2020-06 Verifications of Models and Data for Generators | Draft 1

Description:

Start Date: 05/24/2022
End Date: 07/06/2022

Associated Ballots:

Ballot Name Project Standard Pool Open Pool Close Voting Start Voting End
2020-06 Verifications of Models and Data for Generators MOD-026-2 IN 1 ST 2020-06 Verifications of Models and Data for Generators MOD-026-2 05/23/2022 06/21/2022 06/27/2022 07/06/2022
2020-06 Verifications of Models and Data for Generators Implementation Plan IN 1 OT 2020-06 Verifications of Models and Data for Generators Implementation Plan 05/23/2022 06/21/2022 06/27/2022 07/06/2022

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Hot Answers

FirstEnergy supports EEI's comments :

EEI supports the concept of consolidating the requirements of MOD-026-1 with MOD-027-1, however, the language used within the Applicability section of proposed MOD-026-2 raises questions regarding what constitutes an individual generating unit under Inclusion I2 and what constitutes a dispersed power producing resource under Inclusion I4.  As more hybrid resources are installed (i.e., synchronous generators with battery storage) and collocated at existing synchronous plant sites, it is unclear how these resources are to be modeled and what modeling requirements need to be imposed.  

For this reason, the SDT should more clearly define how hybrid and collocated synchronous generator and IBR resources are to be model.

FE Voter, Segment(s) 1, 3, 5, 6, 4, 12/20/2021

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Anna Todd, On Behalf of: Southern Indiana Gas and Electric Co., RF, Segments 3, 5, 6

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Other Answers

Jack Stamper, Clark Public Utilities, 3, 6/16/2022

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EEI supports the concept of consolidating the requirements of MOD-026-1 with MOD-027-1, however, the language used within the Applicability section of proposed MOD-026-2 raises questions regarding what constitutes an individual generating unit under Inclusion I2 and what constitutes a dispersed power producing resource under Inclusion I4.  As more hybrid resources are installed (i.e., synchronous generators with battery storage) and collocated at existing synchronous plant sites, it is unclear how these resources are to be modeled and what modeling requirements need to be imposed.  

For this reason, the SDT should more clearly define how hybrid and collocated synchronous generator and IBR resources are to be model.

Glen Farmer, Avista - Avista Corporation, 5, 6/28/2022

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No Comments

Brian Lindsey, Entergy, 1, 6/28/2022

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Richard Jackson, U.S. Bureau of Reclamation, 1, 6/29/2022

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Martin Sidor, NRG - NRG Energy, Inc., 6, 6/29/2022

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Nazra Gladu, Manitoba Hydro , 1, 6/29/2022

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Patricia Lynch, NRG - NRG Energy, Inc., 5, 6/29/2022

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Although process and requirement language have basic commonalities across the two standards, MOD26-1 covers generator excitation system testing and modeling and MOD27-1 covers Turbine speed governor control system testing and modeling.  These systems are unique to each system’s function, testing is wholely unique to each system, and models are wholely unique to each system.   Testing may be staged serparately, might be performed by different testing entities and model verification is evaluated for compliance for each on a serparte basis.   There is practical clarity retaining separate MOD26 and MOD27 standards as is.  

Joe O'Brien, NiSource - Northern Indiana Public Service Co., 6, 6/29/2022

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

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Nicolas Turcotte, Hydro-Qu?bec TransEnergie, 1, 6/30/2022

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This approach works well for inverter-based resources but not synchronous machines.  If different systems are modified separately, the validation process becomes convoluted.  This approach will also add a significant cost to GOs that already have detailed work orders, program documents, and procedures in place to assist in compliance with the existing standards.  Previous NERC audits drove GOs to have these documents in place.

Options:

  1. Modify R7 to specify that R2, R3, R4, R5, and R6 can be complied with and submitted separately to ensure there is no confusion between GOs and TPs.  This action will also assist with the conduct of audits.
  2. Create separate standard for inverter based resources.

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

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Isidoro Behar, On Behalf of: Long Island Power Authority, , Segments 1

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AECI supports EEI's comments :

EEI supports the concept of consolidating the requirements of MOD-026-1 with MOD-027-1, however, the language used within the Applicability section of proposed MOD-026-2 raises questions regarding what constitutes an individual generating unit under Inclusion I2 and what constitutes a dispersed power producing resource under Inclusion I4.  As more hybrid resources are installed (i.e., synchronous generators with battery storage) and collocated at existing synchronous plant sites, it is unclear how these resources are to be modeled and what modeling requirements need to be imposed.  

For this reason, the SDT should more clearly define how hybrid and collocated synchronous generator and IBR resources are to be model.

AECI, Segment(s) 1, 3, 6, 5, 3/4/2021

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Sean Steffensen, IDACORP - Idaho Power Company, 1, 6/30/2022

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Michelle Amarantos, APS - Arizona Public Service Co., 5, 6/30/2022

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Constellation agrees with this approach, however requests the consideration to allow excitation and governor modeling to be done separately and not in conjunction, as completing modelings together at the next interval cycle would short cycle models completed under the original implementation plan. As models were planned and executed separately throughout the periodic implementation.

 

Kimberly Turco on behalf of Constellation Segments 5 and 6

Alison Mackellar, Constellation, 5, 6/30/2022

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Constellation agrees with this approach, however requests the consideration to allow excitation and governor modeling to be done separately and not in conjunction, as completing modelings together at the next interval cycle would short cycle models completed under the original implementation plan. As models were planned and executed separately throughout the periodic implementation.

 

Kimberly Turco on behalf of Constellation Segments 5 and 6

Kimberly Turco, Constellation, 6, 6/30/2022

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ATC sees efficiency and potential benefit in combining the two standards.  Having to only reference one complete set of similar requirements could be easier for reference than using two separate standards.  

LaTroy Brumfield, American Transmission Company, LLC, 1, 7/1/2022

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The concept of consolidating the requirements of MOD-026-1 with MOD-027-1 is supported, however, the language used within the Applicability section of proposed MOD-026-2 raises questions regarding what constitutes an individual generating unit under Inclusion I2 and what constitutes a dispersed power producing resource under Inclusion I4.  As more hybrid resources are installed (i.e., synchronous generators with battery storage) and collocated at existing synchronous plant sites, it is unclear how these resources are to be modeled and what modeling requirements need to be imposed.  

For this reason, the SDT should more clearly define how hybrid and collocated synchronous generator and IBR resources are to be model.

Mike Magruder, Avista - Avista Corporation, 1, 7/1/2022

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EEI supports the concept of consolidating the requirements of MOD-026-1 with MOD-027-1, however, the language used within the Applicability section of proposed MOD-026-2 raises questions regarding what constitutes an individual generating unit under Inclusion I2 and what constitutes a dispersed power producing resource under Inclusion I4.  As more hybrid resources are installed (i.e., synchronous generators with battery storage) and collocated at existing synchronous plant sites, it is unclear how these resources are to be modeled and what modeling requirements need to be imposed.   

For this reason, the SDT should more clearly define how hybrid and collocated synchronous generator and IBR resources are to be model.

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

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Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) to question #1.

Alan Kloster, On Behalf of: Allen Klassen, Evergy, 1,3,5,6; Allen Klassen, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Derek Brown, Evergy, 1,3,5,6; Derek Brown, Evergy, 1,3,5,6

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

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N/A

Eric Sutlief, On Behalf of: CMS Energy - Consumers Energy Company - RF - Segments 3, 4, 5

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Leonard Kula, Independent Electricity System Operator, 2, 7/5/2022

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Xcel Energy generally supports the comments of EEI. Below are Xcel Energy comments that indicate additional or differing concerns.

Xcel Energy disagrees with including excitation modeling (R2) and governor modeling (R3) within the same standard.  A modification to "governor" shall not require a revision to the excitation model, and vice-versa.  MOD-026-2 submittal shall allow for only submitting modeling for applicable equipment that is modified.  Although they have similar reporting requirements, there are no commonalities between an excitation system and a turbine-governor system in a synchronous generating facility.  Even further, it will be more confusing to include both synchronous, non-synchronous, and IBR generating facilities in the same standard.  It makes more sense to have non-synchronous and IBR resources covered under a separate standard since those resources are not at all similar to synchronous generation.

Joe Gatten, On Behalf of: Xcel Energy, Inc. - MRO, WECC - Segments 1, 3, 5, 6

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Scott Kinney, Avista - Avista Corporation, 3, 7/5/2022

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Karl Blaszkowski, CMS Energy - Consumers Energy Company, 3, 7/5/2022

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WECC Entity Monitoring, Segment(s) 10, 1/30/2022

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Portland General Electric Company supports the comments provided by EEI.

Portland General Electric Co., Segment(s) 1, 3, 5, 6, 7/5/2022

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Dwanique Spiller, Berkshire Hathaway - NV Energy, 5, 7/5/2022

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AEP has no objections to the concept of combining MOD-026-1 and MOD-027-1 into a single standard, provided that the resulting obligations themselves are sound.

Thomas Foltz, AEP, 5, 7/5/2022

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Texas RE appreciates the SDT’s efforts to make the standard more efficient and more clear.  Texas RE agrees with the approach to combine MOD-026 and MOD-027.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 7/5/2022

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It would seem more logical to provide a new MOD standard rather than version 2 of MOD-026-1. We believe that it may be best to retire both standards, as to minimize any confusion of what was, continue to be, and the new requirements. Better off creating a whole new standard.

Israel Perez, On Behalf of: Pam Syrjala, Salt River Project, 1,3,5,6; Pam Syrjala, Salt River Project, 1,3,5,6; Zack Heim, Salt River Project, 1,3,5,6; Zack Heim, Salt River Project, 1,3,5,6

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Greg Davis, Georgia Transmission Corporation, 1, 7/5/2022

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 The language in the standard shall make it clear that model verification does not have to occur at the same time for different components.

Christine Kane, WEC Energy Group, Inc., 3, 7/5/2022

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BPA supports combining the standards in general, just not as currently proposed. This proposed consolidation greatly exceeds the scope of what is currently within MOD-026-1 and MOD-027-1. BPA does not believe the scope increase is appropriate. 

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

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Currently Black Hills Corporation supports additional information that EEI has stated in their comments. In addition to Transmission Planner, Planning Coordinator needs to be added to the language.

Claudine Bates, Black Hills Corporation, 6, 7/5/2022

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National Grid supports EEI's comments.

Michael Jones, National Grid USA, 1, 7/5/2022

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Hot Answers

FE agrees with EEI’s comments.

The language contained in Requirement R1, subpart 1.2 appears to require electromagnetic transient (EMT) models for all dynamic model requirements and processes regardless of resource type or study need.  While the Technical Rationale states that R6 limits this requirement, there is no language within MOD-026-2 that clearly states when these models are required.  Additionally, the Planning Coordinator should be included in subparts 1.3, 1.4 and 1.6.

Next, the language in R1, subpart 1.3.1 that includes model parameterization checks is unclear and could negatively impact entities that do not have the tools or experience to conduct such checks.  To address this concern, the SDT should provide add clarifying language to the Technical Rationale to address how such checks are to be performed in light of software limitations and entity inexperience in this area.

To address this concern with Requirement R1, we recommend the following edits:

R1. Each Planning Coordinator, in conjunction with its Transmission Planner, shall jointly develop dynamic model requirements and processes. The dynamic model requirements and processes shall be made available to the Generator Owner and Transmission Owner by the Planning Coordinator, and include at a minimum the following: [Violation Risk Factor: Lower] [Time Horizon: Operations Planning]

1.1. Acceptable positive sequence dynamic models, format, and level of detail, as specified in Requirements R2 and R4;

1.2. Acceptable electromagnetic transient (EMT) models, format, and level of detail, where determined to be necessary by the TP and as defined in Requirement R6;

1.3. Acceptance criteria used by the Transmission Planner and/or Planning Coordinator to determine disposition in Requirement R8 including at a minimum the following:

1.3.1. model parameterization checks;

1.3.2. model usability, initialization, and interoperability; and

1.3.3. model submittal requirements.

1.4. Process for Generator Owner or Transmission Owner to provide verified models to the Transmission Planner and/or Planning Coordinator;

1.5. Process by which verified model(s) are submitted to the applicable Planning Coordinator, after the model(s) meets acceptance criteria of Part 1.3; and

1.6. Process for Generator Owner or Transmission Owner to obtain the model(s) contained in the Transmission Planner’s and/or Planning Coordinator’s database for an existing Facility owned by the Generator Owner or Transmission Owner.     

FE Voter, Segment(s) 1, 3, 5, 6, 4, 12/20/2021

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As a Generator Owner and Transmission Owner we will continue to provide requested model data, but at this time there are no NERC approved EMT models with limited software/expertise.

Anna Todd, On Behalf of: Southern Indiana Gas and Electric Co., RF, Segments 3, 5, 6

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Other Answers

R1.2 should be changed to: Acceptable electromagnetic transient (EMT) models, format, and level of detail if the Transmission Planner area has applicable units of inverter based resources (IBRs) per Section 4.2.3, FACTS devices per Section 4.2.4.2, LCC HVDC per Section 4.2.5.1, and VSC HVDC per 4.2.5.2.

Many Transmission Planners do not have any applicable units that are subject to Requirement 6 so there is no need for these Transmission Planners to have acceptable EMT models. Otherwise, Transmission Planners will need to argue during audits that there is no need for these provisions in their modeling requirements. However, the current language requires that Transmission Planners have EMT modeling requirements even if the modeling requirements will not be utilized.

Jack Stamper, Clark Public Utilities, 3, 6/16/2022

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The language contained in Requirement R1, subpart 1.2 appears to require electromagnetic transient (EMT) models for all  dynamic model requirements and processes regardless of resource type or study need.  While the Technical Rationale states that R6 limits this requirement, there is no language within MOD-026-2 that clearly states when these models are required.  Additionally, the Planning Coordinator should be included in subparts 1.3, 1.4 and 1.6.

Next, the language in R1, subpart 1.3.1 that includes model parameterization checks is unclear and could negatively impact entities that do not have the tools or experience to conduct such checks.  To address this concern, the SDT should provide add clarifying language to the Technical Rationale to address how such checks are to be performed in light of software limitations and entity inexperience in this area.

To address this concern with Requirement R1, we recommend the following edits:

R1. Each Transmission Planner and its Planning Authority Coordinator, in conjunction with its Transmission Planner, shall jointly develop dynamic model requirements and processes. The dynamic model requirements and processes shall be made available to the Generator Owner and Transmission Owner by the Transmission PlannerPlanning Coordinator, and include at a minimum the following: [Violation Risk Factor: Lower] [Time Horizon: Operations Planning]

1.1. Acceptable positive sequence dynamic models, format, and level of detail, as specified in Requirements R2 and R4;

1.2. Acceptable electromagnetic transient (EMT) models, format, and level of detail, where determined to be necessary by the TP and as defined in Requirement R6;

1.3. Acceptance criteria used by the Transmission Planner and/or Planning Coordinator to determine disposition in Requirement R8 including at a minimum the following:

1.3.1. model parameterization checks;

1.3.2. model usability, initialization, and interoperability; and

1.3.3. model submittal requirements.

1.4. Process for Generator Owner or Transmission Owner to provide verified models to the Transmission Planner and/or Planning Coordinator;

1.5. Process by which verified model(s) are submitted to the applicable Planning AuthorityCoordinator, after the model(s) meets acceptance criteria of Part 1.3; and

1.6. Process for Generator Owner or Transmission Owner to obtain the model(s) contained   in the Transmission Planner’s and/or Planning Coordinator’s database for an existing Facility owned by the Generator Owner or Transmission Owner.

 

Glen Farmer, Avista - Avista Corporation, 5, 6/28/2022

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No Comments

Brian Lindsey, Entergy, 1, 6/28/2022

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Richard Jackson, U.S. Bureau of Reclamation, 1, 6/29/2022

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Each TP is allowed to establish and dictate their own methods, requirements, processes, and acceptance criteria without constraints, boundaries, or need of consistency with other industry participants.  The allowance of arbitrary requisites implies the requirement has no technical basis or justification.  This results in Generator Owners, especially those in multiple TP areas, providing various types of data in different formats based upon TP preferences only, with no basis of demonstrated reliability improvement.

R1.2, and other relevant sections, allows the TP to mandate EMT models without sufficiently demonstrating that EMT models are needed in addition to positive sequence models.

Martin Sidor, NRG - NRG Energy, Inc., 6, 6/29/2022

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Manitoba Hydro agrees that the positive sequence dynamic and electromagnetic transient (EMT) models minimum requirements and development of models’ validation and other processes should be developed by the Planning Authority and Transmission Planner. However, we think that the required models level of detail should be within the simulation tool's modeling capabilities to avoid the need for developing user's defined models (which may add a lot of complexity and overhead to developing these models with some level of approximation which makes it more difficult to share with other PA and more difficult to maintained and validated). Also, the model's level of details should be within the reasonably industrial practice as some of the levels of detail may not be possible to present due to the vender's trade secret. The focus should be on the model validation criteria from the field results with a clear list of acceptable test types or system disturbances.

Nazra Gladu, Manitoba Hydro , 1, 6/29/2022

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Each TP is allowed to establish and dictate their own methods, requirements, processes, and acceptance criteria without constraints, boundaries, or need of consistency with other industry participants.  The allowance of arbitrary requisites implies the requirement has no technical basis or justification.  This results in Generator Owners, especially those in multiple TP areas, provide various types of data in different formats based upon TP preferences only, with no basis of demonstrated reliability improvement. R1.2, and other relevant sections, allows the TP to mandate EMT models without sufficiently demonstrating that EMT models are needed in addition to positive sequence models.

Patricia Lynch, NRG - NRG Energy, Inc., 5, 6/29/2022

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: R1 1.3 States the acceptance criteria used by Transmission Planner for only updated models. It does not state the requirement for new models.

Joe O'Brien, NiSource - Northern Indiana Public Service Co., 6, 6/29/2022

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

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Requirement R1 instructs the TP to maintain a requirement document that states the accepted models and the level of detail needed. This requirement is largely covered by MOD-032, R1 and is therefore partially redundant.

Nicolas Turcotte, Hydro-Qu?bec TransEnergie, 1, 6/30/2022

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R1 1.2  EMT models are not used by most Transmission Planners.  This addition will add significant cost to generation owners.  The EMT models should only be provided based on appropriate justification and on a case-by-case basis.  The financial impacts to generator operators to provide these models for every applicable facility is not justified.  Positive sequence generic models if properly populated and verified are adequate for most transmission studies.  The transmission software tools to study the entire system with EMT models do not exist.

Requirements should be detailed in this standard.  Utilities that operate in multiple regions will be required to submit different levels of detail to comply with this Standard.  The wording in R1.1, R1.2, and R1.3 gives the TP authority to request data above the needed intent of the Standard (Performance Curves, Response Characteristics, Response Times etc.).

The specific acceptance criteria for the model in R1.1, 1.2, and 1.3 should be developed by the industry modeling experts or remain the same as existing MOD-026 and 027 standards.

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

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Requirement R1 would require the TP to maintain model requirement documentation that outlines the accepted models and the level of detail needed. A concern is that parts of Requirement 1 (such as 1.1 and 1.2) are largely covered by MOD-032, R1 and are therefore partially redundant.

Isidoro Behar, On Behalf of: Long Island Power Authority, , Segments 1

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AECI agrees with EEI’s comments:

The obligations related to Requirement R2, subpart 2.3 as it relates to GO and TO modifications to protection systems synchronous generation identified in Section 4.2.1 or 4.2.2 or a synchronous condenser identified in Section 4.2.4.1 should be clarified.  Specifically, the SDT should clarify the timeframe that will be required to complete and submit updated models to the TP after protection system changes. 

EEI requests similar clarifications regarding GO and TO obligations as it relates to Requirement R3, subpart 3.3.

Additionally, the Planning Coordinator should be added to these requirements since they share in the development of the planning models.

AECI, Segment(s) 1, 3, 6, 5, 3/4/2021

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Sean Steffensen, IDACORP - Idaho Power Company, 1, 6/30/2022

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AZPS does not agree that EMT models should be required for the following reasons:

The EMT modeling requirement seems excessive for this application as there has not been sufficient justification of why this level of detail is required. Concerns for large-signal disturbance behavior are already being addressed by recommended practices such as PRC-024 and the NERC “BPS-Connected Inverter-Based Resource Performance Reliability Guideline.” While these do not directly address modeling, they require that the type of behavior that was witnessed during the Blue Cut fire is mitigated. Since we are currently setting protection to be broad enough to ride through these disturbances, requiring EMT models in addition to positive sequence models would add significant cost and time to model verification without creating additional reliability. 

In addition, AZPS also agrees with the following comment that has been submitted by EEI: “The language contained in Requirement R1, subpart 1.2 appears to require electromagnetic transient (EMT) models for all dynamic model requirements and processes regardless of resource type or study need. While the Technical Rationale states that R6 limits this requirement, there is no language within MOD-026-2 that clearly states when these models are required.”

AZPS does not agree with the inclusion of subpart 1.3.1.  Previous MOD 026 model criteria was intentionally vague in order to leave room for engineering judgement when conducting the model validation. No model is a facsimile of reality, and there needs to be room for creating a model that adequately reflects reality based on the judgement of the person conducting the model validation.  For this reason, AZPS requests further information regarding the intent of subpart 1.3.1. 

In addition, AZPS supports the following comment that has been submitted by EEI: “The language in R1, subpart 1.3.1 that includes model parameterization checks is unclear and could negatively impact entities that do not have the tools or experience to conduct such checks. To address this concern, the SDT should provide clarifying language to the Technical Rationale to address how such checks are to be performed in light of software limitations and entity inexperience in this area.

Michelle Amarantos, APS - Arizona Public Service Co., 5, 6/30/2022

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Constellation agrees with the proposed language.

Kimberly Turco on behalf of Constellation Segments 5 and 6

Alison Mackellar, Constellation, 5, 6/30/2022

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Constellation agrees with the proposed language.

 

Kimberly Turco on behalf of Constellation Segments 5 and 6

Kimberly Turco, Constellation, 6, 6/30/2022

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More explanation for why the Planning Authority (PA) is involved in the development of the dynamic model requirements and processes should be explained since they have no other major part of the standard (mostly applies to the TOs, GOs, and TPs).  ATC suggests that R1 should apply only to the TP so they can have wider discretion in writing their process to meet their requirements.  Perhaps the PA can coordinate and review each of their TPs processes before they are finalized, rather than jointly work on it.

LaTroy Brumfield, American Transmission Company, LLC, 1, 7/1/2022

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Comments: The language contained in Requirement R1, subpart 1.2 appears to require electromagnetic transient (EMT) models for all  dynamic model requirements and processes regardless of resource type or study need.  While the Technical Rationale states that R6 limits this requirement, there is no language within MOD-026-2 that clearly states when these models are required.  Additionally, the Planning Coordinator should be included in subparts 1.3, 1.4 and 1.6.

Next, the language in R1, subpart 1.3.1 that includes model parameterization checks is unclear and could negatively impact entities that do not have the tools or experience to conduct such checks.  To address this concern, the SDT should provide add clarifying language to the Technical Rationale to address how such checks are to be performed in light of software limitations and entity inexperience in this area.

 

To address this concern with Requirement R1, we recommend the following edits:

R1. Each Planning Coordinator, in conjunction with its Transmission Planner, shall jointly develop dynamic model requirements and processes. The dynamic model requirements and processes shall be made available to the Generator Owner and Transmission Owner by the Planning Coordinator, and include at a minimum the following: [Violation Risk Factor: Lower] [Time Horizon: Operations Planning]

1.1. Acceptable positive sequence dynamic models, format, and level of detail, as specified in Requirements R2 and R4;

1.2. Acceptable electromagnetic transient (EMT) models, format, and level of detail, where determined to be necessary by the TP and as defined in Requirement R6;

1.3. Acceptance criteria used by the Transmission Planner and/or Planning Coordinator to determine disposition in Requirement R8 including at a minimum the following:

1.3.1. model parameterization checks;

1.3.2. model usability, initialization, and interoperability; and

1.3.3. model submittal requirements.

1.4. Process for Generator Owner or Transmission Owner to provide verified models to the Transmission Planner and/or Planning Coordinator;

1.5. Process by which verified model(s) are submitted to the applicable Planning Coordinator, after the model(s) meets acceptance criteria of Part 1.3; and

1.6. Process for Generator Owner or Transmission Owner to obtain the model(s) contained   in the Transmission Planner’s and/or Planning Coordinator’s database for an existing Facility owned by the Generator Owner or Transmission Owner.

Mike Magruder, Avista - Avista Corporation, 1, 7/1/2022

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The language contained in Requirement R1, subpart 1.2 appears to require electromagnetic transient (EMT) models for all  dynamic model requirements and processes regardless of resource type or study need.  While the Technical Rationale states that R6 limits this requirement, there is no language within MOD-026-2 that clearly states when these models are required.  Additionally, the Planning Coordinator should be included in subparts 1.3, 1.4 and 1.6.

Next, the language in R1, subpart 1.3.1 that includes model parameterization checks is unclear and could negatively impact entities that do not have the tools or experience to conduct such checks.  To address this concern, the SDT should provide clarifying language to the Technical Rationale to address how such checks are to be performed in light of software limitations and entity inexperience in this area.

To address this concern with Requirement R1, we recommend the following edits:

R1. Each Planning Coordinator, in conjunction with its Transmission Planner, shall jointly develop dynamic model requirements and processes. The dynamic model requirements and processes shall be made available to the Generator Owner and Transmission Owner by the Planning Coordinator, and include at a minimum the following: [Violation Risk Factor: Lower] [Time Horizon: Operations Planning]

1.1. Acceptable positive sequence dynamic models, format, and level of detail, as specified in Requirements R2 and R4;

1.2. Acceptable electromagnetic transient (EMT) models, format, and level of detail, where determined to be necessary by the Transmission Planner and Planning Coordinator, through a formal analysis, conducted by the responsible Transmission Planner, that indicates their inability to conduct accurate simulations with preexisting Transmission Planner tools that reflect and assess BES reliability performance. (e.g., areas with IBR growth impacts or IBRs installed in areas with low short circuit strength);

1.3. Acceptance criteria used by the Transmission Planner and/or Planning Coordinator to determine disposition in Requirement R8 including at a minimum the following:

1.3.1. model parameterization checks;

1.3.2. model usability, initialization, and interoperability; and

1.3.3. model submittal requirements.

1.4. Process for Generator Owner or Transmission Owner to provide verified models to the Transmission Planner and/or Planning Coordinator;

1.5. Process by which verified model(s) are submitted to the applicable Planning Coordinator, after the model(s) meets acceptance criteria of Part 1.3; and

1.6. Process for Generator Owner or Transmission Owner to obtain the model(s) contained in the Transmission Planner’s and/or Planning Coordinator’s database for an existing Facility owned by the Generator Owner or Transmission Owner.     

 

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

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Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) to question #2.

Alan Kloster, On Behalf of: Allen Klassen, Evergy, 1,3,5,6; Allen Klassen, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Derek Brown, Evergy, 1,3,5,6; Derek Brown, Evergy, 1,3,5,6

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

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Consumers Energy is fine with this Requirement; however, it would be good to get the Generator Owners perspective on this dynamic model requirements and processes.

Eric Sutlief, On Behalf of: CMS Energy - Consumers Energy Company - RF - Segments 3, 4, 5

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Leonard Kula, Independent Electricity System Operator, 2, 7/5/2022

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Xcel Energy generally supports the comments of EEI. Below are Xcel Energy comments that indicate additional or differing concerns.

It is Xcel Energy's belief that EMT models may not always be attainable by GOs from equipment manufacturers. EMT models are not generic and are often considered confidential by manufacturers. A requirement should not be placed on TPs to place a requirement on GOs to provide information that may not be attainable from the equipment manufacturers. Furthermore, if the EMT models are to remain a requirement then the language in R1 does not make it clear that EMT models are only required for FACTS devices, IBRs, LCC HVDC, and VSC HVDC. The language of R1 appears to require EMT models for all generation.

Joe Gatten, On Behalf of: Xcel Energy, Inc. - MRO, WECC - Segments 1, 3, 5, 6

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Scott Kinney, Avista - Avista Corporation, 3, 7/5/2022

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Consumers Energy is fine with this Requirement, however it would be good to get the Generator Owners perspective on this dynamic model requirements and processes.

Karl Blaszkowski, CMS Energy - Consumers Energy Company, 3, 7/5/2022

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WECC agress with the language and purpose of the Requirement. However, WECC suggests changing Planning Authority to Planning Coordinator to align with current terminology.

WECC Entity Monitoring, Segment(s) 10, 1/30/2022

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Portland General Electric Company supports the comments provided by EEI.

Portland General Electric Co., Segment(s) 1, 3, 5, 6, 7/5/2022

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Dwanique Spiller, Berkshire Hathaway - NV Energy, 5, 7/5/2022

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AEP has no objections to the language proposed for R1.

Thomas Foltz, AEP, 5, 7/5/2022

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Texas RE agrees on the approach to revising Requirement R1.  Texas RE does, however,recommend enhancing the language of Requirement R1 to include more guidance on how the “dynamic model requirements and processes shall be made available”.

 

In Requirement Part 1.6, Texas RE recommends including the Planning Authority’s database from which the GO or TO could obtain the model for an existing Facility owned by the GO or TO.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 7/5/2022

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Israel Perez, On Behalf of: Pam Syrjala, Salt River Project, 1,3,5,6; Pam Syrjala, Salt River Project, 1,3,5,6; Zack Heim, Salt River Project, 1,3,5,6; Zack Heim, Salt River Project, 1,3,5,6

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The SDT proposal makes use of obsolete Functional Entity references to Planning Authority instead of Planning Coordinator.  This comment applies to all Planning Authority references throughout the proposed standard.

It is unclear why the Planning Authority (Coordinator) is being added to this requirement when the existing MOD-026 & 027 standards do not apply to this function.  Further, the aspect of joint development of dynamic model requirements is redundant with MOD-032.

As currently worded, the Time Horizon appears to be applicable to both Long-Term Planning (joint verification of dynamic models [see MOD-032]) and Operations Planning (the portion more consistent with currently approved MOD-027 & 027).

Greg Davis, Georgia Transmission Corporation, 1, 7/5/2022

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WEC Energy Group supports EEI and NAGF comments.

  • Need to add a sub requirement "Acceptable protective relay models, format and level of detail." 
  • Need to state EMT models are only required for inverter based resources.
  • Need to state that the acceptable models are from industry standards (i.e. IEEE 421.5 for exciters) clearly definded in generic file format (text file, spreadsheet), specifically not in a specific's software proprietry file format.                                                                                                                                                                                    

Christine Kane, WEC Energy Group, Inc., 3, 7/5/2022

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NERC MOD-026-1 and MOD-027-1 standards cover models used in BES level studies, while EMT models are used for specialized equipment studies.  BPA does not believe it is appropriate to require EMT model validation as a part of the MOD-026 and MOD-027 standards. BPA recommends a separate standard to address EMT modeling ourside of MOD-026 and MOD-027.

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

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Black Hills Corporation supports EEI and NAGF comments to R1, and as noted particularly in EEI’s comments that address concern with subpart1.3.1 to include parameterization check and the negative impact to entities. 

Claudine Bates, Black Hills Corporation, 6, 7/5/2022

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The language in Requirement R1, subpart 1.2 appears to require electromagnetic transient (EMT) models for all dynamic model requirements and processes regardless of resource type or study need.  Would the requrement to have EMT models also apply to double-fed induction generators (DFIG)?

In addition, National Grid supports EEI's comments.

Michael Jones, National Grid USA, 1, 7/5/2022

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Hot Answers

FE agrees with EEI’s comments:

The obligations related to Requirement R2, subpart 2.3 as it relates to GO and TO modifications to protection systems synchronous generation identified in Section 4.2.1 or 4.2.2 or a synchronous condenser identified in Section 4.2.4.1 should be clarified.  Specifically, the SDT should clarify the timeframe that will be required to complete and submit updated models to the TP after protection system changes. 

EEI requests similar clarifications regarding GO and TO obligations as it relates to Requirement R3, subpart 3.3.

Additionally, the Planning Coordinator should be added to these requirements since they share in the development of the planning models.

FE Voter, Segment(s) 1, 3, 5, 6, 4, 12/20/2021

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We support the subpoints in 2.1, 2.2, 2.3, 3.1, 3.2, and 3.3. However, the generators are able to provide the best available models to the Transmission Planner, but the TP would need to validate the model and provide changes back to the Generator Owner and Transmission Owner.  

Anna Todd, On Behalf of: Southern Indiana Gas and Electric Co., RF, Segments 3, 5, 6

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Other Answers

Requirements 2.3 and 3.3 are essentially a repeat of the protection system/generator limiter requirements of PRC-019. In PRC-019, GOs and TOs are required to submit this data using the traditional "D" curve which plots a generator capabilities, all generator limiters, and all generator protection system responses including loss of field and volts per hertz. There is no modeling need for any of the protection indicated. If the SDT believes that the Transmission Planner needs to know the performance characteristics of over- and under-voltage, stator and field overcurrent, loss of field, outof-step, and volts per hertz protection or any of the other protection system elements enabled for generator protection, that should be part of the protection system coordination standard, PRC-019.

The SAR indicates that voltage control behavior during large disturbance conditions is not verified. That is not so. PRC-024 requires generators to meet region-specific voltage and frequency ride through requirements and to provide the settings for it voltaage and frequecy protection to Transmission Planners. In addition, PRC-006 requires the provision of UFLS tripping data that includes generator frequecy ride through trip settings. Adding these to MOD-026 does nothing more than make Generator Owners prove compliance with multiple standards for the same action. This is not in accordance witht the efficiency goals of the NERC Standards development which included consolidation identical actions in multiple standards into a single standard to avoid unnecessary duplication of efforts.

I don't think Generator Owners would have a problem providing Transmission Planners with an entire list of all generator Protection System elements that are enabled, however, for ease of implementation, that would be better complied with and evidenced if the requirements were all under one standard.

Consider either putting R2.3 and 3.3 requirements under PRC-019 (my perferred approach) or eliminating PRC-019 and putting all generator and synchronous condenser protection system coordination and modeling under the new MOD-026.

Jack Stamper, Clark Public Utilities, 3, 6/16/2022

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The obligations related to Requirement R2, subpart 2.3 as it relates to GO and TO modifications to protection systems synchronous generation identified in Section 4.2.1 or 4.2.2 or a synchronous condenser identified in Section 4.2.4.1 should be clarified.  Specifically, the SDT should clarify the timeframe that will be required to complete and submit updated models to the TP after protection system changes.  

EEI requests similar clarifications regarding GO and TO obligations as it relates to Requirement R3, subpart 3.3.

Additionally, the Planning Coordinator should be added to these requirements since they share in the development of the planning models.

Glen Farmer, Avista - Avista Corporation, 5, 6/28/2022

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No Comments

Brian Lindsey, Entergy, 1, 6/28/2022

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The modeling of protective elements such as field overcurrent, V/Hz, over voltage, and loss of field is not appropriate if an excitation system incorporates limiters designed/tested/verified to prevent such operation as documented via PRC-019. Including protection models in such cases will lead to erroneous tripping in the simulation of dynamic events where actual limiter operation would prevail. The best case scenario for including both limiter and protection models is that protection models are redundant and a waste of effort and computer/database resources. Some issues to be considered are:

  • Protection models can be very precise whereas limiter models are approximations. Models will normally not exhibit the same margins of coordination as the actual equipment.
  • V/Hz and overvoltage limiter models are currently not available in commercial simulation packages and standard model development takes several years. Including protection models instead of limiter models does not represent unit behavior.
  • Field overcurrent protection (possibly other functions) in most cases is integrated and coordinated with the limiter in the excitation system software and would only operate in an excitation control system failure scenario and therefore should not be modeled.

Richard Jackson, U.S. Bureau of Reclamation, 1, 6/29/2022

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The basis for the SAR was the deficiency of dynamic models to represent ride-through operation modes of IBRs such as momentary cessation. There is no justification in the SAR to expand the scope of the standard to include excitation limiters and Protection System settings as field verified models.  There is no demonstrated reliability gap, no tangible justification of how a reliability gap will be closed, and no technical foundation in the SAR to justify the need for field validated models of limiters and protection.  The justification provided in the Rationale for Requirement 3 makes unsubstantiated statements about exacerbating grid disturbances potentially causing cascading failures, while the Rationale ignores the technical basis used for the development of the PRC Standards such as PRC-019, -024, -025, -026, etc.   If the technical basis for those standards is valid, the Rationale for R3 is inaccurate.  

For example, the no-trip boundaries of PRC-024 is the criteria for the TP to design and plan the system operation; if the operation of protection elements occurs outside the no-trip zone, this operation should be irrelevant to the TP process, because this is an unacceptable operating region and the reason why the Protection System exists.  There are no industry established acceptance criteria used to identify what constitutes a “validated” excitation limiter model (consistent with practices used to validate dynamic models and parameters), especially when the limiter settings are outside the boundaries of reachable or desirable operation under normal conditions.  Within dynamic model software packages, excitation limiter models do not have full representation of OEM equipment suppliers that are actively in service.  Prior to mandating requirements in a standard, there should be independent, published studies of prototype efforts where the effectiveness and actual benefits of improved reliability are demonstrated and quantified in real numbers (rather than generic language) providing a true cost to benefit analysis.

For effectiveness, Protection System model development must accommodate all installed devices and protection elements regardless of equipment or technology.  It is not desirable to have the Protection System model development process becoming the preeminent driver of setting development or the bottleneck of Protection System settings implementation, which is at risk of happening with this requirement.  A more effective means to implement, the industry should first develop acceptable, consistent methods for the TP to receive excitation limiter and protection device setting characteristics.  Then, the TP can develop models as needed or justified.  The GO should not have the obligation to develop limiter or protection validated models for the TP.  There are no established criteria developed to determine when an outer-loop controller impacts dynamic volt/volt-ampere reactive (VAR) performance. 

Martin Sidor, NRG - NRG Energy, Inc., 6, 6/29/2022

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Manitoba Hydro does not agree with including  2.1, 2.2, and 2.3 as minimum modeling requirements. We think that it is up to the TP / PA to determine the required minimum modeling requirements and level of the modeling details as stated in R1 (1.1). If the TP / PA determines that some or all of these listed minimum requirements are needed to include in the model base or the type of performed studies they can include these as part of the R1 (1.1, level of detail). The level of detail and minimum requirements may change based on the type of studies and studies issues. The model requirements for the new facilities may differ from the in-service facilities and some in-service facilities may require a different level of detail. Therefore, the model(s) level of detail should be left to the TP / PA.

The R2 part 2.3  should be limited to the applicable protection models when requested by the Planning Authority and the Transmission Planner. Some of these models stated in 2.2 and 2.3 may not be available in the standard library of the required simulation tools (developing user's defined models) and they may not add any additional benefit to the modeling accuracy and validation process. Also, it could be very hard to validate the accuracy of these models. No point in adding more information to the models if it is not possible to test them with a reasonably overhead cost.

Alternately,

We recommend replacing 2.1, 2.2, and 2.3 with the following:

 2.1 The verified model(s) and accompanying information shall include the minimum model requirements and level of detail as stated in R1 part 1.1 and part 1.3 by their TP / PA.

Or

 The verified model(s) and accompanying information shall include the minimum model requirements as stated by their TP / PA in R1 part 1.1 and part 1.3 which may include the following:

2.1. Manufacturer, model number (if available), and type of generator/synchronous condenser, excitation system hardware, and Protection System(s) of Part 2.3;

2.2. Model(s) representing the generator/synchronous condenser, and associated excitation system including voltage regulator, impedance compensation, power system stabilizer, excitation limiters, and outer-loop controls which impact dynamic volt/volt-ampere reactive (VAR) performance;

2.3. Model(s) representing enabled Protection Systems that directly trip the generator/synchronous condenser. Protection Systems that shall be modeled include over- and under-voltage, stator and field overcurrent, loss of field, out-of-step, and volts per hertz protection; and

Manitoba Hydro does not agree with including  3.1, 3.2, and 3.3 as minimum modeling requirements. We think that it is up to the TP / PA to determine the required minimum modeling requirements and level of the modeling details as stated in R1 (1.1). If the TP / PA determines that some or all these listed minimum requirements are needed to include in the model base or the type of performed studies they can include these as part of the R1 (1.1, level of detail).

The R3 part 3.3  should be limited to the applicable protection models when requested by the Planning Authority and the Transmission Planner.

Alternately,

We recommend replacing 3.1, 3.2, and 3.3 with the following: 

3.1 The verified model(s) and accompanying information shall include the minimum model requirements and level of detail as stated in R1 part 1.1 and part 1.3 by their TP / PA.

Or

The verified model(s) and accompanying information shall include the minimum model requirements as stated by their TP / PA in R1 part 1.1 and part 1.3 which may include the following:

3.1. Manufacturer, model number (if available), type of turbine, type of governor, mode of operation, and Protection System(s) of Part 3.3;

3.2. Model(s) representing the turbine, governor control system, load controller, and other outer loop controls that override the governor response or modes of operation that limit frequency response, but exclude automatic generation control;

3.3. Model(s) representing enabled Protection Systems that directly trip the turbine-generator. Protection Systems that shall be modeled include over- and under-speed, and over- and under-frequency;

Nazra Gladu, Manitoba Hydro , 1, 6/29/2022

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The basis for the SAR was the deficiency of dynamic models to represent ride-through operation modes of IBRs such as momentary cessation. There is no justification in the SAR to expand the scope of the standard to include excitation limiters and Protection System settings as field verified models.  There is no demonstrated reliability gap, no tangible justification of how a reliability gap will be closed, and no technical foundation in the SAR to justify the need for field validated models of limiters and protection.  The justification provided in the Rationale for Requirement 3 makes unsubstantiated statements about exacerbating grid disturbances potentially causing cascading failures, while the Rationale ignores the technical basis used for the development of the PRC Standards such as PRC-019, -024, -025, -026, etc.   If the technical basis for those standards is valid, the Rationale for R3 is inaccurate.  For example, the no-trip boundaries of PRC-024 is the criteria for the TP to design and plan the system operation; if the operation of protection elements occurs outside the no-trip zone, this operation should be irrelevant to the TP process, because this is an unacceptable operating region and the reason why the Protection System exists.  There are no industry established acceptance criteria used to identify what constitutes a “validated” excitation limiter model (consistent with practices used to validate dynamic models and parameters), especially when the limiter settings are outside the boundaries of reachable or desirable operation under normal conditions.  Within dynamic model software packages, excitation limiter models do not have full representation of OEM equipment suppliers that are actively in service.  Prior to mandating requirements in a standard, there should be independent, published studies of prototype efforts where the effectiveness and actual benefits of improved reliability are demonstrated and quantified in real numbers (rather than generic language) providing a true cost to benefit analysis.  For effectiveness, Protection System model development must accommodate all installed devices and protection elements regardless of equipment or technology.  It is not desirable to have the Protection System model development process becoming the preeminent driver of setting development or the bottleneck of Protection System settings implementation, which is at risk of happening with this requirement.  A more effective means to implement, the industry should first develop acceptable, consistent methods for the TP to receive excitation limiter and protection device setting characteristics.  Then, the TP can develop models as needed or justified.  The GO should not have the obligation to develop limiter or protection validated models for the TP.  There are no established criteria developed to determine when an outer-loop controller impacts dynamic volt/volt-ampere reactive (VAR) performance.   

Patricia Lynch, NRG - NRG Energy, Inc., 5, 6/29/2022

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: R 2.3 covering tripping by protection system components is crossing over matters already in PRC19 and PRC24  

Joe O'Brien, NiSource - Northern Indiana Public Service Co., 6, 6/29/2022

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BC Hydro is unable to support the current draft of R2 as the requirement to “verify and validate” exciter limiters will severely limit the Generator Owners ability to validate models using system disturbance events as an alternative to staged testing.

Requirement R2 Part 2.4 mandates “validation” of models for excitation limiters, which are among the equipment listed under R2 Part 2.2. In BC Hydro’s experience, it is uncommon for system disturbances to result in a large enough response from the excitation system that could be used to validate these limiters. As a result, based on the current R2 draft, a staged test is the only other option for validation of excitation limiter models. It is BC Hydro’s interpretation that a staged test with reduced limiter setting will qualify as “validation” per Section 6.2 of the standard (Please confirm whether this interpretation is correct). However, performing a staged test require generating units to be taken out of service, which has associated costs and efforts not necessary under MOD-026-1.

BC Hydro suggests that the requirement to model limiters be moved from R2 Part 2.2 to R2 Part 2.3. In doing so, the requirement to verify the excitation limiter models is maintained but “validation” will not be required. As a result, system disturbance events can be used for validation of system models.

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

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Nicolas Turcotte, Hydro-Qu?bec TransEnergie, 1, 6/30/2022

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The limiter models in PSSe may or may not be able to accurately represent all manufacturers functions.  The standard needs to acknowledge this deficiency and specifically state that dynamic response matching simulations for limiters is not required to be submitted.

Protection models are in no way required if limiters are being used in the models.  Protection works in the systems even if the limiters don't.  In simulation, this scenario would never occur so there is no need to submit them.  PRC standards are already developed to comply with ride-through requirements.  This requirement is also pushing generator owners to purchase PSSe or PSLF software or to strictly rely on vendors to perform all this work.

Recommended changes:

1 - Remove the need to supply protection models.

2 - Make PRC-019 and PRC-024 documents available to TPs so they can populate models as needed.

3 - Specify simulated response of limiter models do not need to match test data for limiters.

Simply provide limiter settings for OEL, UEL, V/Hz, and SCL and allow the TP to determine study impacts or industry could develop simplified limiter models for use with setpoints

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

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Isidoro Behar, On Behalf of: Long Island Power Authority, , Segments 1

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AECI agrees with EEI’s comments:

The obligations related to Requirement R2, subpart 2.3 as it relates to GO and TO modifications to protection systems synchronous generation identified in Section 4.2.1 or 4.2.2 or a synchronous condenser identified in Section 4.2.4.1 should be clarified.  Specifically, the SDT should clarify the timeframe that will be required to complete and submit updated models to the TP after protection system changes. 

EEI requests similar clarifications regarding GO and TO obligations as it relates to Requirement R3, subpart 3.3.

Additionally, the Planning Coordinator should be added to these requirements since they share in the development of the planning models.

AECI, Segment(s) 1, 3, 6, 5, 3/4/2021

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Sean Steffensen, IDACORP - Idaho Power Company, 1, 6/30/2022

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AZPS does not support subparts 2.2, 2.3 and 2.4 and requests that the STD provide further clarification on what is expected to validate limiter models. 

To perform a staged or measured test with as-left limiter values is impractical.  The coordination of limiter function is already maintained in PRC-24 and PRC-19, therefore under most circumstances limiters will not come into play with proper coordination for most system disturbance events.  In addition, the limiter models are not always easily available, especially in the case of legacy units.  All limiters in the excitation system would need to be modeled in order to prevent nuisance trips from the newly implemented generator protection models. For these reasons, the amount of effort required to model and validate limiter models is large and will not significantly contribute to improved system reliability.

Subpart 2.3 is also impractical as PRC 019 and PRC 024 already require a review of protection settings to prevent unnecessary tripping of units. Creating generator protection models from protection settings would still be a significant amount of work with very little reliability benefit.

Michelle Amarantos, APS - Arizona Public Service Co., 5, 6/30/2022

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Constellation does not agree with the expanded modeling requirements. While we understand there may be value in developing and providing a model for non-linear protection functions, We don’t see the value in developing models for definite-time relay settings rather than just providing those settings. Constellation feels that language should be included that clearly indicates that R2 and R3 do not have to be completed at the same time ,otherwise this will be left to the interpretation of the auditors. Practically these are not always completed together.

 

Kimberly Turco on behalf of Constellation Segments 5 and 6

Alison Mackellar, Constellation, 5, 6/30/2022

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Constellation does not agree with the expanded modeling requirements. While we understand there may be value in developing and providing a model for non-linear protection functions, We don’t see the value in developing models for definite-time relay settings rather than just providing those settings. Constellation feels that language should be included that clearly indicates that R2 and R3 do not have to be completed at the same time ,otherwise this will be left to the interpretation of the auditors. Practically these are not always completed together.

 

Kimberly Turco on behalf of Constellation Segments 5 and 6

Kimberly Turco, Constellation, 6, 6/30/2022

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Before industry could implement all the protection settings for the models (i.e., R2.3 and R3.3) we would need guidance on proper implementation from industry relay vendors.  Better modules within the software should be available to use these settings.  As it is today, much work needs to be done with Siemens, GE, and PowerWorld to get these issues addressed before requiring industry to include verification and validation of these settings. The existing software does not readily support these updates for positive sequence  dynamic models.

LaTroy Brumfield, American Transmission Company, LLC, 1, 7/1/2022

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Comments: The obligations related to Requirement R2, subpart 2.3 as it relates to GO and TO modifications to protection systems synchronous generation identified in Section 4.2.1 or 4.2.2 or a synchronous condenser identified in Section 4.2.4.1 should be clarified.  Specifically, the SDT should clarify the timeframe that will be required to complete and submit updated models to the TP after protection system changes.  

EEI requests similar clarifications regarding GO and TO obligations as it relates to Requirement R3, subpart 3.3.

Additionally, the Planning Coordinator should be added to these requirements since they share in the development of the planning models.

Mike Magruder, Avista - Avista Corporation, 1, 7/1/2022

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The obligations related to Requirement R2, subpart 2.3 as it relates to GO and TO modifications to protection systems synchronous generation identified in Section 4.2.1 or 4.2.2 or a synchronous condenser identified in Section 4.2.4.1 should be clarified.  Specifically, the SDT should clarify the timeframe that will be required to complete and submit updated models to the TP after protection system changes.  

EEI requests similar clarifications regarding GO and TO obligations as it relates to Requirement R3, subpart 3.3.

Additionally, the Planning Coordinator should be added to these requirements since they share in the development of the planning models.

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

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Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) to question #3.

Alan Kloster, On Behalf of: Allen Klassen, Evergy, 1,3,5,6; Allen Klassen, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Derek Brown, Evergy, 1,3,5,6; Derek Brown, Evergy, 1,3,5,6

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

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Based on the initial requirement Consumers Energy is voting no for this question. We believe  that there needs to be a technical attachment added to this requirement clarifying the expectations.

Eric Sutlief, On Behalf of: CMS Energy - Consumers Energy Company - RF - Segments 3, 4, 5

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Comments: R2.3  is unclear. The Protection Systems that directly trip the generator/synchronous condenser include typically protection functions that use positive, negative or zero sequence quantities. While it might be implied that  protection functions based on positive sequence quantities should be modelled, since the planning/ operating tools are typically using positive sequence models, the current wording can be confusing. 

Some of the Out of Step protection function implementations can’t be simulated in the current planning/operating tools. 

Modelling of field current limiters is very challenging from accuracy perspective for example for rotating type exciters. 

R3.3 is unclear. The Protection Systems that directly trip the turbine-generator include typically protection functions that use positive, negative or zero sequence quantities. While it might be implied that  protection functions based on positive sequence quantities should be modelled, since the planning/ operating tools are typically using positive sequence models, the current wording can be confusing.

When renewable energy resources (wind or solar farms) are aggregated in equivalent planning/operating feeder/generator models, the accuracy required by protection functions installed at turbine/inverter /feeder level might be difficult to achieve, leading to simulated erroneous protection actions/non-actions.

R2.3 and R3.3 should consider that the planning/operating tools based on positive sequence models have limited capabilities in properly simulating the Protection Systems performance.

The following standards: PRC 019, PRC-024 (currently under substantial revision), PRC-025 and PRC-026 are meant to ensure that the applicable BES facilities are not inadvertently tripped under various planning/operating conditions. 

Leonard Kula, Independent Electricity System Operator, 2, 7/5/2022

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Xcel Energy generally supports the comments of EEI. Below are Xcel Energy comments that indicate additional or differing concerns.

Xcel Energy disagrees with including protective system trips in the standard for Requirements 2.3 and 3.3.  Relay settings are static, not dynamic as the Standard title indicates.  Relay settings are already included in other PRC Standards and PRC Standards manage those settings.  These modifications would require Generator Owners (GO) to perform unnecessary model revisions as relay settings change more frequently and it will create an administrative burden with the number of modeling revisions and significantly increase costs for GOs when protective system changes are made.   Specifically, field overcurrent protective systems protect the generator field during collector ring flashover events and have nothing to do with the dynamic response of a generator.  This protective system shall not be included in the Standard.  Relay settings can be provided to Transmission Planners (TP) via PRC Standard communications and can also be provided in different formats and still achieve the same benefit; without causing GOs to perform unnecessary modeling. In addition, the TP can request protection system settings through MOD-032 data specifications if necessary.

Existing dynamic models for excitation limiters do not adequately represent the behaviors of the various manufacturer equipment. For this reason, limiters are often not modeled. Excitation limiter models should not be required unless adequate generic models are developed. Alternatively, an exemption could be provided if the generic models do not adequately represent the installed equipment. If TPs require data about the limiters, then the data can be requested as part of the data specification in MOD-032.

If limiter models are required by the standard, then clarification is required on the validation requirement of the limiters. It is impractical to provide measured data of the actual limiter response with every validation, particularly if limiter settings remain unchanged. In order to dynamically test the behavior of the limiters, it will be necessary to alter settings in order to activate them within acceptable normal operation limits (voltage, equipment capability curves, etc). The modification of settings while online increases the risk of equipment problems during the test and also increases the likelihood that inadvertent setting changes occur. Performing the modifications while offline increases the burdens imposed by the testing. Because of this, it is unreasonable to require dynamic validation of the limiters, particularly if required with every revalidation.

To correct these concerns, the requirement for excitation limiters and electrical protection should be removed from MOD-026. Data can be requested as part of MOD-032 data specifications if needed by TPs. 

Joe Gatten, On Behalf of: Xcel Energy, Inc. - MRO, WECC - Segments 1, 3, 5, 6

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Scott Kinney, Avista - Avista Corporation, 3, 7/5/2022

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Based on the initial requirement Consumers Energy is voting no for this question. We believe  that there needs to be a technical attachment added to this requirement clarifying the expectations.

Karl Blaszkowski, CMS Energy - Consumers Energy Company, 3, 7/5/2022

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WECC agress wtih and supports the language and purpose of R2 and R3. However, since the initial language of R2 and R3 are extremely similar, and it is not until Parts 2.2 (R2) and 3.2 (R3) that what is being asked for is identified, it may make the Requirements clearer and not initially interpreted as the same requirement if the following clarifying language was added before the existing language in the proposed requirements:

R2: For Excitation System Modeling, synchronours generation...

R3: For Turbine/Governor Modeling, synchrounous generation...

Bold text identifies potential clarifying language.

WECC Entity Monitoring, Segment(s) 10, 1/30/2022

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Portland General Electric Company supports the comments provided by EEI and observes that the language of R3 omits reference to the Transmission Owner function.

 

 

Portland General Electric Co., Segment(s) 1, 3, 5, 6, 7/5/2022

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Dwanique Spiller, Berkshire Hathaway - NV Energy, 5, 7/5/2022

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AEP does not agree with the inclusion of language pertaining to the models representing Protection Systems of synchronous generating units as stated in R2 and R3, as we believe this to be outside the scope and intention of the Standard Authorization Request “MOD-026-1 Verification of Models and Data for Generator Excitation Control System or Plant Volt/Var Control Functions, MOD-027-1 Verification of Models and Data for Turbine/Governor and Load Control or Active Power/Frequency Control Functions” and that of the IRPTF, respectively.  The language as stated puts undue burden on the Generator Owners to provide additional protection model data, which may be unnecessary, as well as extremely challenging to execute.  As one example, standard model types may be unavailable due to existing limitations of the standard software applications within the utility industry that are needed to perform these analyses. The absence of model types would warrant a significant expenditure of time and resources to comply. Since MOD-032 allows the TP and PC to request protection system data and modeling (if it is believed to be necessary), and since MOD-026-2 is a model verification/validation standard and it is not feasible to validate the modeling of protection functions, this modeling should be left to MOD-032

In addition, the proposed requirements R2 part 2.3 and R3 part 3.3 introduce compliance duplication by requiring the Generator Owner to verify and validate generator protection models whose settings data is already captured through the scope of obligations within a host of active Protection and Control Reliability Standards (e.g. PRC-019, PRC-024, PRC-025, PRC-026, PRC-027, etc.). These standards, when considered in their entirety, serve to meet the concerns expressed by the SDT, as they require that data to be evaluated for in-service equipment, devices, and systems against a wide-range of stipulated criteria designed to address the myriad of scenarios that could negatively impact BES reliability. Therefore, we do not believe the proposed further inclusion of protective function verifications in MOD-026 would result in meaningful contributions to improving the reliability of the BES.

Lastly, for the specific protective functions listed within Requirements R2 part 2.3 and R3 part 3.3, the mechanism to request the desired modeling data by the Transmission Planner/Planning Coordinator already exists via MOD-032. A recommendation would be for those Transmission Planners and/or Planning Coordinators that prefer these modeled protective functions to utilize their existing MOD-032 process to meet that preference and avoid creating inter-reliability standard inefficiencies or duplication and mandating Generator Owners to provide potentially-unnecessary modeling data.  AEP’s experience is that the proposed protective function modeling data has not been seen as necessary by Transmission Planners and Planning Coordinators. The rationale for removing the listed protective functions are as follows:

  • Stator overcurrent - Not universally applied on synchronous units but if applied, it is likely a limiter or alarm only, not a trip function. If a limiter, it would have an inverse time characteristic likely to extend beyond normal simulation durations. Historically, no requests for this relay protection model have been warranted via MOD-032.
  • Field overcurrent – Backup to the over-excitation limiter/maximum excitation limiter (OEL/MXL). It is not necessary to model trip function and has been reinforced through no requests via MOD-032. No model in PSS/E.
  • Loss of field - No contingency exists to warrant modeling of the trip function which has been reinforced through no requests for this protection model via MOD-032. Coordinated with the UEL/MEL for out-of-step operation and loss of excitation due to equipment failure which is not a TP studied contingency.
  • Out-of-step – Not universally applied on all synchronous units. There are other means to remove unstable units from simulations (there is a check box option in PSS/E, for example). It is not necessary to have this in simulation models which has been reinforced by receiving no requests for this protection model via MOD-032.
  • Volts per hertz – Applied to prevent over-excitation of generators/GSUs during start-up and shutdown. Generally a limiter function is coordinated with trip, but in many cases the trip function is active only while the unit is off-line. With exception of UFLS studies, not generally necessary (there are even time-based V/Hz constraints on UFLS program settings in PRC-006 to avoid V/Hz limiter activation); thus, this would not be necessary for modeling as reinforced by receiving no requests for this protection model via MOD-032. No limiter function in PSS/E; trip or monitor only in PSS/E.
  • Over/Underspeed – This protective function does not meet the definition of a Protection System as defined within the NERC Glossary of Terms.  While this can be synonymous with frequency in an operational context, the NERC definition is explicit in which it refers to “Protective relays which respond to *electrical* quantities”. Protective functions which respond to mechanical quantities such as pressure, temperature, etc. are not applicable to the NERC Protection System and should be removed from R3 part 3.3 of the draft standard. This is reinforced via the PRC-005-6 Supplementary Reference which states when defining the Components of Protection Systems…
    • Component of Protection System: Protective relays which respond to electrical quantities
    • Includes: All protective relays that use current and/or voltage inputs from current & voltage sensors and that trip the 86, 94 or trip coil.
    • Excludes: Devices that use non‐electrical methods of operation including thermal, pressure, gas accumulation, and vibration. Any ancillary equipment not specified in the definition of Protection Systems. Control and/or monitoring equipment that is not a part of the automatic tripping action of the Protection System.

Thomas Foltz, AEP, 5, 7/5/2022

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Texas RE requests clarification on the term “turbine-generator” in Requirement Part 3.3.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 7/5/2022

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Israel Perez, On Behalf of: Pam Syrjala, Salt River Project, 1,3,5,6; Pam Syrjala, Salt River Project, 1,3,5,6; Zack Heim, Salt River Project, 1,3,5,6; Zack Heim, Salt River Project, 1,3,5,6

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Requirements R2 and R3 are almost identical. It is recommended they be grouped into one requirement.

Greg Davis, Georgia Transmission Corporation, 1, 7/5/2022

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  WEC Energy Group supports EEI and NAGF comments. 

Christine Kane, WEC Energy Group, Inc., 3, 7/5/2022

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BPA identified that R3.3 is covered under NERC standards PRC-019 and PRC-024.  BPA disagrees with including it as part of MOD-026 or MOD-027. BPA believes these revisions are redundant and unnecessary.

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

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Black Hills Corporation supports EEI’s comments with the clarification of obligations to R2 subpart 2.3, Sections 4.2.1, 4.2.2 and 4.2.4.1. In addition to Transmission Planner, Planning Coordinator needs to be added to the requirements language. 

Claudine Bates, Black Hills Corporation, 6, 7/5/2022

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National Grid supports EEI's comments.

Michael Jones, National Grid USA, 1, 7/5/2022

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Hot Answers

FE agrees with EEI’s comments:

The obligations related to Requirement R4, subpart 4.3 as it relates to GO and TO modifications to protections for inverter based resources (IBRs) identified in Section 4.2.3, FACTS devices identified in Section 4.2.4.2, and VSC HVDC identified in section 4.2.5.2 should be clarified.  Specifically, the SDT should clarify the timeframe that will be required to complete and submit updated models to the TP after protection changes.

EEI requests similar clarifications regarding GO and TO obligations as it relates to Requirement R5, subpart 5.3.

Additionally, the Planning Coordinator should be added to these requirements since they share in the development of the planning models.

FE Voter, Segment(s) 1, 3, 5, 6, 4, 12/20/2021

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We support the subpoints in 4.1, 4.2, 4.3, 5.1, 5.2, and 5.3. However, the generators are able to provide the best available models to the Transmission Planner, but the TP would need to validate the model and provide changes back to the Generator Owner and Transmission Owner.

Anna Todd, On Behalf of: Southern Indiana Gas and Electric Co., RF, Segments 3, 5, 6

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Other Answers

Same logic as my comments for R2 and R3. Protection System coordination should remain under PRC-019. Any new TP reporting R4.3 and R5.3) should be added to PRC-019.

Jack Stamper, Clark Public Utilities, 3, 6/16/2022

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The obligations related to Requirement R4, subpart 4.3 as it relates to GO and TO modifications to protections for inverter based resources (IBRs) identified in Section 4.2.3, FACTS devices identified in Section 4.2.4.2, and VSC HVDC identified in section 4.2.5.2 should be clarified.  Specifically, the SDT should clarify the timeframe that will be required to complete and submit updated models to the TP after protection changes.

EEI requests similar clarifications regarding GO and TO obligations as it relates to Requirement R5, subpart 5.3.

Additionally, the Planning Coordinator should be added to these requirements since they share in the development of the planning models.

Glen Farmer, Avista - Avista Corporation, 5, 6/28/2022

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No Comments

Brian Lindsey, Entergy, 1, 6/28/2022

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Richard Jackson, U.S. Bureau of Reclamation, 1, 6/29/2022

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Similar to the response of Question 3, the addition of limiters and Protection System settings are not justified.

Martin Sidor, NRG - NRG Energy, Inc., 6, 6/29/2022

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Manitoba Hydro does not agree with including  4.1, 4.2, and 4.3 as minimum modeling requirements. We think that it is up to the TP / PA to determine the required minimum modeling requirements and level of the modeling details as stated in R1 (1.1). If the TP / PA determines that some or all these listed minimum requirements are needed to include in the model base or the type of performed studies they can include these as part of the R1 (1.1, level of detail).

The R4 part 2.3  should be limited to the applicable protection and limiting functions models when requested by the Planning Authority and the Transmission Planner. Some of these models stated in 4.2 and 4.3 may not be available in the standard library of the required simulation tools (developing user's defined models) and they may not add any additional benefit to the modeling accuracy and validation process. Also, it could be very hard to validate the accuracy of these models. No point in adding more information to the models if it is not possible to test them with a reasonably overhead cost.

Alternately,

We recommend replacing 4.1, 4.2, and 4.3 with the following:

3.1 The verified model(s) and accompanying information shall include the minimum model requirements and level of detail as stated in R1 part 1.1 and part 1.3 by their TP / PA.

Or

The verified model(s) and accompanying information shall include the minimum model requirements as stated by their TP / PA in R1 part 1.1 and part 1.3 which may include the following 

4.1. Manufacturer, model number, and software/firmware version number of the IBR unit (s)3 and power plant controller;

4.2. Model(s) representing the IBR unit(s), and associated reactive power control system4 including the IBR unit’s electrical control, power plant controller, auxiliary reactive resources, and other equipment which impacts plant voltage and reactive power dynamic response;

4.3. Model(s) representing enabled protections5 and limiting functions,6 that either directly trip IBR unit(s) or plant, or limit active/reactive output of the IBR unit or plant; and

Regarding R5: Same as the above comments.

Nazra Gladu, Manitoba Hydro , 1, 6/29/2022

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Similar to the response of Question 3, the addition of limiters and Protection System settings are not justified.

Patricia Lynch, NRG - NRG Energy, Inc., 5, 6/29/2022

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Joe O'Brien, NiSource - Northern Indiana Public Service Co., 6, 6/29/2022

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

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Nicolas Turcotte, Hydro-Qu?bec TransEnergie, 1, 6/30/2022

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Suggest the following actions:

  1. Create a seperate standard for IBRs.
  2. Remove requirement to provide software/firmware version numbers to transmission planners.
  3. Remove the requirement to supply protection models.
  4. Make PRC-019 and PRC-024 documents available to TPs so they can populate models as needed.

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

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See observations for Requirment 6 noted below for Question #5.

Isidoro Behar, On Behalf of: Long Island Power Authority, , Segments 1

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AECI agrees with EEI’s comments:

The obligations related to Requirement R4, subpart 4.3 as it relates to GO and TO modifications to protections for inverter based resources (IBRs) identified in Section 4.2.3, FACTS devices identified in Section 4.2.4.2, and VSC HVDC identified in section 4.2.5.2 should be clarified.  Specifically, the SDT should clarify the timeframe that will be required to complete and submit updated models to the TP after protection changes.

EEI requests similar clarifications regarding GO and TO obligations as it relates to Requirement R5, subpart 5.3.

Additionally, the Planning Coordinator should be added to these requirements since they share in the development of the planning models.

AECI, Segment(s) 1, 3, 6, 5, 3/4/2021

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Sean Steffensen, IDACORP - Idaho Power Company, 1, 6/30/2022

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Michelle Amarantos, APS - Arizona Public Service Co., 5, 6/30/2022

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Constellation feels that language should be included that clearly indicates that R4, R5, and R6 do not have to be completed at the same time ,otherwise this will be left to the interpretation of the auditors. Practically these are not always completed together.

Kimberly Turco on behalf of Constellation Segments 5 and 6

Alison Mackellar, Constellation, 5, 6/30/2022

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Constellation feels that language should be included that clearly indicates that R4, R5, and R6 do not have to be completed at the same time, otherwise this will be left to the interpretation of the auditors. Practically these are not always completed together.

 

Kimberly Turco on behalf of Constellation Segments 5 and 6

Kimberly Turco, Constellation, 6, 6/30/2022

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Clarification is needed on the implementation period for existing IBR devices that were not part of the scope of MOD-026 or MOD-027 before this change (i.e., Transmission Owner devices), but which are now going to be applicable to R4 and R5. 

We also believe that clarification needs to be made that models for aggregations of plants with similar inverters need to be taken into account rather than modeling all individual inverters.

LaTroy Brumfield, American Transmission Company, LLC, 1, 7/1/2022

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Comments: The obligations related to Requirement R4, subpart 4.3 as it relates to GO and TO modifications to protections for inverter based resources (IBRs) identified in Section 4.2.3, FACTS devices identified in Section 4.2.4.2, and VSC HVDC identified in section 4.2.5.2 should be clarified.  Specifically, the SDT should clarify the timeframe that will be required to complete and submit updated models to the TP after protection changes.

EEI requests similar clarifications regarding GO and TO obligations as it relates to Requirement R5, subpart 5.3.

Additionally, the Planning Coordinator should be added to these requirements since they share in the development of the planning models.

Mike Magruder, Avista - Avista Corporation, 1, 7/1/2022

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The obligations related to Requirement R4, subpart 4.3 as it relates to GO and TO modifications to protections for inverter based resources (IBRs) identified in Section 4.2.3, FACTS devices identified in Section 4.2.4.2, and VSC HVDC identified in section 4.2.5.2 should be clarified.  Specifically, the SDT should clarify the timeframe that will be required to complete and submit updated models to the TP after protection changes.

EEI requests similar clarifications regarding GO and TO obligations as it relates to Requirement R5, subpart 5.3.

Additionally, the Planning Coordinator should be added to these requirements since they share in the development of the planning models.

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

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Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) to question #4.

Alan Kloster, On Behalf of: Allen Klassen, Evergy, 1,3,5,6; Allen Klassen, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Derek Brown, Evergy, 1,3,5,6; Derek Brown, Evergy, 1,3,5,6

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

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The approved models need more development and there will still need to be a technical attachment clarifying the expectations.

Eric Sutlief, On Behalf of: CMS Energy - Consumers Energy Company - RF - Segments 3, 4, 5

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Leonard Kula, Independent Electricity System Operator, 2, 7/5/2022

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Xcel Energy generally supports the comments of EEI. Below are Xcel Energy comments that indicate additional or differing concerns.

As in response to Question 3 of this comment form, Xcel Energy also disagrees with including protective system trips in the Standard for Requirements 4.3 and 5.3.  Xcel Energy maintains that relay settings are static, not dynamic as the Standard title indicates.  Relay settings are already included in other PRC Standards and PRC Standards manage those settings. As indicated in Question 3, these modifications would require Generator Owners (GO) to perform unnecessary model revisions as relay settings change more frequently and it will create an administrative burden with the number of modeling revisions and significantly increase costs for GOs when protective system changes are made.  Relay settings can be provided to Transmission Planners (TP) via PRC Standard communications and can also be provided in different formats and still achieve the same benefit; without causing GOs to perform unnecessary modeling. In addition, the TP can request protection system settings through MOD-032 data specifications if necessary.

Joe Gatten, On Behalf of: Xcel Energy, Inc. - MRO, WECC - Segments 1, 3, 5, 6

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Scott Kinney, Avista - Avista Corporation, 3, 7/5/2022

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The approved models need more development and there will still need to be a technical attachment clarifying the expectations.

Karl Blaszkowski, CMS Energy - Consumers Energy Company, 3, 7/5/2022

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WECC agress wtih and supports the language and purpose of R4 and R5. 

Similar to the comment for Question 3, WECC suggests the addition of a few clarifying words prior to the existing language in the proposed Requirements

R4: For voltage modeling, inverter bases resources...

R5: For frequency modeling, inverter based resources...

Bold text identifies potential clarifying language.

WECC Entity Monitoring, Segment(s) 10, 1/30/2022

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Portland General Electric Company supports the comments provided by EEI.

Portland General Electric Co., Segment(s) 1, 3, 5, 6, 7/5/2022

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Dwanique Spiller, Berkshire Hathaway - NV Energy, 5, 7/5/2022

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Thomas Foltz, AEP, 5, 7/5/2022

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Texas RE agrees with the SDT’s approach to include inverter-based resources.  Texas RE recommends defining the term IBR unit(s) in the NERC Glossary of terms rather than describing it in a footnote of a single requirement (Requirement Part 4.1).  It seems as though this term could be used in additional future requirements and it would be more clear to have a NERC Glossary definition.

 

Texas RE seeks clarification on the difference in the terms “IBR unit(s)” and “plant” as used in Requirement Parts 4.3 and 6.3.  The addition of “or plant” appears in some parts, but not others.

 

Texas RE noticed Requirement R5.1 says “IBR unit(s), power plant controller,” while Requirement 4.1 said IBR unit(s) and power plant controller.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 7/5/2022

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Israel Perez, On Behalf of: Pam Syrjala, Salt River Project, 1,3,5,6; Pam Syrjala, Salt River Project, 1,3,5,6; Zack Heim, Salt River Project, 1,3,5,6; Zack Heim, Salt River Project, 1,3,5,6

- 0 - 0

 Requirements R4 and R5 are almost identical. It is recommended they be grouped into one requirement.

Greg Davis, Georgia Transmission Corporation, 1, 7/5/2022

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WEC Energy Group supports EEI and NAGF comments. 

Christine Kane, WEC Energy Group, Inc., 3, 7/5/2022

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R5 – BPA uses standard HVDC models available in grid simulation packages like Siemens PSS/E, GE PSLF or PowerWorld. The model data must match model structure that is implemented in the industry used grid simulators.

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

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Black Hills Corporation supports EEI comment.

Claudine Bates, Black Hills Corporation, 6, 7/5/2022

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Are modeling requirements in Requirement R4 applicable to double-fed induction generators (DFIG)?

In addition, National Grid supports EEI's comments.

Michael Jones, National Grid USA, 1, 7/5/2022

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Hot Answers

FE agrees with EEI’s comments:

EEI does not agree that EMT models are needed everywhere at this time.  We also do not agree that the industry is sufficiently prepared to develop large scale EMT models at this time.  Instead, these models should be limited to those areas where  the needs are most urgent and as directed by the responsible Transmission Planner (TP), in cooperation with the responsible Planning Coordinator (PC).  For this reason,  criteria should be developed by the SDT to help guide the industry when EMT models are needed.  This will ensure that lessons learned can be developed and applied over time as these models become necessary.  We recommend the following edits to Requirement R6:

 

R6:  After a formal analysis by the Transmission Planner (TP) and as a result of their inability to conduct accurate dynamic simulations that reflect and assess BES reliability performance that due to the growth of IBRs (or in cases where IBRs are being installed in areas with low short circuit strength) the TP shall submit data requests to affected GOs and TOs to provide a verified EMT model(s), associated parameters, and accompanying information that represent the in-service equipment of the effected Facilities to its Transmission Planner, in accordance with the periodicity in MOD-026-2 Attachment 1. The verified model(s)and accompanying information shall include at a minimum the following:

Requirement R6, subpart 6.2 and the use of the term “large signal disturbances” should be clarified.  Currently, small signal disturbances are tested and verified by injecting a small step change (e.g., a 2.5% step change) into excitation and frequency response controls.  A large disturbance potentially means something that would be outside of a control system or units deadband.  EEI does not agree that entities should be required to inject large signal disturbances which could damage equipment or cause a system disturbance for a mandatory test.  For this reason, clarity regarding what was intended by this language should be provided.

FE Voter, Segment(s) 1, 3, 5, 6, 4, 12/20/2021

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As a Generator Owner and Transmission Owner we will continue to provide requested model data, but at this time there are no NERC approved EMT models with limited software/expertise.

Anna Todd, On Behalf of: Southern Indiana Gas and Electric Co., RF, Segments 3, 5, 6

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Other Answers

Jack Stamper, Clark Public Utilities, 3, 6/16/2022

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EEI does not agree that EMT models are needed everywhere at this time.  We also do not agree that the industry is sufficiently prepared to develop large scale EMT models at this time.  Instead, these models should be limited to those areas where  the needs are most urgent and as directed by the responsible Transmission Planner (TP), in cooperation with the responsible Planning Coordinator (PC).  For this reason,  criteria should be developed by the SDT to help guide the industry when EMT models are needed.  This will ensure that lessons learned can be developed and applied over time as these models become necessary.  We recommend the following edits to Requirement R6:

R6:  After a formal analysis by the Transmission Planner (TP) and as a result of their inability to conduct accurate dynamic simulations that reflect and assess BES reliability performance that due to the growth of IBRs (or in cases where IBRs are being installed in areas with low short circuit strength) the TP shall submit data requests to affected GOs and TOs to For applicable units of inverter based resources (IBRs) per Section 4.2.3, FACTS devices per Section 4.2.4.2, LCC HVDC per Section 4.2.5.1, and VSC HVDC per 4.2.5.2, each Generator Owner or Transmission Owner shall provide a verified EMT model(s), associated parameters, and accompanying information that represent the in-service equipment of the effected Facilities to its Transmission Planner, in accordance with the periodicity in MOD-026-2 Attachment 1. The verified model(s)and accompanying information shall include at a minimum the following:

Requirement R6, subpart 6.2 and the use of the term “large signal disturbances” should be clarified.  Currently, small signal disturbances are tested and verified by injecting a small step change (e.g., a 2.5% step change) into excitation and frequency response controls.  A large disturbance potentially means something that would be outside of a control system or units deadband.  EEI does not agree that entities should be required to inject large signal disturbances which could damage equipment or cause a system disturbance for a mandatory test.  For this reason, clarity regarding what was intended by this language should be provided.

 

Glen Farmer, Avista - Avista Corporation, 5, 6/28/2022

- 0 - 0

No Comments

Brian Lindsey, Entergy, 1, 6/28/2022

- 0 - 0

Richard Jackson, U.S. Bureau of Reclamation, 1, 6/29/2022

- 0 - 0

The use of EMT models has not been effectively demonstrated as necessary in addition to the use of positive sequence models in the context of stability/planning.  The limited applicability of EMT models to isolated locations does not justify their inclusion into the standard. 

Martin Sidor, NRG - NRG Energy, Inc., 6, 6/29/2022

- 0 - 0

Manitoba Hydro recommends that this requirement should be limited only to newly interconnecting inverter-based resources (IBRs) per Section 4.2.3, FACTS devices per Section 4.2.4.2, LCC HVDC per Section 4.2.5.1, and VSC HVDC per 4.2.5.2 to the BPS and to upon request of any of these applicable in-service devices by the TP / PA. EMT models are complex and it will take long time to train personnel and develop EMT models.

Manitoba Hydro does not agree with including  6.1, 6.2, and 6.3 as minimum modeling requirements. We think that it is up to the TP / PA to determine the required minimum modeling requirements and level of the modeling details as stated in R1 (1.2). If the TP / PA determines that some or all these listed minimum requirements are needed to include in the model base or the type of performed studies they can include these as part of the R1 (1.2, level of detail). The level of detail and minimum requirements may change based on the type of studies and studies issues. The model requirements for the new facilities may differ from the in-service facilities and some in-service facilities may require a different level of detail. Therefore, the model(s) level of detail should be left to the TP / PA.

Alternately,

We recommend replacing 6.1, 6.2, and 6.3 with the following:

3.1 The verified model(s) and accompanying information shall include the minimum model requirements and level of detail as stated in R1 part 1.2 and part 1.3 by their TP / PA.

Or

The verified model(s) and accompanying information shall include the minimum model requirements as stated by their TP / PA in R1 part 1.2 and part 1.3 which may include the following: 

6.1. Attestation from respective original equipment manufacturer(s) (OEM) stating the IBR unit model(s), power plant controller model, and auxiliary control devices model(s) represent the equipment supplied by the OEM.8 If an attestation from an OEM is not obtainable, the Generator Owner or Transmission Owner shall document the reason;

6.2. Device test9 results demonstrating a comparison of the IBR unit’s response and the IBR unit’s EMT model response for large signal disturbances. If device test results are not obtainable, the Generator Owner or Transmission Owner shall document the reason;

6.3. Facility EMT model and associated parameters representing the IBR unit(s), collector system, auxiliary devices, power plant controller, main transformer(s), and enabled protections and controls that either directly trip IBR unit(s) or plant, or limit active/reactive output of the IBR unit or plant;10

Regarding the 6.5 requirement: this requirement should be removed.  Manitoba Hydro does not think that comparing the response of positive sequence dynamic model(s) of Requirement R4 and R5 to the response of Facility EMT model of Requirement R6 for large signal disturbances will add any tangible benefit to the model validation process. These two models required different levels of detail model representation and simulation time steps. What are the validation criteria?

Nazra Gladu, Manitoba Hydro , 1, 6/29/2022

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The use of EMT models has not been effectively demonstrated as necessary in addition to the use of positive sequence models in the context of stability/planning.  The limited applicability of EMT models to isolated locations does not justify their inclusion into the standard.

Patricia Lynch, NRG - NRG Energy, Inc., 5, 6/29/2022

- 0 - 0

Joe O'Brien, NiSource - Northern Indiana Public Service Co., 6, 6/29/2022

- 0 - 0

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

- 0 - 0

Nicolas Turcotte, Hydro-Qu?bec TransEnergie, 1, 6/30/2022

- 0 - 0

Transmission planners can't study the entire system with EMT models and should only be required if Transmission provides justification for them on a case-by-case basis.  Technical Justification should include conditions needed to study (e.g., insulation coordination, switching surge, SSR, TRV, higher-frequency control interactions, series capacitor design studies, etc.).  If positive sequence models are properly validated/verified, the system can be accurately studied.  Providing EMT models will put a significant financial burden on generator owners with minute benefit to the system.

Suggestions:

  1. Revise this section to only be required if justification is provided from TP. 
  2. Remove 6.1.  This requirement requests excessive oversight by transmission and implies GOs are not capable of ensuring models are properly documented and expands audit scope.  The risk of non-compliance outweighs the reliability benefits.  Not all facilities use a single supplier for all systems.  Requiring attestation from OEM is implying GOs are not capable of supplying the correct data. 
  3. Remove 6.5.  Comparisons of EMT and Positive Sequence Models may have slight differences and comparing the response becomes a point for TP to dispute.
  4. Create a separate standard for IBRs.
  5. It will take considerable time for the industry to become knowledgeable on IBRs with EMT models so a 5-year implementation period is suggested.

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

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Requirement 6 is for applicable units of inverter based resources (IBRs) per Section 4.2.3, FACTS devices per Section 4.2.4.2, LCC HVDC per Section 4.2.5.1, and VSC HVDC per 4.2.5.2.

Sub requirements R6.1, 6.2 and 6.3 specifically mention “IBR units”. Using this term may be confusing. It is recommended to change the term “IBR units” within 6.1, 6.2 nd 6.3 to encompass all applicable faciltiies itemized at the beginning of R6 (for examples, FACTS, etc).

It is also recommended to append / clarify the first sentence with respect to ownership -- as follows:

For applicable units of inverter based resources (IBRs) per Section 4.2.3, FACTS devices per Section 4.2.4.2, LCC HVDC per Section 4.2.5.1, and VSC HVDC per 4.2.5.2, each Generator Owner, or Transmission Owner that owns a Facility listed in Section 4.2.4 or 4.2.5 shall provide a verified EMT model(s), associated parameters, and accompanying information that represent the in-service equipment of the Facility to its Transmission Planner, in accordance with the periodicity in MOD-026-2 Attachment 1.

Isidoro Behar, On Behalf of: Long Island Power Authority, , Segments 1

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AECI agrees with EEI’s comments:

EEI does not agree that EMT models are needed everywhere at this time.  We also do not agree that the industry is sufficiently prepared to develop large scale EMT models at this time.  Instead, these models should be limited to those areas where  the needs are most urgent and as directed by the responsible Transmission Planner (TP), in cooperation with the responsible Planning Coordinator (PC).  For this reason,  criteria should be developed by the SDT to help guide the industry when EMT models are needed.  This will ensure that lessons learned can be developed and applied over time as these models become necessary.  We recommend the following edits to Requirement R6:

R6:  After a formal analysis by the Transmission Planner (TP) and as a result of their inability to conduct accurate dynamic simulations that reflect and assess BES reliability performance that due to the growth of IBRs (or in cases where IBRs are being installed in areas with low short circuit strength) the TP shall submit data requests to affected GOs and TOs to provide a verified EMT model(s), associated parameters, and accompanying information that represent the in-service equipment of the effected Facilities to its Transmission Planner, in accordance with the periodicity in MOD-026-2 Attachment 1. The verified model(s)and accompanying information shall include at a minimum the following:

Requirement R6, subpart 6.2 and the use of the term “large signal disturbances” should be clarified.  Currently, small signal disturbances are tested and verified by injecting a small step change (e.g., a 2.5% step change) into excitation and frequency response controls.  A large disturbance potentially means something that would be outside of a control system or units deadband.  EEI does not agree that entities should be required to inject large signal disturbances which could damage equipment or cause a system disturbance for a mandatory test.  For this reason, clarity regarding what was intended by this language should be provided.

AECI, Segment(s) 1, 3, 6, 5, 3/4/2021

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Sean Steffensen, IDACORP - Idaho Power Company, 1, 6/30/2022

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AZPS does not support Requirement R6 for the following reasons:

The EMT modeling requirement seems excessive for this application as there has not been sufficient justification of why this level of detail is required. Concerns for large-signal disturbance behavior are already being addressed by recommended practices such as PRC-024 and the NERC “BPS-Connected Inverter-Based Resource Performance Reliability Guideline.” While these do not directly address modeling, they require that the type of behavior that was witnessed during the Blue Cut fire is mitigated. Since we are currently setting protection to be broad enough to ride through these disturbances, requiring EMT models in addition to positive sequence models would add significant cost and time to model verification without creating additional reliability. 

Any protection and limiters should already be modeled adequately based on the revised R4 and R5. Sub-Synchronous Resonance and negative/zero sequence events affect traditional generation as well. Even though EMT modeling has been available for decades, it has not been required to develop these models, provide them to other entities, or shown that doing so will provide any meaningful increase in system reliability. Transmission planners do not currently use these models in their positive sequence studies, and very few transmission planners have the capability of using these types of models today.

As a GO, it would be nearly impossible to create and validate an EMT model without manufacturer support. PRC-024 and industry best practices should provide adequate safety margin for the system by requiring that the equipment not trip within the no-trip zone. Creating an EMT model is unreasonably burdensome for the rare event where this information might be useful and a large enough system disturbance to adequately validate these models would be incredibly rare, and difficult or impossible to stage. Furthermore, MOD-33 already requires system model validation for these types of events.

If the requirement to use EMT models is not removed from the standard, AZPS supports the following recommendation submitted by EEI: “EEI does not agree that EMT models are needed everywhere at this time. We also do not agree that the industry is sufficiently prepared to develop large scale EMT models at this time.  Instead, these models should be limited to those areas where the needs are most urgent and as directed by the responsible Transmission Planner (TP), in cooperation with the responsible Planning Coordinator (PC). For this reason, criteria should be developed by the SDT to help guide the industry when EMT models are needed. This will ensure that lessons learned can be developed and applied over time as these models become necessary.”

Michelle Amarantos, APS - Arizona Public Service Co., 5, 6/30/2022

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Constellation does not agree with the addition of EMT models due to the limited number of subject matter experts in the industry, equipment manufacturers and vendors that are able to implement the requirements in this standard as stated in the implementation plan.

Kimberly Turco on behalf of Constellation Segments 5 and 6

Alison Mackellar, Constellation, 5, 6/30/2022

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Constellation does not agree with the addition of EMT models due to the limited number of subject matter experts in the industry, equipment manufacturers and vendors that are able to implement the requirements in this standard as stated in the implementation plan.

 

Kimberly Turco on behalf of Constellation Segments 5 and 6

Kimberly Turco, Constellation, 6, 6/30/2022

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More information on Footnote 9 is required.  Notably, what is meant by “factory type test, hardware in the loop test, or other manufacture test.” 

Also, with respect to R6.2 and R6.5, more information is needed on the definition of a “large signal disturbance.” 

LaTroy Brumfield, American Transmission Company, LLC, 1, 7/1/2022

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Comments: EEI does not agree that EMT models are needed everywhere at this time.  We also do not agree that the industry is sufficiently prepared to develop large scale EMT models at this time.  Instead, these models should be limited to those areas where  the needs are most urgent and as directed by the responsible Transmission Planner (TP), in cooperation with the responsible Planning Coordinator (PC).  For this reason,  criteria should be developed by the SDT to help guide the industry when EMT models are needed.  This will ensure that lessons learned can be developed and applied over time as these models become necessary.  We recommend the following edits to Requirement R6:

 

R6:  After a formal analysis by the Transmission Planner (TP) and as a result of their inability to conduct accurate dynamic simulations that reflect and assess BES reliability performance that due to the growth of IBRs (or in cases where IBRs are being installed in areas with low short circuit strength) the TP shall submit data requests to affected GOs and TOs to For applicable units of inverter based resources (IBRs) per Section 4.2.3, FACTS devices per Section 4.2.4.2, LCC HVDC per Section 4.2.5.1, and VSC HVDC per 4.2.5.2, each Generator Owner or Transmission Owner shall provide a verified EMT model(s), associated parameters, and accompanying information that represent the in-service equipment of the effected Facilities to its Transmission Planner, in accordance with the periodicity in MOD-026-2 Attachment 1. The verified model(s)and accompanying information shall include at a minimum the following:

Requirement R6, subpart 6.2 and the use of the term “large signal disturbances” should be clarified.  Currently, small signal disturbances are tested and verified by injecting a small step change (e.g., a 2.5% step change) into excitation and frequency response controls.  A large disturbance potentially means something that would be outside of a control system or units deadband.  EEI does not agree that entities should be required to inject large signal disturbances which could damage equipment or cause a system disturbance for a mandatory test.  For this reason, clarity regarding what was intended by this language should be provided.

Mike Magruder, Avista - Avista Corporation, 1, 7/1/2022

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EEI does not agree that EMT models are needed everywhere at this time.  We also do not agree that the industry is sufficiently prepared to develop large scale EMT models at this time.  Instead, these models should be limited to those areas where  the needs are most urgent and as directed by the responsible Transmission Planner (TP), in cooperation with the responsible Planning Coordinator (PC).  For this reason,  criteria should be developed by the SDT to help guide the industry when EMT models are needed.  This will ensure that lessons learned can be developed and applied over time as these models become necessary.  We recommend the following edits to Requirement R6:

 

R6:  For applicable units of inverter based resources (IBRs), identified under R1, subpart 1.2, GOs and TOs shall provide a verified EMT model(s), associated parameters, and accompanying information that represent the in-service equipment of the effected Facilities to its Transmission Planner, in accordance with the periodicity in MOD-026-2 Attachment 1. The verified model(s)and accompanying information shall include at a minimum the following:

Requirement R6, subpart 6.2 and the use of the term “large signal disturbances” should be clarified.  Currently, small signal disturbances are tested and verified by injecting a small step change (e.g., a 2.5% step change) into excitation and frequency response controls.  A large disturbance potentially means something that would be outside of a control system or units deadband.  EEI does not agree that entities should be required to inject large signal disturbances which could damage equipment or cause a system disturbance for a mandatory test.  For this reason, clarity regarding what was intended by this language should be provided.

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

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Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) to question #5.

Alan Kloster, On Behalf of: Allen Klassen, Evergy, 1,3,5,6; Allen Klassen, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Derek Brown, Evergy, 1,3,5,6; Derek Brown, Evergy, 1,3,5,6

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

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Yes, Consumers approved this question, however, there are some technical issues directly involved with R4 and R5 that need to be clarified.

Eric Sutlief, On Behalf of: CMS Energy - Consumers Energy Company - RF - Segments 3, 4, 5

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Leonard Kula, Independent Electricity System Operator, 2, 7/5/2022

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Xcel Energy generally supports the comments of EEI. Below are Xcel Energy comments that indicate additional or differing concerns. 

As indicated in response to Questions 3 and 4 of this comment form, Xcel Energy disagrees with including protective system trips in the Standard for Requirement 6.3.  Xcel Energy maintains that relay settings are static, not dynamic as the Standard title indicates.  Relay settings are already included in other PRC Standards and PRC Standards manage those settings. As indicated in Questions 3 and 4, these modifications would require Generator Owners (GO) to perform unnecessary model revisions as relay settings change more frequently and it will create an administrative burden with the number of modeling revisions and significantly increase costs for GOs when protective system changes are made.  Relay settings can be provided to Transmission Planners (TP) via PRC Standard communications and can also be provided in different formats and still achieve the same benefit; without causing GOs to perform unnecessary modeling. In addition, the TP can request protection system settings through MOD-032 data specifications if necessary.

Joe Gatten, On Behalf of: Xcel Energy, Inc. - MRO, WECC - Segments 1, 3, 5, 6

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Scott Kinney, Avista - Avista Corporation, 3, 7/5/2022

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Yes, Consumers approved this question, however, there are some technical issues directly involved with R4 and R5 that need to be clarified.

Karl Blaszkowski, CMS Energy - Consumers Energy Company, 3, 7/5/2022

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For Parts 6.1 and 6.2 should there be some level of criteria identified of acceptable reasons the attestation (6.1) or the test results (6.2) are not available. The current language appears to leave reason(s) open, which is difficult to audit.

WECC Entity Monitoring, Segment(s) 10, 1/30/2022

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Portland General Electric Company supports the comments provided by EEI.

Portland General Electric Co., Segment(s) 1, 3, 5, 6, 7/5/2022

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Dwanique Spiller, Berkshire Hathaway - NV Energy, 5, 7/5/2022

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AEP recommends that the content of the following sentence from the Technical Rationale in reference to the R6.5 term “large-signal disturbance” be factored into the standard itself, either as a subrequirement or a footnote, so that the term may be adequately defined and not open to wide interpretation that could detract from the effectiveness of the R6.5 verification: “The specific large-signal simulation tests that may be run on both EMT and positive sequence models for benchmarking comparisons may include balanced and unbalanced faults, delayed clearing phase-ground point of interconnection faults, temporary or transient over-voltages, rates of change of frequency (ROCOF), varying short circuit levels (or ratios), and phase angle jumps as may be specified by the Transmission Planner under R1.3.”.

Thomas Foltz, AEP, 5, 7/5/2022

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Texas RE seeks clarification on the difference in the terms “IBR unit(s)” and “plant” as used in Requirement Parts 4.3 and 6.3.  The addition of “or plant” appears in some parts, but not others.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 7/5/2022

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Israel Perez, On Behalf of: Pam Syrjala, Salt River Project, 1,3,5,6; Pam Syrjala, Salt River Project, 1,3,5,6; Zack Heim, Salt River Project, 1,3,5,6; Zack Heim, Salt River Project, 1,3,5,6

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Greg Davis, Georgia Transmission Corporation, 1, 7/5/2022

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WEC Energy Group supports EEI comments. 

Christine Kane, WEC Energy Group, Inc., 3, 7/5/2022

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BPA uses standard HVDC models available in grid simulation packages like Siemens PSS/E, GE PSLF or PowerWorld. The model data must match model structure that is implemented in the industry used grid simulators.

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

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Black Hills Corporation supports EEI and NAGF comments. 

Claudine Bates, Black Hills Corporation, 6, 7/5/2022

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National Grid supports EEI's comments.

Michael Jones, National Grid USA, 1, 7/5/2022

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Hot Answers

FE agrees with EEI’s comments:

EEI does not agree that 180 days is sufficient, noting that vendors often delay providing needed documentation (e.g., 60-90 days before receipt of documentation is not uncommon).  We further note that the current version of MOD-026 & 027 provide entities with 365 days to update the TP with new models.  For these reasons, EEI asks that the proposed  draft be changed from 180 days to 365 days.

Next, EEI does not agree the information provided in footnote #13 should be left as a footnote.  Footnote #13 contains important information regarding the expectations of changes to equipment that alter resource response characteristic, therefore this information should be contained in the body of the standard not a footnote. 

EEI recommends the following changes to Requirement R8 add needed clarity to this requirement, and provide the TP with 120 calendar days to review and provide a written response to the GOs and TOs (noting expanded data reviews will be required, including EMT models). See suggested edits to R8 below:

Each Transmission Planner shall review materials submitted pursuant to requirements R2-R7 and R9.  The Transmission Planner will send a written response to the submitter within 120 calendar days from receiving each submission. The written response shall include one of the following: [Violation Risk Factor: Lower] [Time Horizon: Operations Planning]

·    Notification of acceptance: the model and accompanying information meet the acceptance criteria established in Requirement R1, or

·    Notification of denial: the model and accompanying information does not meet acceptance criteria established in Requirement R1, or information submitted is incomplete. The notification of denial shall include an explanation and supporting evidence.

EEI suggests that Requirement R9 should include a dispute resolution process in order to resolve disagreements between the TP and GOs and TOs on the acceptability of the models provided. 

EEI also recommends that the Planning Coordinator also be added to these requirements.

FE Voter, Segment(s) 1, 3, 5, 6, 4, 12/20/2021

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Anna Todd, On Behalf of: Southern Indiana Gas and Electric Co., RF, Segments 3, 5, 6

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Other Answers

Jack Stamper, Clark Public Utilities, 3, 6/16/2022

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EEI does not agree that 180 days is sufficient, noting that vendors often delay providing needed documentation (e.g., 60-90 days before receipt of documentation is not uncommon).  We further note that the current version of MOD-026 & 027 provide entities with 365 days to update the TP with new models.  For these reasons, EEI asks that the proposed  draft be changed from 180 days to 365 days.

Next, EEI does not agree the information provided in footnote #13 should be left as a footnote.  Footnote #13 contains important information regarding the expectations of changes to equipment that alter resource response characteristic, therefore this information should be contained in the body of the standard not a footnote. 

 

EEI recommends the following changes to Requirement R8 add needed clarity to this requirement, and provide the TP with 120 calendar days to review and provide a written response to the GOs and TOs (noting expanded data reviews will be required, including EMT models). See suggested edits to R8 below:

Each Transmission Planner shall review materials submitted pursuant to requirements R2-R7 and R9.  The Transmission Planner will send a written response to the submitter within 120 calendar days from receiving each submission. the verified model and accompanying information, an updated verified model provided under Requirement R7, or a written response provided under Requirement R9, provided by a Generator Owner or Transmission Owner, and provide a written response to the submitter within 90 calendar days from receiving the verified model information. The written response shall include one of the following: [Violation Risk Factor: Lower] [Time Horizon: Operations Planning]

{C}·         Notification of acceptance: the model and accompanying information meet the acceptance criteria established in Requirement R1, or

{C}·         Notification of denial: the model and accompanying information does not meet acceptance criteria established in Requirement R1, or information submitted is incomplete. The notification of denial shall include an explanation and supporting evidence.

EEI suggests that Requirement R9 should include a dispute resolution process in order to resolve disagreements between the TP and GOs and TOs on the acceptability of the models provided. 

EEI also recommends that the Planning Coordinator also be added to these requirements.

Glen Farmer, Avista - Avista Corporation, 5, 6/28/2022

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No Comments

Brian Lindsey, Entergy, 1, 6/28/2022

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Richard Jackson, U.S. Bureau of Reclamation, 1, 6/29/2022

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Model verification for a given contingency should be maintained within the responsibility of the Transmission Planner, not the GO.

Martin Sidor, NRG - NRG Energy, Inc., 6, 6/29/2022

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Nazra Gladu, Manitoba Hydro , 1, 6/29/2022

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Model verification for a given contingency should be maintained within the responsibility of the Transmission Planner, not the GO.

Patricia Lynch, NRG - NRG Energy, Inc., 5, 6/29/2022

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OK

Joe O'Brien, NiSource - Northern Indiana Public Service Co., 6, 6/29/2022

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

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Nicolas Turcotte, Hydro-Qu?bec TransEnergie, 1, 6/30/2022

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Suggestions:

  1. Modify R7 to specify that R2, R3, R4, R5, and R6 can be complied with and submitted separately to ensure there is no confusion between GOs and TPs.  This action would also assist with audits.
  2. Remove note 13.  This action expands audit scope and the risk of non-compliance outweighs the benefits provided to reliability.
  3. R1 is open ended.  Specifics to comply should be detailed in this standard as in the existing MOD-026 and MOD-027 standards.
  4. M8: Remove the need to supply review date of submitted model and accompanying information.  Response within the 90 days is sufficient.
  5. Provide clarity on how the 180 day requirement applies.  Existing language could be read that it only applies to the agreed upon plan, and not to the updated model.

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

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Isidoro Behar, On Behalf of: Long Island Power Authority, , Segments 1

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AECI agrees with EEI’s comments:

 

EEI does not agree that 180 days is sufficient, noting that vendors often delay providing needed documentation (e.g., 60-90 days before receipt of documentation is not uncommon).  We further note that the current version of MOD-026 & 027 provide entities with 365 days to update the TP with new models.  For these reasons, EEI asks that the proposed  draft be changed from 180 days to 365 days.

Next, EEI does not agree the information provided in footnote #13 should be left as a footnote.  Footnote #13 contains important information regarding the expectations of changes to equipment that alter resource response characteristic, therefore this information should be contained in the body of the standard not a footnote. 

 

EEI recommends the following changes to Requirement R8 add needed clarity to this requirement, and provide the TP with 120 calendar days to review and provide a written response to the GOs and TOs (noting expanded data reviews will be required, including EMT models). See suggested edits to R8 below:

Each Transmission Planner shall review materials submitted pursuant to requirements R2-R7 and R9.  The Transmission Planner will send a written response to the submitter within 120 calendar days from receiving each submission. The written response shall include one of the following: [Violation Risk Factor: Lower] [Time Horizon: Operations Planning]

·    Notification of acceptance: the model and accompanying information meet the acceptance criteria established in Requirement R1, or

·    Notification of denial: the model and accompanying information does not meet acceptance criteria established in Requirement R1, or information submitted is incomplete. The notification of denial shall include an explanation and supporting evidence.

EEI suggests that Requirement R9 should include a dispute resolution process in order to resolve disagreements between the TP and GOs and TOs on the acceptability of the models provided. 

EEI also recommends that the Planning Coordinator also be added to these requirements.

AECI, Segment(s) 1, 3, 6, 5, 3/4/2021

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Sean Steffensen, IDACORP - Idaho Power Company, 1, 6/30/2022

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AZPS generally supports the language in Requirements R7, R8, and R9 but supports the following EEI recommendation: “EEI does not agree the information provided in footnote #13 should be left as a footnote. Footnote #13 contains important information regarding the expectations of changes to equipment that alter resource response characteristic, therefore this information should be contained in the body of the standard not a footnote.”

Michelle Amarantos, APS - Arizona Public Service Co., 5, 6/30/2022

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Constellation agrees with proposed language.

Kimberly Turco on behalf of Constellation Segments 5 and 6

Alison Mackellar, Constellation, 5, 6/30/2022

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Constellation agrees with proposed language.

 

Kimberly Turco on behalf of Constellation Segments 5 and 6

Kimberly Turco, Constellation, 6, 6/30/2022

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For R7, ATC suggests the following change to assure that the updated models will be verified before equipment is installed.  The word “within” could mean after installation.

“Each Generator Owner or Transmission Owner shall provide an updated verified model(s) or a mutually agreed upon plan with its Transmission Planner to verify the model in accordance with Requirements R2–R6 to its Transmission Planner within 180 calendar days prior to of making a change to in-service equipment specified in Part 2.2, 3.2, 4.2, 5.2, or 6.3 that alters the equipment response characteristic”

LaTroy Brumfield, American Transmission Company, LLC, 1, 7/1/2022

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Comments: EEI does not agree that 180 days is sufficient, noting that vendors often delay providing needed documentation (e.g., 60-90 days before receipt of documentation is not uncommon).  We further note that the current version of MOD-026 & 027 provide entities with 365 days to update the TP with new models.  For these reasons, EEI asks that the proposed  draft be changed from 180 days to 365 days.

Next, EEI does not agree the information provided in footnote #13 should be left as a footnote.  Footnote #13 contains important information regarding the expectations of changes to equipment that alter resource response characteristic, therefore this information should be contained in the body of the standard not a footnote. 

 

EEI recommends the following changes to Requirement R8 add needed clarity to this requirement, and provide the TP with 120 calendar days to review and provide a written response to the GOs and TOs (noting expanded data reviews will be required, including EMT models). See suggested edits to R8 below:

Each Transmission Planner shall review materials submitted pursuant to requirements R2-R7 and R9.  The Transmission Planner will send a written response to the submitter within 120 calendar days from receiving each submission.  The written response shall include one of the following: [Violation Risk Factor: Lower] [Time Horizon: Operations Planning]

{C}·         Notification of acceptance: the model and accompanying information meet the acceptance criteria established in Requirement R1, or

{C}·         Notification of denial: the model and accompanying information does not meet acceptance criteria established in Requirement R1, or information submitted is incomplete. The notification of denial shall include an explanation and supporting evidence.

EEI suggests that Requirement R9 should include a dispute resolution process in order to resolve disagreements between the TP and GOs and TOs on the acceptability of the models provided. 

EEI also recommends that the Planning Coordinator also be added to these requirements.

Mike Magruder, Avista - Avista Corporation, 1, 7/1/2022

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EEI does not agree that 180 days is sufficient, noting that vendors often delay providing needed documentation (e.g., 60-90 days before receipt of documentation is not uncommon).  We further note that the current version of MOD-026 & 027 provide entities with 365 days to update the TP with new models.  For these reasons, EEI asks that the proposed  draft be changed from 180 days to 365 days.

Next, EEI does not agree the information provided in footnote #13 should be left as a footnote.  Footnote #13 contains important information regarding the expectations of changes to equipment that alter resource response characteristic, therefore this information should be contained in the body of the standard not a footnote. 

 

EEI recommends the following changes to Requirement R8 add needed clarity to this requirement, and provide the TP with 120 calendar days to review and provide a written response to the GOs and TOs (noting expanded data reviews will be required, including EMT models). See suggested edits to R8 below:

Each Transmission Planner shall review materials submitted pursuant to requirements R2-R7 and R9.  The Transmission Planner will send a written response to the submitter within 120 calendar days from receiving each submission. The written response shall include one of the following: [Violation Risk Factor: Lower] [Time Horizon: Operations Planning]

  • Notification of acceptance: the model and accompanying information meet the acceptance criteria established in Requirement R1, or
  • Notification of denial: the model and accompanying information does not meet acceptance criteria established in Requirement R1, or information submitted is incomplete. The notification of denial shall include an explanation and supporting evidence.

EEI suggests that Requirement R9 should include a dispute resolution process in order to resolve disagreements between the TP and GOs and TOs on the acceptability of the models provided. 

EEI also recommends that the Planning Coordinator also be added to these requirements.

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

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Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) to question #6.

Alan Kloster, On Behalf of: Allen Klassen, Evergy, 1,3,5,6; Allen Klassen, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Derek Brown, Evergy, 1,3,5,6; Derek Brown, Evergy, 1,3,5,6

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

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Consumers agree with these requirements; however, we would like the 360 days rather than the 180 calendar days of making changes to in-service equipment.

Eric Sutlief, On Behalf of: CMS Energy - Consumers Energy Company - RF - Segments 3, 4, 5

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Leonard Kula, Independent Electricity System Operator, 2, 7/5/2022

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Xcel Energy supports EEI's comment. 

Joe Gatten, On Behalf of: Xcel Energy, Inc. - MRO, WECC - Segments 1, 3, 5, 6

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Scott Kinney, Avista - Avista Corporation, 3, 7/5/2022

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Consumers agree with these requirements; however, we would like the 360 days rather than the 180 calendar days of making changes to in-service equipment.

Karl Blaszkowski, CMS Energy - Consumers Energy Company, 3, 7/5/2022

- 0 - 0

WECC Entity Monitoring, Segment(s) 10, 1/30/2022

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Portland General Electric Company supports the comments provided by EEI.

Portland General Electric Co., Segment(s) 1, 3, 5, 6, 7/5/2022

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R7 should be updated to also include that the GO or TO provide updated protection models specified in R2.3, R3.3, R4.3 and R5.3 when protection settings are modified.

Dwanique Spiller, Berkshire Hathaway - NV Energy, 5, 7/5/2022

- 0 - 0

While AEP has no objections to the language proposed in MOD-026-2 Requirements R7, R8, and R9, we do recommend that a footnote be added to R9 to make it clear that the Transmission Planner’s request for a model review may also be justified on the basis of the simulated unit or plant response not matching the measured unit or plant response to an event as in the existing MOD-026 and MOD-027. Also, the language provided in the mapping document on page 6 for R9 differs from that in the proposed standard R9 text and we prefer the language as provided in the mapping document (“…or a technical justification for model review…”) which suggests a model review may be initiated for reasons not limited to “identified model or accompanying information deficiencies”.

Thomas Foltz, AEP, 5, 7/5/2022

- 0 - 0

Texas RE recommends including 2.3, 3.3, 4.3, and 5.3 in Requirement R7 so a change in Protection System response is captured in the updated verified model.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 7/5/2022

- 0 - 0

Israel Perez, On Behalf of: Pam Syrjala, Salt River Project, 1,3,5,6; Pam Syrjala, Salt River Project, 1,3,5,6; Zack Heim, Salt River Project, 1,3,5,6; Zack Heim, Salt River Project, 1,3,5,6

- 0 - 0

The SDT should consider clarifying wording changes to R8.  wording such as, "Each Transmission Planner shall review the verified model and accompanying information under Requirements R2-R6,…" may provide value-added specifity to the requirement.

Greg Davis, Georgia Transmission Corporation, 1, 7/5/2022

- 0 - 0

WEC Energy Group supports EEI comments. 

Christine Kane, WEC Energy Group, Inc., 3, 7/5/2022

- 0 - 0

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

- 0 - 0

Black Hills Corporation supports EEI comments. In addition to transmission planner, planning coordinator needs to be added to the language.

Claudine Bates, Black Hills Corporation, 6, 7/5/2022

- 0 - 0

National Grid supports EEI's comments.

Michael Jones, National Grid USA, 1, 7/5/2022

- 0 - 0

Hot Answers

Clarification toward our comments will determine cost effectiveness

FE Voter, Segment(s) 1, 3, 5, 6, 4, 12/20/2021

- 0 - 0

The changes to MOD-026-2 to require GO/TOs to have validated models to provide to the TP is not consistent with the proposed SARs. The EMT modeling requirements is not mention in either SAR and implementation would not be cost effective.

Anna Todd, On Behalf of: Southern Indiana Gas and Electric Co., RF, Segments 3, 5, 6

- 0 - 0

Other Answers

No. As I stated above, the SAR indicates that voltage control behavior during large disturbance conditions is not verified. That is not so. PRC-024 requires generators to meet region-specific voltage and frequency ride through requirements and to provide the settings for it voltaage and frequecy protection to Transmission Planners. In addition, PRC-006 requires the provision of UFLS tripping data that includes generator frequecy ride through trip settings. Adding these to MOD-026 does nothing more than make Generator Owners prove compliance with multiple standards for the same action. This is not in accordance witht the efficiency goals of the NERC Standards development which included consolidation identical actions in multiple standards into a single standard to avoid unnecessary duplication of efforts.

The addition of the protection system modeling data to MOD-026 increases the efforts (and cost) of providing protection system performance characteristices by including the requirements in multiple standards. This is not efficient or cost effective.

Jack Stamper, Clark Public Utilities, 3, 6/16/2022

- 0 - 0

Glen Farmer, Avista - Avista Corporation, 5, 6/28/2022

- 0 - 0

No Comments

Brian Lindsey, Entergy, 1, 6/28/2022

- 0 - 0

Richard Jackson, U.S. Bureau of Reclamation, 1, 6/29/2022

- 0 - 0

By their inherent nature, GOs do not belong in the transmission planning process.  GOs should not have the assigned model development and validation responsibility for an ever-increasing growth of scope in the transmission planning process. Therefore, it is not cost-effective for a GO to function in a transmission planning role to perform model parameterization checks, usability, initialization, and interoperability assessments.  This is effectively passing some of the cost of transmission planning to the Generator Owners, and the proposed models have not been shown to improve reliability.    

MOD-026 & -027 originated from a simple but costly need to validate dynamic models of generators, exciters, and governors.  The activity was important due to the uncertainty of accurate models for the dynamic response of excitation controls and governors, which was manifested in high profile blackouts in WECC during the 1990s.  At the time, all controls were analog with less predictable performance characteristics and less certainty.   Nowadays, with microprocessor-based controls and PRC-005 maintenance practices in place for GOs, there is little justification to mandate field-verified models of excitation control limiters, frequency controls, or Protection System elements if the technical basis for requiring PRC-019, -024, -025, -026 were correct. We are not aware of identified reliability gaps or quantified improvements in reliability to justify the scope growth of R2 and R3; this was not the reason for the SAR to initiate a standard revision. 

Martin Sidor, NRG - NRG Energy, Inc., 6, 6/29/2022

- 0 - 0

See the previous comments regarding the minimum modeling requirements.

Nazra Gladu, Manitoba Hydro , 1, 6/29/2022

- 0 - 0

By their inherent nature, GOs do not belong in the transmission planning process.  GOs should not have the assigned model development and validation responsibility for an ever-increasing growth of scope in the transmission planning process. Therefore, it is not cost-effective for a GO to function in a transmission planning role to perform model parameterization checks, usability, initialization, and interoperability assessments.  This is effectively passing some of the cost of transmission planning to the Generator Owners, and the proposed models have not been shown to improve reliability.    MOD-026 & -027 originated from a simple but costly need to validate dynamic models of generators, exciters, and governors.  The activity was important due to the uncertainty of accurate models for the dynamic response of excitation controls and governors, which was manifested in high profile blackouts in WECC during the 1990s.  At the time, all controls were analog with less predictable performance characteristics and less certainty.   Nowadays, with microprocessor-based controls and PRC-005 maintenance practices in place for GOs, there is little justification to mandate field-verified models of excitation control limiters, frequency controls, or Protection System elements if the technical basis for requiring PRC-019, -024, -025, -026 were correct. We are not aware of identified reliability gaps or quantified improvements in reliability to justify the scope growth of R2 and R3; this was not the reason for the SAR to initiate a standard revision.

Patricia Lynch, NRG - NRG Energy, Inc., 5, 6/29/2022

- 0 - 0

Joe O'Brien, NiSource - Northern Indiana Public Service Co., 6, 6/29/2022

- 0 - 0

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

- 0 - 0

Nicolas Turcotte, Hydro-Qu?bec TransEnergie, 1, 6/30/2022

- 0 - 0

Properly populated generic positive sequence models for IBRs can accurately represent the equipment sufficiently for studies.  The cases mentioned in the SAR were a result of improper parameters in those models.  Requiring EMT models and simulations will add significant costs to GOs when the focus should be on properly verifying existing ones. 

While EMT and positive sequence models are useful for their specific studies (e.g., EMT is mainly used for insulation coordination, switching surge, SSR, TRV, higher-frequency control interactions, series capacitor design studies, etc.), when comparing the models one has to be aware of the differences of the two domains and the limitations of such comparisons.

Transmission planners can't study the entire system with EMT models and should only be required if Transmission provides justification for them on a case-by-case basis. 

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

- 0 - 0

Isidoro Behar, On Behalf of: Long Island Power Authority, , Segments 1

- 0 - 0

Clarification toward our comments will determine cost effectiveness

 

 

AECI, Segment(s) 1, 3, 6, 5, 3/4/2021

- 0 - 0

Sean Steffensen, IDACORP - Idaho Power Company, 1, 6/30/2022

- 0 - 0

The new standard addresses the needs of inverter-based resources, however, the need for EMT models in addition to positive sequence models would add significant cost and time to model verification. The reason for EMT models described in the technical rationale was to address unbalanced faults which was not a need described in the SAR. 

Sub-Synchronous Resonance and unbalanced faults affect traditional generation as well. Even though EMT modeling has been available for decades, it has not been required to develop these models or provide them to any entity for traditional resources. Since most utilities do not currently model generation resources with an EMT program, it would require significant investment in personnel, training, or consulting services to prepare and validate EMT models. The proposed standard does not adequately justify this expense. R4 and R5 should be more than adequate for modeling IBRs accurately for transmission planning purposes.

Michelle Amarantos, APS - Arizona Public Service Co., 5, 6/30/2022

- 0 - 0

Constellation relies on third party contractors for the completion of MOD-026-1 and MOD-027-1 models due to this lack of expertise and modeling software. The addition of expanded modeling requirements will increase the scope and likely the cost of analysis being completed, as there is limited experts in the industry.

Kimberly Turco on behalf of Constellation Segments 5 and 6

Alison Mackellar, Constellation, 5, 6/30/2022

- 0 - 0

Constellation relies on third party contractors for the completion of MOD-026-1 and MOD-027-1 models due to this lack of expertise and modeling software. The addition of expanded modeling requirements will increase the scope and likely the cost of analysis being completed, as there is limited experts in the industry.

 

Kimberly Turco on behalf of Constellation Segments 5 and 6

Kimberly Turco, Constellation, 6, 6/30/2022

- 0 - 0

Unsure

LaTroy Brumfield, American Transmission Company, LLC, 1, 7/1/2022

- 0 - 0

Mike Magruder, Avista - Avista Corporation, 1, 7/1/2022

- 0 - 0

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

- 0 - 0

Evergy contends that their will be costs associated with procurring the software required to perform EMT model studies, train employees who do not posses the skills required to perform EMT models, and develop the processes necessary to ensure compliance with the various modeling requirements when using EMT models.  Evergy estimates those costs will be at least $100,000.

Alan Kloster, On Behalf of: Allen Klassen, Evergy, 1,3,5,6; Allen Klassen, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Derek Brown, Evergy, 1,3,5,6; Derek Brown, Evergy, 1,3,5,6

- 0 - 0

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

- 0 - 0

Consumers Energy believes there needs to be a technical attachment added to this requirement clarifying expectations.  Also, this SAR is a little open-ended, this may give entities different outcomes.

Eric Sutlief, On Behalf of: CMS Energy - Consumers Energy Company - RF - Segments 3, 4, 5

- 0 - 0

Leonard Kula, Independent Electricity System Operator, 2, 7/5/2022

- 0 - 0

The proposed modifications to the Standard will cause Generator Owners to perform a high increase in model revisions and incur a dramatic increase in costs that outweigh any potential benefit to BES reliability. 

Joe Gatten, On Behalf of: Xcel Energy, Inc. - MRO, WECC - Segments 1, 3, 5, 6

- 0 - 0

Scott Kinney, Avista - Avista Corporation, 3, 7/5/2022

- 0 - 0

Consumers Energy believes there needs to be a technical attachment added to this requirement clarifying expectations.  Also, this SAR is a little open-ended, this may give entities different outcomes.

Karl Blaszkowski, CMS Energy - Consumers Energy Company, 3, 7/5/2022

- 0 - 0

WECC Entity Monitoring, Segment(s) 10, 1/30/2022

- 0 - 0

Portland General Electric Company supports the comments provided by EEI.

Portland General Electric Co., Segment(s) 1, 3, 5, 6, 7/5/2022

- 0 - 0

Dwanique Spiller, Berkshire Hathaway - NV Energy, 5, 7/5/2022

- 0 - 0

AEP does not agree the language of MOD-026-2 addresses the issues outlined in the two SARs in a cost effective manner. The proposed revisions would result in the Generator Owner of synchronous units incurring significant, additional costs to model protection functions.

Thomas Foltz, AEP, 5, 7/5/2022

- 0 - 0

Texas RE does not have comments on this question.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 7/5/2022

- 0 - 0

The addition of EMT models would add significant cost and time to get everyone trained and be able to maintain these models. The additional implementation timeframe of 48 months for R2-R6 does not make it more cost effective, but it helps distribute the additional upfront costs.

Israel Perez, On Behalf of: Pam Syrjala, Salt River Project, 1,3,5,6; Pam Syrjala, Salt River Project, 1,3,5,6; Zack Heim, Salt River Project, 1,3,5,6; Zack Heim, Salt River Project, 1,3,5,6

- 0 - 0

Cost impact is not clear. Reference comments to other questions.

Greg Davis, Georgia Transmission Corporation, 1, 7/5/2022

- 0 - 0

 Concern about cost for 2 year implementation of EMT models.

Christine Kane, WEC Energy Group, Inc., 3, 7/5/2022

- 0 - 0

BPA believes this version of the standard puts a substantial burden on the industry to find contractors to do a complete overhaul of testing and is not cost effective to meet the standards.  The proposed standard does not take into effect the current life cycle of the existing standards. There is very limited expertise available for the EMT models on the Generator Owner and Transmission Planner sides which also creates a burden.

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

- 0 - 0

Black Hills Corporation is unable to determine if this will or will not be cost effective. 

Claudine Bates, Black Hills Corporation, 6, 7/5/2022

- 0 - 0

Michael Jones, National Grid USA, 1, 7/5/2022

- 0 - 0

Hot Answers

FE agrees with EEI’s comments:

EEI does not support the additional 2 year compliance requirement for EMT models.  The skills and tools necessary to develop these models are only now being developed within most companies and while we recognize that some areas have a  need to become quickly proficient, this is not reflective of all areas or regions.  Moreover, compulsory compliance within 2 years  of the effective date of this standard is too aggressive, even in those areas with higher needs, and does not provide those entities with the latitude to develop the necessary skills that will, over time, be beneficial learnings for the rest of the industry.  For these reasons, the SDT should modify the 2 year compliance requirement for EMT models to 4 years.  This will better ensure the industry has the skills, tools, training and experience needed to meet this challenging goal as the resource mix grows and expands its dependance on IBRs.

FE Voter, Segment(s) 1, 3, 5, 6, 4, 12/20/2021

- 0 - 0

We could comply with the dynamic modeling as proposed within the implementation period, however we could not provide the EMT modeling within the proposed implemnation plan. It would be difficult to provide an alternate estimate timeframe for the EMT requirements since we currently do not have any modeling and would require further guidance from NERC. 

Anna Todd, On Behalf of: Southern Indiana Gas and Electric Co., RF, Segments 3, 5, 6

- 0 - 0

Other Answers

I agree with this. My utility only has one applicable generaton and is planning on completing its existing MOD-026-1 and MOD-026-2 modeling update in June, 2022. I believe it would be ineficient to require compliance with any new modeling requirements of MOD-026-2 until the new ten year time period has elapsed in 2032.

Jack Stamper, Clark Public Utilities, 3, 6/16/2022

- 0 - 0

EEI does not support the additional 2 year compliance requirement for EMT models.  The skills and tools necessary to develop these models are only now being developed within most companies and while we recognize that some areas have a  need to become quickly proficient, this is not reflective of all areas or regions.  Moreover, compulsory compliance within 2 years  of the effective date of this standard is too aggressive, even in those areas with higher needs, and does not provide those entities with the latitude to develop the necessary skills that will, over time, be beneficial learnings for the rest of the industry.  For these reasons, the SDT should modify the 2 year compliance requirement for EMT models to 4 years.  This will better ensure the industry has the skills, tools, training and experience needed to meet this challenging goal as the resource mix grows and expands its dependance on IBRs.

 

Glen Farmer, Avista - Avista Corporation, 5, 6/28/2022

- 0 - 0

No Comments

Brian Lindsey, Entergy, 1, 6/28/2022

- 0 - 0

Reclamation recommends the new R1 model requirements and processes be developed and made available to Generator Owners and Transmission Owners within 24 months following regulatory approval. For newly applicable Facilities, Reclamation recommends an additional 24 months after the new model requirements and processes are received to complete the models of the applicable units. For existing applicable Facilities, Reclamation recommends requirements R2 through R9 have a 10-year implementation plan for all Facilities to maintain continuity with entities’ existing modeling schedules under the current versions of MOD-025, MOD-026, and MOD-027.

Richard Jackson, U.S. Bureau of Reclamation, 1, 6/29/2022

- 0 - 0

At least 4 years will be required for retesting planning.

Martin Sidor, NRG - NRG Energy, Inc., 6, 6/29/2022

- 0 - 0

Nazra Gladu, Manitoba Hydro , 1, 6/29/2022

- 0 - 0

At least 4 years will be required for retesting planning.

Patricia Lynch, NRG - NRG Energy, Inc., 5, 6/29/2022

- 0 - 0

With such major changes the Implementation plan should be increased by at least 4 years.

Joe O'Brien, NiSource - Northern Indiana Public Service Co., 6, 6/29/2022

- 0 - 0

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

- 0 - 0

Nicolas Turcotte, Hydro-Qu?bec TransEnergie, 1, 6/30/2022

- 0 - 0

Duke Energy suggest a 5-year implementation plan for R2-6 and a 2-year implementation for R1, R7, R8, and R9.  This period is needed because NERC auditors require GOs to put program documents, procedures, test plans, work orders, etc., in place.  Duke Energy will require time to make these changes and considers the suggested timeframe to restrictive.

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

- 0 - 0

It is recommended that the implementation plan and compliance dates for R4 and R6 for existing “FACTS devices per Section 4.2.4.2”, which are being affected by these modeling requirements for the first time, be clarified. It is not clear if the compliance date is 2 years or 10 years.

Specifically for Requirements 4 and 6 –

The Implementation plan states that “Applicable Entities shall not be required to comply with Requirement R2, R3, R4, R5, and R6 until twenty-four (24) months after the effective date of Reliability Standard MOD-026-2.”

For existing “FACTS devices per Section 4.2.4.2”, which are being affected by these modeling requirements for the first time, it is interpreted that the compliance date for R4 and R6 is twenty-four months after the effective date of Reliability Standard MOD-026-2. If this interpretation is correct, then this implementation plan timeframe is deemed to be too short.

It is likely that many Transmission Owners (TOs) that own rely on the services of the nonsynchronous resource (i.e. FACTS, HVDC) vendor / OEM for model development, verficiation and validation – due to the specialized nature of these resources. The proposed MOD-026-2 would likely increase a TO’s reliance on support services from their nonsynchronous resource vendors / OEMs. This increased reliance on specific OEMs across the continent may lead to much longer lead times for OEM support services related to model development, benchmarking and verification. Such OEM longer lead times may put TO compliance obligations in jeopardy.

As an alternative, for existing “FACTS devices per Section 4.2.4.2” which are being affected by these modeling requirements for the first time, it is recommended that the compliance date for R4 and R6 be at least forty-eight months after the effective date of Reliability Standard MOD-026-2.

It is recommended that the drafting team consider working with industry vendors / OEMs of transmission connected nonsynchronous sources (i.e. FACTS, HVDC) to see from their perpsective if the stated implementation plan / compliance dates are feasible.

 

Isidoro Behar, On Behalf of: Long Island Power Authority, , Segments 1

- 0 - 0

AECI agrees with EEI’s comments:

EEI does not support the additional 2 year compliance requirement for EMT models.  The skills and tools necessary to develop these models are only now being developed within most companies and while we recognize that some areas have a  need to become quickly proficient, this is not reflective of all areas or regions.  Moreover, compulsory compliance within 2 years  of the effective date of this standard is too aggressive, even in those areas with higher needs, and does not provide those entities with the latitude to develop the necessary skills that will, over time, be beneficial learnings for the rest of the industry.  For these reasons, the SDT should modify the 2 year compliance requirement for EMT models to 4 years.  This will better ensure the industry has the skills, tools, training and experience needed to meet this challenging goal as the resource mix grows and expands its dependance on IBRs.

AECI, Segment(s) 1, 3, 6, 5, 3/4/2021

- 0 - 0

Sean Steffensen, IDACORP - Idaho Power Company, 1, 6/30/2022

- 0 - 0

AZPS agrees with the implementation plan if the recommendation to remove the required use of EMT models is accepted. If it is not removed, AZPS supports the following comment submitted by EEI: “EEI does not support the additional 2 year compliance requirement for EMT models. The skills and tools necessary to develop these models are only now being developed within most companies and while we recognize that some areas have a need to become quickly proficient, this is not reflective of all areas or regions. Moreover, compulsory compliance within 2 years of the effective date of this standard is too aggressive, even in those areas with higher needs, and does not provide those entities with the latitude to develop the necessary skills that will, over time, be beneficial learnings for the rest of the industry. For these reasons, the SDT should modify the 2 year compliance requirement for EMT models to 4 years. This will better ensure the industry has the skills, tools, training and experience needed to meet this challenging goal as the resource mix grows and expands its dependance on IBRs.”

Michelle Amarantos, APS - Arizona Public Service Co., 5, 6/30/2022

- 0 - 0

Constellation requests the consideration to allow excitation and governor modeling to be done separately and not in conjunction, as completing modeling's together at the next interval cycle would short cycle models completed under the original implementation plan. As models were planned and executed separately throughout the periodic implementation.

Kimberly Turco on behalf of Constellation Segments 5 and 6

Alison Mackellar, Constellation, 5, 6/30/2022

- 0 - 0

Constellation requests the consideration to allow excitation and governor modeling to be done separately and not in conjunction, as completing modeling's together at the next interval cycle would short cycle models completed under the original implementation plan. As models were planned and executed separately throughout the periodic implementation.

 

Kimberly Turco on behalf of Constellation Segments 5 and 6

Kimberly Turco, Constellation, 6, 6/30/2022

- 0 - 0

LaTroy Brumfield, American Transmission Company, LLC, 1, 7/1/2022

- 0 - 0

Comments: EEI does not support the additional 2 year compliance requirement for EMT models.  The skills and tools necessary to develop these models are only now being developed within most companies and while we recognize that some areas have a  need to become quickly proficient, this is not reflective of all areas or regions.  Moreover, compulsory compliance within 2 years  of the effective date of this standard is too aggressive, even in those areas with higher needs, and does not provide those entities with the latitude to develop the necessary skills that will, over time, be beneficial learnings for the rest of the industry.  For these reasons, the SDT should modify the 2 year compliance requirement for EMT models to 4 years.  This will better ensure the industry has the skills, tools, training and experience needed to meet this challenging goal as the resource mix grows and expands its dependance on IBRs.

 

Mike Magruder, Avista - Avista Corporation, 1, 7/1/2022

- 0 - 0

EEI does not support the additional 2 year compliance requirement for EMT models.  The skills and tools necessary to develop these models are only now being developed within most companies and while we recognize that some areas have a  need to become quickly proficient, this is not reflective of all areas or regions.  Moreover, compulsory compliance within 2 years  of the effective date of this standard is too aggressive, even in those areas with higher needs, and does not provide those entities with the latitude to develop the necessary skills that will, over time, be beneficial learnings for the rest of the industry.  For these reasons, the SDT should modify the 2 year compliance requirement for EMT models to 4 years.  This will better ensure the industry has the skills, tools, training and experience needed to meet this challenging goal as the resource mix grows and expands its dependance on IBRs.

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

- 0 - 0

Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) to question #8.

Alan Kloster, On Behalf of: Allen Klassen, Evergy, 1,3,5,6; Allen Klassen, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Derek Brown, Evergy, 1,3,5,6; Derek Brown, Evergy, 1,3,5,6

- 0 - 0

Dominion Energy does not agree that the 2-year implementation plan for Requirements R2-R6 is adequate. The expansion of the applicable unit criteria will bring a large number of our existing facilities which previously were not in scope within scope of MOD-026-2, many of which are solar facilities requiring additional EMT model verifications under Requirement R6. With the limited number of engineering firms capable of model development and verification, as well as the continued model reverifications for changes under Requirement R7 and initial verifications for new applicable units during the implementation period, it will be a challenge to meet the 2-year compliance deadline.

Dominion Energy proposes either an extension to the implementation plan to at least 3 years or a phased-in implementation plan, similar to MOD-026-1 and MOD-027-1, over at least a 3-year period to allow for the planning, scheduling, testing, and model development of the additional in-scope facilities.

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

- 0 - 0

Consumers Energy is fine with this implementation plan time frame. 

Eric Sutlief, On Behalf of: CMS Energy - Consumers Energy Company - RF - Segments 3, 4, 5

- 0 - 0

Leonard Kula, Independent Electricity System Operator, 2, 7/5/2022

- 0 - 0

Xcel Energy supports EEI's comment.

Joe Gatten, On Behalf of: Xcel Energy, Inc. - MRO, WECC - Segments 1, 3, 5, 6

- 0 - 0

Scott Kinney, Avista - Avista Corporation, 3, 7/5/2022

- 0 - 0

Consumers Energy is fine with this implementation plan time frame. 

Karl Blaszkowski, CMS Energy - Consumers Energy Company, 3, 7/5/2022

- 0 - 0

No Comment

WECC Entity Monitoring, Segment(s) 10, 1/30/2022

- 0 - 0

  • Portland General Electric supports EEI comments for extension of the compliance requirement for EMT models to four years.   
  • We do agree with the implementation plan's Initial Performance of Periodic Requirements and in particular language around when a periodic model verification date falls between the effective date of MOD-026-2 and the Compliance Date.

Portland General Electric Co., Segment(s) 1, 3, 5, 6, 7/5/2022

- 0 - 0

The proposed implementation plan is reasonable with the exception of the requirements related to EMT models.  NV Energy does not have the experience, knowledge, or tools required to create requirements and processes to determine acceptable EMT models.  NV Energy proposes that an implementation timeline of at least 2 years for R1.3 should be used to procure software capable of analyzing EMT models and proper training to ensure that the models are being analyzed correctly.

Dwanique Spiller, Berkshire Hathaway - NV Energy, 5, 7/5/2022

- 0 - 0

AEP believes the proposed Implementation Plan is too aggressive and would not allow entities to accomplish all the proposed changes within its wider scope. In addition, all Generator Owners would be competing with the same group of third party consultants that specialize in performing model verification, leading to additional impacts and challenges in achieving compliance. Rather than allowing only two additional years for compliance with R2-R6, we suggest allowing three or four additional years.

Thomas Foltz, AEP, 5, 7/5/2022

- 0 - 0

Texas RE understands the Implementation Plan as follows:

{C}·       {C}The first bookend for the 10-year verification occurs during the implementation of MOD-026-1 and MOD-027-1.  This could potentially be anytime between July 1, 2014 and July 1, 2024. 

{C}·       {C}The second verification would need to occur 10 years after the first verification, which was done in the time between July 1, 2014 and July 1, 2024 or the Compliance Date for R2-R6, whichever is later. 

 

Regarding this sentence: “When the periodic timeframe falls between the effective date of MOD-026-2 and the Compliance Date for the respective requirement, the Applicable Entity shall comply with the Requirement(s) of MOD-026-2 by the Compliance Date.”  Texas RE understands this to mean, in the case where MOD-026-2 is approved on 10/15/2022 making the Effective Date 1/1/2023 and the Compliance Date 1/1/2025, the following:

Scenario 1: The verification occurred on 7/1/2016, making the second verification due by 7/1/2026.  In this scenario, the entity would have to do its second verification by 7/1/2026, since the due date is after the Compliance Date.

 

Scenario 2:  The verification occurred on 8/1/2014, making the second verification due 8/1/2024.  In this scenario, entity would have until 1/1/2025 to do the second verification, since the due date is between the effective date of MOD-026-2 and the Compliance Date.   

 

Is this the intent of the SDT’s language in the implementation plan?

 

Additionally, Texas RE noticed that the Implementation Plan uses the term Applicable Entities.  Since the term is capitalized, it seems as though it should be defined somewhere.  It is not in the NERC Glossary, nor is it defined in the standard.  Is it intended that Applicable Entities are the Functional Entities described in section A. 4?

Rachel Coyne, Texas Reliability Entity, Inc., 10, 7/5/2022

- 0 - 0

We support other entities sentiment that 24 months is not sufficient for EMT models. As such, we agree with others that 48 months is more appropriate for R2-R6, rather than the 24 months currently spelled out in the implementation plan.

Israel Perez, On Behalf of: Pam Syrjala, Salt River Project, 1,3,5,6; Pam Syrjala, Salt River Project, 1,3,5,6; Zack Heim, Salt River Project, 1,3,5,6; Zack Heim, Salt River Project, 1,3,5,6

- 0 - 0

Greg Davis, Georgia Transmission Corporation, 1, 7/5/2022

- 0 - 0

 Agree with 1 year implementation period for R1, R7, R8 and R9.  Would like 4 years for R2-6.

Christine Kane, WEC Energy Group, Inc., 3, 7/5/2022

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If a GO’s testing is due within two years, the GO would then also need to include the EMT models, which isn’t feasible.  BPA believes that more time may be needed to better understand the EMT models from the GO and TP perspective as well.

EMT – BPA does not feel that EMT should be a priority, as it is categorically buredensome.  BPA does not believe this requirement is needed.  The timeline is not practical, BPA believes the EMT requirement is not achievable by the industry within this timeframe.

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

- 0 - 0

Black Hills Corporation supports EEI comments.

Claudine Bates, Black Hills Corporation, 6, 7/5/2022

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National Grid supports EEI's comments.

Michael Jones, National Grid USA, 1, 7/5/2022

- 0 - 0

Hot Answers

First Energy agrees with EEI's comments:

Proposed change to Facilities Section to more clearly align with the approved BES Definition (see below):

4.2. Facilities: For the purpose of this standard, the term “applicable units” shall mean any one of the following:

4.2.1 Individual generating resource meeting the unit criteria set by Inclusion I2 of the BES definition.

4.2.2 Generating plant/Facility meeting the plant/Facility criteria set by Inclusion I2 of the BES definition.

4.2.3 Dispersed power producing resources that aggregate to a total capacity set by Inclusion I4 of the BES definition.

4.2.4 Dynamic reactive resources meeting the criteria set by Inclusion I5 of the BES definition with a gross nameplate rating greater than 20 MVAr, or an aggregated site rating greater than 20 MVAr, including, but not limited to:

4.2.4.1 Synchronous condenser; and

4.2.4.2 Flexible alternating current transmission system (FACTS) devices.

4.2.5 HVDC terminal equipment including:

4.2.5.1 Line commutated converter (LCC); and

4.2.5.2 Voltage source converter (VSC)

Attachment 1 (Model Verification Periodicity) Comment

EEI suggests the following changes to Row 11, noting that OEMs are under no specific obligation to provide the models identified in MOD-026-2, unless such a requirement was written into the contract at the time the resource was purchased.

Verification Conditions:

Commissioning date of the Facility is before January 1, 2015;

OR

OEM is no longer in business; OR

OEM no longer supports model(s) for in-service equipment at

the Facility; OR

OEM is unwilling (or otherwise unable) to provide the supporting model (s) for in-service equipment at the Facility.

(Requirement R6 exemption)

Throughout MOD-026-2 it uses the legacy title of Planning Authority.  EEI suggests that the wherever this term is used, it be replaced with the preferred term “Planning Coordinator.

Section C “Compliance”

EEI asks the SDT to use the most up-to-date language in this section.

Section E “Associated Documents”

EEI asks the SDT to add the Implementation Plan and Technical Rationale to this section.

FE Voter, Segment(s) 1, 3, 5, 6, 4, 12/20/2021

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N/A

Anna Todd, On Behalf of: Southern Indiana Gas and Electric Co., RF, Segments 3, 5, 6

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Other Answers

Jack Stamper, Clark Public Utilities, 3, 6/16/2022

- 0 - 0

Proposed change to Facilities Section to more clearly align with the approved BES Definition (see below):

 

4.2. Facilities: For the purpose of this standard, the term “applicable units” shall mean any one of the following:

4.2.1 Individual generating resource meeting the unit criteria set by identified through Inclusion I2 of the BES definition.

4.2.2 Generating plant/Facility meeting the plant/Facility criteria set by identified through Inclusion I2 of the BES definition.

4.2.3 Generating plant/Facility of dDispersed power producing resources that aggregate to a total capacity set by identified through Inclusion I4 of the BES definition.

4.2.4 Dynamic reactive resources identified through meeting the criteria set by Inclusion I5 of the BES definition with a gross nameplate rating greater than 20 MVAr, or an aggregated site rating greater than 20 MVAr, including, but not limited to:

4.2.4.1 Synchronous condenser; and

4.2.4.2 Flexible alternating current transmission system (FACTS) devices.

4.2.5 HVDC terminal equipment including:

4.2.5.1 Line commutated converter (LCC); and

4.2.5.2 Voltage source converter (VSC

Attachment 1 (Model Verification Periodicity) Comment

EEI suggests the following changes to Row 11, noting that OEMs are under no specific obligation to provide the models identified in MOD-026-2, unless such a requirement was written into the contract at the time the resource was purchased.

Verification Conditions:

Commissioning date of the Facility is before January 1, 2015;

OR

OEM is no longer in business; OR

OEM no longer supports model(s) for in-service equipment at

the Facility; OR

OEM is unwilling (or otherwise unable) to provide the supporting model (s) for in-service equipment at the Facility.

(Requirement R6 exemption

 

Throughout MOD-026-2 it uses the legacy title of Planning Authority.  EEI suggests that the wherever this term is used, it be replaced with the preferred term “Planning Coordinator.

 

Section C “Compliance”

EEI asks the SDT to use the most up-to-date language in this section.

 

Section E “Associated Documents”

EEI asks the SDT to add the Implementation Plan and Technical Rationale to this section.

 

 

 

Glen Farmer, Avista - Avista Corporation, 5, 6/28/2022

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No Comments

Brian Lindsey, Entergy, 1, 6/28/2022

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None

Richard Jackson, U.S. Bureau of Reclamation, 1, 6/29/2022

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There is a lack of published assessment on the effectiveness of transmission planning resulting from the implementation of the current versions of MOD-026-1 and MOD-027-1.  Without these assessments, proposed additions to MOD-026-2 appear like a wish list of nice-to-have features, rather than necessary additions with quantified justification.  Further requirements should be added only when tangible reliability gaps are identified.  Before proposing new standard requirements, more fully developed technical foundation documents are needed. 

Martin Sidor, NRG - NRG Energy, Inc., 6, 6/29/2022

- 0 - 0

Nazra Gladu, Manitoba Hydro , 1, 6/29/2022

- 0 - 0

 There is a lack of published assessment on the effectiveness of transmission planning resulting from the implementation of the current versions of the MOD-026-1 and MOD-027-1.  Without these assessments, proposed additions to MOD-026-2 appear like a wish list of nice-to-have features, rather than necessary additions with quantified justification.  Further requirements should be added only when tangible, reliability gaps are identified.  Before proposing new standard requirements, more fully developed technical foundation documents are needed.

Patricia Lynch, NRG - NRG Energy, Inc., 5, 6/29/2022

- 0 - 0

Joe O'Brien, NiSource - Northern Indiana Public Service Co., 6, 6/29/2022

- 0 - 0

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

- 0 - 0

To better align with the Standards Alignment with Registration NERC project (2017-07), Planning Authority should be replaced with Planning Coordinator in all documents related to this project (MOD-026-2, Implementation Plan, Mapping Document, VRF/VSL Justifications and Technical Rationale). 

Nicolas Turcotte, Hydro-Qu?bec TransEnergie, 1, 6/30/2022

- 0 - 0

General comments:

Applicable Facilities in Section 4.2.3 criteria is changing.  It proposes every interconnect align with Inclusion I2.  Our previous criteria in the Eastern Interconnect was 100MVA or 100MVA station aggregate.  New requirements state a 20MVA nameplate or 75MVA station aggregate.  This action will add a significant cost to GOs and from our conversations with TP, the synchronous machines that will be pulled in will provide no benefit to their studies.  Suggest standard maintain the existing MVA thresholds currently in MOD-026 and MOD-027.

Generation feels the timeline change in Attachment 1 rows 5 and 6 needs to remain the same as existing standards.  The lack of qualified personnel, coordination of testing, and system conditions all contribute to extended submittal times.

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

- 0 - 0

In terms of dynamic simulation modeling of nonsynchronous sources (i.e. FACTS, HVDC), it is expected that such dynamic models would be developed by and provided by the device vendor. It is encouraged that the applicable standards promote the development of, and use of, standardized “off the shelf” dynamic simulation software models. 

 

It is likely that many Transmission Owners (that own a Facility listed in Section 4.2.4 or 4.2.5) rely on the services of the nonsynchronous resource (i.e. FACTS, HVDC) vendor / OEM for model development, benchmarking and verification – due to the specialized nature of these resources. The proposed MOD-026-2 would likely increase a TO’s reliance on support services from their nonsynchronous resource vendors / OEMs, with a corresponding increase in TO costs.

Isidoro Behar, On Behalf of: Long Island Power Authority, , Segments 1

- 0 - 0

AECI agrees with EEI's comments:

 

Proposed change to Facilities Section to more clearly align with the approved BES Definition (see below):

4.2. Facilities: For the purpose of this standard, the term “applicable units” shall mean any one of the following:

4.2.1 Individual generating resource meeting the unit criteria set by Inclusion I2 of the BES definition.

4.2.2 Generating plant/Facility meeting the plant/Facility criteria set by Inclusion I2 of the BES definition.

4.2.3 Dispersed power producing resources that aggregate to a total capacity set by Inclusion I4 of the BES definition.

4.2.4 Dynamic reactive resources meeting the criteria set by Inclusion I5 of the BES definition with a gross nameplate rating greater than 20 MVAror an aggregated site rating greater than 20 MVAr, including, but not limited to:

4.2.4.1 Synchronous condenser; and

4.2.4.2 Flexible alternating current transmission system (FACTS) devices.

4.2.5 HVDC terminal equipment including:

4.2.5.1 Line commutated converter (LCC); and

4.2.5.2 Voltage source converter (VSC)

 

Attachment 1 (Model Verification Periodicity) Comment

EEI suggests the following changes to Row 11, noting that OEMs are under no specific obligation to provide the models identified in MOD-026-2, unless such a requirement was written into the contract at the time the resource was purchased.

Verification Conditions:

Commissioning date of the Facility is before January 1, 2015;

OR

OEM is no longer in business; OR

OEM no longer supports model(s) for in-service equipment at

the Facility; OR

OEM is unwilling (or otherwise unable) to provide the supporting model (s) for in-service equipment at the Facility.

(Requirement R6 exemption)

Throughout MOD-026-2 it uses the legacy title of Planning Authority.  EEI suggests that the wherever this term is used, it be replaced with the preferred term “Planning Coordinator.

 

Section C “Compliance”

EEI asks the SDT to use the most up-to-date language in this section.

 

Section E “Associated Documents”

EEI asks the SDT to add the Implementation Plan and Technical Rationale to this section.

AECI, Segment(s) 1, 3, 6, 5, 3/4/2021

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Sean Steffensen, IDACORP - Idaho Power Company, 1, 6/30/2022

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Michelle Amarantos, APS - Arizona Public Service Co., 5, 6/30/2022

- 0 - 0

Constellation requests that the SDT evaluate and clarify the language under draft MOD-026-2 Attachment 1 "Model Verification Periodicity" specifically Row 9 that gives an exemption to R3 or R5 requirement to provide a validated model (and therefore any associated testing or analysis) for any unit that meets the conditions of the Row (i.e., a written statement to the TP stating the unit meets the condition is sufficient to meet the R3 or R5 requirements). The Verification Condition stated in Row 9 has historically been interpreted by GOs in two different ways: 1. The row applies if the unit does not respond in either direction: a. Unit does not respond to over frequency events, and b. Unit does not respond to under frequency events. 2. The row applies if the unit responds in just one direction: a. Unit does not respond to an over frequency event but does respond to an under frequency event, or b. Unit does not respond to an under frequency event but does respond to an over frequency event.

Kimberly Turco on behalf of Constellation Segments 5 and 6

Alison Mackellar, Constellation, 5, 6/30/2022

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Constellation requests that the SDT evaluate and clarify the language under draft MOD-026-2 Attachment 1 "Model Verification Periodicity" specifically Row 9 that gives an exemption to R3 or R5 requirement to provide a validated model (and therefore any associated testing or analysis) for any unit that meets the conditions of the Row (i.e., a written statement to the TP stating the unit meets the condition is sufficient to meet the R3 or R5 requirements). The Verification Condition stated in Row 9 has historically been interpreted by GOs in two different ways: 1. The row applies if the unit does not respond in either direction: a. Unit does not respond to over frequency events, and b. Unit does not respond to under frequency events. 2. The row applies if the unit responds in just one direction: a. Unit does not respond to an over frequency event but does respond to an under frequency event, or b. Unit does not respond to an under frequency event but does respond to an over frequency event.

 

Kimberly Turco on behalf of Constellation Segments 5 and 6

Kimberly Turco, Constellation, 6, 6/30/2022

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  1. ATC would like to assure our ability to collect an updated model if we observe a disturbance on the system that does not match the model response.  While a version of this language is generally present in MOD-032, we believe the requirement for a GO to submit updated modeling information in response to a transmission system event should still be present in MOD-026-2.  ATC would like to see the language restored to the proposed standard similar to MOD-026-1/MOD-027-1 R3 (Bullet 3) that states the GO shall provide a written response to its TP within 90 calendar days of receiving the following notice,

“Written comments and supporting evidence from its Transmission Planner indicating that the simulated (excitation control system or plant volt/var control function model)/(turbine/governor and load control or active power/frequency control) response did not match the recorded response to a transmission system event.”

 

         2. The name of the standard should be renamed to incorporate the act of validation as called out in section 6.2.  Perhaps the standard can be renamed as, “MOD-026-2 – Verification and Validation of Dynamic Models and Data for BES Connected Facilities.”

 

                            3. Additionally, the acts of validation and verification of models should be better explained within the standard and/or      requirements.  The standard defines verification and validation in section 6, but then makes validation a part of verified models as shown in R2-R6. “The verified model shall include… RX.4 validation of…”. There should be verification of models before changes or resource interconnection, then validation some time shortly after the change. In other words, there should be discussion within the standard of verified models separately from validated models and using a “verified and validated” term to tie the processes together at the end of validation. Both verification and validation need to work hand in hand to inform the process of the other.

Definitions used in the standard

6.1. Verification refers to the static process of checking documents and files, and comparing them to model parameters, model structure, or equipment settings.

6.2. Validation refers to the dynamic process of testing or monitoring the in-service equipment behavior, and then using the testing or monitoring results and comparing them to the model simulated response.

 

4. For Attachment 1, Row 2, “Initial verification for a newly commissioned Facility,” ATC suggests that the GO transmit a verified model and accompanying information to the Transmission Planner within 180 calendar days instead of 365 calendar days after the commissioning date.  Waiting a full year with a potentially inaccurate model before a plant gets updated through validation could prove to be too long and could result in significant delays.

LaTroy Brumfield, American Transmission Company, LLC, 1, 7/1/2022

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Comments: Proposed change to Facilities Section to more clearly align with the approved BES Definition (see below):

 

4.2. Facilities: For the purpose of this standard, the term “applicable units” shall mean any one of the following:

4.2.1 Individual generating resource meeting the unit criteria set by Inclusion I2 of the BES definition.

4.2.2 Generating plant/Facility meeting the plant/Facility criteria set by Inclusion I2 of the BES definition.

4.2.3 Dispersed power producing resources that aggregate to a total capacity set by Inclusion I4 of the BES definition.

4.2.4 Dynamic reactive resources identified through meeting the criteria set by Inclusion I5 of the BES definition with a gross nameplate rating greater than 20 MVAr, or an aggregated site rating greater than 20 MVAr, including, but not limited to:

4.2.4.1 Synchronous condenser; and

4.2.4.2 Flexible alternating current transmission system (FACTS) devices.

4.2.5 HVDC terminal equipment including:

4.2.5.1 Line commutated converter (LCC); and

4.2.5.2 Voltage source converter (VSC

Attachment 1 (Model Verification Periodicity) Comment

EEI suggests the following changes to Row 11, noting that OEMs are under no specific obligation to provide the models identified in MOD-026-2, unless such a requirement was written into the contract at the time the resource was purchased.

Verification Conditions:

Commissioning date of the Facility is before January 1, 2015;

OR

OEM is no longer in business; OR

OEM no longer supports model(s) for in-service equipment at

the Facility; OR

OEM is unwilling (or otherwise unable) to provide the supporting model (s) for in-service equipment at the Facility.

(Requirement R6 exemption

 

Throughout MOD-026-2 it uses the legacy title of Planning Authority.  EEI suggests that the wherever this term is used, it be replaced with the preferred term “Planning Coordinator.

 

Section C “Compliance”

EEI asks the SDT to use the most up-to-date language in this section.

 

Section E “Associated Documents”

EEI asks the SDT to add the Implementation Plan and Technical Rationale to this section.

 

Mike Magruder, Avista - Avista Corporation, 1, 7/1/2022

- 0 - 0

Proposed change to Facilities Section to more clearly align with the approved BES Definition (see below):

4.2. Facilities: For the purpose of this standard, the term “applicable units” shall mean any one of the following:

4.2.1 Individual generating resource meeting the unit criteria set by identified through Inclusion I2 of the BES definition.

4.2.2 Generating plant/Facility meeting the plant/Facility criteria set by Inclusion I2 of the BES definition.

4.2.3 Dispersed power producing resources that aggregate to a total capacity set by Inclusion I4 of the BES definition.

4.2.4 Dynamic reactive resources meeting the criteria set by Inclusion I5 of the BES definition with a gross nameplate rating greater than 20 MVAr, or an aggregated site rating greater than 20 MVAr, including, but not limited to:

4.2.4.1 Synchronous condenser; and

4.2.4.2 Flexible alternating current transmission system (FACTS) devices.

4.2.5 HVDC terminal equipment including:

4.2.5.1 Line commutated converter (LCC); and

4.2.5.2 Voltage source converter (VSC

Attachment 1 (Model Verification Periodicity) Comment

EEI suggests the following changes to Row 11, noting that OEMs are under no specific obligation to provide the models identified in MOD-026-2, unless such a requirement was written into the contract at the time the resource was purchased.

Verification Conditions:

Commissioning date of the Facility is before January 1, 2015;

OR

OEM is no longer in business; OR

OEM no longer supports model(s) for in-service equipment at

the Facility; OR

OEM is unwilling (or otherwise unable) to provide the supporting model (s) for in-service equipment at the Facility.

(Requirement R6 exemption

 

Throughout MOD-026-2 it uses the legacy title of Planning Authority.  EEI suggests that the wherever this term is used, it be replaced with the preferred term “Planning Coordinator.

 

Section C “Compliance”

EEI asks the SDT to use the most up-to-date language in this section.

 

Section E “Associated Documents”

EEI asks the SDT to add the Implementation Plan and Technical Rationale to this section.

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

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Evergy supports and incorporates by reference the comments of the Edison Electric Institute (EEI) to question #9.

Alan Kloster, On Behalf of: Allen Klassen, Evergy, 1,3,5,6; Allen Klassen, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Derek Brown, Evergy, 1,3,5,6; Derek Brown, Evergy, 1,3,5,6

- 0 - 0

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

- 0 - 0

Eric Sutlief, On Behalf of: CMS Energy - Consumers Energy Company - RF - Segments 3, 4, 5

- 0 - 0

Leonard Kula, Independent Electricity System Operator, 2, 7/5/2022

- 0 - 0

Xcel Energy supports EEI's comment.

Joe Gatten, On Behalf of: Xcel Energy, Inc. - MRO, WECC - Segments 1, 3, 5, 6

- 0 - 0

See comments from Glen Farmer at Avista.

Scott Kinney, Avista - Avista Corporation, 3, 7/5/2022

- 0 - 0

Karl Blaszkowski, CMS Energy - Consumers Energy Company, 3, 7/5/2022

- 0 - 0

Nothing in addtion to the proposed change from PA to PC in Q2 and the potential clarifying language identified in the response to Q3 and Q4.

WECC Entity Monitoring, Segment(s) 10, 1/30/2022

- 0 - 0

Portland General Electric Co., Segment(s) 1, 3, 5, 6, 7/5/2022

- 0 - 0

Dwanique Spiller, Berkshire Hathaway - NV Energy, 5, 7/5/2022

- 0 - 0

AEP appreciates the efforts of the Standards Drafting Team. While we disagree with some aspects of what was proposed in the most recent draft, AEP supports the SDT’s overall goals and objectives.

AEP believes that in addition to HVDC, FACTS, and Synchronous Condensers, the following facilities would also be brought into scope in the proposed standard, and requests that clarity be added to the technical justification and mapping document to affirm these additional inclusions.

*  Individual generating units 20-100 MVA with POI 100 kV and greater in Eastern Interconnection.

*  Aggregate generating units 75-100 MVA with POI 100 kV and greater in Eastern Interconnection.

*  Individual generating units 20-50 MVA with POI 100 kV and greater in ERCOT.

Thomas Foltz, AEP, 5, 7/5/2022

- 0 - 0

Texas RE has the following additional comments regarding clarification:

 

Facilities Section

In the facilities section, this standard says that it applies to resources/facilities that meet the BES Inclusions, but it does not mention the BES Exclusions.  BES resources/facilities are determined by applying the Inclusions and then applying the Exclusions (for example, Exclusion E2).  By only referring to the Inclusions in the facilities section, this standard could apply to some non-BES resources/facilities.  Is this the intent of the SDT?

 

Also, is it the intent of the SDT that the HVDC terminal equipment should be BES?  If so, a reference to the BES definition is needed for 4.2.5

 

Finally, Blackstart units are included as a separate category in the Inclusions of the BES definition.  Texas RE recommends including Blackstart units in this standard applicability since the goal is to ensure accurate models for engineers to adequately study system conditions.

 

Texas RE recommends the following revisions to address the concerns regarding the Facilities section:

 

4.2.1 Individual generating resource identified through Inclusion I2 the application of the BES definition.
4.2.2 Generating plant/Facility identified through Inclusion I2 the application of the BES definition.
4.2.3 Generating plant/Facility of dispersed power producing resources identified through Inclusion I2 the application of the BES definition.

4.2.4 Dynamic reactive resources identified through Inclusion I2 the application of the BES definition with a gross nameplate rating greater than 20 MVA including, but not limited to:
             4.2.4.1 Synchronous condenser; and
             4.2.4.2 Flexible alternating current transmission system (FACTS) devices.
 4.2.5 HVDC terminal equipment identified through the application of the BES definition including:

4.2.5.1 Line commutated converter (LCC); and
          4.2.5.2 Voltage source converter (VSC).

4.2.6 Blackstart resource identified through the application of the BES definition.

 

Evidence Retention Section

Texas RE recommends the retention before 10 years in order for the entity to demonstrate compliance for the verified tests.

 

Attachment 1

As a general matter, Texas RE recommends including the attachment information in the requirement language to minimize the dependency on extraneous information.  That said, Texas RE seeks clarification regarding the language on the following rows in Attachment 1:

 

Row 1 - Texas RE recommends clarifying the phrase “implementation period”. For MOD-026-1 there was a phased-in implementation for the fleet.  Is the SDT indicating that a fleet percentage should still be considered from MOD-026-1 Implementation Plan (and therefore 100% be met by July 1, 2024-10 years after the July 1, 2014 effective date of MOD-026-1)?  Please see Texas RE’s comment on #8.

 

Row 2 - Texas RE recommends using the term registration date as there is no consistent and clear definition of commissioning date.

 

Row 4 – Texas RE recommends repeating or referring to the measure for Requirements R3 or R5 to explain how compliance should be met.

 

Rows 5 and 6 refer to Requirements R7, R8, and R9.  None of these requirements reference Attachment 1 and they each have periodicities in the requirements.  Should the requirement language reference attachment 1?

 

Row 5 - It appears that this should reference R7, rather than R8 since R7 discusses the change of in-service equipment and the obligations to supply information.

 

Row 7 – Texas RE recommends describing the phrase “same components and settings” in more detail as it is pretty broad.  If one component or setting was different, demonstration of compliance becomes more challenging.

 

Row 8 -  Texas RE recommends the information in rows 8 and 9 be included in the requirement language.  It is somewhat buried in this attachment and would be easy to miss.  Additionally, Texas RE requests justification for the exemption language.  The response characteristics should be provided to the TP.  Texas RE recommends referring to the measures in the requirements for which information should be provided to the TP.

 

Row 10 - Texas RE does not agree that current average net capacity factor over the most recent three calendar years, beginning on January 1 and ending on December 31, of 5% or less should be a reason to be exempted from the periodicity in Requirements R2, R3, R4, R5, or R6.  A low capacity factor means the unit does not run often, which implies that when it does run, it is needed.  The TP should understand all scenarios.  

Rachel Coyne, Texas Reliability Entity, Inc., 10, 7/5/2022

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Israel Perez, On Behalf of: Pam Syrjala, Salt River Project, 1,3,5,6; Pam Syrjala, Salt River Project, 1,3,5,6; Zack Heim, Salt River Project, 1,3,5,6; Zack Heim, Salt River Project, 1,3,5,6

- 0 - 0

 

·         It is recommended the SDT consider using bullet points instead of long sentences. Using R5 as an example:

For…

  • Inverter based resources (IBRs) identified in Section 4.2.3,
  • LCC HVDC identified in Section 4.2.5.1, and
  • VSC HVDC identified in Section 4.2.5.2,

Each Generator Owner or Transmission Owner shall provide…

  • A verified positive sequence dynamic model(s), 
  • Associated parameters, and
  • Accompanying information

…that represent the in-service equipment of the Facility to its Transmission Planner.  This in accordance with the periodicity in MOD-026-2 Attachment 1. The verified model(s)shall include at a minimum the following:

The inclusion of the Planning Authority (Coordinator) should be reconsidered as it is not consistent with the existing MOD-026 & 072 standards that are being combined and, in the proposed standard, is redundant with MOD-032.

The VRFs for R2 – R6 match in the SDT proposed standard.  The SDT should consider making the VRF for R7 consistent with the VRF for R2 – R6.

The SDT should consider whether the “Operations Planning” time horizon is appropriate for this standard.  “Long-term Planning” appears to be the more appropriate choice for the entire standard.

Greg Davis, Georgia Transmission Corporation, 1, 7/5/2022

- 0 - 0

WEC Energy Group supports EEI and NAGF comments. 

Christine Kane, WEC Energy Group, Inc., 3, 7/5/2022

- 0 - 0

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

- 0 - 0

Black Hills Corporation supports EEI and NAGF comments. 

Claudine Bates, Black Hills Corporation, 6, 7/5/2022

- 0 - 0

RE: Facilities: What was the rationale to propose augmenting the inclusion of dynamic reactive power resources, per I5, with a 20MVA threshold?  This seems to not fully follow the statement in the Technical Rationale Document for Reliability Standard MOD-026-2, "[t]he proposed standard links applicability to the BES definition (as opposed to defined rating or other thresholds) to be sure that now and in the future, should the BES definition be modified, the standard is consistent with applicable BES facilities"

In addition, National Grid supports EEI's comments.

Michael Jones, National Grid USA, 1, 7/5/2022

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