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

Description:

Start Date: 10/23/2020
End Date: 12/07/2020

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 4 ST 2015-09 Establish and Communicate System Operating Limits FAC-014-3 09/29/2017 07/20/2020 11/27/2020 12/07/2020
2015-09 Establish and Communicate System Operating Limits Implementation Plan AB 4 OT 2015-09 Establish and Communicate System Operating Limits Implementation Plan 09/29/2017 07/20/2020 11/27/2020 12/07/2020

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Hot Answers

None.

Brandon Gleason, 12/7/2020

- 0 - 0

Wayne Guttormson, SaskPower, 1, 12/7/2020

- 0 - 0

Other Answers

See prior NCPA and John Allen City Utilities prior balloting comments.

Michael Whitney, On Behalf of: Northern California Power Agency, , Segments 3, 4, 5, 6

- 1 - 0

See prior NCPA and John Allen City Utilities prior balloting comments

Dennis Sismaet, Northern California Power Agency, 6, 10/26/2020

- 0 - 0

Robert Hirchak, Cleco Corporation, 6, 11/2/2020

- 0 - 0

John Allen, City Utilities of Springfield, Missouri, 4, 11/9/2020

- 0 - 0

Bruce Reimer, Manitoba Hydro , 1, 11/19/2020

- 0 - 0

While we do appreciate the Standards Drafting Team’s proposal of the 24-month rather than the originally proposed 12-month Implementation Plan, we still believe 36 months would be more appropriate. As stated previously, the proposed changes 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. Once again, we believe 36 months would be more appropriate.

Thomas Foltz, AEP, 5, 11/24/2020

- 0 - 0

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

- 0 - 0

Richard Brooks, On Behalf of: Reliable Energy Analytics LLC, , Segments 8

- 0 - 0

Laura Nelson, 11/30/2020

- 0 - 0

Colleen Campbell, 11/30/2020

- 0 - 0

Kjersti Drott, 11/30/2020

- 0 - 0

no comments

Glen Allegranza, On Behalf of: Imperial Irrigation District, , Segments 1, 3, 5, 6

- 0 - 0

Nurul Abser, On Behalf of: NB Power Corporation, , Segments 1, 5

- 0 - 0

AZPS supports the change from 12-months to the 24-month implementation plan.

Daniela Atanasovski, APS - Arizona Public Service Co., 1, 12/1/2020

- 0 - 0

Rahn Petersen, On Behalf of: PNM Resources - Public Service Company of New Mexico - WECC - Segments 1, 3, 5

- 0 - 0

Basin Electric supports the MRO NSRF comments.  Jerry Horner

Jerry Horner, Basin Electric Power Cooperative, 6, 12/3/2020

- 0 - 0

The MRO NERC Standards Review Forum (MRO NSRF) supports the changes made by the SDT to extend the Implementation Plan from 12 to 24 months.

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

- 0 - 0

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

- 0 - 0

Leonard Kula, Independent Electricity System Operator, 2, 12/4/2020

- 0 - 0

Anthony Jablonski, ReliabilityFirst , 10, 12/4/2020

- 0 - 0

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

- 0 - 0

Terry Harbour, Berkshire Hathaway Energy - MidAmerican Energy Co., 1, 12/4/2020

- 0 - 0

None.

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

- 0 - 0

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

- 0 - 0

MPC supports the changes made by the SDT to extend the Implementation Plan from 12 to 24 months.

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

- 0 - 0

Larry Heckert, Alliant Energy Corporation Services, Inc., 4, 12/7/2020

- 0 - 0

While AEPC appreciates the SDT’s proposal of 24-months rather than the initial proposal of a 12-month Implementation Plan, AEPC believes a 36-month timeframe would be more appropriate as the proposed changes are time intensive to implement.

AEPC also signed on to ACES comments.

Jennifer Bray, Arizona Electric Power Cooperative, Inc., 1, 12/7/2020

- 0 - 0

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

Jamie Johnson, California ISO, 2, 12/7/2020

- 0 - 0

Sandra Ellis, On Behalf of: Pacific Gas and Electric Company, WECC, Segments 3

- 0 - 0

Please see comments submitted by the Edison Electric Institute.

Neil Shockey, 12/7/2020

- 0 - 0

MISO supports comments submitted by the ISO/RTO Council Standards Review Committee (IRC SRC) and MRO NERC Standards Review Forum (MRO NSRF).

Bobbi Welch, Midcontinent ISO, Inc., 2, 12/7/2020

- 0 - 0

Please see comments submitted by the Edison Electric Institute.

Kenya Streeter, Edison International - Southern California Edison Company, 6, 12/7/2020

- 0 - 0

Entergy supports MISO's comments.

Oliver Burke, Entergy - Entergy Services, Inc., 1, 12/7/2020

- 0 - 0

We endorse the comments provided by AEP on 11/24/2020.

Steven Taddeucci, NiSource - Northern Indiana Public Service Co., 3, 12/7/2020

- 1 - 0

James Baldwin, Lower Colorado River Authority, 1, 12/7/2020

- 0 - 0

Rachel Coyne, Texas Reliability Entity, Inc., 10, 12/7/2020

- 0 - 0

Teresa Krabe, Lower Colorado River Authority, 5, 12/7/2020

- 0 - 0

Richard Jackson, U.S. Bureau of Reclamation, 1, 12/7/2020

- 0 - 0

Southern Company supports the proposed 24-month Implementation Plan.

Southern Company, Segment(s) 1, 6, 3, 5, 9/1/2016

- 0 - 0

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

- 0 - 0

Exelon supports the proposed 24-month Implementation Plan.  

Submitted on behalf of Exelon: Segments 1, 3, 5, 6

Daniel Gacek, Exelon, 1, 12/7/2020

- 0 - 0

Yes, Oncor agrees with the 24-month Implementation Plan.

Tammy Porter, On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; Lee Maurer, Oncor Electric Delivery, 1

- 0 - 0

sean erickson, Western Area Power Administration, 1, 12/7/2020

- 0 - 0

NPCC Regional Standards Committee, Segment(s) 10, 2, 4, 7, 3, 1, 5, 6, 9/21/2020

- 0 - 0

The ISO/RTO Council Standards Review Committee (IRC/SRC) supports the changes made by the SDT to extend the Implementation Plan from 12 to 24 months.

ISO/RTO Standards Review Committee, Segment(s) 2, 12/7/2020

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Quintin Lee, Eversource Energy, 1, 12/7/2020

- 0 - 0

SPP RTO, Segment(s) 2, 12/7/2020

- 0 - 0

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

- 0 - 0

Evergy incorporates by reference and supports the comments of Edison Electric Institute (EEI) in response to Question 1. 

Douglas Webb, On Behalf of: Evergy, MRO, Segments 1, 3, 5, 6

- 0 - 0

Ameren agrees with and supports EEI commnets

David Jendras, Ameren - Ameren Services, 3, 12/7/2020

- 0 - 0

Karen Weaver, Tallahassee Electric (City of Tallahassee, FL), 5, 12/7/2020

- 0 - 0

Scott Langston, Tallahassee Electric (City of Tallahassee, FL), 1, 12/7/2020

- 0 - 0

Kevin Salsbury, Berkshire Hathaway - NV Energy, 5, 12/7/2020

- 0 - 0

Jose Avendano Mora, Edison International - Southern California Edison Company, 1, 12/7/2020

- 0 - 0

While ACES appreciates the SDT’s proposal of 24-months rather than the initial proposal of a 12-month Implementation Plan, ACES believes a 36-month timeframe would be more appropriate as the proposed changes are time intensive to implement.

ACES Standard Collaborations, Segment(s) 1, 3, 4, 5, 12/7/2020

- 0 - 0

EEI supports the proposed 24-month Implementation Plan.

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

- 0 - 0

Constantin Chitescu, Ontario Power Generation Inc., 5, 12/7/2020

- 0 - 0

Ed Hanson, Pacific Gas and Electric Company, 5, 12/7/2020

- 0 - 0

Hot Answers

ERCOT appreciates the Standard Drafting Team’s revisions to FAC-014-3, Requirement R8, in response to the last round of comments.  However, ERCOT believes Requirement R8 should be further clarified in order to remove an ambiguity that exists in the current draft.

 

In Requirement R8, the word “impacted” is ambiguous (impacted by what?) because the requirement also refers to “instability, Cascading or uncontrolled separation.”  As written, the requirement can be interpreted as implying an impact to virtually everything in a particular interconnection.  It is unclear whether Requirement R8  is intended to mean that only the owners of the facilities that comprise the planning event contingency(ies) that cause “instability,” 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 “instability.”  If this is the correct interpretation, which ERCOT believes to be the case, ERCOT suggests Requirement R8 provide as follows in order to remove the ambiguity:

 

R8. Each Planning Coordinator and each Transmission Planner shall annually provide each Transmission Owner and Generation Owner that owns Facilities that are part of one or more planning event Contingencyies that would cause instability, Cascading or uncontrolled separation that adversely impacts the reliability of the BES, as identified in its Planning Assessment of the Near-Term Transmission Planning Horizon, a list of the Transmission Owner’s or Generation Owner’s Facilities that are part of each planning event Contingency that would cause instability, Cascading or uncontrolled separation that adversely impacts the reliability of the BES.  [Violation Risk Factor: Medium] [Time Horizon: Long- term Planning]

 

Alternatively, confirmation from NERC in the form of guidance accompanying FAC-014-3 may be helpful in clarifying the scope of Requirement R8. 

 

ERCOT further notes that it intends to vote in favor of a revised FAC-014-3, provided the scope of Requirement R8 is further clarified.

Brandon Gleason, 12/7/2020

- 0 - 0

Support the MRO-NSRF comments for R5.6 and M3.

Recommend removing Req 8 or addressing the issue directly in CIP 002 or FAC 003.  It is unclear how TO's and GO's would use this information as presented otherwise. 

For FAC-003, with the retirement of FAC‐010‐3 the PC is not resposible for identifying IROLs, and the language for '4.2.2. Each overhead transmission line operated below 200kV identified as an element of an IROL under NERC Standard FAC-014 by the Planning Coordinator.' should be changed to denote the RC. 

For CIP-002 '2.6. Generation at a single plant location or Transmission Facilities at a single station or substation location that are identified by its Reliability Coordinator, Planning Coordinator, or Transmission Planner as critical to the derivation of Interconnection Reliability Operating Limits (IROLs) and their associated contingencies.' the reference to PC should be removed.

Wayne Guttormson, SaskPower, 1, 12/7/2020

- 0 - 0

Other Answers

See prior NCPA and John Allen City Utilities prior balloting comments.

Michael Whitney, On Behalf of: Northern California Power Agency, , Segments 3, 4, 5, 6

- 1 - 0

See prior NCPA and John Allen City Utilities prior balloting comments

Dennis Sismaet, Northern California Power Agency, 6, 10/26/2020

- 0 - 0

Robert Hirchak, Cleco Corporation, 6, 11/2/2020

- 0 - 0

John Allen, City Utilities of Springfield, Missouri, 4, 11/9/2020

- 0 - 0

Bruce Reimer, Manitoba Hydro , 1, 11/19/2020

- 0 - 0

AEP is supportive of R5.6 as the proposed requirement clearly aligns and supports criteria outlined in CIP-002 and CIP-014. This requirement should remove any previous ambiguities that may have occurred in identifying facilities that are critical to the derivation of an IROL and its associated contingencies.

AEP is also supportive of R8 as proposed as this will ensure GO’s and TO’s receive information for Facilities within their systems that could lead to instability/cascading and would create a more clear line of sight for those entities to take action on identified facilities accordingly to reduce potential risk of future instability/cascading. It should be noted however, the Corrective Action Plan and critical facility reports proposed within R7 and R8 are direct outcomes of TPL-001-4 requirements and should instead be included in that standard, if in any at all. There is no benefit having requirements pertaining to the reporting of planning studies scattered across different families of standards.

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, 11/24/2020

- 0 - 0

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

- 0 - 0

Richard Brooks, On Behalf of: Reliable Energy Analytics LLC, , Segments 8

- 0 - 0

Laura Nelson, 11/30/2020

- 0 - 0

N/A

Colleen Campbell, 11/30/2020

- 0 - 0

Tri-State does not believe the revisions provide clear instruction. R5.6 language could be improved within the context of IROL development. 'Critical' to the derivation of an IROL is ambiguous and requires further clarification to ensure uniform interpretation and implementation.

Kjersti Drott, 11/30/2020

- 0 - 0

no comments

Glen Allegranza, On Behalf of: Imperial Irrigation District, , Segments 1, 3, 5, 6

- 0 - 0

Nurul Abser, On Behalf of: NB Power Corporation, , Segments 1, 5

- 0 - 0

AZPS does not have comments for the revised measurement M3 of FAC-014-3. AZPS does not have comments for the the added requirement 5.6 as it currently does not impact AZPS however may have potential impact in the future. AZPS does not have comments for R8.

 

Daniela Atanasovski, APS - Arizona Public Service Co., 1, 12/1/2020

- 0 - 0

Rahn Petersen, On Behalf of: PNM Resources - Public Service Company of New Mexico - WECC - Segments 1, 3, 5

- 0 - 0

Basin Electric supports the MRO NSRF comments.  Jerry Horner

Jerry Horner, Basin Electric Power Cooperative, 6, 12/3/2020

- 0 - 0

FAC-014-3, Part 5.6

The MRO NSRF notes that FAC-014, Part 5.6 modifies and expands the existing FAC-014-2, requirements R5.1.1 and R5.1.3, to require Reliability Coordinators provide Transmission Owners and Generator Owners with a list of their Facilities identified as critical to the derivation of an IROL and its associated contingencies. If the application of Part 5.6 is intended to include: Operations Planning, Same-day Operations and Real-Time Operations (with emphasis on the latter time horizons), the MRO NSRF believes that an FAC standard is not the best fit for this requirement and recommends this be relocated to an IRO standard.

If, however, the intent is to limit the time horizon to Operations Planning as indicated in Parts 5.1, 5.2 and 5.4 (tied to Part 5.2), which are limited in their application to “at least once every 12 months,” FAC-014 may be the best fit location. If this is the case, the MRO NSRF recommends Part 5.6 be clarified to “at least once every 12 months” and Same-day Operations and Real-Time Operations be stricken from the applicable Time Horizons for Requirement R5 as illustrated below:

R5. Each Reliability Coordinator shall provide: [Violation Risk Factor: High] [Time Horizon: Operations Planning, Same-day Operations, Real-Time Operations]

5.6 Each impacted Generator Owner or Transmission Owner, within its Reliability Coordinator Area, with a list of their Facilities that have been identified as critical to the derivation of an IROL and its associated critical contingencies at least once every twelve calendar months.

Finally, if the deriviation of an IROL and its associated critical contingencies is considered temporary, there is no language in Part 5.6 of the standard that limits when and if CIP-002-5.1a must be applied to these facilities. The MRO NSRF recommends the SDT address this as part of this project as this has the potential to trigger a new Medium Impact Rating for an entity. 

Regardless of location, the Guidelines and Technical Basis for CIP-002-5.1a will need to be updated to reflect and align with these changes (see references cited for Criterion 2.6 at the bottom of page 25 and page 28).

FAC-014-3, Requirement 8

The MRO NSRF notes that FAC-014, R8 modifies and expands the existing FAC-014-2, requirements R5.1.1 and R5.1.3, to require Planning Coordinators and Transmission Planners provide Transmission Owners and Generator Owners with a list of their Facilities that comprise planning event Contingencies that would cause instability, Cascading or uncontrolled separation that adversely impact BES reliability as identified in its Planning Assessment. Similar to what is noted above for Part 5.6 , the Guidelines and Technical Basis for CIP-002-5.1a will need to be updated to reflect and align with these changes (see references cited for Criterion 2.6 at the bottom of page 25 and page 28). Without this linkage, Generator Owners receiving information pursuant to FAC-014-3, Requirement 8 for the first time may fail to make the correlation to CIP-002-5.1a.

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

- 0 - 0

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

- 0 - 0

FAC-014-3, R5.6

 

FAC-014-3, Part 5.6 modifies and expands the existing FAC-014-2  to require Reliability Coordinators provide Transmission Owners and Generator Owners with a list of their Facilities identified as critical to the derivation of an IROL and its associated contingencies.

 

Facilities identified as critical to the derivation of an IROL and its associated contingencies is a criterion for applying a Medium Impact Rating under CIP-002-5.1a. The proposed requirement R5.6 is redundant and we suggest that there is no reliability need to expand FAC-014-2 with the proposed R5.6.

Leonard Kula, Independent Electricity System Operator, 2, 12/4/2020

- 0 - 0

Anthony Jablonski, ReliabilityFirst , 10, 12/4/2020

- 0 - 0

In regards to requirement R8, BC Hydro requests that the drafting team confirm if it the intent was to include the extreme events (as referenced on page 11 in Table 1 of TPL-001-4) when determining the “list of Facilities that comprise the planning event Contingency(ies) that would cause instability, Cascading or uncontrolled separation that adversely impacts the reliability of the BES as identified in its Planning Assessment of the Near‐Term Transmission Planning Horizon”?

Including the extreme events for consideration under the FAC-014-3 R8 appears to be an expansion of the current requirement R6 of FAC-014-2, which only references multiple contingencies per TPL-003 (not including extreme events, which were covered in TPL-004 System Performance under Extreme Events prior to TPL-001-4 becoming effective).

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

- 0 - 0

I'm supporting MRO NSRF comments: 

FAC-014-3, Part 5.6

The MRO NSRF notes that FAC-014, Part 5.6 modifies and expands the existing FAC-014-2, requirements R5.1.1 and R5.1.3, to require Reliability Coordinators provide Transmission Owners and Generator Owners with a list of their Facilities identified as critical to the derivation of an IROL and its associated contingencies. If the application of Part 5.6 is intended to include: Operations Planning, Same-day Operations and Real-Time Operations (with emphasis on the latter time horizons), the MRO NSRF believes that an FAC standard is not the best fit for this requirement and recommends this be relocated to an IRO standard.

If, however, the intent is to limit the time horizon to Operations Planning as indicated in Parts 5.1, 5.2 and 5.4 (tied to Part 5.2), which are limited in their application to “at least once every 12 months,” FAC-014 may be the best fit location. If this is the case, the MRO NSRF recommends Part 5.6 be clarified to “at least once every 12 months” and Same-day Operations and Real-Time Operations be stricken from th applicable Time Horizons for Requirement R5 as illustrated below:

 

R5. Each Reliability Coordinator shall provide: [Violation Risk Factor: High] [Time Horizon: Operations Planning, Same-day Operations, Real-Time Operations]

5.6 Each impacted Generator Owner or Transmission Owner, within its Reliability Coordinator Area, with a list of their Facilities that have been identified as critical to the derivation of an IROL and its associated critical contingencies at least once every twelve calendar months.

Finally, if the deriviation of an IROL and its associated critical contingencies is considered temporary, there is no language in Part 5.6 of the standard that limits when and if CIP-002-5.1a must be applied to these facilities. The MRO NSRF recommends the SDT address this as part of this project as this has the potential to trigger a new Medium Impact Rating for an entity.  

Regardless of location, the Guidelines and Technical Basis for CIP-002-5.1a will need to be updated to reflect and align with these changes (see references cited for Criterion 2.6 at the bottom of page 25 and page 28).

 

FAC-014-3, Requirement 8

The MRO NSRF notes that FAC-014, R8 modifies and expands the existing FAC-014-2, requirements R5.1.1 and R5.1.3, to require Planning Coordinators and Transmission Planners provide Transmission Owners and Generator Owners with a list of their Facilities that comprise planning event Contingencies that would cause instability, Cascading or uncontrolled separation that adversely impact BES reliability as identified in its Planning Assessment. Similar to what is noted above for Part 5.6 , the Guidelines and Technical Basis for CIP-002-5.1a will need to be updated to reflect and align with these changes (see references cited for Criterion 2.6 at the bottom of page 25 and page 28). Without this linkage, Generator Owners receiving information pursuant to FAC-014-3, Requirement 8 for the first time may fail to make the correlation to CIP-002-5.1a.

Terry Harbour, Berkshire Hathaway Energy - MidAmerican Energy Co., 1, 12/4/2020

- 0 - 0

The addition of the term ‘critical’ to R5.6 makes this revision difficult to support and impossible to ensure compliance.  ‘Critical’ is not a defined term in the NERC Glossary - consider removing the term 'critical' or adding term to the NERC Glossary.  The term critical was also inserted into R 5.2.4.

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

- 0 - 0

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

- 0 - 0

MPC agrees with and supports the MRO NERC Standards Review Forums comments:

FAC-014-3, Part 5.6

 

The MRO NSRF notes that FAC-014, Part 5.6 modifies and expands the existing FAC-014-2, requirements R5.1.1 and R5.1.3, to require Reliability Coordinators provide Transmission Owners and Generator Owners with a list of their Facilities identified as critical to the derivation of an IROL and its associated contingencies. If the application of Part 5.6 is intended to include: Operations Planning, Same-day Operations and Real-Time Operations (with emphasis on the latter time horizons), the MRO NSRF believes that an FAC standard is not the best fit for this requirement and recommends this be relocated to an IRO standard.

 

If, however, the intent is to limit the time horizon to Operations Planning as indicated in Parts 5.1, 5.2 and 5.4 (tied to Part 5.2), which are limited in their application to “at least once every 12 months,” FAC-014 may be the best fit location. If this is the case, the MRO NSRF recommends Part 5.6 be clarified to “at least once every 12 months” and Same-day Operations and Real-Time Operations be stricken from the applicable Time Horizons for Requirement R5 as illustrated below:

 

R5. Each Reliability Coordinator shall provide: [Violation Risk Factor: High] [Time Horizon: Operations Planning, Same-day Operations, Real-Time Operations]

 

5.6 Each impacted Generator Owner or Transmission Owner, within its Reliability Coordinator Area, with a list of their Facilities that have been identified as critical to the derivation of an IROL and its associated critical contingencies at least once every twelve calendar months.

 

Finally, if the deriviation of an IROL and its associated critical contingencies is considered temporary, there is no language in Part 5.6 of the standard that limits when and if CIP-002-5.1a must be applied to these facilities. The MRO NSRF recommends the SDT address this as part of this project as this has the potential to trigger a new Medium Impact Rating for an entity.  

 

Regardless of location, the Guidelines and Technical Basis for CIP-002-5.1a will need to be updated to reflect and align with these changes (see references cited for Criterion 2.6 at the bottom of page 25 and page 28).

 

FAC-014-3, Requirement 8

 

The MRO NSRF notes that FAC-014, R8 modifies and expands the existing FAC-014-2, requirements R5.1.1 and R5.1.3, to require Planning Coordinators and Transmission Planners provide Transmission Owners and Generator Owners with a list of their Facilities that comprise planning event Contingencies that would cause instability, Cascading or uncontrolled separation that adversely impact BES reliability as identified in its Planning Assessment. Similar to what is noted above for Part 5.6 , the Guidelines and Technical Basis for CIP-002-5.1a will need to be updated to reflect and align with these changes (see references cited for Criterion 2.6 at the bottom of page 25 and page 28). Without this linkage, Generator Owners receiving information pursuant to FAC-014-3, Requirement 8 for the first time may fail to make the correlation to CIP-002-5.1a.

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

- 0 - 0

Alliant Energy supports the comments filed by the MRO NERC Standards Review Forum (NSRF) for this question.

Larry Heckert, Alliant Energy Corporation Services, Inc., 4, 12/7/2020

- 0 - 0

If the application of Part 5.6 is intended to include three latter time horizons (Operations Planning, Same-day Operations and Real-Time Operations), AEPC believes that an FAC standard is not the best fit for this requirement and recommends this be relocated to an IRO standard.

A common language has been utilized to revise R8 which includes the language: “that adversely impact the reliability of the BES”. This language does not detail what is considered “adverse impact,” and therefore introduces inconsistencies among the industry.

AEPC also signed on to ACES comments.

Jennifer Bray, Arizona Electric Power Cooperative, Inc., 1, 12/7/2020

- 0 - 0

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

Jamie Johnson, California ISO, 2, 12/7/2020

- 0 - 0

Sandra Ellis, On Behalf of: Pacific Gas and Electric Company, WECC, Segments 3

- 0 - 0

Please see comments submitted by the Edison Electric Institute.

Neil Shockey, 12/7/2020

- 0 - 0

MISO supports comments submitted by the ISO/RTO Council Standards Review Committee (IRC SRC) and MRO NERC Standards Review Forum (MRO NSRF).

Bobbi Welch, Midcontinent ISO, Inc., 2, 12/7/2020

- 0 - 0

Please see comments submitted by the Edison Electric Institute.

Kenya Streeter, Edison International - Southern California Edison Company, 6, 12/7/2020

- 0 - 0

Entergy supports MISO's comments.

Oliver Burke, Entergy - Entergy Services, Inc., 1, 12/7/2020

- 0 - 0

We endorse the comments provided by AEP on 11/24/2020.

Steven Taddeucci, NiSource - Northern Indiana Public Service Co., 3, 12/7/2020

- 0 - 0

James Baldwin, Lower Colorado River Authority, 1, 12/7/2020

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Texas RE is concerned there is no timeline for the provision of the list of Facilities in the new Requirement R5.6.  Texas RE suggests being consistent with Requirements 5.1 and 5.2 which specify “at least once every twelve calendar months.”  Texas RE also recommends capitalizing “Contingency(ies)” since it is defined in the NERC Glossary.

 

For Requirement R8, Texas RE inquires as to whether it is intended that all lines “that comprise the planning event Contingency(ies) that would cause instability, Cascading or uncontrolled separation that adversely impacts the reliability of the BES” that are communicated to the GO or TO under R8 would be applicable to FAC-003-5.  FAC-003-5 section 4.2.2 states “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.”

 

Texas RE reads this language to require all overhead transmission lines operated below 200 kV communicated by Planning Coordinators and Transmission Planners comprising planning event Contingencies causing instability, Cascading, or uncontrolled separate to remain subject to the FAC-003-5 vegetation management requirements. However, Texas RE is concerned that, for a planning event that involves multiple Contingencies (P3 – P7), the standard could be read to exclude single Facilities associated with the event by virtue of the fact that the loss of the individual Facility does not result, by itself, in instability, Cascading, or uncontrolled separation that adversely impacts the reliability of the Bulk Electric System.  Texas RE believes that such a reading could result in a reliability gap if individual Facilities under 200 kV that contribute to instability, Cascading, or uncontrolled separation in planning studies are arguably not included within the scope of FAC-003-5.  Accordingly, Texas RE requests that the SDT clarify that it did not intend to exclude such Facilities from the scope of the FAC-003-5 vegetation management requirements.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 12/7/2020

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Teresa Krabe, Lower Colorado River Authority, 5, 12/7/2020

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Requirement R5.6 does not reference any schedule or frequency. Reclamation recommends adding a required communication cycle to align with the language in Requirement R5.2, to ensure that GOs and TOs have access to updated information, and to provide the RCs with greater confidence in responses received from entities that must document the lack of Facilities critical to the derivation of an IROL for CIP-002. Reclamation recommends the following language:

Change from:

Each impacted Generator Owner or Transmission Owner, within its Reliability Coordinator Area, with a list of their Facilities that have been identified as critical to the derivation of an IROL and its associated critical contingencies.

To:

Each impacted Generator Owner or Transmission Owner, within its Reliability Coordinator Area, with a list of their Facilities that have been identified as critical to the derivation of an IROL and its associated critical contingencies at least once every twelve calendar months.

Richard Jackson, U.S. Bureau of Reclamation, 1, 12/7/2020

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Southern Company agrees with the addition of requirement R5.6 as well as the revisions to measure M3.

While the revised wording in requirement R8 is an improvement to the the previous posting, Southern Company believes that this requirement could result in burdensome communication even if there isn’t any identified issues per the Planning Assessment to communicate. As such, Southern Company recommends the addition of the following sentence at the end of Requirement R8:

“Planning Coordinators and Transmission Planners that do not identify any Facilities are not required to perform the annual communication”.

Southern Company, Segment(s) 1, 6, 3, 5, 9/1/2016

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

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Exelon concurs with the comments submitted by the Edison Electric Insititue (EEI). 

Submitted on behalf of Exelon: Segments 1, 3, 5, 6

Daniel Gacek, Exelon, 1, 12/7/2020

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Tammy Porter, On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; Lee Maurer, Oncor Electric Delivery, 1

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  1. Does this mean PC/TPs need to have “adverse impact” criteria in their Annual Assessment or does this return to the concept of any failure to meet TPL-001-4/5 System performance requirements of Table 1?  As an alternative to all of this confusion, why not simply mirror the concept and clear language in Requirement R7:

    Requirement R8 -   Each Planning Coordinator and each Transmission Planner shall annually communicate to each impacted Transmission Owner and Generation Owner a list of their Facilities identified as part of a Corrective Action Plan(s) developed to address any that comprise the planning event Contingency(ies) that would cause instability, Cascading or uncontrolled separation that adversely impacts the reliability of the BES as identified in its Planning Assessment of the Near-Term Transmission Planning Horizon.

sean erickson, Western Area Power Administration, 1, 12/7/2020

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We agree with the revisions, however, please consider revising and renumbering the R5.2 sub-requirements 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 Contingeny(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).

NPCC Regional Standards Committee, Segment(s) 10, 2, 4, 7, 3, 1, 5, 6, 9/21/2020

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FAC-014-3, Part 5.6

The IRC SRC notes that FAC-014, Part 5.6 modifies and expands the existing FAC-014-2, requirements R5.1.1 and R5.1.3, to require Reliability Coordinators provide Transmission Owners and Generator Owners with a list of their Facilities identified as critical to the derivation of an IROL and its associated contingencies. If the application of Part 5.6 is intended to include: Operations Planning, Same-day Operations and Real-Time Operations (with emphasis on the latter time horizons), the IRC SRC believes that an FAC standard is not the best fit for this requirement and recommends this be relocated to an IRO standard.

If, however, the intent is to limit the time horizon to Operations Planning as indicated in Parts 5.1, 5.2 and 5.4 (tied to Part 5.2), which are limited in their application to “at least once every 12 months,” FAC-014 may be an appropriate location. The latter being the case, the IRC SRC recommends the time horizon for Part 5.6 be clarified to “at least once every 12 months” and Same-day Operations and Real-Time Operations be stricken from the applicable Time Horizons for Requirement R5 as illustrated below:

R5. Each Reliability Coordinator shall provide: [Violation Risk Factor: High] [Time Horizon: Operations Planning]

5.6 Each impacted Generator Owner or Transmission Owner, within its Reliability Coordinator Area, with a list of their Facilities that have been identified as critical to the derivation of an IROL and its associated critical contingencies at least once every twelve calendar months.

Finally, if the derivation of an IROL and its associated critical contingencies is considered temporary, we ask for clarification whether these facilities become subject to requirements under CIP-002-5.1a. There is no language in Part 5.6 of the standard that limits when and if CIP-002-5.1a must be applied to these facilities. The IRC SRC asks the SDT exclude the ability of temporary IROLs from triggering CIP-002-5.1a, Attachment 1, Medium Impact Rating provisions. This could be accomplished by defining the time horizon for Criterion 2.6, similar to what has been done with Criterion 2.3; i.e. “as necessary to avoid an Adverse Reliability Impact in the planning horizon of more than one year.  

Regardless of location, the Guidelines and Technical Basis for CIP-002-5.1a will need to be updated to reflect and align with these changes (see references cited for Criterion 2.6 at the bottom of page 25 and page 28). Without this linkage, Generator Owners receiving information pursuant to FAC-014-3, Requirement 8 may fail to correlate this information with CIP-002-5.1a, particularly as FAC-014-3, measure M5 allows information to be provided via posting to a secure website. As FAC-014-3 is not directly applicable to Generator Owners (section 4), they may not even be aware that they would need to check their Reliability Coordinator’s website for this posting and that they would need to check it on a daily basis should the Same-day Operations and Real-Time Operations time horizons for R5 be retained.

FAC-014-3, Requirement 8

The IRC SRC notes that FAC-014, R8 modifies and expands the existing FAC-014-2, requirements R5.1.1 and R5.1.3, to require Planning Coordinators and Transmission Planners provide Transmission Owners and Generator Owners with a list of their Facilities that comprise planning event Contingencies that would cause instability, Cascading or uncontrolled separation that adversely impact BES reliability as identified in its Planning Assessment. Similar to what is noted above for Part 5.6 , the Guidelines and Technical Basis for CIP-002-5.1a will need to be updated to reflect and align with these changes (see references cited for Criterion 2.6 at the bottom of page 25 and page 28). Without this linkage, Generator Owners receiving information pursuant to FAC0-014-3, Requirement 8 for the first time may fail to make the correlation to CIP-002-5.1a. Without this linkage, Generator Owners receiving information pursuant to FAC-014-3, Requirement 8 may fail to correlate this information with CIP-002-5.1a, particularly as FAC-014-3 is not directly applicable to Generator Owners.

FAC-014-3, Measurement 3

 The byproduct of removing “in accordance with its Reliability Coordinator’s SOL methodology” to align with Requirement 3 language, introduces an inconsistency with similar FAC-014-3 language around each of its other Requirements and Measures and which is not justified by the Rationale which effectively makes it an option to include or not include the language within an RC’s SOL methodology.

Doing so effectively allows for a TOP to provide their SOLs to the RC in any timeframe of their choosing, so long as they are provided.  While the SDT Rationale points to potential duplicity or alignment with that of IRO-010-2 and thus the need for flexibility through the removal of “in accordance with its Reliability Coordinator’s SOL methodology”, IRO-010-2 makes no direct reference to System Operating Limits.  As such, the IRC SRC believes “in accordance with its Reliability Coordinator’s methodology” to be appended to both R3 and M3.

 

ISO/RTO Standards Review Committee, Segment(s) 2, 12/7/2020

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Quintin Lee, Eversource Energy, 1, 12/7/2020

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The Southwest Power Pool (SPP) Regional Transmission Organization (RTO) agrees the proposed language in requirement 5.6 plays a role in the reliability of the Bulk Electric System (BES), however, SPP RTO recommends the Reliability Coordinators (RCs) communication to the Transmission Owners (TOs) and Generation Owners (GOs) of facilities could be incorporated into an IRO Reliability Standard, possibly IRO-009, based on the contribution potential of the derivation of Interconnection Reliability Operating Limits (IROL’s), and/or IRO-010 which contains actions for the RC to operate within IROLS and contain the requirements for the RC and asset owners to communicate information for IROLs.

SPP RTO interrupts that the FAC Reliability Standards are intended for specifying what the RC needs to include in the methodology to calculate System Operating Limits (SOLs) and IROLs. In a requirement such as 5.6, the calculation for IROL could confuse the communication of the obligations of asset owners to the RC.

SPP recommends the proposed modification of the 5.6 requirement language:

The original language states “identified as critical to the derivation of an IROL” and SPP is proposing “identified by the RC as critical to the derivation of an IROL”.

SPP RTO, Segment(s) 2, 12/7/2020

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

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Evergy incorporates by reference and supports the comments of Edison Electric Institute (EEI) in response to Question 2. 

Douglas Webb, On Behalf of: Evergy, MRO, Segments 1, 3, 5, 6

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Ameren agrees with and supports EEI commnets

David Jendras, Ameren - Ameren Services, 3, 12/7/2020

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Karen Weaver, Tallahassee Electric (City of Tallahassee, FL), 5, 12/7/2020

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Scott Langston, Tallahassee Electric (City of Tallahassee, FL), 1, 12/7/2020

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NV Energy is supporting MRO NSRF comments: 

FAC-014-3, Part 5.6

The MRO NSRF notes that FAC-014, Part 5.6 modifies and expands the existing FAC-014-2, requirements R5.1.1 and R5.1.3, to require Reliability Coordinators provide Transmission Owners and Generator Owners with a list of their Facilities identified as critical to the derivation of an IROL and its associated contingencies. If the application of Part 5.6 is intended to include: Operations Planning, Same-day Operations and Real-Time Operations (with emphasis on the latter time horizons), the MRO NSRF believes that an FAC standard is not the best fit for this requirement and recommends this be relocated to an IRO standard.

If, however, the intent is to limit the time horizon to Operations Planning as indicated in Parts 5.1, 5.2 and 5.4 (tied to Part 5.2), which are limited in their application to “at least once every 12 months,” FAC-014 may be the best fit location. If this is the case, the MRO NSRF recommends Part 5.6 be clarified to “at least once every 12 months” and Same-day Operations and Real-Time Operations be stricken from th applicable Time Horizons for Requirement R5 as illustrated below:

 

R5. Each Reliability Coordinator shall provide: [Violation Risk Factor: High] [Time Horizon: Operations Planning, Same-day Operations, Real-Time Operations]

5.6 Each impacted Generator Owner or Transmission Owner, within its Reliability Coordinator Area, with a list of their Facilities that have been identified as critical to the derivation of an IROL and its associated critical contingencies at least once every twelve calendar months.

Finally, if the deriviation of an IROL and its associated critical contingencies is considered temporary, there is no language in Part 5.6 of the standard that limits when and if CIP-002-5.1a must be applied to these facilities. The MRO NSRF recommends the SDT address this as part of this project as this has the potential to trigger a new Medium Impact Rating for an entity.  

Regardless of location, the Guidelines and Technical Basis for CIP-002-5.1a will need to be updated to reflect and align with these changes (see references cited for Criterion 2.6 at the bottom of page 25 and page 28).

 

FAC-014-3, Requirement 8

The MRO NSRF notes that FAC-014, R8 modifies and expands the existing FAC-014-2, requirements R5.1.1 and R5.1.3, to require Planning Coordinators and Transmission Planners provide Transmission Owners and Generator Owners with a list of their Facilities that comprise planning event Contingencies that would cause instability, Cascading or uncontrolled separation that adversely impact BES reliability as identified in its Planning Assessment. Similar to what is noted above for Part 5.6 , the Guidelines and Technical Basis for CIP-002-5.1a will need to be updated to reflect and align with these changes (see references cited for Criterion 2.6 at the bottom of page 25 and page 28). Without this linkage, Generator Owners receiving information pursuant to FAC-014-3, Requirement 8 for the first time may fail to make the correlation to CIP-002-5.1a

Kevin Salsbury, Berkshire Hathaway - NV Energy, 5, 12/7/2020

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Jose Avendano Mora, Edison International - Southern California Edison Company, 1, 12/7/2020

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If the application of Part 5.6 is intended to include three latter time horizons (Operations Planning, Same-day Operations and Real-Time Operations), ACES believes that an FAC standard is not the best fit for this requirement and recommends this be relocated to an IRO standard.

A common language has been utilized to revise R8 which includes the language: “that adversely impact the reliability of the BES”. This language does not detail what is considered “adverse impact,” and therefore introduces inconsistencies among the industry.

ACES Standard Collaborations, Segment(s) 1, 3, 4, 5, 12/7/2020

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EEI agrees that the addition of Requirement R5, part 5.6 enhances and clarifies the obligations of the RC under requirement R5. This change also supports GO and TO CIP compliance activities for CIP-002 and/or CIP-014.  However, the reference within the FAC-014-3 Technical Rationale, on the top of page 6, incorrectly references “4.1.1.4 in CIP-014.”  This reference should be 4.1.1.3 (see below).

Excerpt from FAC-014-3 Technical Rationale, Page 6 (Rationale R5)

Finally, Requirement R5, part 5.6, requires that the RC must provide each impacted Generation Owner or Transmission Owner within its Reliability Coordinator area with a list of Facilities that they can use to satisfy the criteria in Attachment 1 part 2.6 in CIP-002 and/or 4.1.1.4 in CIP-014. Of the three possible entities, RC, TP and PC listed in CIP-002 and CIP-014 that could deliver this information to the TOs and GOs, the RC is ultimately responsible given they’re required to establish IROLs. Thus, the requirement for provision of the list of Facilities identified as critical to the derivation of an IROL and its associated critical contingencies should rest with the RC.

CIP-014-2

Applicability Section

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

4.1.1.4 Transmission Facilities identified as essential to meeting Nuclear Plant Interface Requirements.

EEI supports the modification to Measure M3.

EEI supports the changes made to Requirement R8, which address our earlier concerns and  provides clear requirements for Planning Coordinators and Transmission Planners that define what they must communicate to impacted TOs and GOs whenever planned contingency events indicate that instability, Cascading and uncontrolled separation would occur resulting in negative impacts to BES reliability in the Near-Term Transmission Planning Horizon.

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

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OPG support NPCC Regional Standards Committee’s comments.

Constantin Chitescu, Ontario Power Generation Inc., 5, 12/7/2020

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Ed Hanson, Pacific Gas and Electric Company, 5, 12/7/2020

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Hot Answers

None.

Brandon Gleason, 12/7/2020

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R6:  Techincal rational seems inconsistent with how the language as written could be read.  Requirement does give the RC authority over the PC in it sets a performance requirement for the PC to meet outside of the TPL standard.  It seems to pre-suppose that the PC's criteria and the Facility Ratings it uses may be suspect.  Suggest the SDT draft language for the RC to simply submit its SOL methodology and ratings and perhaps more importantly the basis to the PC for review and comment.  The PC can then determine what is applicable for its planning assessment.  

Wayne Guttormson, SaskPower, 1, 12/7/2020

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Other Answers

See prior NCPA and John Allen City Utilities prior balloting comments.

Michael Whitney, On Behalf of: Northern California Power Agency, , Segments 3, 4, 5, 6

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See prior NCPA and John Allen City Utilities prior balloting comments

Dennis Sismaet, Northern California Power Agency, 6, 10/26/2020

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No other comments

Robert Hirchak, Cleco Corporation, 6, 11/2/2020

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City Utilities of Springfield appreciates the 2015-09 team's consideration of our previous comments. We understand the desire to complete this five year old project, but respectfully disagree that additional changes are not necessary. We believe that current projects should not continue creating requirements that are either unclear, redundant or out of place in the body of Reliability Standards. This is contrary to all the efforts industry is putting forward in the Standards Efficiency Review project. Therefore, City Utilities stands firm on our previous comments.

John Allen, City Utilities of Springfield, Missouri, 4, 11/9/2020

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Bruce Reimer, Manitoba Hydro , 1, 11/19/2020

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AEP is concerned by the usage and meaning of “stability criteria” within R6, and request that the SDT provide clarity regarding the exact meaning of this phrase. Does it mean the acceptable power swing damping level and transient voltage dip and recovery durations? Does it mean the bare necessity for the system to remain stable? Does it mean the P1-P7 contingency definitions used in studies to evaluate stability? Does it mean the stability SOLs themselves? Uncertainty regarding the exact meaning of this phrase leads us to offer the following feedback…

If “stability criteria” means stability SOLs themselves, then the following feedback paragraph applies. The RC must deal with real-time outages, often simultaneous multiple outages that may result in more restrictive stability operating limits than are considered in planning studies. Example: the RC secures system against P4 stuck CB events during other real-time outages. In planning, prior outages are not required to be simulated by the TPL standard for P4 events, nor have they been regarded as necessary for P4 event planning purposes in the past. Depending on a RC’s SOL methodology, the proposed R6 may impose more restrictive limits on planning studies, and for this reason, might result in corrective action plans and expense that would not have been identified in the past. R6 may also result in complication and confusion between planning and operations because it may never be clear out of the numerous outage conditions encountered by operations in any day, season, or year, which of these must be considered in planning studies under the proposed R6. It is also quite likely that particular combinations of outages will never appear again, rendering planning studies that are forced to recognize SOLs resulting from such outage combinations as “more limiting stability criteria” not very relevant.

If “stability criteria” means the acceptable power swing damping level and transient voltage dip and recovery durations, or the bare necessity for the system to remain stable, or the P1-P7 contingency definitions used in studies to evaluate stability then the following feedback paragraph applies. The RCs, PCs, and TPs most probably already have (and in our experience *do* have) coordinated power swing damping criteria and would have consistent transient voltage criteria should that ever be applied in operations. There is no valid reason to require this in FAC-014. The performance measure requiring system stability to be maintained is the same by definition in both operations and planning. Contingency event definitions are also the same between operations and planning. If there are no other stability criteria to be coordinated between RC and PC/TP, the proposed R6 may be useless for stability planning purposes and will only cause needless administrative paperwork.

In addition, real-time generation redispatch is often assumed in planning studies to resolve instability and it is not always considered a Corrective Action Plan. Real-time generation redispatch may be particularly relevant to P6 scenarios as “system adjustments” as distinguished from “corrective action plans.” Thus, real-time redispatch may either result in no corrective action plan because it is not considered a corrective action plan (nullifying R7) or, as a system adjustment, will result in no planning event instability, cascading, or uncontrolled separation (nullifying R8). The reliability benefit of the proposed R7 and R8 may be nullified if generation redispatch is used to resolve instability.

AEP recommends removal of “stability criteria” from the proposed R6 and transfer of the proposed 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 R7 and R8 be placed within FAC-014. These requirements are best served if drafted and reviewed from a Transmission Planner perspective which can properly evaluate their necessity in view of the potential for nullification by possible reliance on operational actions and system adjustments not considered corrective action plans.

While we obviously do not yet know the answers to the “stability criteria” question we have posed above, we would like to propose the following revisions to R6 which we believe may provide clarity and minimize compliance burden...

 

Each Planning Coordinator and each Transmission Planner shall implement a documented process to use *incorporate* Facility Ratings, System steady-state voltage limits and stability limits criteria in its Planning Assessment of Near Term Transmission Planning Horizon that are equally limiting or more limiting than the criteria for Facility Ratings, System Voltage Limits and stability described in its Reliability Coordinator’s SOL methodology *as identified in Requirement 5.1 and 5.2.*

 

 

 

• The Planning Coordinator may *also* use less limiting Facility Ratings, System steady-state voltage limits and stability criteria if it provides a technical rationale to each affected Transmission Planner, Transmission Operator and Reliability Coordinator.

 

• The Transmission Planner may *also* use less limiting Facility Ratings, System steady-state voltage limits and stability criteria if it provides a technical rationale to each affected Planning Coordinator, Transmission Operator and Reliability Coordinator.

 

In the event that the formatting used for our suggested revisions to R6 (showing both our deleted and added text) are not retained by the SBS system, we provide it here again, showing only the retained and added text in a “clean format.” 

Each Planning Coordinator and each Transmission Planner shall incorporate Facility Ratings, System steady-state voltage limits and stability limits in its Planning Assessment of Near Term Transmission Planning Horizon as identified in Requirement 5.1 and 5.2. 

 

• The Planning Coordinator may also use less limiting Facility Ratings, System steady-state voltage limits and stability criteria if it provides a technical rationale to each affected Transmission Planner, Transmission Operator and Reliability Coordinator.

 

• The Transmission Planner may also use less limiting Facility Ratings, System steady-state voltage limits and stability criteria if it provides a technical rationale to each affected Planning Coordinator, Transmission Operator and Reliability Coordinator.

 

 

The compliance burden is minimized by simply requiring the PC/TP to incorporate RC ratings and limits in TPL assessments instead of requiring yet another process document for what should be a straightforward comparison check. Emphasizing Requirements R5.1 and R5.2 in R6 clarifies the responsibility of the PC/TP. R5.1 and R5.2 provide the PC/TP specific SOL/IROL/stability limits from the RC that can be incorporated into Planning Assessments. Only referencing an RC’s SOL methodology as originally proposed in R6 could lead to much interpretation by the PC/TP since they are only methodology documents. In addition, from a stability perspective, requiring the PC/TP to evaluate specific stability events as identified by the RC in R5.1/R5.2 provides a finite set of events to be considered for the Planning Assessment. It is possible that some of the stability limits from the RC will not satisfy Planning Assessment criteria, but using R5.1/R5.2 as the point of reference provides structure to the Planning Assessment process.

Thomas Foltz, AEP, 5, 11/24/2020

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None

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

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Richard Brooks, On Behalf of: Reliable Energy Analytics LLC, , Segments 8

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Laura Nelson, 11/30/2020

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Colleen Campbell, 11/30/2020

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Kjersti Drott, 11/30/2020

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no comments

Glen Allegranza, On Behalf of: Imperial Irrigation District, , Segments 1, 3, 5, 6

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Nurul Abser, On Behalf of: NB Power Corporation, , Segments 1, 5

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The current effective standard FAC-014-2 version, Requirement 5.1.3 states “The associated Contingency(ies)”. The proposed FAC-014-3, Requirement 5.2.4, states “The associated critical Contingency(ies).” What distinguishes a “critical” contingency(ies)?

Daniela Atanasovski, APS - Arizona Public Service Co., 1, 12/1/2020

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No Additional comments

Rahn Petersen, On Behalf of: PNM Resources - Public Service Company of New Mexico - WECC - Segments 1, 3, 5

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Basin Electric supports the MRO NSRF comments.  Jerry Horner

Jerry Horner, Basin Electric Power Cooperative, 6, 12/3/2020

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FAC-014-3, Requirement R6

The provided rationale document for Requirement 6 states, “The intent of Requirement 6 is not to change, limit, or modify Facility Ratings determined by the equipment owner per FAC-008, nor to allow the PCs or TPs to revise those limits.  The intent is to utilize those owner-provided Facility Ratings such that the System is planned to support the reliable operation of that System.”  The rationale document also states (following on from the earlier quote), “This is accomplished by requiring the PC and TP to use the owner-provided Facility Ratings that are equally limiting or more limiting than those established in accordance with the RC’s SOL methodology.” 

From a Planning study perspective, TPL-001-4, Requirement 1, obligates PCs and TPs as part of their Planning Assessment of the Near Term Transmission Planning Horizon to use data consistent with what is provided in accordance with MOD-032. 

The MRO NSRF also recommends the following additional changes to the language in the requirement:

{C}·         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 MRO NSRF recommends that consistent terminology be used across these standards.

{C}·         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 MRO NSRF recommends that consistent terminology be used across these standards.

Finally, the MRO NSRF recommends that the following change be made to R6 to clarify the intent of the requirement:

Each Planning Coordinator and each Transmission Planner shall implement a documented process to use Facility Ratings, System 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 use of Facility Ratings, System Voltage Limits and stability criteria described in its respective Reliability Coordinator’s SOL methodology.

FAC-014-3, Requirement 7

As proposed FAC-014-3, R7 is partially duplicative of existing requirements under IRO-017-1, R3 and TPL-001-4, R8 which obligate Planning Coordinators and Transmission Planners to provide  Planning Assessments to impacted Reliability Coordinators and adjacent Planning Coordinators and Transmission Planners, respectively. The MRO NSRF requests the SDT update an existing requirement rather than introduce a new requirement so that this type of information is consolidated in a single location. That said, the MRO NSRF recognizes that the information referenced in FAC-014, R7 is not explicitly required under either of the aforementioned standards and the option to reopen TPL has been discussed at length by the SDT. As a decision has been made not to reopen TPL-001 at this time, the MRO NSRF requests TPL-001, R8 be expanded to include Transmission Operators and Reliability Coordinators when it is next reopened for modifications and FAC-014-3, R7 be retired at that time.

FAC-011-4, Part 6.4

Finally, the MRO NSRF requests the SDT confirm in a response to comments or in a Technical Rationale document that FAC-011-4, Part 6.4, “planned manual load shedding is acceptable only after all other available System adjustments have been made,” only applies to addressing overloads that are observed in a planning or forecasted timeframe and is not intended to address actual overloads in Real-time on the system. This observation is made based on the Time Horizon for R6; i.e. ‘Operations Planning,’ and the descriptor of “planned“ manual load shedding.

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

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R6: 

The SDT agreed with BPA’s previous comments to the proposed revisions.The SDT noted that the Technical Rationale would be revised to ensure this clarity was captured and explained.  BPA’s concern is that the Technical Rationale is apart from  the Standard and would likely not be used by the auditors.  BPA believes this language needs to be explicitly stated in the Standard.

Additionally, after further review of the SDT’s proposed language, BPA does not agree with using the term “criteria” before Facility Ratings.

SDT Proposed Language for 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 are equally limiting or more limiting than the criteria for Facility Ratings, System Voltage Limits and stability described in its respective Reliability Coordinator’s SOL methodology. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

BPA recommends the following edits to add clarity to the STD’s proposed R6 revisions. BPA also believes ‘system voltage limits’ should not be capitalized, as it is not defined in the NERC Glossary of Terms. (Bold, italic text for additions):          

R6. Each Planning Coordinator and each Transmission Planner shall ensure 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 ensure 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]

BPA has no suggested changes to the R6 bullets below.

• The Planning Coordinator may use less limiting Facility Ratings, System steady-state voltage limits and stability criteria if it provides a technical rationale to each affected Transmission Planner, Transmission Operator and Reliability Coordinator.

• The Transmission Planner may use less limiting Facility Ratings, System steady-state voltage limits and stability criteria if it provides a technical rationale to each affected Planning Coordinator, Transmission Operator and Reliability Coordinator.

R7: 

BPA appreciates the SDT incorporating the language “…that adversely impacts the reliability of the Bulk Electric System…” into the modified R8.  BPA’s other comments were in response to Corrective Action Plans. BPA does not believe that the addition of language in R8 satisfies our concerns with R7.  BPA believes R8 is a subset of R7.4 where R7.4 is related to the contingency event, and R8 is related to the facilities that comprise the contingency event. 

BPA believes it should only be required to communicate/report information for Corrective Action Plans to impacted Transmission Operators and Reliability Coordinators that adversely impact the reliability of the Bulk Electric System.  Corrective Action Plans for local issues within a TP’s system that do not impact the reliability of the Bulk Electric System should not have to be communicated/reported.  As R7 is currently written, all Corrective Action Plans would need to be communicated/reported.  This is consistent with the SDT’s response to comments from earlier postings. 

BPA suggests modifying R7 with the following language below (bold, italic text added) to avoid the burden of communicating/reporting on local issue Corrective Action Plans. By making this change, enitities will only be required to report Corrective Action Plans that affect the larger BES.

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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Leonard Kula, Independent Electricity System Operator, 2, 12/4/2020

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Draft 3 of this standard added requirements for the quality of transmission assessments performed per TPL-001.  In particular, R6 calls for Near Term Transmission Planning to use Facility Ratings and Voltage Limits that are equally or more limiting than in the Reliability Coordinator’s SOL methodology.  Also, R7 calls for Planning Coordinators and Transmission Planners to annually communicate selected results of the Near-Term Transmission Planning results with Transmission Operators and Teliability Coordinators.

 

Ideally, requirements R6 and R7 need to be in TPL-001 instead of FAC-014.

Anthony Jablonski, ReliabilityFirst , 10, 12/4/2020

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

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FAC-014-3, Requirement R6

The provided rationale document for Requirement 6 states, “The intent of Requirement 6 is not to change, limit, or modify Facility Ratings determined by the equipment owner per FAC-008, nor to allow the PCs or TPs to revise those limits.  The intent is to utilize those owner-provided Facility Ratings such that the System is planned to support the reliable operation of that System.”  The rationale document also states (following on from the earlier quote), “This is accomplished by requiring the PC and TP to use the owner-provided Facility Ratings that are equally limiting or more limiting than those established in accordance with the RC’s SOL methodology.” 

From a Planning study perspective, TPL-001-4, Requirement 1, obligates PCs and TPs as part of their Planning Assessment of the Near Term Transmission Planning Horizon to use data consistent with what is provided in accordance with MOD-032. 

The MRO NSRF also recommends 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 MRO NSRF 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 MRO NSRF recommends that consistent terminology be used across these standards.

Finally, the MRO NSRF recommends that the following change be made to R6 to clarify the intent of the requirement:

Each Planning Coordinator and each Transmission Planner shall implement a documented process to use Facility Ratings, System 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 use of Facility Ratings, System Voltage Limits and stability criteria described in its respective Reliability Coordinator’s SOL methodology.

 

 

FAC-014-3, Requirement 7

As proposed FAC-014-3, R7 is partially duplicative of existing requirements under IRO-017-1, R3 and TPL-001-4, R8 which obligate Planning Coordinators and Transmission Planners to provide  Planning Assessments to impacted Reliability Coordinators and adjacent Planning Coordinators and Transmission Planners, respectively. The MRO NSRF requests the SDT update an existing requirement rather than introduce a new requirement so that this type of information is consolidated in a single location. That said, the MRO NSRF recognizes that the information referenced in FAC-014, R7 is not explicitly required under either of the aforementioned standards and the option to reopen TPL has been discussed at length by the SDT. As a decision has been made not to reopen TPL-001 at this time, the MRO NSRF requests TPL-001, R8 be expanded to include Transmission Operators and Reliability Coordinators when it is next reopened for modifications and FAC-014-3, R7 be retired at that time.

 

FAC-011-4, Part 6.4

Finally, the MRO NSRF requests the SDT confirm in a response to comments or in a Technical Rationale document that FAC-011-4, Part 6.4, “planned manual load shedding is acceptable only after all other available System adjustments have been made,” only applies to addressing overloads that are observed in a planning or forecasted timeframe and is not intended to address actual overloads in Real-time on the system. This observation is made based on the Time Horizon for R6; i.e. ‘Operations Planning,’ and the descriptor of “planned“ manual load shedding.

 

Terry Harbour, Berkshire Hathaway Energy - MidAmerican Energy Co., 1, 12/4/2020

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None.

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

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Dominion Energy suggests modifying the term “an instability”, as contained in Requirement R4, to “an identified instability”.  This proposed change makes Requirement R4 clear that the intent is for the RC to act on identified instability, not after an instability event has occurred.

Dominion Energy requests the SDT clarify the addition 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.  For Dominion Energy to support this change, the term “critical Contingency(ies)” need to be clarified or removed.

Alternatively, the SDT could consider revising the supporting subparts of 5.2 (Requirement R5), as indicated below, as a possible solution to the use of the undefined term “critical Contingency(ies)”.

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).

 

Dominion Energy disagrees with the inclusion of “as established in FAC-011-4” within the Severe VSL level within FAC-014-3, Requirement R1.  Since requirements can be moved out of one Reliability Standard to another, modified, or retired, this creates a burden to ensure all references are identified when modifications are made.  Each Reliability Standard should stand on its own and should not contain linkage to other Reliability Standards. 

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

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FAC-014-3, Requirement R6

 

The provided rationale document for Requirement 6 states, “The intent of Requirement 6 is not to change, limit, or modify Facility Ratings determined by the equipment owner per FAC-008, nor to allow the PCs or TPs to revise those limits.  The intent is to utilize those owner-provided Facility Ratings such that the System is planned to support the reliable operation of that System.”  The rationale document also states (following on from the earlier quote), “This is accomplished by requiring the PC and TP to use the owner-provided Facility Ratings that are equally limiting or more limiting than those established in accordance with the RC’s SOL methodology.” 

 

From a Planning study perspective, TPL-001-4, Requirement 1, obligates PCs and TPs as part of their Planning Assessment of the Near Term Transmission Planning Horizon to use data consistent with what is provided in accordance with MOD-032. 

 

The MRO NSRF also recommends 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 MRO NSRF 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 MRO NSRF recommends that consistent terminology be used across these standards.

Finally, the MRO NSRF recommends that the following change be made to R6 to clarify the intent of the requirement:

 

Each Planning Coordinator and each Transmission Planner shall implement a documented process to use Facility Ratings, System 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 use of Facility Ratings, System Voltage Limits and stability criteria described in its respective Reliability Coordinator’s SOL methodology.

 

 

FAC-014-3, Requirement 7

As proposed FAC-014-3, R7 is partially duplicative of existing requirements under IRO-017-1, R3 and TPL-001-4, R8 which obligate Planning Coordinators and Transmission Planners to provide  Planning Assessments to impacted Reliability Coordinators and adjacent Planning Coordinators and Transmission Planners, respectively. The MRO NSRF requests the SDT update an existing requirement rather than introduce a new requirement so that this type of information is consolidated in a single location. That said, the MRO NSRF recognizes that the information referenced in FAC-014, R7 is not explicitly required under either of the aforementioned standards and the option to reopen TPL has been discussed at length by the SDT. As a decision has been made not to reopen TPL-001 at this time, the MRO NSRF requests TPL-001, R8 be expanded to include Transmission Operators and Reliability Coordinators when it is next reopened for modifications and FAC-014-3, R7 be retired at that time.

 

FAC-011-4, Part 6.4

Finally, the MRO NSRF requests the SDT confirm in a response to comments or in a Technical Rationale document that FAC-011-4, Part 6.4, “planned manual load shedding is acceptable only after all other available System adjustments have been made,” only applies to addressing overloads that are observed in a planning or forecasted timeframe and is not intended to address actual overloads in Real-time on the system. This observation is made based on the Time Horizon for R6; i.e. ‘Operations Planning,’ and the descriptor of “planned“ manual load shedding.

 

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

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Alliant Energy supports the comments filed by the MRO NERC Standards Review Forum (NSRF) for this question.

Larry Heckert, Alliant Energy Corporation Services, Inc., 4, 12/7/2020

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N/A

Jennifer Bray, Arizona Electric Power Cooperative, Inc., 1, 12/7/2020

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

Jamie Johnson, California ISO, 2, 12/7/2020

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Sandra Ellis, On Behalf of: Pacific Gas and Electric Company, WECC, Segments 3

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Please see comments submitted by the Edison Electric Institute.

Neil Shockey, 12/7/2020

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MISO supports comments submitted by the ISO/RTO Council Standards Review Committee (IRC SRC) and MRO NERC Standards Review Forum (MRO NSRF).

Bobbi Welch, Midcontinent ISO, Inc., 2, 12/7/2020

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Please see comments submitted by the Edison Electric Institute.

Kenya Streeter, Edison International - Southern California Edison Company, 6, 12/7/2020

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N/A - Entergy supports MISO's comments.

Oliver Burke, Entergy - Entergy Services, Inc., 1, 12/7/2020

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NIPSCO endorses the other comments on R6, R7, and R8 provided by AEP on 11/24/2020. And reiterates our prior NIPSCO comments provided 7/31/2020.

Steven Taddeucci, NiSource - Northern Indiana Public Service Co., 3, 12/7/2020

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James Baldwin, Lower Colorado River Authority, 1, 12/7/2020

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Texas RE has the following comments, noted by section.

 

Implementation Plan – Effective Date sectionn

  • There is a missing delimiter (“) around System Operating Limit (shows “System Voltage Limit” and System Operating Limit” but should be “System Voltage Limit” and “System Operating Limit”).

 

Implementation Plan - Prior Implementation Plans section:

  • PRC-005-3 is referenced and it seems that it should reference PRC-005-6.
  • Texas RE recommends noting that there have been changes to the language of FAC-003-5 to include the TP as an entity that can designate a line and also uses the language “identified the line in Applicability under 4.2” instead of “designates the line as being an element of an IROL”.  Texas RE agrees this change should not significantly modify the application of the implementation plan.
  • For FAC-003-5 “Newly Designated Lines” - There seems to be some ambiguity about what happens to the lines newly designated under FAC-003-4 Applicability Section 4.2 language in the last year of applicability for FAC-003-4.  Do those lines receive an additional year of non-applicability because the new version of the Standard is being applied?
  • For PRC-002-3, “TO” and “RC” should be spelled out to be consistent.

 

Implementation Plan - Additional Provisions section:

  • For FAC-014-3 Requirement R6, Texas RE recommends a clear date by which the Planning Assessment must reflect the implementation of Requirement R6 (e.g 24 calendar months after effective date).  The language “when it begins its next cycle for conducting the studies to support its Planning Assessment” for R6 is not measureable and may lead to inconsistent understanding and application.

 

Additional FAC-014-3 Comments:

  • Texas RE noticed the SDT added the word “critical” in in FAC-014-3  5.2.4.  Texas RE is concerned that since there is no criteria or definition of the word critical,  inconsistencies could arise between entities regarding the meaning of “critical” which, in turn, could lead to perceived inconsistencies in monitoring.  Texas RE recommends drafting clear criteria to determine “critical” to ensure reliability.  While it was added to accommodate the 5.6 language addition there is no clear meaning of the word or intent.  When reviewed in audit space there will be a need to understand what “critical” means to an entity and how they derived, and applied, the thought process.
  • In Requirement R6, there should be a hyphen in “Near Term”.  This is consistent with the NERC Glossary Term.

 

Texas RE continues to be concerned with the following:

  • The asterisk on FAC-003 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.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 12/7/2020

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Teresa Krabe, Lower Colorado River Authority, 5, 12/7/2020

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For Requirements R5 and R8, Reclamation recommends that the SDT consider adding an annual notice to the TOs and GOs that do not own impacted Facilities. This would increase transparency and provide direct evidence of the lack of impact. 

Richard Jackson, U.S. Bureau of Reclamation, 1, 12/7/2020

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Southern Company disagrees with the revision to R4. The revision creates unnecessary confusion compared to the original language, seeming to imply that each Reliability Coordinator shall establish stability limits only after an instability event that impacts adjacent Reliability Coordinator Areas has occurred. As such, if the revision is to remain, the following revision is suggested to clarify that this is a proactive coordination, not reactive:

              Revise from “an instability” to “an identified instability”.

Southern Company disagrees with Requirement R5.2.2, as the modifications to the requirement create unnecessary ambiguity. Specifically, Southern Company disagrees with the inclusion of the word “derivation” in R5.2.2 as there can be a significant number of Facilities across the Interconnections needed to accurately model and simulate a stability event and therefore are critical to the “derivation” of a stability limit. It is suggested instead that “derivation” be defined or replaced with “establishment” to better clarify those Facilities that should be identified.

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.

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:”.
  • Add another sentence at the end of R8, as also suggested in Comment Form Question 2 above:  “Planning Coordinators and Transmission Planners that do not identify any Facilities are not required to perform the annual communication”.

Southern Company, Segment(s) 1, 6, 3, 5, 9/1/2016

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

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Exelon concurs with the comments submitted by the Edison Electric Insititue (EEI). 

Submitted on behalf of Exelon: Segments 1, 3, 5, 6

Daniel Gacek, Exelon, 1, 12/7/2020

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Tammy Porter, On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; Lee Maurer, Oncor Electric Delivery, 1

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thank you

sean erickson, Western Area Power Administration, 1, 12/7/2020

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Please consider if revisions to section “C. Compliance” are necessary to update FAC-014-3 with the current NERC wording for the Compliance section. For example, “Compliance Enforcement Authority” could be abbreviated as CEA in the Compliance section.

RE: Violation Severity Levels, R1, Severe VSL: Please consider removing, “as established in FAC-011-4” since this reference appears to be unnecessary.

RE: Technical Rationale for Reliability Standard FAC-014-3, Rationale R5, part 5.6: Please consider correcting the reference to 4.1.1.4 in CIP-014 to read as 4.1.1.3 in CIP-014.

Requirement 6

The provided rationale document for Requirement 6 states, “The intent of Requirement 6 is not to change, limit, or modify Facility Ratings determined by the equipment owner per FAC-008, nor to allow the PCs or TPs to revise those limits.  The intent is to utilize those owner-provided Facility Ratings such that the System is planned to support the reliable operation of that System.”  The rationale document also states (following on from the earlier quote), “This is accomplished by requiring the PC and TP to use the owner-provided Facility Ratings that are equally limiting or more limiting than those established in accordance with the RC’s SOL methodology.”  In consideration of the RC SOL methodology to be provided per the draft FAC-001-4, Requirement 2 states, “each Reliability Coordinator shall include in its SOL methodology the method for Transmission Operators to determine which owner-provided Facility Ratings are to be used in operations such that the Transmission Operator and its Reliability Coordinator use common Facility Ratings.” 

 

NPCC RSC believes that several standards (such as FAC-008 and MOD-032) place the obligations of determining Facility Ratings on the GO and/or TO.  Additionally, from a Planning study perspective, TPL-001-4 Requirement 1 obligates PCs and TPs as part of their Planning Assessment of the Near Term Transmission Planning Horizon to use data consistent with what is provided in accordance with MOD-032. 

 

In its reply to the previous comments from the SRC IRC, the Standard Drafting Team (SDT) states that they understand the perception of redundancy of this requirement as compared to other NERC Standards, but industry and regulatory comments/inputs moved the SDT down the current path of including Facility Ratings as part of R6.  Further, the SDT recognizes the facility owner's responsibility in providing Facility Ratings per FAC-008 and that this does not conflict with what is proposed in FAC-014.  NPCC RSC recommends that by including the Facility Ratings requirement in other standards (such as MOD-032), increased benefit is seen across additional standards and not just the Planning Assessment of Near-Term Transmission Planning Horizon. 

 

NPCC RSC also recommends the following additional changes to the language in the requirement:

 

{C}·       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”.  We recommend that consistent terminology be used across these standards.

{C}·       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”.  We recommend that consistent terminology be used across these standards.

Finally, NPCC RSC recommends that the following change be made to R6 to clarify the intent of the requirement:

 

Each Planning Coordinator and each Transmission Planner shall implement a documented process to use Facility Ratings, System 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 criteria for use of Facility Ratings, System Voltage Limits and stability criteria described in its respective Reliability Coordinator’s SOL methodology.

NPCC Regional Standards Committee, Segment(s) 10, 2, 4, 7, 3, 1, 5, 6, 9/21/2020

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FAC-014-3 Comments

Requirement 6

The provided rationale document for Requirement 6 states, “The intent of Requirement 6 is not to change, limit, or modify Facility Ratings determined by the equipment owner per FAC-008, nor to allow the PCs or TPs to revise those limits.  The intent is to utilize those owner-provided Facility Ratings such that the System is planned to support the reliable operation of that System.”  The rationale document also states (following on from the earlier quote), “This is accomplished by requiring the PC and TP to use the owner-provided Facility Ratings that are equally limiting or more limiting than those established in accordance with the RC’s SOL methodology.”  In consideration of the RC SOL methodology to be provided per the draft FAC-001-4, Requirement 2 states, “each Reliability Coordinator shall include in its SOL methodology the method for Transmission Operators to determine which owner-provided Facility Ratings are to be used in operations such that the Transmission Operator and its Reliability Coordinator use common Facility Ratings.” 

The IRC SRC agrees with previously provided comments from the IRC SRC that several standards (such as FAC-008 and MOD-032) place the obligations of determining Facility Ratings on GOs and TOs.  Additionally, from a Planning study perspective TPL-001-4 Requirement 1 obligates PCs and TPs as part of their Planning Assessment of the Near Term Transmission Planning Horizon to use data consistent with what is provided in accordance with MOD-032. 

In its reply to comments submitted by the IRC SRC, the Standard Drafting Team (SDT) states that they understand the perception of redundancy of this requirement as compared to other NERC Standards, but industry and regulatory comments/inputs moved the SDT down the current path of including Facility Ratings as part of R6.  Further, the SDT recognizes the facility owner’s responsibility in providing Facility Ratings per FAC-008 and that this does not conflict with what is proposed in FAC-014.  The IRC SRC recommends that by including the Facility Ratings requirement in other standards (such as MOD-032), increased benefit is seen across additional standards and not just the Planning Assessment of Near-Term Transmission Planning Horizon. 

The IRC SRC also recommends 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.

Finally, the IRC SRC recommends 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 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 use of Facility Ratings, System Voltage Limits and stability criteria described in its respective Reliability Coordinator’s SOL methodology.

 

Requirement 7

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.  The IRC SRC recommended IRO-017-1, R3 be updated so that this type of request is located in a single requirement or standard.  The SDT response to this request is that the IRO-17 standard deals with outage coordination (and not SOLs) that FAC-014 is the proper place for SOL transmittal and related information between entities.  Additionally, the SDT acknowledges that they discussed at length the annual planning assessment created per TPL-001, and noted that the information described in FAC-014-3, R7 is not necessarily included explicitly in annual planning assessments, but is of great use to operating entities seeking to monitor and mitigate any potential instability.  The IRC SRC disagrees as the information required in FAC-014 R7 is included in TPL-001 assessments.  Requirement 2.7 of TPL-001 requires that the assessment identify the Corrective Action Plan for instances where the analysis indicates the inability to meet the performance requirements.  Obligating the Planning Coordinator and Transmission Planner to only communicate Corrective Action Plans for instability issues falls short of information that would be important for Transmission Operators and Reliability Coordinators.  As such, updated TPL-001 to provide the report in its entity to Transmission Operators and Reliability Coordinators provides a more holistic view of all Corrective Action Plans that may be forthcoming to the system.  As such, the IRC SRC recommends that TPL-001 R8 be modified to specifically include Transmission Operators and Reliability Coordinators.

FAC-011-4

Finally, the IRC SRC would like the drafting team to confirm in a response to comments or the technical rational document that FAC-011-4, Part 6.4 only applies to addressing overloads that are observed in a planning or forecasted timeframe and Part 6.4 would not restrict the RC from taking actions in Real-time if the planned mitigating actions are ineffective or insufficient to address an impending IROL exceedance. This observation is made based on the reference to time horizon being identified as ‘Operations Planning’ and the use of planned manual load shedding

ISO/RTO Standards Review Committee, Segment(s) 2, 12/7/2020

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Quintin Lee, Eversource Energy, 1, 12/7/2020

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N/A

SPP RTO, Segment(s) 2, 12/7/2020

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

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Evergy incorporates by reference and supports the comments of Edison Electric Institute (EEI) in response to Question 3. 

Douglas Webb, On Behalf of: Evergy, MRO, Segments 1, 3, 5, 6

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Ameren agrees with and supports EEI commnets

David Jendras, Ameren - Ameren Services, 3, 12/7/2020

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Karen Weaver, Tallahassee Electric (City of Tallahassee, FL), 5, 12/7/2020

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Scott Langston, Tallahassee Electric (City of Tallahassee, FL), 1, 12/7/2020

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NV Energy supports MRO NSRF's additional comments: 

FAC-014-3, Requirement R6

The provided rationale document for Requirement 6 states, “The intent of Requirement 6 is not to change, limit, or modify Facility Ratings determined by the equipment owner per FAC-008, nor to allow the PCs or TPs to revise those limits.  The intent is to utilize those owner-provided Facility Ratings such that the System is planned to support the reliable operation of that System.”  The rationale document also states (following on from the earlier quote), “This is accomplished by requiring the PC and TP to use the owner-provided Facility Ratings that are equally limiting or more limiting than those established in accordance with the RC’s SOL methodology.” 

From a Planning study perspective, TPL-001-4, Requirement 1, obligates PCs and TPs as part of their Planning Assessment of the Near Term Transmission Planning Horizon to use data consistent with what is provided in accordance with MOD-032. 

The MRO NSRF also recommends 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 MRO NSRF 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 MRO NSRF recommends that consistent terminology be used across these standards.

Finally, the MRO NSRF recommends that the following change be made to R6 to clarify the intent of the requirement:

Each Planning Coordinator and each Transmission Planner shall implement a documented process to use Facility Ratings, System 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 use of Facility Ratings, System Voltage Limits and stability criteria described in its respective Reliability Coordinator’s SOL methodology.

 

 

FAC-014-3, Requirement 7

As proposed FAC-014-3, R7 is partially duplicative of existing requirements under IRO-017-1, R3 and TPL-001-4, R8 which obligate Planning Coordinators and Transmission Planners to provide  Planning Assessments to impacted Reliability Coordinators and adjacent Planning Coordinators and Transmission Planners, respectively. The MRO NSRF requests the SDT update an existing requirement rather than introduce a new requirement so that this type of information is consolidated in a single location. That said, the MRO NSRF recognizes that the information referenced in FAC-014, R7 is not explicitly required under either of the aforementioned standards and the option to reopen TPL has been discussed at length by the SDT. As a decision has been made not to reopen TPL-001 at this time, the MRO NSRF requests TPL-001, R8 be expanded to include Transmission Operators and Reliability Coordinators when it is next reopened for modifications and FAC-014-3, R7 be retired at that time.

 

FAC-011-4, Part 6.4

Finally, the MRO NSRF requests the SDT confirm in a response to comments or in a Technical Rationale document that FAC-011-4, Part 6.4, “planned manual load shedding is acceptable only after all other available System adjustments have been made,” only applies to addressing overloads that are observed in a planning or forecasted timeframe and is not intended to address actual overloads in Real-time on the system. This observation is made based on the Time Horizon for R6; i.e. ‘Operations Planning,’ and the descriptor of “planned“ manual load shedding

Kevin Salsbury, Berkshire Hathaway - NV Energy, 5, 12/7/2020

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Please see comments submitted by the Edison Electric Institute

Jose Avendano Mora, Edison International - Southern California Edison Company, 1, 12/7/2020

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None and thank you for the opportunity to comment.

ACES Standard Collaborations, Segment(s) 1, 3, 4, 5, 12/7/2020

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EEI suggests modifying the term “an instability”, as contained in Requirement R4, to “an identified instability”.  This proposed change makes Requirement R4 clear that the intent is for the RC to act on identified instability, not after an instability event has occurred.

EEI requests the SDT clarify the addition 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.  For EEI to support this change, the term “critical Contingency(ies)” need to be clarified or removed.

Alternatively, the SDT could consider revising the supporting subparts of 5.2 (Requirement R5), as indicated below, as a possible solution to the use of the undefined term “critical Contingency(ies)”.

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).

 

EEI disagrees with the inclusion of “as established in FAC-011-4” within the Severe VSL level within FAC-014-3, Requirement R1.  Since requirements can be moved out of one Reliability Standard to another, modified, or retired, this creates a burden to ensure all references are identified when modifications are made.  Each Reliability Standard should stand on its own and should not contain linkage to other Reliability Standards. 

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

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OPG support NPCC Regional Standards Committee’s comments.

Constantin Chitescu, Ontario Power Generation Inc., 5, 12/7/2020

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No comments

Ed Hanson, Pacific Gas and Electric Company, 5, 12/7/2020

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