, 4, 1, 6, 3, 5, 3/31/2021

- 0 - 0

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

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MPC supports MRO NERC Standards Review Forum comments.

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

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not at this time, thank you.

DTE Energy - DTE Electric, Segment(s) 5, 4, 3, 1/24/2020

- 0 - 0

Scott Miller, On Behalf of: David Weekley, MEAG Power, 1,3; Roger Brand, MEAG Power, 1,3

- 0 - 0

No comments

Steven Taddeucci, NiSource - Northern Indiana Public Service Co., 3, 4/1/2021

- 0 - 0

Let move foward with the Standards Effieciency Review Porject to get rid of non Results based Standards, redunancy in Standards, and  inefficiencies.  

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

- 0 - 0

N/A.

Leonard Kula, Independent Electricity System Operator, 2, 4/1/2021

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Thank you for the opportunity to provide comments.

ACES Standard Collaborations, Segment(s) 1, 3, 4/1/2021

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

- 0 - 0

Minnesota Power agrees with MRO’s NERC Standards Review Forum’s (NSRF) comments.

Jamie Monette, Allete - Minnesota Power, Inc., 1, 4/2/2021

- 0 - 0

James Baldwin, Lower Colorado River Authority, 1, 4/5/2021

- 0 - 0

CPS Energy does not have any comments.

Gladys DeLaO, CPS Energy, 1, 4/5/2021

- 0 - 0

Texas RE does not have additional comments.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 4/5/2021

- 0 - 0

Support the MRO NSRF comments.

Wayne Guttormson, SaskPower, 1, 4/5/2021

- 0 - 0

Requirement R6 is confusingly written, mainly because it confuses the concept of “criteria” and the use of components of criteria.  

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 are equally limiting or more limiting than the Facility Ratings, System Voltage Limits and/or stability criteria used, as described in its respective Reliability Coordinator’s SOL methodology.

sean erickson, Western Area Power Administration, 1, 4/5/2021

- 0 - 0

Robert Stevens, On Behalf of: CPS Energy, , Segments 1, 3, 5

- 0 - 0

Teresa Krabe, Lower Colorado River Authority, 5, 4/5/2021

- 0 - 0

None

Daniela Atanasovski, APS - Arizona Public Service Co., 1, 4/5/2021

- 0 - 0

Truong Le, 4/5/2021

- 0 - 0

Ameren agrees with and supports EEI comments.

David Jendras, Ameren - Ameren Services, 3, 4/5/2021

- 0 - 0

The CAISO Planning Coordinator recommends the following changes to the draft FAC-014-3 :

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

•Requirement R6 is misplaced and should be addressed in TPL-001, which governs Planning Assessments, rather than in FAC-014-3. Keeping “like” requirements together in one standard will avoid inconsistency, retain the overall context of the requirements, increase efficiency, and avoid undue regulatory burden.

•Requirement R7 is also misplaced and should be addressed in TPL-001, which governs Planning Assessments, rather than in FAC-014-3.  The comment above regarding keeping like requirements together applies here as well.

•Requirement R8 should be removed from FAC-014-3 because FAC-014-3 makes the Reliability Coordinator (RC) the sole functional entity that establishes IROLs.  As such, the PC and the TP that no longer establish IROLs should not be required to provide facilities that are critical to the derivation of IROLs and their contingencies to the impacted Transmission Owner (TO) and Generation Owner (GO) in accordance with CIP-002, CIP-014, etc.  Requirement R5.6, which requires the RC to provide such information to the impacted TO and GO, should be sufficient to address their IROL-related needs.  If the SDT determines there is Planning Assessment related information that the PC and TP should provide to the TO and GO, the requirement should be addressed in TPL-001 that governs their Planning Assessment, rather than in FAC-014, to keep like requirements together. Also, because TPL-001 does not allow planning event Contingency(ies) to cause instability, Cascading or uncontrolled separation that adversely impacts the reliability of the BES, Requirement R8 is inconsistent with TPL-001. 

• 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 Applicability Section (Section 4).

Jamie Johnson, California ISO, 2, 4/5/2021

- 0 - 0

Alliant Energy supports the comments submitted by the MRO NSRF.

Larry Heckert, Alliant Energy Corporation Services, Inc., 4, 4/5/2021

- 0 - 0

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

- 0 - 0

Changes to R6-R8 may be perceived as an attempt of the SDT to modify TPL-001 and MOD-032. In addition, the proposed changes to FAC-014-3 appears to be an attempt to possibly require additional information and additional coordination between operations and planning. If the SDT feels strongly that these modifications to TPL-001 and MOD-032 are required to support the reliable operation of the BES Facilities, it may be be of benefit of the SDT to submit a SAR for TPL-001 and MOD-032 instead of spreading the requirement out across multiple standards.

Aidan Gallegos, 4/5/2021

- 0 - 0

Daniel Gacek, Exelon, 1, 4/5/2021

- 0 - 0

NPCC Regional Standards Committee, Segment(s) 10, 2, 4, 7, 3, 1, 5, 6, 4/5/2021

- 0 - 0

 

The IRC continues to believe that the drafting team should be given the opportunity to address efficiencies identified by the Standards Efficiency Review Project to reduce redundancy in the requirements and exposure to double jeopardy. FAC-013-3 R7 proposed to annually share CAP’s with RC’s and TOP’s. IRO-017 R3 already has the requirement to share the CAP’s with RC’s. FAC-014-3, continues to say what should be included in that CAP, while TPL-001-4 R2.7 provides the initial requirement for completing a CAP and what should be included.

 

The IRC SRC continues to believe that the following additional changes to the language in the requirement:

-          FAC-011-4 uses the phrase, “System Voltage Limits” (see FAC-011-4 R3).  FAC-014 R6 uses a mix of terms such as “System steady state voltage limits” as well as “System Voltage Limits”.  The IRC SRC recommends that consistent terminology be used across these standards.

-          FAC-011-4 uses the phrases, “stability limits”, and “stability performance criteria” (see FAC-011-4 R4).  FAC-014 R6 uses a mix of terms such as “stability criteria” or just “stability”. The IRC SRC recommends that consistent terminology be used across these standards.

In addition, the IRC SRC continues to recommend that the following change be made to R6 to clarify the intent of the requirement:

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 the Near Term Transmission Planning Horizon that are equally limiting or more limiting than the the criteria for the use of Facility Ratings, System Voltage Limits and stability criteria described in its respective Reliability Coordinator’s SOL methodology.

The IRC continues to believe there is confusion with in this requirement. Facility Ratings are provided by asset owners. Is that the case for System Voltage Limits as well.

 

Finally, from a proofreading perspective, the IRC SRC notes there is an incomplete sentence (located as the last sentence in paragraph 2) on page 6 of the Technical Rationale for Reliability Standard FAC-014-3 : “Those IROLs which may manifest in real time, due to forced outage…” that needs to be completed or deleted.

ISO/RTO Standards Review Committee, Segment(s) 2, 4/5/2021

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BPA continues to be concerned that the Technical Rationale document is apart from the Standard. There appears to be risks asscociated with this approach as neither an entity nor an auditor are required to consider Technical Rationale guidance when implementing requirements or performing audits, respectively. To remove this potential compliance issue, BPA believes language requiring Facility Ratings and system voltage limits to be equally limiting or more limiting than what’s provided by the TOP in accordance with its RC’s SOL methodology needs to be explicitly stated in the Standard.

Furthermore, BPA believes language requiring that criteria developed and documented for stability performance be equally limiting or more limiting than the criteria in its respective RC’s SOL methodology needs to be explicitly stated in the Standard.

In consideration of the SDT's comments with regard to the word ‘ensure’, BPA offers revisions to its comments regarding R6 to replace ‘ensure’ with ‘require’. See below.

R6. Each Planning Coordinator and each Transmission Planner shall require that Facility Ratings and system voltage limits used in its Planning Assessment of the Near Term Transmission Planning Horizon are equally limiting or more limiting than the Facility Ratings and system voltage limits provided by the TOP to its RC in accordance with its Reliability Coordinator’s SOL methodology.

In addition, each Planning Coordinator and each Transmission Planner shall require that criteria developed and documented for stability performance for its Planning Assessment of the Near-Term Transmission Planning Horizon are equally limiting or more limiting than the criteria for stability specified in its respective Reliability Coordinator’s SOL methodology. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

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

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ERCOT appreciates the Standard Drafting Team’s revision to the rationale accompanying Requirement R8.

 

For purposes of further clarification, is Requirement R8 intended to mean that only the owners of the facilities that comprise the planning event contingency(ies) that cause instability, Cascading or uncontrolled separation that adversely impacts the reliability of the BES as identified in the near-term planning assessment need to be notified that certain specific facilities they own are part of a planning event contingency that would cause cause instability, Cascading or uncontrolled separation that adversely impacts the reliability of the BES? 

Brandon Gleason, 4/5/2021

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