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2016-EPR-02 Enhanced Periodic Review of VAR Standards | Template for VAR-001-4.1

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Start Date: 02/28/2017
End Date: 04/13/2017

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Hot Answers

ERCOT agrees that TOPs should periodically review any exemptions provided along with the criteria for granting such exemptions, but it is not necessary to require that through a standard. If a unit’s exemption is causing reliability issues, the symptoms will more likely be observed in Planning Assessments, Operational Planning Analysis, and Real Time Assessments.  This will prompt either Corrective Actions Plans or Operating Plans to be developed to address.

Elizabeth Axson, On Behalf of: Elizabeth Axson, , Segments 2

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Michael Godbout, On Behalf of: Hydro-Qu?bec TransEnergie, NPCC, Segments 1

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Other Answers

Glen Farmer, On Behalf of: Avista - Avista Corporation, , Segments 1, 3, 5

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

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Preston Walker, On Behalf of: PJM Interconnection, L.L.C., RF, Segments 2

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There should be a requirement to conduct a periodic review to the units that are exempt, at a minimum of every three years of the exemption criteria. In addition, the specified voltage schedule supplied to the unit should be reviewed as well. For example, the initial stages of a wind farm project may not require a specific voltage schedule (i.e. exempt), but as the project progresses, changes (perhaps driven by a proposed increase in the size of the wind farm), a voltage schedule may need to be developed.

 

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

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Michelle Amarantos, On Behalf of: APS - Arizona Public Service Co., , Segments 1, 3, 5, 6

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Sean Bodkin, On Behalf of: Dominion - Dominion Resources, Inc., , Segments 3, 5, 6

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DTE Energy - DTE Electric, Segment(s) 5, 4, 3, 2/27/2017

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Agree that there is a gap there. The review could be periodic or trigger based such as an equipment modification or any change that could impact the exempted status.

Entergy/NERC Compliance, Segment(s) 1, 5, 3/1/2017

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BPA does not exempt any qualified units.

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

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Jesus Sammy Alcaraz, On Behalf of: Imperial Irrigation District, , Segments 1

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Not necessarily.  Generally speaking, IAs and Operating Agreements usually contain language that requires notifications between the GO and TO/TSP/TOP and vice-versa when there are changes.  That would serve as the prompt to re-evaluate. Even absent the aforementioned prompt to re-evaluate, nothing precludes the TOP from re-evaluating exemptions.

Southern Company, Segment(s) 1, 3, 5, 6, 8/3/2016

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This sounds like an improvement in theory but it would manifest as a documentation requirement and add little value. A requirement would likely be met by showing an annual review of a procedure containing the exemption criteria.

Stephanie Burns, On Behalf of: International Transmission Company Holdings Corporation, MRO, SPP RE, RF, Segments 2

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David Jendras, On Behalf of: Ameren - Ameren Services, , Segments 1, 3, 6

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There is no need for an administrative requirement to conduct a periodic review.

Daniel Gacek, On Behalf of: Exelon, , Segments 1, 3, 5, 6

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Laura Nelson, On Behalf of: Laura Nelson, , Segments 1

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Sandra Shaffer, On Behalf of: Sandra Shaffer, , Segments 6

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LS Power Transmission's comments address a problem wth both and are therefore separately attached..

John Seelke, On Behalf of: John Seelke, , Segments 1

LS Power Transmission Comments Project 2016-EPR 04.13,17.docx

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Exemptions and exemption units should be required to ensure statuses have been updated to and from TOP and GOP on a predetermined periodic schedule.

Aubrey Short, On Behalf of: Aubrey Short, , Segments 1, 3, 4

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Michael Cruz-Montes, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

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The exemption should be based on the system need. Operating experience will bring to light when an exeption needs to be reconsidered. There is no need to create a requirement to perform a review.

RSC no ISO-NE, Segment(s) 1, 0, 2, 4, 5, 6, 7, 3, 4/13/2017

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There are 30 minute system evaluations, next day analysis and other operation studies being run that would highlight if this were an issue.  See Reliability Standards – TOP-001-3 & TOP-002-4.

Russel Mountjoy, On Behalf of: Russel Mountjoy, , Segments 10

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Duke Energy does not believe a periodic review or a review triggered by the specified changes is necessary, and does not believe that the lack of a requirement impacts reliability.

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

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SPP Standards Review Group, Segment(s) , 4/13/2017

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Texas RE recommends periodic reviews of exemptions.   In order to determine the best actions to support the reliability of the grid, TOPs need to understand the status or capability of available resources.  When a generating unit becomes exempt, the TOP loses visibility to that generator. 

Rachel Coyne, On Behalf of: Texas Reliability Entity, Inc., , Segments 10

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TOPs already assess operations that would impact reliability through various Real Time Assessments and Operational Planning Analyses, as required in NERC Reliability Standards TOP-001-3 and TOP-002-4.  We feel introducing a requirement for a periodic review of these exemptions would only cause confusion.

ACES Standards Collaborators, Segment(s) 1, 5, 3, 4, 6, 4/13/2017

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ISO/RTO Standards Review Committee, Segment(s) 2, 4/13/2017

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Reclamation asserts it is prudent to apply a time period for the TOP to review their specific criteria for generator exemptions. Reclamation asserts that the logical time period would coincide with the time period specified in the NERC system modeling (MOD) standards.  Reclamation suggests Requirement R4 should specify that at least once every 10 years the Transmission Operator shall review and evaluate its exemption criteria for generators and notify pertinent Generator Operators of any changes to the previous criteria.

Richard Jackson, On Behalf of: U.S. Bureau of Reclamation, , Segments 1, 5

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Hien Ho, On Behalf of: Tacoma Public Utilities (Tacoma, WA), , Segments 1, 3, 4, 5, 6

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Hot Answers

A lack of dynamic reactive reserves on only a single unit will not typically have a reliability impact.  However, multiple generating units in the same reactive zone all running at Qmax or Qmin limits while using their dynamic reactive capability to provide that response could have a reliability impact.   If seen ahead of time, or if monitored in real time with voltage stability applications, voltage stability System Operating Limits can be established to monitor when it would become a reliability impact.  Voltage Schedules should be optimized to use static reactive devices first in order to maximize availability of generating unit dynamic reactive capability.  While this is best practice, ERCOT does not necessarily agree that this should be captured in a standard

Elizabeth Axson, On Behalf of: Elizabeth Axson, , Segments 2

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Not necessarily. A specific unit running at maximum doesn not mean there is a lack of dynamic reactive reserve.

Michael Godbout, On Behalf of: Hydro-Qu?bec TransEnergie, NPCC, Segments 1

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Other Answers

Glen Farmer, On Behalf of: Avista - Avista Corporation, , Segments 1, 3, 5

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

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Any impact on the system would be highly dependent on the specific system characteristics as well as the specific unit characteristics.  A large unit near a critical interface has more impact than a small unit attached to a very strong network.  This issue should not be addressed in a continent wide reliability standard.

Preston Walker, On Behalf of: PJM Interconnection, L.L.C., RF, Segments 2

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While a potential lack of dynamic reserves for a single unit may not have far-reaching impacts, a wide-scale lack of dynamic reserves could very well have an impact on reliability. Voltage schedules should be developed to allow a unit to have dynamic reserves available under normal conditions to respond to contingencies or disturbances. If a unit is hitting limits on reactive capability, the GOP and TOP should work together to resolve the issue (for example, voltage schedule change, exemptions, GSU tap changes, auxiliary transformer tap changes, etc.).

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

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A lack of dynamic reactive reserves could have a reliability impact if the TOP system is depending upon the generator to provide VAR support during transients to maintain reliability. However, the TOPs study work should identify this condition in advance.

Michelle Amarantos, On Behalf of: APS - Arizona Public Service Co., , Segments 1, 3, 5, 6

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Any impact on the system would be highly dependent on the specific system characteristics as well as the specific unit characteristics.  A large unit near a critical interface has more impact than a small unit attached to a very strong network.  This issue should not be addressed in a continent wide reliability standard.

Sean Bodkin, On Behalf of: Dominion - Dominion Resources, Inc., , Segments 3, 5, 6

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If additional reactive is needed for BES operation, the generator will not be able to assist in suppling additional reactive. If the generator is routinely running at maximum limits, system upgrades need to be performed such as installation of additional capacitiors. This should be addressed with the TOP yearly review of the Voltage Schedules.

DTE Energy - DTE Electric, Segment(s) 5, 4, 3, 2/27/2017

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Entergy expressed concerns that there is not a feedback loop between the TOP and GOP to raise concerns for issues with the voltage schedule – this should be allowed by the standard. If a generating unit is struggling ot meet its voltage schedule, it would also not have margin left for dynamic reserves.

Entergy/NERC Compliance, Segment(s) 1, 5, 3/1/2017

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BPA believes it depends on whether the voltage schedule would place the whole plant or multiple plants under stress.  The wide area risk would not be significant for a single unit operating at reactive limits.

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

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Jesus Sammy Alcaraz, On Behalf of: Imperial Irrigation District, , Segments 1

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Not necessarily - this cannot be generally answered.  A single unit in an entire interconnect running at it maximum limits should not have an adverse reliability impact.  If something like this occurs routinely, it could indicate the need for an overall review of reactive planning in the area.  However, the described behavior of the generating unit could be in line with the overall reactive plan for that area.

 

Southern Company, Segment(s) 1, 3, 5, 6, 8/3/2016

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Maybe, this is very situational. The TOP would need the discretion to decide what is best for the system for each situation.

Stephanie Burns, On Behalf of: International Transmission Company Holdings Corporation, MRO, SPP RE, RF, Segments 2

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David Jendras, On Behalf of: Ameren - Ameren Services, , Segments 1, 3, 6

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Difficult to answer at the unit level. A reasonable presumption is that if a unit is always at the max point then the unit is not able to supply dynamic support but the TOP is in a position to know if that is a concern. 

Daniel Gacek, On Behalf of: Exelon, , Segments 1, 3, 5, 6

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This would impact reliability, which is why we do not operate this way.

Laura Nelson, On Behalf of: Laura Nelson, , Segments 1

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This question is not clear. 

Sandra Shaffer, On Behalf of: Sandra Shaffer, , Segments 6

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John Seelke, On Behalf of: John Seelke, , Segments 1

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In a circumstance where numerous generators (not specified within the question) were operating at their VAR limits there would be potential for some impact on the reliability of the system.  The systems, capability to react to an event would render the local area with the highest risk. 

Aubrey Short, On Behalf of: Aubrey Short, , Segments 1, 3, 4

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Michael Cruz-Montes, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

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Not necessarily. This would have to be studied to determine whether there is a reliability impact. Planning studies should identify areas that lack sufficient reactive capability. If there are, system modifications should be proposed.

RSC no ISO-NE, Segment(s) 1, 0, 2, 4, 5, 6, 7, 3, 4/13/2017

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TOP’s have the responsibility to ensure adequate dynamic reactive response.  From the TOP perspective,             reliability impact depends on available resources for the area and dynamic response available for the TOP footprint.  

Russel Mountjoy, On Behalf of: Russel Mountjoy, , Segments 10

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

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The SPP Review Group has the perspective that a single generating unit is not a concern, because voltage control is a wider area issue involving multiple generator resources. However, if the drafting team feels that the focus of this project extends beyond the single generator, we recommend the drafting team revise the project language to reflect those concerns.

SPP Standards Review Group, Segment(s) , 4/13/2017

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Generation routinely running at maximum reactive output is an indicator of insufficient reactive infrastructure support in the surrounding system.  Voltage collapse or voltage degradation can result in load loss or equipment damage.  Planning studies should encompass periodic corrections for inductive load growth.

Rachel Coyne, On Behalf of: Texas Reliability Entity, Inc., , Segments 10

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The question is ambiguous and does not provide sufficient background regarding the system’s current conditions and configurations for proper context.  Furthermore, the question assumes that the generator is the sole source for reactive reserves in the local region.  However, we believe TOP-required Real Time Assessments and Operational Planning Analyses, as well as annual TP-required Planning Assessments, would already identify areas where additional infrastructure would be necessary to address potential voltage and reactive reserves issues.

ACES Standards Collaborators, Segment(s) 1, 5, 3, 4, 6, 4/13/2017

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We do not fully understand the question since the term “lack of dynamic reactive reserve” needs to be clarified wrt whether it means:

a.     Lack of dynamic reactive reserve capability?

b.     Lack of dynamic reactive reserve requirements?

c.      Both

Not knowing the exact meaning of the term, we are unable to provide relevant comment wrt whether or not the lack of any of the above can have a reliability impact.

In general, we hold the view that if there are dynamic reactive reserve requirements, then they need to be met by having sufficient dynamic reactive reserve capability. Hence, the lack of dynamic reactive requirements does not have any reliability impact. On the other hand, the lack of dynamic reactive reserve capability may have a reliability impact; it depends on whether or not there are any dynamic reactive reserve requirements.

             Footnote: ERCOT does not support the joint response provided.

ISO/RTO Standards Review Committee, Segment(s) 2, 4/13/2017

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Reclamation asserts there are serveral variables to consider. Reclamation considers routinely operating all generating units at the maximum limits to be an undesirable practice because it removes available reactive margin to respond to a grid event. The TOP, as the entity with the area-wide purview, should be aware of other available equipment (for adequate reactive reserves), and would need the flexibility to develop voltage schedules accordingly.  If System design limits dictate the need for a voltage schedule which requires routinely running the generating units at maximum limits, the design should be modified to allow units to have more reactive reserve capability.

Richard Jackson, On Behalf of: U.S. Bureau of Reclamation, , Segments 1, 5

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Hien Ho, On Behalf of: Tacoma Public Utilities (Tacoma, WA), , Segments 1, 3, 4, 5, 6

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Hot Answers

MVAR or Reactive reserves should be monitored to ensure pre and post contingency voltage stability.  With many entities having real time / online voltage stability monitoring tools, MVAR reserves can be monitored in terms of MW flows along an interface.  So, if all reactive zones are either monitored via real time / next day voltage stability limit calculating tools (i.e. an SOL exists for each zone) OR thermal constraints (Facility Ratings) are always more limiting than Voltage stability limits, then it would not impact reliability.  OPA and RTA is predicated on evaluation for SOL exceedances, so if there is not an SOL that represents a reactive zone/area, then there is potential for voltage stability issues if MVAR reserves is not monitored in its stead.  Voltage instability and reactive reserve deficiencies were contributing causes to the 2003 Northeast Blackout. 

Elizabeth Axson, On Behalf of: Elizabeth Axson, , Segments 2

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Michael Godbout, On Behalf of: Hydro-Qu?bec TransEnergie, NPCC, Segments 1

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Other Answers

Glen Farmer, On Behalf of: Avista - Avista Corporation, , Segments 1, 3, 5

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

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The absence of an explicit requirement to monitor reactive reserves does not create a reliability gap. 

The IRO suite of standards requires the RC to perform Operational Analyses and Real-time Assessments to prevent instability, uncontrolled separation, or Cascading and to ensure prompt action to prevent or mitigate instances of exceeding Interconnection Reliability Operating Limits (IROLs).

The TOP suite of standards requires the TOP to perform Operational Analyses and Real-time Assessments to prevent instability, uncontrolled separation, or Cascading and to ensure prompt action to prevent or mitigate instances of exceeding System Operating limits SOLs).

Preston Walker, On Behalf of: PJM Interconnection, L.L.C., RF, Segments 2

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From an overall situational awareness point of view, there should be a mechanism to monitor reactive reserve capabilities. While we agree there needs to be an awareness, it is unclear what “adequate” reactive reserves mean. If voltage contingencies in your Real Time Assessment are being monitored, operating plans should be developed for any potential SOL’s. While we believe that there should be a requirement for monitoring reactive reserves, the diversity in the renewable generation mix makes modeling of the reserve units more complex.

 

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

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Michelle Amarantos, On Behalf of: APS - Arizona Public Service Co., , Segments 1, 3, 5, 6

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The absence of an explicit requirement to monitor reactive reserves does not create a reliability gap. 

The IRO suite of standards requires the RC to perform Operational Analyses and Real-time Assessments to prevent instability, uncontrolled separation, or Cascading and to ensure prompt action to prevent or mitigate instances of exceeding Interconnection Reliability Operating Limits (IROLs).

The TOP suite of standards requires the TOP to perform Operational Analyses and Real-time Assessments to prevent instability, uncontrolled separation, or Cascading and to ensure prompt action to prevent or mitigate instances of exceeding System Operating limits SOLs).

Sean Bodkin, On Behalf of: Dominion - Dominion Resources, Inc., , Segments 3, 5, 6

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Reactive reserves must be available to support the reliable operation of the BES. The TOP must be required to know the status of reactive reserves at all times.

DTE Energy - DTE Electric, Segment(s) 5, 4, 3, 2/27/2017

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Entergy agrees, monitoring reactive reserves is part of the purpose of this standard but is not addressed by any requirements.

Entergy/NERC Compliance, Segment(s) 1, 5, 3/1/2017

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In lieu of RTCA voltage stablility analysis, BPA believes an explicit requirement for monitoring is necessary.

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

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Jesus Sammy Alcaraz, On Behalf of: Imperial Irrigation District, , Segments 1

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No, TPL-001-4 covers this. In addition, reactive reserve requirements are generally specific to each region or locale, and each TOP is best-qualified to determine those requirements within their respective transmission systems.

Southern Company, Segment(s) 1, 3, 5, 6, 8/3/2016

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One could argue that VAR-001-4.1 R2, the RTA, and the OPA work to ensure adequate reactive reserves. However, there are no requirements for monitoring reactive reserves. For many TOPs, there are not frequent reactive reserve issues. Therefore, it is often not given adequate attention. A lack of frequent reactive reserve issues may lead some to discount their importance. Lack of awareness of reactive reserves is a common factor during voltage collapse events.

Not requiring that any party monitor reactive reserves (in real-time) impacts relaibilty. Furthermore, the TOP is the appropriate party to monitor reactive reserves. A requirement to monitor reactive reserves would fit well within the VAR-001 standard.

Stephanie Burns, On Behalf of: International Transmission Company Holdings Corporation, MRO, SPP RE, RF, Segments 2

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With no requirements to monitor or ensure adequate reactive reserves within the IRO, TOP, or VAR standards, there is a risk of falling below adequate resources and not being aware.  Were this to occur and an initiating even occurred, it could be too late to acquire such resources.  

David Jendras, On Behalf of: Ameren - Ameren Services, , Segments 1, 3, 6

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IRO and TOP standards are sufficient to address this.

Daniel Gacek, On Behalf of: Exelon, , Segments 1, 3, 5, 6

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N/A

Laura Nelson, On Behalf of: Laura Nelson, , Segments 1

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Monitoring and operations are covered by other NERC Reliaiblity standaads such as TOPs.

Sandra Shaffer, On Behalf of: Sandra Shaffer, , Segments 6

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John Seelke, On Behalf of: John Seelke, , Segments 1

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Primary reliance on TO’s to accurately report VAR reserves absent a specific requirement could negatively impact accurate knowledge of VAR reserves available on the system and create the potential to impact reliability.

Aubrey Short, On Behalf of: Aubrey Short, , Segments 1, 3, 4

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Michael Cruz-Montes, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

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There are requirements to remain within limits post contingency. Operators would be aware of reactive reserve deficiencies if a plan cannot be developed to maintain the system within voltage limits post contingency. See TOP-002-4 R2, TOP-004-2 R1 and TOP-006-2 R3. Therefore monitoring is being done. Additionaly it may be impossible to “ensure” adequate reactive reserves if the planning process did not provide adequate reserves.

RSC no ISO-NE, Segment(s) 1, 0, 2, 4, 5, 6, 7, 3, 4/13/2017

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Reactive reserves adequacy is addressed in the Real-time and next day Operating studies.

Russel Mountjoy, On Behalf of: Russel Mountjoy, , Segments 10

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Duke Energy does not believe that the lack of requirments for monitoring of reactive resources impacts reliability. An effective operator will already be aware of reactive reserves, and adequacy of reactive reserves is covered by Real-time assessments already.

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

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The SPP Review Group agrees with the TOP/IRO mapping document that provides supportive details addressing monitoring adequate reactive reserves in the VAR Standards. However, we recommend that the drafting team include the mapping document in future resource materials to provide clarity on these type of discussions.

SPP Standards Review Group, Segment(s) , 4/13/2017

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Texas RE is concerned the entity will have too much leeway in determining its reactive reserves.  TOPs need to understand its voltage levels.  The TOPs need to have the ability to accurately assess current voltage control capability in order to take proper action during abnormal voltage conditions.

Rachel Coyne, On Behalf of: Texas Reliability Entity, Inc., , Segments 10

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We believe other reliability requirements in place to conduct Real Time Assessments and Operational Planning Analyses already address these concerns.

ACES Standards Collaborators, Segment(s) 1, 5, 3, 4, 6, 4/13/2017

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ISO/RTO Standards Review Committee, Segment(s) 2, 4/13/2017

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Reclamation supports that the absence of explicit requirements for monitoring or ensuring adequate reactive reserves does not in itself impact reliability; however, the absence of adequate reactive reserves would impact reliability. Reclamation contends that ensuring sufficient var capacity is quite difficult outside of requiring AVRs and sufficient amounts of spinning reserve. In order to ensure adequate reactive reserves, Reclamation suggests that an explicit requirement be retained.

Richard Jackson, On Behalf of: U.S. Bureau of Reclamation, , Segments 1, 5

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Hien Ho, On Behalf of: Tacoma Public Utilities (Tacoma, WA), , Segments 1, 3, 4, 5, 6

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Hot Answers

TOP-003 already provides a mechanism for TOPs to notify GOPs of duration requirements.

Elizabeth Axson, On Behalf of: Elizabeth Axson, , Segments 2

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Michael Godbout, On Behalf of: Hydro-Qu?bec TransEnergie, NPCC, Segments 1

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Other Answers

Glen Farmer, On Behalf of: Avista - Avista Corporation, , Segments 1, 3, 5

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

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Preston Walker, On Behalf of: PJM Interconnection, L.L.C., RF, Segments 2

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While there may be no significant impact to reliability, not specifying the duration that a unit can be outside the specified band could result in communication issues. For example, this could potentially result in excessive phone calls which could be distracting to both the GOP and TOP. Perhaps the language in the requirement could be changed to suggest examples of what can be included in the notification requirement from the TOP to the GOP.

 

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

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Michelle Amarantos, On Behalf of: APS - Arizona Public Service Co., , Segments 1, 3, 5, 6

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Sean Bodkin, On Behalf of: Dominion - Dominion Resources, Inc., , Segments 3, 5, 6

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There is not an impact to reliability but this issue needs to be addressed for compliance monitoring. The GOP must know how long the voltage can be outside the generator bus schedule. This will assist the auditor when reviewing compliance and assist the GOP in knowing when a self report is required.

DTE Energy - DTE Electric, Segment(s) 5, 4, 3, 2/27/2017

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Agree that the timing portion should be required to be specified by the TOP. Do not agree that this parameter should be prescriptively defined by NERC.

Entergy/NERC Compliance, Segment(s) 1, 5, 3/1/2017

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If BPA dispatch specified a deviation from the voltage or reactive schedule, it would include a projected time frame.  This is considered an Operating Instruction in accordance with COM-002-4.

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

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Jesus Sammy Alcaraz, On Behalf of: Imperial Irrigation District, , Segments 1

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Not necessarily - the TOP has the flexiblity to specify the time frame for any required notification where they determine that timing is critical.  R5.2 of VAR-001-4.1 is sufficient as it is.

Southern Company, Segment(s) 1, 3, 5, 6, 8/3/2016

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Relibility may not be affected, but a timing duration that a generator can be outside of a schedule before notification is required can significantly reduce compliance risk for the GOP. This compliance risk does not align with an improvement to reliability. It would be reasonable for NERC to require the TOP specify a time duration before a notification is required by the GOP.

Stephanie Burns, On Behalf of: International Transmission Company Holdings Corporation, MRO, SPP RE, RF, Segments 2

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If the TOP is not required to specify the timing portion of notifying them of a generator being outside of the voltage schedule and VAR-002 does not specify such timing for notification, a generator could be outside of the TOP's provided voltage schedule an indefinite amount of time.  We believe that it is obvious that this could have an impact to reliability.   

Currently the voltage schedule is an hourly average, however, this has nothing to do with notification.  Currently the schedule that we send only indicates, "All such notices to the TOS shall be without intentional delay."   If there is no stipulation in 5.2, we envision some GOPs will insist that they have no requirement for notification.  

David Jendras, On Behalf of: Ameren - Ameren Services, , Segments 1, 3, 6

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We don't believe this has a significant reliability impact, This should be left to the discretion of the TOP and can be detailed in the voltage schedule issued to the GOP if the TOP requires it.

Daniel Gacek, On Behalf of: Exelon, , Segments 1, 3, 5, 6

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Laura Nelson, On Behalf of: Laura Nelson, , Segments 1

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Sandra Shaffer, On Behalf of: Sandra Shaffer, , Segments 6

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John Seelke, On Behalf of: John Seelke, , Segments 1

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While the requirement does not specify a timing requirement it is likely implemented in practice. For FirstEnergy, PJM manuals document the notification requirement for when a generator is outside of its voltage schedule and a timing aspect is included.  The standard should not mandate a specific time, however, it could generally indicate that the notification must specify an expected timing for the notification. 

Aubrey Short, On Behalf of: Aubrey Short, , Segments 1, 3, 4

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Michael Cruz-Montes, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

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No, the TOP is aware of real time and post contingency voltages and whether the system is or will be within limits. If the system is not or will not be within limits the TOP can call the generator to inquire the status of the AVR or their ability to control to the reactive schedule.

RSC no ISO-NE, Segment(s) 1, 0, 2, 4, 5, 6, 7, 3, 4/13/2017

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Requirement 5.2 states that the TOP provides the GOP with the notification requirements for deviations from the voltage schedule.   

Russel Mountjoy, On Behalf of: Russel Mountjoy, , Segments 10

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Duke Energy does not believe that the absence of a requirement outlining a time duration that a generator can be outside of the voltage schedule before notification is required presents a clear impact to reliability. From a reliability standpoint, there are already standards that require the TOP to monitor SOL limits. In doing so, a TOP would be notified based on monitoring of SOL(s) whether a GOP sent notification or not. We believe this mitigates any potential issue pertaining to reliability of the system. We do feel that additional guidance around this topic may be useful to industry stakeholders in the form of a guidelines and technical basis section.

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

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We have no concerns that the TOP notification to the GOP doesn’t contain a timing limit for the generator in Part 5.2 of the standard. The TOP’s responsibility to provide the GOP with notification requirements would reasonably include the timing of such notifications.

SPP Standards Review Group, Segment(s) , 4/13/2017

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:   Texas is concerned that if there is no timing requirement, there is no control in place to ensure the generator’s reactive schedule is reset back to normal, which could mean an entity could be out of its voltage schedule indefinitely.   Texas RE frequently recommends entities provide timing in notifications so expectations are set. 

Rachel Coyne, On Behalf of: Texas Reliability Entity, Inc., , Segments 10

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The question is ambiguous.  The TOP is already required to specify a duration when a GOP deviates outside the required range or tolerance band.  We assume the question asks how soon after the initial deviation occurs that the GOP must notify the TOP.  If so, we believe System Operators who monitor the BES will likely be notified by EMS alarms first for significant deviations causing a reliability impact.  For other deviations, the TOP has followed best practices and established a notification requirement for the GOP, as part of the timing duration requirement.

ACES Standards Collaborators, Segment(s) 1, 5, 3, 4, 6, 4/13/2017

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ISO/RTO Standards Review Committee, Segment(s) 2, 4/13/2017

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Reclamation asserts it is appropriate to allow the TOP to determine whether to specify a timing portion of the notification requirement.

Richard Jackson, On Behalf of: U.S. Bureau of Reclamation, , Segments 1, 5

- 0 - 0

Hien Ho, On Behalf of: Tacoma Public Utilities (Tacoma, WA), , Segments 1, 3, 4, 5, 6

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Hot Answers

IRO-010 provides the RC the means to get the desired information, if necessary. 

Elizabeth Axson, On Behalf of: Elizabeth Axson, , Segments 2

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We support NPCC's comments. That is, requirement 1.1 provides for an mandatory communication of the schedules to the RC upon the RC's request.

Michael Godbout, On Behalf of: Hydro-Qu?bec TransEnergie, NPCC, Segments 1

- 0 - 0

Other Answers

Glen Farmer, On Behalf of: Avista - Avista Corporation, , Segments 1, 3, 5

- 0 - 0

Provided within a timeframe specified by the RC upon request would be adequate.

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

- 0 - 0

Preston Walker, On Behalf of: PJM Interconnection, L.L.C., RF, Segments 2

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The RC is required to monitor SOL’s and IROL’s. The information in the voltage/reactive power schedules could, at a minimum, be used to improve the RC’s awareness. While this could potentially have a positive reliability impact, we do not believe VAR-001 is the proper standard for such an obligation. Rather, we believe IRO-010-2 would be more appropriate.

 

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

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Michelle Amarantos, On Behalf of: APS - Arizona Public Service Co., , Segments 1, 3, 5, 6

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Sean Bodkin, On Behalf of: Dominion - Dominion Resources, Inc., , Segments 3, 5, 6

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Voltage control is a local issue. The TOP, GOP and DP must be aware and concerned with voltage control. The RC is looking a higher level and at a much larger area where local voltage control should not be a concern.

DTE Energy - DTE Electric, Segment(s) 5, 4, 3, 2/27/2017

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This is already addressed in IRO-010 and VAR-001 is not the appropriate place to address this. Entergy disagrees with adding this requirement to VAR-001.

Entergy/NERC Compliance, Segment(s) 1, 5, 3/1/2017

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BPA believes VAR-001-4.1, R1.1 ensures that the RC and adjacent TOP’s receive the system voltage schedule on request. BPA believes the IRO-010 data request would be available for the RC to receive the voltage or Reactive Power schedules.

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

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Jesus Sammy Alcaraz, On Behalf of: Imperial Irrigation District, , Segments 1

- 0 - 0

 R1.1 of VAR-001-4.1 gives the RC the ability to request this information if needed.    

Southern Company, Segment(s) 1, 3, 5, 6, 8/3/2016

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The RC can specify this as required data in their documented specification for data from IRO-010-2.

Stephanie Burns, On Behalf of: International Transmission Company Holdings Corporation, MRO, SPP RE, RF, Segments 2

- 0 - 0

In many cases the RC is the Planning Authority for the TOP.  If the RC is not aware of the voltage schedule provided to the generators, this cannot be taken into account for system planning.

David Jendras, On Behalf of: Ameren - Ameren Services, , Segments 1, 3, 6

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The RC has other ways of getting this information.

Daniel Gacek, On Behalf of: Exelon, , Segments 1, 3, 5, 6

- 0 - 0

Laura Nelson, On Behalf of: Laura Nelson, , Segments 1

- 0 - 0

RC is informed as part of IRO-010. 

Sandra Shaffer, On Behalf of: Sandra Shaffer, , Segments 6

- 0 - 0

John Seelke, On Behalf of: John Seelke, , Segments 1

- 0 - 0

Aubrey Short, On Behalf of: Aubrey Short, , Segments 1, 3, 4

- 0 - 0

Michael Cruz-Montes, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

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Per R1.1 the RC can obain a copy of the voltage schedule. Therefore the schedules are available to the RC.

RSC no ISO-NE, Segment(s) 1, 0, 2, 4, 5, 6, 7, 3, 4/13/2017

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The TOP is responsible for system operations and reliability. The RC can specify their data needs per IRO-010-2.   

Russel Mountjoy, On Behalf of: Russel Mountjoy, , Segments 10

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An RC may already be receiving this information via established agreements with member entities, and can request this information at any time. While having this information may be helpful for the RC, we do not see a real impact to reliability with there not being a requirement to provide the RC with these scehdules.

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

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The review group does not find any reliability impact with the RC not receiving the voltage and Reactive Power schedules from the TOP. However as registered RC, SPP finds the data in the schedules to be very valuable to other processes associated with the RC function. For example, this particular data can help increase the accuracy of the network applications as well as the Real-time Assessment. In our review and interpretation of the IRO Standards, it is our understanding that the IRO-010-2 Standard addresses the RC receiving this type of data and eliminating any concerns for reliability issues.

SPP Standards Review Group, Segment(s) , 4/13/2017

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Texas RE suggests it would be prudent for the RC to understand its entities’ voltage and Reactive Power schedules.  Understanding these schedules allow for better planning of reactive resources and, system awareness.  Since the RC has the authority to direct dispatch of generation outside of its voltage or reactive power schedule due to real time concerns or contingencies, it should know it is doing so. Knowledge of normal reactive schedules is a primary means by which an RC can realize the extent of reactively deficient areas.

Rachel Coyne, On Behalf of: Texas Reliability Entity, Inc., , Segments 10

- 0 - 0

By its definition, a TOP is the entity responsible for the reliability of its “local” transmission system.  The issuance of voltage or Reactive Power schedules to generators should be identified as a “local” reliability concern.  We feel the inclusion of the RC as a recipient would be burdensome, particularly when monitoring and assessing the Wide Area view of the BES.

ACES Standards Collaborators, Segment(s) 1, 5, 3, 4, 6, 4/13/2017

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NERC currently has IRO Standards that require RC’s to obtain this information.

ISO/RTO Standards Review Committee, Segment(s) 2, 4/13/2017

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Reclamation proposes the TOP should provide the RC with copies of the voltage or Reactive Power schedules issued to generators so that the RC has the appropriate information for analysis and operations.

Richard Jackson, On Behalf of: U.S. Bureau of Reclamation, , Segments 1, 5

- 0 - 0

Hien Ho, On Behalf of: Tacoma Public Utilities (Tacoma, WA), , Segments 1, 3, 4, 5, 6

- 0 - 0

Hot Answers

There are instances where the PSS will have an impact on IROL Limits.  PSS desired states should be determined for each generator.  ERCOT has Protocols that identify the necessary coordination.  While this is a best practice, ERCOT sees no need to codify this in a standard. 

Elizabeth Axson, On Behalf of: Elizabeth Axson, , Segments 2

- 0 - 0

Michael Godbout, On Behalf of: Hydro-Qu?bec TransEnergie, NPCC, Segments 1

- 0 - 0

Other Answers

Glen Farmer, On Behalf of: Avista - Avista Corporation, , Segments 1, 3, 5

- 0 - 0

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

- 0 - 0

Preston Walker, On Behalf of: PJM Interconnection, L.L.C., RF, Segments 2

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While Power System Stabilizers are not used on all generating units, a requirement to inform the TOP of the initial state of the PSS may be beneficial for those instances where they are used. That being said, since a Power System Stabilizer does not regulate voltage or reactive power, and, instead, is used to dampen electro-mechanical oscillations, references to Power System Stabilizers should not be added to VAR-001. In addition, consideration might also be given to removing PSS references from VAR-002 as well. It may be worth considering that requirements relating to PSS operation and status be placed in a different standard or technical guide; otherwise, the scope of these standards should be expanded to encompass PSS operation and status.

 

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

- 0 - 0

The PSS status information does not meaningfully impact the TOP. 

Michelle Amarantos, On Behalf of: APS - Arizona Public Service Co., , Segments 1, 3, 5, 6

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Sean Bodkin, On Behalf of: Dominion - Dominion Resources, Inc., , Segments 3, 5, 6

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The PSS on many units do not come into service until the unit is on line and loaded to some point. The initial state of the PSS should be considered out of service until documentation provided by the GOP states when the PSS comes into service. Once that point is obtained, the PSS should be considered in service unless notied other wise by the GOP.

 

DTE Energy - DTE Electric, Segment(s) 5, 4, 3, 2/27/2017

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Agree that clarity is needed, but this should appear in VAR-002 R1, not related to VAR-001 R5. Disagree with putting this content in VAR-001.

Entergy/NERC Compliance, Segment(s) 1, 5, 3/1/2017

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As BPA is a part of the WECC region, there is already standard VAR-501-WECC-2 with a requirement for PSS to be kept in service.

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

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Jesus Sammy Alcaraz, On Behalf of: Imperial Irrigation District, , Segments 1

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PSS requirements are often already detailed in the interconnection requirements or existing regional requirements.  A PSS is typically set up in such a way it would be automatically turned on/off at pre-determined MW setpoints when the AVR is in service.  So, with languge on AVR, it will typically also cover the PSS.

Southern Company, Segment(s) 1, 3, 5, 6, 8/3/2016

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It may not be wise for the TOP to dictate the PSS status as part of a NERC standard. However, the TOP should be aware of the PSS status. Perhaps, the GOP should be required to tell the TOP the actual and normal PSS status on an annual basis, in additional to real-time notification of status changes.

Stephanie Burns, On Behalf of: International Transmission Company Holdings Corporation, MRO, SPP RE, RF, Segments 2

- 0 - 0

In many cases system stability is greatly altered with a PSS out of service.  Therefore the initial state of the PSS is very important and should be stipulated.    PSS is normally fixed in the firmware of the generator and cannot be changed or altered.

If a unit is designed such that the initial state of the PSS will be “on” when the unit is first synchronized, that this information can be shared with the TOP in a ONE TIME notification which will inform the TOP that the PSS is always on, unless notified. It is essential that the TOP know the state of the PSS but if the design “forces” the PSS to be on unless otherwise “switched” off and the “switch off” entails notice, then the TOP would know the status.

David Jendras, On Behalf of: Ameren - Ameren Services, , Segments 1, 3, 6

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A PSS does not function like an AVR, a PSS is typically not enabled automatically until a certain MWe when ramping a unit up in power and subsequently disabled at a certain MWe on ramping a unit down in power.  Specifying an initial state may not be meaningful.

Daniel Gacek, On Behalf of: Exelon, , Segments 1, 3, 5, 6

- 0 - 0

Laura Nelson, On Behalf of: Laura Nelson, , Segments 1

- 0 - 0

Sandra Shaffer, On Behalf of: Sandra Shaffer, , Segments 6

- 0 - 0

John Seelke, On Behalf of: John Seelke, , Segments 1

- 0 - 0

Aubrey Short, On Behalf of: Aubrey Short, , Segments 1, 3, 4

- 0 - 0

Michael Cruz-Montes, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

- 0 - 0

A PSS would only be installed if there was a reliability reason. Presumably when the generator and PSS were commissioned the TOP knew the status. Therefore only notifications of chages to the status are necessary.

RSC no ISO-NE, Segment(s) 1, 0, 2, 4, 5, 6, 7, 3, 4/13/2017

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The NSRF acknowledges a potential impact on reliability, but only when there is an identified reliability need per the TPL-001-4 stability analysis. We agree there is a need to know the initial state.  However, VAR-002-4 R3 already requires the GOP to notify the TOP of PSS change.  The TOP can pursue other avenues via a data specification request (TOP-003-3 and IRO-010-2).

Russel Mountjoy, On Behalf of: Russel Mountjoy, , Segments 10

- 0 - 0

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

- 0 - 0

The SPP Review Group has no concerns with the power system stabilizer (PSS) initial state not being mentioned in this particular requirement. After reviewing VAR-001 and VAR-002 Standards, the review group believes that the PSS status change concerns are addressed in VAR-002-4 under Requirement R3 and there are no concerns in reference to reliability issues.

SPP Standards Review Group, Segment(s) , 4/13/2017

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Texas RE recommends a similar requirement for the PSS.  Understanding the PSS availability gives a broader view of the system and its ability to damp out instability.  While the PSS is not a reactive resource (it is a real power resource), studies should provide input on which assumptions concerning PSS were used, and whether there should be PSS in-service requirements for regional generation. If determined dynamically necessary, enough PSSs must be in service regionally to provide the necessary oscillatory damping. 

Rachel Coyne, On Behalf of: Texas Reliability Entity, Inc., , Segments 10

- 0 - 0

The question assumes that all generators have a PSS.  This is simply not true.  For those that do, the GOP is already required to notify the TOP of a PSS status change in Requirement R3 of NERC Standard VAR-002-4.  This notification is used to identify what is outside normal operation and could affect a generator’s availability.

ACES Standards Collaborators, Segment(s) 1, 5, 3, 4, 6, 4/13/2017

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Impacts on the system would be highly dependent on the specific system characteristics as well as the specific unit characteristics, however There can be instances where the PSS will have an impact on IROL Limits.

ISO/RTO Standards Review Committee, Segment(s) 2, 4/13/2017

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Reclamation contends both AVR and PSS should be addressed in both VAR-001-4.1 and VAR-002-4. The lack of including PSS creates the need to address PSS in regional variances to ensure grid stability. Reclamation asserts that it is important for PSSs to be required as applicable.

Richard Jackson, On Behalf of: U.S. Bureau of Reclamation, , Segments 1, 5

- 0 - 0

Hien Ho, On Behalf of: Tacoma Public Utilities (Tacoma, WA), , Segments 1, 3, 4, 5, 6

- 0 - 0

Hot Answers

If there are external controls loops that could override the AVR and limit the reactive output, some level of coordination or notification is appropriate.  However, this does not necessarily require modification to a standard.

Elizabeth Axson, On Behalf of: Elizabeth Axson, , Segments 2

- 0 - 0

Michael Godbout, On Behalf of: Hydro-Qu?bec TransEnergie, NPCC, Segments 1

- 0 - 0

Other Answers

Glen Farmer, On Behalf of: Avista - Avista Corporation, , Segments 1, 3, 5

- 0 - 0

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

- 0 - 0

Preston Walker, On Behalf of: PJM Interconnection, L.L.C., RF, Segments 2

- 0 - 0

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

- 0 - 0

Michelle Amarantos, On Behalf of: APS - Arizona Public Service Co., , Segments 1, 3, 5, 6

- 0 - 0

Sean Bodkin, On Behalf of: Dominion - Dominion Resources, Inc., , Segments 3, 5, 6

- 0 - 0

No comments

DTE Energy - DTE Electric, Segment(s) 5, 4, 3, 2/27/2017

- 0 - 0

The "how" of meeting the specifications of the TOP is not the TOP's job to define. This may be a lessons learned to consider these factors in your "net" response. This should be results based and not method determinate.

Entergy/NERC Compliance, Segment(s) 1, 5, 3/1/2017

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There are external control loops, like VAR regulators and power factor controllers, that can over-ride action of generator’s Automatic Voltage Regulator. The action of such controls is one of the contributing factors to the August 10, 1996 Western Interconnection power outage. BPA believes if language were to be included in a Standard revision, it would need to be carefully drafted as it may become too prescriptive, requiring expensive equipment replacements.

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

- 0 - 0

Jesus Sammy Alcaraz, On Behalf of: Imperial Irrigation District, , Segments 1

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Not necessarily - it depends - at the high speed response level (the inverter) most DGR sites do not employ voltage control - most run in reactive control or PF control.  They respond to commands from the outer loop plant voltage control. The external (plant wide) control loops are slower in response time to what is traditionally considered to be used for system transient voltage conditions.  The external loops can assist with ensuring that the voltage schedule is followed.    

Southern Company, Segment(s) 1, 3, 5, 6, 8/3/2016

- 0 - 0

Both GOP and TOP need to understand how a generator is going to control voltage. Requiring that the GOP understand and document any external control schemes lends itself to improving reliability.

Stephanie Burns, On Behalf of: International Transmission Company Holdings Corporation, MRO, SPP RE, RF, Segments 2

- 0 - 0

If the AVR response is altered due to external control loops, this needs to be taken into account.  The purpose of VAR-001 in its entirety is for the TOP to understand the VAR resources available from each generator.  If the resource availability is altered due to something other than automatic voltage control, the TOP needs to be aware of it and also have the latitude to request removal of the loop if it is not for the protection of the unit, transmission system or equipment on which either is dependent.

AVR is required to operate in auto if not a notification is required per VAR-002. 

We are concerned that even though the AVR could stay in auto, an external control loop might impact the reactive response of the generator.  We believe that this could, in effect, defeat the purpose of the AVR to control the voltage as mandated. 

David Jendras, On Behalf of: Ameren - Ameren Services, , Segments 1, 3, 6

- 0 - 0

Daniel Gacek, On Behalf of: Exelon, , Segments 1, 3, 5, 6

- 0 - 0

N/A

Laura Nelson, On Behalf of: Laura Nelson, , Segments 1

- 0 - 0

Sandra Shaffer, On Behalf of: Sandra Shaffer, , Segments 6

- 0 - 0

John Seelke, On Behalf of: John Seelke, , Segments 1

- 0 - 0

Aubrey Short, On Behalf of: Aubrey Short, , Segments 1, 3, 4

- 0 - 0

Michael Cruz-Montes, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

- 0 - 0

RSC no ISO-NE, Segment(s) 1, 0, 2, 4, 5, 6, 7, 3, 4/13/2017

- 0 - 0

Russel Mountjoy, On Behalf of: Russel Mountjoy, , Segments 10

- 0 - 0

While external control loops can provide an unintended impact to reliability we do not believe that VAR-001 is the correct standard to address identifying and correcting these deficiencies. We believe MOD-025 or MOD-026 would be a more appropriate standard to identify the need to document and communicate the impact of external control loop actions on the AVR to the TOP.

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

- 0 - 0

The SPP Review Group has no concerns with control loops not being mentioned in this particular requirement as well as seeing no reliability issues. The status change of the alternative voltage controlling device (control loops) has been addressed in the VAR-002-4 Standard under Requirement R3. 

SPP Standards Review Group, Segment(s) , 4/13/2017

- 0 - 0

Texas RE recommends external control loops (for example, PSS) that have an affect on AVR operations should be considered in planning studies to alleviate impacts to reliability. 

Rachel Coyne, On Behalf of: Texas Reliability Entity, Inc., , Segments 10

- 0 - 0

We do not believe there is a need to require coordination of external loops.  Though we thank the Periodic Review Team for reaffirming the importance of this documented NERC lesson learned, we disagree that the occurrence of this singularity necessitates a NERC enforceable requirement.  This would set a precedence for all future NERC Lesson Learned and undermine the intent of that program.

ACES Standards Collaborators, Segment(s) 1, 5, 3, 4, 6, 4/13/2017

- 0 - 0

If there are external controls loops that could override the AVR and limit the reactive output, some level of coordination or notification should be required. Plant owners need to be diligent that external control loops do not counteract the primary function of excitation or governor control.

ISO/RTO Standards Review Committee, Segment(s) 2, 4/13/2017

- 0 - 0

Reclamation contends that VAR-001-4.1 should require external control loops to be coordinated.

Richard Jackson, On Behalf of: U.S. Bureau of Reclamation, , Segments 1, 5

- 0 - 0

Hien Ho, On Behalf of: Tacoma Public Utilities (Tacoma, WA), , Segments 1, 3, 4, 5, 6

- 0 - 0

Hot Answers

Elizabeth Axson, On Behalf of: Elizabeth Axson, , Segments 2

- 0 - 0

Michael Godbout, On Behalf of: Hydro-Qu?bec TransEnergie, NPCC, Segments 1

- 0 - 0

Other Answers

Glen Farmer, On Behalf of: Avista - Avista Corporation, , Segments 1, 3, 5

- 0 - 0

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

- 0 - 0

Preston Walker, On Behalf of: PJM Interconnection, L.L.C., RF, Segments 2

- 0 - 0

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

- 0 - 0

Michelle Amarantos, On Behalf of: APS - Arizona Public Service Co., , Segments 1, 3, 5, 6

- 0 - 0

Sean Bodkin, On Behalf of: Dominion - Dominion Resources, Inc., , Segments 3, 5, 6

- 0 - 0

No comments

DTE Energy - DTE Electric, Segment(s) 5, 4, 3, 2/27/2017

- 0 - 0

2.4 Reactive Power Schedule should be defined and included the “which could include” statement one time and not repeated throughout the document. It impairs readability.

Entergy/NERC Compliance, Segment(s) 1, 5, 3/1/2017

- 0 - 0

No comments

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

- 0 - 0

Jesus Sammy Alcaraz, On Behalf of: Imperial Irrigation District, , Segments 1

- 0 - 0

Southern Company, Segment(s) 1, 3, 5, 6, 8/3/2016

- 0 - 0

Stephanie Burns, On Behalf of: International Transmission Company Holdings Corporation, MRO, SPP RE, RF, Segments 2

- 0 - 0

David Jendras, On Behalf of: Ameren - Ameren Services, , Segments 1, 3, 6

- 0 - 0

Daniel Gacek, On Behalf of: Exelon, , Segments 1, 3, 5, 6

- 0 - 0

Laura Nelson, On Behalf of: Laura Nelson, , Segments 1

- 0 - 0

No comment.

Sandra Shaffer, On Behalf of: Sandra Shaffer, , Segments 6

- 0 - 0

John Seelke, On Behalf of: John Seelke, , Segments 1

- 0 - 0

Aubrey Short, On Behalf of: Aubrey Short, , Segments 1, 3, 4

- 0 - 0

Michael Cruz-Montes, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

- 0 - 0

RSC no ISO-NE, Segment(s) 1, 0, 2, 4, 5, 6, 7, 3, 4/13/2017

- 0 - 0

The NSRF agrees with the review team.

Russel Mountjoy, On Behalf of: Russel Mountjoy, , Segments 10

- 0 - 0

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

- 0 - 0

SPP Standards Review Group, Segment(s) , 4/13/2017

- 0 - 0

Texas RE recommends using the latest Results Based Standards template for VAR-001.  Texas RE noticed R4 starts with “The Transmission Operator…” but the R4 Measure says “Each Transmission Operator…”

Rachel Coyne, On Behalf of: Texas Reliability Entity, Inc., , Segments 10

- 0 - 0

We agree with the errata list and thank the Periodic Review Team for identifying these administrative type observations.

ACES Standards Collaborators, Segment(s) 1, 5, 3, 4, 6, 4/13/2017

- 0 - 0

ISO/RTO Standards Review Committee, Segment(s) 2, 4/13/2017

- 0 - 0

Reclamation agrees with the proposed errata.

Richard Jackson, On Behalf of: U.S. Bureau of Reclamation, , Segments 1, 5

- 0 - 0

Hien Ho, On Behalf of: Tacoma Public Utilities (Tacoma, WA), , Segments 1, 3, 4, 5, 6

- 0 - 0

Hot Answers

It may be helpful to define the terms “voltage schedules” and “Automatic Voltage Regulators” for the sake of clarity.  There has been confusion around the terms “voltage schedules,” “reactive power schedules,” and “voltage limits.”  The recent Reactive Power Planning Realibility Guideline has added some clarity to what is a “voltage schedule,” and it seems clear that this is not synonomous with “voltage limits,” but the definition could be clearer than the parentheticals in the requirements R1 and R5 today.  Additionally there has been confusion between the voltage schedules in R1 and those mentioned in R5 if they are one and the same or different. 

Elizabeth Axson, On Behalf of: Elizabeth Axson, , Segments 2

- 0 - 0

Attachment 5, point 5.3.

In the Québec interconnection, a number of step-up transformers are owned by TOs. Standards like FAC-008-3 and PRC-025-1 allow for this reality. This standard does not (R6). We believe that when this standard is revised, this change should be made in order to make the standard consistently applicable.

This same requirement (R6) (and the matching requirements in VAR-002-4) do not seem to be RBS. In particular, they do not specify a performance to be achieved, only a means - tap changes - by which an unspecified goal must be attained. In the Enhanced Periodic Review, some parties stated that such a requirement regarding tap changes was necessary in some regions. Nevertheless, such a requirement currently calls out a single manner of achieving an unnamed goal. Currently, the requirement, as written, causes us no problems. However, when the standard is revised, it should be rewritten to reflect a performance-based approach.

Michael Godbout, On Behalf of: Hydro-Qu?bec TransEnergie, NPCC, Segments 1

- 0 - 0

Other Answers

Glen Farmer, On Behalf of: Avista - Avista Corporation, , Segments 1, 3, 5

- 0 - 0

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

- 0 - 0

Preston Walker, On Behalf of: PJM Interconnection, L.L.C., RF, Segments 2

- 0 - 0

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

- 0 - 0

Michelle Amarantos, On Behalf of: APS - Arizona Public Service Co., , Segments 1, 3, 5, 6

- 0 - 0

Sean Bodkin, On Behalf of: Dominion - Dominion Resources, Inc., , Segments 3, 5, 6

- 0 - 0

No comments

DTE Energy - DTE Electric, Segment(s) 5, 4, 3, 2/27/2017

- 0 - 0

1.1 Disagree, these are separate actions by separate functional entities and need to be required independently. Could reword to say “…in automatic control mode as specified by the TOP”.

2.1 Entergy does not find this unclear – is this a frequently violated or misunderstood requirement in the industry?

2.2 Disagree - don't see this as an action that will improve reliability. This seems like an administrative or business practice that is out of scope of the standard.

2.3 agree

2.4 disagree. the transmission operators are already tasked with maintaining the reliability of the BES in their interconnection by detailed means.

2.5 Recommend solving this issue with a glossary term, as commented above. Avoid excess noisy verbiage in the requirements that might cause confusion and impair readability.

3.1 Agree, see comments above.

4.1 and 4.2 - Disagree, would like to see "assess and schedule" added to R2 to make the wording more robust.

4.3 Agree - - term “instruct” should be used consistently throughout the standards (it is an Operating Instruction).

4.5 Agree, change to "all applicable" or "all non-exempt" also applies to part 1 of R5 severe VSL

4.6 Agree, Severe is for missing all of the applicable GOPs, High would be for missing 1 or more of non-exempt GOPs.

4.7 and 4.8 Agree

4.9 We agree that this information is important and needs to be considered, but feel that dynamic voltage schedules need to be developed into a new/separate requirement (new R6) and make the original R6 into R7.

5.1 agree

5.2 agree, recommend to go with "instruct" consistently in this and other standards. (see reasoning above)

5.3 Agree - TOP should coordinate with the "GSU Owner" rather than trying to specify any Functional Entity.

9.1 Not necessary for clarity - is this a highly violated and misunderstood requirement in industry?

Entergy/NERC Compliance, Segment(s) 1, 5, 3/1/2017

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No comments

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

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Jesus Sammy Alcaraz, On Behalf of: Imperial Irrigation District, , Segments 1

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Item 1.1:  R5.1 of VAR-001-4.1 is not a GOP requirement, so there is no redundancy with R1 of VAR-002-4.   

Item 2.2:  No additional clarity is needed for R2.2 of VAR-001-4.1 for how a TP determines the exemption criteria needs to be individually decided and not dictated.   

Item 3.1:   It is not necessary to define the terms listed in the article - generator owners and operators are already fully aware of the meaning of the terms. 

Item 2.4:  No additional clarity is needed  around coordination of implementing voltage schedules at the same point in time.  Transmission Operators are well aware of the system response to changes in voltage schedule and already take that into consideration.

Southern Company, Segment(s) 1, 3, 5, 6, 8/3/2016

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Stephanie Burns, On Behalf of: International Transmission Company Holdings Corporation, MRO, SPP RE, RF, Segments 2

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For #1 in Attachment 5, VAR-002-4 Requirement R1 is not redundant with VAR-001-4.1 Requirement R5 in that it does not specify the location of the monitoring or control.  VAR-002-4 Requirement R2, Part 2.3 does stipulate that the GOP must inform the TOP if the location is not the location the TOP required when they provided the voltage schedule.  However, it does not allow for approval by the TOP of the methodology for conversion of the schedule.  Therefore, the requirement in VAR-001-4.1 Requirement 5 should not be retired.

David Jendras, On Behalf of: Ameren - Ameren Services, , Segments 1, 3, 6

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Daniel Gacek, On Behalf of: Exelon, , Segments 1, 3, 5, 6

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Laura Nelson, On Behalf of: Laura Nelson, , Segments 1

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No comment.

Sandra Shaffer, On Behalf of: Sandra Shaffer, , Segments 6

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John Seelke, On Behalf of: John Seelke, , Segments 1

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Aubrey Short, On Behalf of: Aubrey Short, , Segments 1, 3, 4

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Michael Cruz-Montes, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

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RSC no ISO-NE, Segment(s) 1, 0, 2, 4, 5, 6, 7, 3, 4/13/2017

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The review team has highlighted a number of issues that would help with clarification of requirements, however the review team has also indicated that this is not a highly violated standard, is practically implemented and addresses a reliability need.

Russel Mountjoy, On Behalf of: Russel Mountjoy, , Segments 10

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

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SPP Standards Review Group, Segment(s) , 4/13/2017

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Texas RE does not have comments on this question.

Rachel Coyne, On Behalf of: Texas Reliability Entity, Inc., , Segments 10

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We thank the Periodic Review Team for identifying Paragraph 81 requirements within this standard.  However, the team also identified the need for additional requirements.  We believe this is a step in the wrong direction for a standard that is not often violated.

ACES Standards Collaborators, Segment(s) 1, 5, 3, 4, 6, 4/13/2017

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ISO/RTO Standards Review Committee, Segment(s) 2, 4/13/2017

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Reclamation agrees with the proposed observations.

Richard Jackson, On Behalf of: U.S. Bureau of Reclamation, , Segments 1, 5

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Hien Ho, On Behalf of: Tacoma Public Utilities (Tacoma, WA), , Segments 1, 3, 4, 5, 6

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Hot Answers

Elizabeth Axson, On Behalf of: Elizabeth Axson, , Segments 2

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Michael Godbout, On Behalf of: Hydro-Qu?bec TransEnergie, NPCC, Segments 1

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Other Answers

Glen Farmer, On Behalf of: Avista - Avista Corporation, , Segments 1, 3, 5

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

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Preston Walker, On Behalf of: PJM Interconnection, L.L.C., RF, Segments 2

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

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Michelle Amarantos, On Behalf of: APS - Arizona Public Service Co., , Segments 1, 3, 5, 6

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Without additional information and studies it is difficult to determine cost impacts relative to the reliability benefits provided by the standard.

Sean Bodkin, On Behalf of: Dominion - Dominion Resources, Inc., , Segments 3, 5, 6

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No comments

DTE Energy - DTE Electric, Segment(s) 5, 4, 3, 2/27/2017

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Entergy/NERC Compliance, Segment(s) 1, 5, 3/1/2017

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Per Question 7 – BPA believes any new requirement would need to be drafted in such a way that the needed functionality can be achieved without requiring the potential for replacing a bevy of equipment.

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

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Jesus Sammy Alcaraz, On Behalf of: Imperial Irrigation District, , Segments 1

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Southern Company, Segment(s) 1, 3, 5, 6, 8/3/2016

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Stephanie Burns, On Behalf of: International Transmission Company Holdings Corporation, MRO, SPP RE, RF, Segments 2

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David Jendras, On Behalf of: Ameren - Ameren Services, , Segments 1, 3, 6

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Daniel Gacek, On Behalf of: Exelon, , Segments 1, 3, 5, 6

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Laura Nelson, On Behalf of: Laura Nelson, , Segments 1

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Cost effectiveness is always a concern but should not take precedence over reliability issues. 

Sandra Shaffer, On Behalf of: Sandra Shaffer, , Segments 6

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John Seelke, On Behalf of: John Seelke, , Segments 1

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Aubrey Short, On Behalf of: Aubrey Short, , Segments 1, 3, 4

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Michael Cruz-Montes, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

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RSC no ISO-NE, Segment(s) 1, 0, 2, 4, 5, 6, 7, 3, 4/13/2017

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Russel Mountjoy, On Behalf of: Russel Mountjoy, , Segments 10

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

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SPP Standards Review Group, Segment(s) , 4/13/2017

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Rachel Coyne, On Behalf of: Texas Reliability Entity, Inc., , Segments 10

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ACES Standards Collaborators, Segment(s) 1, 5, 3, 4, 6, 4/13/2017

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ISO/RTO Standards Review Committee, Segment(s) 2, 4/13/2017

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Reclamation does not have any concerns related to the cost effectiveness of VAR-001-4.1, but asserts that the standard would be more cost-effective after incorporating the above suggestions.

Richard Jackson, On Behalf of: U.S. Bureau of Reclamation, , Segments 1, 5

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Hien Ho, On Behalf of: Tacoma Public Utilities (Tacoma, WA), , Segments 1, 3, 4, 5, 6

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Hot Answers

ERCOT does believe the Reliability Standard is sufficient to protect reliability and meet the reliability objective of the standard and does not need immediate modification through standards development. 

Elizabeth Axson, On Behalf of: Elizabeth Axson, , Segments 2

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The EPR has identified a number of issues. However, most issues identified so far seem relatively minor. We do not see a pressing need to revise the standard at this time. At some point though, the standard will have to be revised and cleaned up though.

 

Michael Godbout, On Behalf of: Hydro-Qu?bec TransEnergie, NPCC, Segments 1

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Other Answers

Glen Farmer, On Behalf of: Avista - Avista Corporation, , Segments 1, 3, 5

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

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Preston Walker, On Behalf of: PJM Interconnection, L.L.C., RF, Segments 2

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

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AZPS recommends a change the Purpose to remove “monitoring” since there are no monitoring requirements. 

Michelle Amarantos, On Behalf of: APS - Arizona Public Service Co., , Segments 1, 3, 5, 6

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Sean Bodkin, On Behalf of: Dominion - Dominion Resources, Inc., , Segments 3, 5, 6

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No comments

DTE Energy - DTE Electric, Segment(s) 5, 4, 3, 2/27/2017

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Entergy/NERC Compliance, Segment(s) 1, 5, 3/1/2017

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No comments

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

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Jesus Sammy Alcaraz, On Behalf of: Imperial Irrigation District, , Segments 1

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 All suggested changes found in Attachment 4 of the periodic review are acceptable.   The other changes suggested are not needed.    

Southern Company, Segment(s) 1, 3, 5, 6, 8/3/2016

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Due to the lack of a requirement across all the NERC standards for any party to monitor reactive reserves, the VAR-001 standard should be revised to include such a requirement on the TOP. This standard review should be graded as REVISE – RED.

Stephanie Burns, On Behalf of: International Transmission Company Holdings Corporation, MRO, SPP RE, RF, Segments 2

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David Jendras, On Behalf of: Ameren - Ameren Services, , Segments 1, 3, 6

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Daniel Gacek, On Behalf of: Exelon, , Segments 1, 3, 5, 6

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Laura Nelson, On Behalf of: Laura Nelson, , Segments 1

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Sandra Shaffer, On Behalf of: Sandra Shaffer, , Segments 6

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John Seelke, On Behalf of: John Seelke, , Segments 1

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While our responses to Q1, Q2 and Q3 suggestion some improvements in the standard may be warranted based on the questions asked, we believe that overall the standard is sufficient.  However, if the majority of industry also believes there may be some reliability impact to the items raised in Q1, Q2 and Q3 then NERC may need to further investigate those items through a standards development project.

Aubrey Short, On Behalf of: Aubrey Short, , Segments 1, 3, 4

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CenterPoint Energy believes that the VAR-001-4.1 Standard is sufficient to protect reliability and meet the reliability objective of the standard and does not need immediate modification through standards development. We appreciate the efforts of the review team in identifying  potential areas for future improvement to low priority issues.

Michael Cruz-Montes, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

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RSC no ISO-NE, Segment(s) 1, 0, 2, 4, 5, 6, 7, 3, 4/13/2017

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Russel Mountjoy, On Behalf of: Russel Mountjoy, , Segments 10

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

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SPP Standards Review Group, Segment(s) , 4/13/2017

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Texas RE frequently encounters wind farms that do not recognize that the technology to maintain voltage is an AVR.  Wind Farm Management Systems (under a variety of names) clearly demonstrate the capability to control volatage and are used daily but, because it is not specifically called an “AVR”, entities often miss responsibilities.  With the penetration of wind, it is imperative that this get corrected globally, rather than one-off awareness (via an compliance discovery method) or workshops that are not necessarily attended by all parties.  Texas RE has done outreach and will continue to do so but would encourage a project to clarify the VAR standards.  

Rachel Coyne, On Behalf of: Texas Reliability Entity, Inc., , Segments 10

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We thank you for this opportunity to provide these comments.

ACES Standards Collaborators, Segment(s) 1, 5, 3, 4, 6, 4/13/2017

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ISO/RTO Standards Review Committee, Segment(s) 2, 4/13/2017

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Reclamation asserts that VAR-001-4.1 should be modified to include the proposed requirements, errata, and observations. Reclamation supports periodic reviews of standards like these as essential, and appreciates the work of the Periodic Review Team.

Richard Jackson, On Behalf of: U.S. Bureau of Reclamation, , Segments 1, 5

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Hien Ho, On Behalf of: Tacoma Public Utilities (Tacoma, WA), , Segments 1, 3, 4, 5, 6

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