This comment form is no longer interactive because the comment period is closed.

2015-08 Emergency Operations | EOP-004-4

Description:

Start Date: 07/25/2016
End Date: 09/08/2016

Associated Ballots:

Ballot Name Project Standard Pool Open Pool Close Voting Start Voting End
2015-08 Emergency Operations | EOP-004-4 EOP-004-4 IN 1 ST 2015-08 Emergency Operations | EOP-004-4 EOP-004-4 07/25/2016 08/23/2016 08/30/2016 09/08/2016
2015-08 Emergency Operations | EOP-004-4 EOP-004-4 NBP IN 1 NB 2015-08 Emergency Operations | EOP-004-4 EOP-004-4 NBP 07/25/2016 08/23/2016 08/30/2016 09/08/2016

Filter:

Hot Answers

None

Jaclyn Massey, 9/8/2016

- 0 - 0

Mark Riley, 9/8/2016

- 0 - 0

Other Answers

Mike Anctil, 7/27/2016

- 0 - 0

Mary Cooper, On Behalf of: Alameda Municipal Power - WECC - Segments 3, 4

- 0 - 0

Marcus Freeman, On Behalf of: ElectriCities of North Carolina, Inc., SERC, Segments 4

- 0 - 0

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

- 0 - 0

Sing Tay, On Behalf of: OGE Energy - Oklahoma Gas and Electric Co., SPP RE, Segments NA - Not Applicable

- 0 - 0

Jeffrey DePriest, DTE Energy - Detroit Edison Company, 5, 8/23/2016

- 0 - 0

Nick Vtyurin, On Behalf of: Manitoba Hydro - MRO - Segments 1, 3, 5, 6

- 0 - 0

RoLynda Shumpert, On Behalf of: SCANA - South Carolina Electric and Gas Co., SERC, Segments 1, 3, 5, 6

- 0 - 0

Jamie Monette, Allete - Minnesota Power, Inc., 1, 8/26/2016

- 0 - 0

PSEG, Segment(s) 5, 6, 1, 3, 3/10/2016

- 0 - 0

Leonard Kula, Independent Electricity System Operator, 2, 8/30/2016

- 0 - 0

Jamie Monette, Allete - Minnesota Power, Inc., 1, 8/30/2016

- 0 - 0

Amy Casuscelli, On Behalf of: Xcel Energy, Inc. - MRO, WECC, SPP RE - Segments 1, 3, 5, 6

- 0 - 0

LG&E and KU Energy, Segment(s) 3, 5, 6, 5/26/2016

- 0 - 0

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

- 0 - 0

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

- 0 - 0

Tennessee Valley Authority, Segment(s) 1, 3, 5, 6, 10/5/2015

- 0 - 0

Quintin Lee, Eversource Energy, 1, 9/6/2016

- 0 - 0

For all questions the California ISO supports the comments of the ISO/RTO Council Standards Review Committee

Richard Vine, California ISO, 2, 9/6/2016

- 0 - 0

Sean Bodkin, Dominion - Dominion Resources, Inc., 6, 9/6/2016

- 0 - 0

- 0 - 0

SRP recommends adjusting the language in R2 to clarify the requirement is referring to events “recognized” during a weekend as opposed to events “occurring” on a weekend.

As the current language stands, an event occurring at 7:00 AM on a Monday would have to be reported by the end of the same business day.

Diana McMahon, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

- 0 - 0

NPPD recommends that the parenthetical text be updated to read:  (which is usually recognized to be 4PM local time on Friday to 8AM local time on Monday, unless the entity is observing a holiday.  For any holiday, the event report shall be submitted no later than then the end of the next business day).  Also, for events occurring after noon (12:00 p.m. local time) on a day prior to a weekend or holiday, the event report shall be submitted no later than the end of the next business day

Don Schmit, Nebraska Public Power District, 5, 9/7/2016

- 1 - 0

Thomas Foltz, AEP, 5, 9/7/2016

- 0 - 0

The NSRF agrees with R1 and recommends a small change to R2.  Recommend the follow additions to clarify that all entities experience “holidays” and those holidays should be included in the same manner as weekends. 

Each Responsible Entity shall report events specified in EOP-004-4 Attachment 1 to the entities specified per their Operating Plan within 24 hours of recognition of meeting an event type threshold for reporting or by the end of the next business day if the event occurs on a weekend (which is recognized to be 4 PM local time on Friday to 8 AM local time on Monday). The NSRF recommend that the parenthetical text be updated to read (which is usually recognized to be 4PM local time on Friday to 8AM local time on Monday, unless the entity is observing a holiday.  For any holiday, the event report shall be submitted no later than then the end of the next business day).  Also, for events occurring after noon (12:00 p.m. local time) on a day prior to a weekend or holiday, the event report shall be submitted no later than the end of the next business day.  

MRO-NERC Standards Review Forum (NSRF), Segment(s) 3, 4, 5, 6, 1, 2, 7/14/2016

- 0 - 0

R2. Each Responsible Entity shall report events specified in EOP-004-4 Attachment 1 to the entities specified per their Operating Plan within 24 hours of recognition of meeting an event type threshold for reporting or by the end of the next business day if the event occurs on a weekend (which is recognized to be 4 PM local time on Friday to 8 AM local time on Monday).

 R2 Recommendation:

NPPD recommends that the parenthetical text be updated to read:  (which is usually recognized to be 4PM local time on Friday to 8AM local time on Monday, unless the entity is observing a holiday.  For any holiday, the event report shall be submitted no later than then the end of the next business day).  Also, for events occurring after noon (12:00 p.m. local time) on a day prior to a weekend or holiday, the event report shall be submitted no later than the end of the next business day. 

Rationale:

Events occurring on a Friday after 12:00 p.m. local time or within the same timing prior to a holiday would have to be reported that day. This does not allow enough time for evaluation and development of a report. In addition, consideration for reporting should also be given to holidays observed by the reporting entity.

Jamison Cawley, Nebraska Public Power District, 1, 9/7/2016

- 1 - 0

We agree with R1 and recommend a small addition to R2 to clarify that all entities experience “holidays” and those holidays may vary from entity to entity and should be included in the same manner as weekends.  Suggested change to R2:

Each Responsible Entity shall report events specified in EOP-004-4 Attachment 1 to the entities specified per their Operating Plan within 24 hours of recognition of meeting an event type threshold for reporting or by the end of the Responsible Entities’ next business day if the event occurs on a holiday or weekend (which is recognized to be 4 PM local time on Friday to 8 AM local time on Monday local time).  Also, for events occurring after noon (12:00 p.m. local time) on a day prior to a weekend or holiday, the event report shall be submitted no later than the end of the Responsible Entities’ next business day.

- 0 - 0

We agree with R1 and recommend a small addition to R2 to clarify that all entities experience “holidays” and those holidays may vary from entity to entity and should be included in the same manner as weekends.  Suggested change to R2:

 Each Responsible Entity shall report events specified in EOP-004-4 Attachment 1 to the entities specified per their Operating Plan within 24 hours of recognition of meeting an event type threshold for reporting or by the end of the Responsible Entities’ next business day if the event occurs on a holiday or weekend (which is recognized to be 4 PM local time on Friday to 8 AM local time on Monday local time).  Also, for events occurring after noon (12:00 p.m. local time) on a day prior to a weekend or holiday, the event report shall be submitted no later than the end of the Responsible Entities’ next business day.

- 0 - 0

Santee Cooper , Segment(s) 1, 9/7/2016

- 0 - 0

Texas RE noticed Requirement R1 has the term “event reporting Operating Plan”, while Requirement R2 just says “Operating Plan”.  Texas RE recommends adding the descriptor “event reporting” to Requirement R2 or removing it from R1 for consistency.  The Requirement R1 VSLs do not include the descriptor except part of the Severe VSL.  It appears that the event report should be a written report yet the VSLs for R2 consider a written or verbal event report.

 

Texas RE noticed there is no requirement specifically indicating how events should be reported.  Additionally, the VSLs indicate that a verbal report is acceptable.  Since an event reporting form exists, Texas RE recommends the requirements specify the form in Attachment 2 be used for event reporting.

 

The language in R2 incorporates the various changes within Attachment 1 by reference.  As such, Texas RE’s concerns regarding changes to Attachment 1 should be incorporated herein by reference. 

Rachel Coyne, Texas Reliability Entity, Inc., 10, 9/7/2016

- 0 - 0

Lynda Kupfer, 9/7/2016

- 0 - 0

Michelle Amarantos, APS - Arizona Public Service Co., 1, 9/7/2016

- 0 - 0

Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 3, 9/7/2016

- 0 - 0

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

- 0 - 0

Johnny Anderson, 9/8/2016

- 0 - 0

 

SMUD/BANC agrees with the intention that the drafting team is heading with the EOP-004 Draft 4 posting.  However, we suggest the Standard Drafting Team consider a minor change to the language in Requirement R2 to address reportable events that occur during holiday periods.  We suggest reportable events occurring during holiday be handled in a similar manner that the ‘weekend’ reportable event schedule that is reported events over the holiday would be reported on next business day.

 

Joe Tarantino, On Behalf of: Sacramento Municipal Utility District - WECC - Segments 1, 3, 4, 5, 6

- 0 - 0

Hydro One Networks is satisfied with the clarification in language in R1 and R2

- 0 - 0

Hydro One Networks is satisfied with the clarification in language in R1 and R2

- 0 - 0

We recommend removing the words “but is not limited to” in M1. This language is no used in R1 and adds no value. It could be interpreted that the Operating Plan must not be limited to the protocols and therefore create an obligation that is not intended to include other elements which are no defined in R1.

 

M1 should read:

M1. Each Responsible Entity will have a dated event reporting Operating Plan that includes the protocol(s) and each organization identified to receive an event report for event types specified in EOP-004-3 Attachment 1 and in accordance with the entity responsible for reporting.

 

Drafting team should consider adding more specificity to the “other organizations” from Requirement 1. As written this is a potential compliance issue if the Registered Entity elects not to include any “other organizations” such as the Regional Entity or the RC. It is unclear if adding other organizations is voluntary or specifically required by the Requirement. 

 

The examples should be removed unless they are required. These would be more appropriate in the measure, not the language of the requirement. If it is not removed, then the Drafting team should consider removing any entities from the example section not specifically related to the ERO Enterprise. For example, the inclusion of law enforcement is unclear. There are many events listed in Attachment 1 in which law enforcement would not need to be notified. Conversely, there are many types of situations that should be reported to law enforcement that are not considered in Attachment 1. Further, all entities that need to be notified of conditions in real-time should be removed from consideration, such as the RC. Notifications to these types of entities is already required within other standards (changes in operating conditions or capabilities in IRO and TOP standards). As this is in the “Operation Planning” time horizon and will be used to inform the industry as needed and support events analysis the only entities that should be listed in this standard is NERC and the Applicable Regional Entity.

 

In R1 and R2 all provisions related to weekends should be removed. The standard requires notification within 24 hours of recognition. If an event occurs on the weekend at an unstaffed location and is not recognized until Monday morning, the entity should still have the 24-hour time frame to complete the notification. As the reporting obligation time frame begins upon “…recognition of meeting an event type threshold for reporting…” there is no need to have a weekend provision. This also removes an ambiguity in R2 which does not have the provision for “recognition of meeting an event type…” for events on the weekend. As written, weekend occurring events must be reported by the end of business Monday regardless of recognizing it as an event identified in Attachment 1.

 

M2 should be revised to remove the implication that EOP-004-4 Attachment 2 or the DOE-OE-417 forms are the only acceptable forms of evidence. As these forms are not specifically listed in the requirement language there should be flexibility written into the measure allowing for other evidence of event reporting. Conversely, the Attachment 2 and OE-417 forms should be listed in the R2 if they are required to demonstrate compliance.

RSC no Dominion and NextEra, Segment(s) 1, 0, 2, 4, 5, 6, 7, 3, 9/8/2016

- 0 - 0

No comments.

Oliver Burke, Entergy - Entergy Services, Inc., 1, 9/8/2016

- 0 - 0

Jennifer Wright, Sempra - San Diego Gas and Electric, 5, 9/8/2016

- 0 - 0

Elizabeth Axson, 9/8/2016

- 0 - 0

ISO/RTO Council Standards Review Committee, Segment(s) 2, 8/12/2016

- 0 - 0

Hydro One Networks Inc. is satisfied with the clarification provided and language in R1 and R2.

Oshani Pathirane, 9/8/2016

- 0 - 0

Justin Mosiman, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

- 0 - 0

NV Energy agrees with R1 and recommends a minor change to R2 to consider holidays and recommends that for any holiday, the event report shall be submitted no later than then the end of the next business day.  Also, for events occurring after noon (12:00 p.m. local time) on a day prior to a weekend or holiday, the event report shall be submitted no later than the end of the next business day. 

- 0 - 0

The proposed changes to R2 are not substantive, which raises the question for the need to revise R2 at all.  R2 states, “Each Responsible Entity shall report events specified in EOP-004-4 Attachment 1 to the entities specified per their Operating Plan within 24 hours of recognition of meeting an event type…”  This change does not propose any new action, as this is already listed in the Operating Plan.  The revision to R2 is not needed.

ACES Standards Collaborators - EOP Project, Segment(s) 1, 5, 3, 6, 4, 9/8/2016

- 0 - 0

Erika Doot, 9/8/2016

- 0 - 0

We request that the SDT confirm that the time clock starts in R2 upon ‘recognition’ of the event threshold rather than when the event occurred.  There may be analysis of the event that later reveals that the threshold was crossed. 

We suggest the following clarification to M2 in order to provide additional clarity that this requirement does not supersede any OE-417 reporting timelines.  This requirement may allow additional time to report to NERC, but OE-417 requirements may still require reporting within a shorter timeframe.

Perhaps all that is needed is the following addition to the proposed M2:

M2.  Each Responsible Entity will have as evidence of reporting an event either a copy of the completed EOP-004-4 Attachment 2 form or a DOE-OE-417 form; and some evidence of submittal (e.g., operator log or other operating documentation, voice recording, electronic mail message, or confirmation of facsimile) demonstrating that the event report was submitted to NERC within 24 hours of recognition of meeting the threshold for reporting or by the end of the next business day if the event occurs on a weekend (which is recognized to be 4 PM local time on Friday to 8 AM local time on Monday).

SPP Standards Review Group, Segment(s) 0, 9/8/2016

- 0 - 0

Dave Thomas, 9/8/2016

- 0 - 0

Kansas City Power and Light Company endorses and incorporates by reference Nebraska Public Power District’s response in opposition to Question 1.

In addition, we offer the following:

Capitalization:  The words “control center” are used in the Rationale. Since the term is an approved NERC Glossary Term, we suggest it be capitalized. If the intent of the SDT was not to use the Glossary Term, Control Center, additional definition and parameters are needed to provide clarity to the meaning of “control center.”

- 0 - 0

Hot Answers

None

Jaclyn Massey, 9/8/2016

- 0 - 0

Mark Riley, 9/8/2016

- 0 - 0

Other Answers

Mike Anctil, 7/27/2016

- 0 - 0

Mary Cooper, On Behalf of: Alameda Municipal Power - WECC - Segments 3, 4

- 0 - 0

Marcus Freeman, On Behalf of: ElectriCities of North Carolina, Inc., SERC, Segments 4

- 0 - 0

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

- 0 - 0

Sing Tay, On Behalf of: OGE Energy - Oklahoma Gas and Electric Co., SPP RE, Segments NA - Not Applicable

- 0 - 0

Jeffrey DePriest, DTE Energy - Detroit Edison Company, 5, 8/23/2016

- 0 - 0

Nick Vtyurin, On Behalf of: Manitoba Hydro - MRO - Segments 1, 3, 5, 6

- 0 - 0

RoLynda Shumpert, On Behalf of: SCANA - South Carolina Electric and Gas Co., SERC, Segments 1, 3, 5, 6

- 0 - 0

Jamie Monette, Allete - Minnesota Power, Inc., 1, 8/26/2016

- 0 - 0

PSEG, Segment(s) 5, 6, 1, 3, 3/10/2016

- 0 - 0

Leonard Kula, Independent Electricity System Operator, 2, 8/30/2016

- 0 - 0

Jamie Monette, Allete - Minnesota Power, Inc., 1, 8/30/2016

- 0 - 0

Amy Casuscelli, On Behalf of: Xcel Energy, Inc. - MRO, WECC, SPP RE - Segments 1, 3, 5, 6

- 0 - 0

LG&E and KU Energy, Segment(s) 3, 5, 6, 5/26/2016

- 0 - 0

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

- 0 - 0

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

- 0 - 0

Tennessee Valley Authority, Segment(s) 1, 3, 5, 6, 10/5/2015

- 0 - 0

Quintin Lee, Eversource Energy, 1, 9/6/2016

- 0 - 0

Richard Vine, California ISO, 2, 9/6/2016

- 0 - 0

Sean Bodkin, Dominion - Dominion Resources, Inc., 6, 9/6/2016

- 0 - 0

- 0 - 0

Diana McMahon, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

- 0 - 0

Don Schmit, Nebraska Public Power District, 5, 9/7/2016

- 0 - 0

While we agree with the proposed retirement of R3, we believe the RC should gather and provide (perhaps on their website) contact information for applicable RCs, REs, and TOs within their footprint to ensure that reports are provided to appropriate entities.

Thomas Foltz, AEP, 5, 9/7/2016

- 0 - 0

MRO-NERC Standards Review Forum (NSRF), Segment(s) 3, 4, 5, 6, 1, 2, 7/14/2016

- 0 - 0

Jamison Cawley, Nebraska Public Power District, 1, 9/7/2016

- 0 - 0

- 0 - 0

- 0 - 0

Santee Cooper , Segment(s) 1, 9/7/2016

- 0 - 0

Texas RE is concerned that contact list will not be updated if there is no requirement to do so.  By removing the obligation, entities may learn of an outdated contact when the contact is needed.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 9/7/2016

- 0 - 0

Lynda Kupfer, 9/7/2016

- 0 - 0

Michelle Amarantos, APS - Arizona Public Service Co., 1, 9/7/2016

- 0 - 0

Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 3, 9/7/2016

- 0 - 0

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

- 0 - 0

Johnny Anderson, 9/8/2016

- 0 - 0

Joe Tarantino, On Behalf of: Sacramento Municipal Utility District - WECC - Segments 1, 3, 4, 5, 6

- 0 - 0

Hydro One Networks is satisfied with the removal of R3.

- 0 - 0

Hydro One Networks is satisfied with the removal of R3.

- 0 - 0

RSC no Dominion and NextEra, Segment(s) 1, 0, 2, 4, 5, 6, 7, 3, 9/8/2016

- 0 - 0

No comments.

Oliver Burke, Entergy - Entergy Services, Inc., 1, 9/8/2016

- 0 - 0

Jennifer Wright, Sempra - San Diego Gas and Electric, 5, 9/8/2016

- 0 - 0

Elizabeth Axson, 9/8/2016

- 0 - 0

ISO/RTO Council Standards Review Committee, Segment(s) 2, 8/12/2016

- 0 - 0

Hydro One Networks Inc. is satisfied with the removal of R3.

Oshani Pathirane, 9/8/2016

- 0 - 0

Justin Mosiman, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

- 0 - 0

- 0 - 0

We agree with the retirement of Requirement R3, because there are administrative aspects to this requirement.

ACES Standards Collaborators - EOP Project, Segment(s) 1, 5, 3, 6, 4, 9/8/2016

- 0 - 0

The Bureau of Reclamation agrees with the drafting team’s proposal to retire EOP-004 Requirement R3 because it is administrative in nature.  

Erika Doot, 9/8/2016

- 0 - 0

SPP Standards Review Group, Segment(s) 0, 9/8/2016

- 0 - 0

Dave Thomas, 9/8/2016

- 0 - 0

- 0 - 0

Hot Answers

a.       At times there may be a need for a Transmission Operator (“TOp”) to implement a public appeal for load reduction in certain areas of their system if there is a system operating limit that can only be controlled by reduced load. Entergy recommends replacing “BA” with initiating Balancing Authority (“BA”) or TOp.

b.       The event types with multiple applicable entities such as, “Firm load shedding resulting from a BES Emergency”, “Uncontrolled loss of firm load resulting from a BES Emergency” and “System separation (islanding)” will most likely have the same event reported multiple times if the BA, TOp, or Reliability Coordinator (“RC”) are different entities. This has in the past been a source of confusion with the same event being reported multiple times. We recommend changing the Entity with Reporting Responsibility for the Event Type. “Firm load shedding resulting from a BES Emergency” to “Initiating RC, BA, or TOp”. We recommend changing the Entity with Reporting Responsibility for Event Type, “Uncontrolled loss of firm load resulting from a BES Emergency” to just BA. We recommend changing the Entity with Reporting Responsibility for the Even Type, “System separation (islanding)” to just the BA. This would eliminate multiple reports for the same event, while still making sure the events are reported.

c.       Under Event Type “Uncontrolled loss of firm load resulting from a BES Emergency” the MW lost amount may be better representative of an impact to a BA if it was a specific percentage of peak load. The current threshold goes from a 10% of total load value for a 3000 MW BA to less than 1% of total load for the bigger BAs.

d.       For Event Type Complete Loss of Interpersonal Communications capability at a BES control center, consider also adding Alternative Communication Capability. This will differentiate the event form a COM standard requirement. On event type include the word “staffed” to match working in the Threshold section. Entergy does not agree that the loss of primary/use of backup control center should be a reportable event. Please provide clarification of this point.   

Jaclyn Massey, 9/8/2016

- 0 - 0

AECI agrees with the revisions to Attachment 1.  However, AECI requests the SDT to revise the term BES control center.  Control Center is already defined in the NERC Glossary of Terms and should be used in lieu of BES control center throughout the attachment.

Mark Riley, 9/8/2016

- 0 - 0

Other Answers

Mike Anctil, 7/27/2016

- 0 - 0

Mary Cooper, On Behalf of: Alameda Municipal Power - WECC - Segments 3, 4

- 0 - 0

Marcus Freeman, On Behalf of: ElectriCities of North Carolina, Inc., SERC, Segments 4

- 0 - 0

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

- 0 - 0

Sing Tay, On Behalf of: OGE Energy - Oklahoma Gas and Electric Co., SPP RE, Segments NA - Not Applicable

- 0 - 0

No suggested changes to the text that has been modified.  In addition, suspicious activity must be defined. 

Jeffrey DePriest, DTE Energy - Detroit Edison Company, 5, 8/23/2016

- 0 - 0

Nick Vtyurin, On Behalf of: Manitoba Hydro - MRO - Segments 1, 3, 5, 6

- 0 - 0

Under Event Type “BES Emergency resulting in voltage deviation on a Facility” the threshold should be updated to include the word ‘exceeding’. The threshold should read ‘A voltage deviation exceeding +/- 10% of nominal voltage sustained for >/= 15 continuous minutes.”

 

 

 

RoLynda Shumpert, On Behalf of: SCANA - South Carolina Electric and Gas Co., SERC, Segments 1, 3, 5, 6

- 0 - 0

Jamie Monette, Allete - Minnesota Power, Inc., 1, 8/26/2016

- 0 - 0

PSEG, Segment(s) 5, 6, 1, 3, 3/10/2016

- 0 - 0

We do not agree with the following changes:

 

  1. For the Event Type “Public appeal for load reduction”: It is unclear what “maintain the continuity of the BES” really means. By “continuity”, does it mean “integrity of the BES” or “continuity of supply”? This needs to be revised to be more specific and to improve clarity.

     

  2. Assigning the TOP to be the responsible entity for reporting system wide voltage reduction

     

    Voltage reduction is intended to reduce system demand to address capacity deficiency. While the TOP may be the entity to actually direct actions (e.g. transformer tap changes) to achieve voltage reduction, the BA is the entity that decides and gives the direction to implement the system wide voltage action/measure to achieve a reduction in system demand. We recommend changing it to the BA. Also, similar to the comment above, it is unclear what “maintain the continuity of the BES” really means. By “continuity”, does it mean “integrity” or “continuity of supply”? Either way, we do not see the value added or the necessity of the having this qualifier. We suggest to revise the Event Type to “System wide voltage reduction” or where a qualifier is deemed to add value, change it to “System wide voltage reduction to maintain load supply” or “to meet system demand”.

     

  3. The Event Type “Firm load shedding resulting from a BES Emergency”: the basis for the reporting threshold, i.e., 100 MW, etc. has not been provided. We would appreciate the SDT providing the technical basis/justification other than just because it existed before.

Leonard Kula, Independent Electricity System Operator, 2, 8/30/2016

- 1 - 0

Jamie Monette, Allete - Minnesota Power, Inc., 1, 8/30/2016

- 0 - 0

In Attachment 1, the removal of the TOP as a responsible reporting Entity for "Damage or destruction of its Facility" and "Physical threats to its Facility" potentially causes concern.  This could be problematic for facilities that are owned by one entity but operated by another.  We request that the SDT have continued discussion around these types of scenarios and consider putting the TOP back in as a responsible Entity.

Amy Casuscelli, On Behalf of: Xcel Energy, Inc. - MRO, WECC, SPP RE - Segments 1, 3, 5, 6

- 0 - 0

LG&E and KU Energy (“LG&E/KU”) appreciates the opportunity to submit this comment for the Standard Drafting Team's consideration.

The reportable event type “Complete loss of Interpersonal Communication capability at a BES control center” has a threshold for reporting of “Complete loss of Interpersonal Communication capability affecting a staffed BES control center for 30 continuous minutes or more.” LG&E/KU proposes the event type be rewritten as “Complete loss of Interpersonal Communication (including Alternative Interpersonal Communication) capability at a BES control center”.  Furthermore, LG&E/KU proposes changing the threshold for reporting to read “Complete loss of Interpersonal Communication (including Alternative Interpersonal Communication) capability affecting a staffed BES control center for 30 continuous minutes or more.”

LG&E and KU Energy, Segment(s) 3, 5, 6, 5/26/2016

- 1 - 0

Event Type: Public appeal for load reduction: There may be a need for a TOP to   implement a public appeal for load reduction in certain areas of their system if there is a system operating limit that can only be controlled by reduced load.  We recommend leaving the “Entity with Reporting Responsibility” as it currently reads: Initiating entity is responsible for reporting.  (Attachment 1, Page 10, 4th Row)

Event Type: Firm load shedding resulting from a BES Emergency:  We recommend leaving the “Entity with Reporting Responsibility” as it currently reads: Initiating entity is responsible for reporting.  (Attachment 1, Page 11, 1st Row)

Event Type: Generation loss; We recommend the following statement for ”Threshold for Reporting:” Reporting of generation loss would be used to report Forced Outages, not weather  patterns or fuel source unavailability for these resources. (Attachment 1, Page 12, 2nd Row)

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

- 0 - 0

CenterPoint Energy appreciates the SDT’s time and effort towards the improvement of the Event Reporting Standard and is agreeable to the proposed revisions to R1 and R2, and the retirement of R3. However, CenterPoint Energy believes that proposed revisions to Attachment 1 may not be completely clear to the industry and would like the SDT to consider the following: 

 

The proposed revisions regarding the “public appeal for load reduction” Event Type appears to expand the threshold to include events beyond the NERC defined “BES Emergency” which is defined as: “Any abnormal system condition that requires automatic or immediate manual action to prevent or limit the failure of transmission facilities or generation supply that could adversely affect the reliability of the Bulk Electric System”. CenterPoint Energy believes removing BES Emergency as a threshold and adding the phrase “continuity of the BES” is ambiguous. The Company appreciates the SDT aligning the language with DOE OE-417; however, DOE OE-417 instructions state that the report should be made only if an appeal is made during emergency conditions. Therefore CenterPoint Energy recommends the reporting threshold read, “BES Emergency requiring public appeal for load reduction to maintain continuity of the BES.

 

CenterPoint Energy also has a similar concern regarding the use of “continuity of the BES” for the proposed changes to the “System-wide voltage reduction…” event type. CenterPoint Energy believes that for consistency the Event type should read, “System-wide voltage reduction” and the threshold for reporting should read, “BES Emergency requiring system wide voltage reduction of 3% or more to maintain continuity of the BES.”

 

In the “BES Emergency requiring manual Firm load shedding” event type, removing the word “manual” potentially broadens the scope and may also include automatic firm load shed, which would incorporate UFLS and UVLS. With these revisions and with the deletion of the Event Type, “BES Emergency resulting in automatic firm load shedding”; is it the SDT’s intent to consolidate all firm load shedding into one event type regardless of whether it is performed automatically or manually? If this is so, are UVLS, UFLS , and RASs still considered as automatic firm load shedding as it would be considered in the revised “Firm load shedding resulting from a BES Emergency” Event Type?

 

CenterPoint Energy considers manual and automatic Firm load shedding to be “controlled” actions that are deliberate and by design, regardless of whether initiated by a System Operator or relay scheme that is triggered by a threshold being met. CenterPoint Energy recommends the “Threshold for Reporting” to read, “Controlled Firm load shedding, manual or automatic via an Undervoltage Load Shedding Program, under-frequency load shedding scheme, or by Remedial Action Scheme ≥ 100 MW.

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

- 0 - 0

At times there may be a need for a TOP to implement a public appeal for load reduction in certain areas of their system if there is a system operating limit that can only be controlled by reduced load.  We recommend replacing “BA” with “Initiating BA or TOP.”

The event types with multiple applicable entities such as, “Firm load shedding resulting from a BES Emergency”, “Uncontrolled loss of firm load resulting from a BES Emergency”, and “System separation (islanding)” will most likely have the same event reported multiple times if the BA, TOP or RC are different entities.  This has in the past been a source of confusion with the same event being reported multiple times.  We recommend changing the Entity with Reporting Responsibility for the Event Type, “Firm load shedding resulting from a BES Emergency” to “Initiating RC, BA, or TOP”.  We recommend changing the Entity with Reporting Responsibility for the Event Type, “Uncontrolled loss of firm load resulting from a BES Emergency” to just the BA.  We recommend changing the Entity with Reporting Responsibility for the Event Type, “System separation (islanding)” to just the BA.  This would eliminate multiple reports for the same event, while still making sure the events are reported.

For Event Type Uncontrolled loss of firm load resulting from a BES Emergency, the MW lost amount may be better representative of an impact to a BA if it was a specific percentage of peak load.  The current threshold goes from a 10% of total load value for a 3000 MW BA to less than 1% of total load for the bigger BAs.

For Event Type Complete Loss of Interpersonal Communications capabilities at a BES control center, consider also adding Alternative Communication Capabilities.  This will differentiate an event from a COM standard requirement.  On the Event Type include “staffed” to match wording in the Threshold section.

For Event Type Unplanned BES control center evacuation, revise to: ‘Unplanned evacuation of its BES control center’ to more specifically identify the control center the Functional Entity is required to report on. This also makes the wording similar to that in the Physical threat Event Type.

Tennessee Valley Authority, Segment(s) 1, 3, 5, 6, 10/5/2015

- 0 - 0

Add the word ‘staffed’ to the threshold column for ‘Complete loss of monitoring or control at a BES control center’ so that it is consistent with the Event Type above it which states:

Complete loss of Interpersonal Communication capability affecting a staffed BES control center for 30 continuous minutes or more.

Quintin Lee, Eversource Energy, 1, 9/6/2016

- 0 - 0

Richard Vine, California ISO, 2, 9/6/2016

- 0 - 0

Consider adding ‘its’ to unplanned evacuation of (its) BES control center for consistency.

Consider adding ‘Alternate Interpersonal Communications’ in addition to complete loss of Interpersonal Communications to add clarity.

Consider adding ‘staffed’ to both event type and threshold for loss of control center Interpersonal Communications (p.12 of 16) for consistency.

Sean Bodkin, Dominion - Dominion Resources, Inc., 6, 9/6/2016

- 0 - 0

- 0 - 0

Diana McMahon, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

- 0 - 0

First Recommendation:  Delete the Transmission loss Event Type in Attachment 1.

 

Rationale: 

 

  1. The EOP-004 reporting should stay focused on larger events, such as the criteria under Generation loss (Total generation loss, within one minute, of greater than or equal to 2,000 MW for entities in the Eastern or Western interconnection).  Three transmission elements provide a very low threshold identified in the Transmission loss section.  These low impact events can be better handled through the NERC Event Analysis Program (EAP).  The EAP has matured over time and now provides an excellent means to identify and document lessons learned from events. 

  2. The Event Analysis Program (EAP) is providing a back door for changes to the EOP-004 reporting process without changes to the EOP-004 reporting process being vetted through the Standards Development Process. Case in point, an entity recently filed an EAP notification for a slow breaker trip impacting three or more elements and in which all related relaying operated by design. The Regional Entity directed that the entity report under the EOP-004 reporting process. The EOP-004 Event Type clearly states three elements “contrary to design”. With continual changes to the EAP and the dissimilarities in the two processes (EAP/EOP) these changes and differences are clearly leading to confusion for both the reporting entity and the Regional Entities.

  3. The EAP is a robust and documented process that provides for interaction between the Regional Entity and the reporting entity in the classification of Event types. All reporting for NERC/FERC classification of Events can be handled under the EAP process for this Event type, along with the current reporting under TADS and GADS. Lessons Learned are developed through this EAP process for the industry to learn from these events. The Transmission loss Event type under the EOP provides no further benefit and, in fact, as noted creates confusion on application for reporting.

  4. The definition of BES Element in this EOP-004 Event type (Transmission loss) includes generation. The reporting requirement for this Event Type is the TOP. The TOP does not have the visibility to report for the GO and/or the GOP for this Event type and also leads to confusion as to the element count for three elements contrary to design.  In addition, the Event Analysis Program (EAP) uses the definition of “BES Facility” in its application and not “BES Element” as used in the EOP Event type which leads to further confusion in evaluating reporting during an Event.

 

Second Recommendation:  Add “Alternate Interpersonal Communication” to the Event type  “Complete loss of Interpersonal Communication capability at a BES control center.

Rationale:  Prior to the implementation of COM-001-2, an Event under EOP-004-2 was the complete loss of voice communications.  With the restructuring of COM-001-2 to include the defined terms Interpersonal Communications and Alternate Interpersonal Communications, the Standard provides for actions to be taken for the loss of Interpersonal Communications.  We suggest that the “Complete” loss of voice communications is now the loss of Interpersonal Communications and Alternate Interpersonal Communications and which rises to the level of reporting for an EOP-004 event.

Don Schmit, Nebraska Public Power District, 5, 9/7/2016

- 1 - 0

It may be beneficial to provide general guidance (perhaps at the very top of the table), exactly which entity has the reporting responsibility. If an entity directs another entity to perform an action, the entity issuing the directive would have the reporting responsibility. In all other instances, the responsible party would be the entity who actually experienced the event. For example, such clarity might be beneficial in cases where the RC is the TOP.

 

Thomas Foltz, AEP, 5, 9/7/2016

- 0 - 0

Suggestion:  Delete or clarify the Transmission loss Event Type in Attachment 1.

Rationale:  Conflicting Event Analysis Program guidance, NERC Glossary definitions, and dispersed generation combine to make this Event Type confusing and challenging to evaluate within reporting timelines, subject to minimal impact, and requiring TOP’s to have greater visibility of generation resources than they possess.

Conflicting Guidance

Both EOP-004-4 Transmission loss Threshold for Reporting and EAP Category 1a apply to unexpected loss/outage of three or more BES Elements/Facilities contrary to design.

NERC Addendum for EAP Category 1a Events, footnote 2, page 2, explains “contrary to design”:  “If a single line fault results in the faulted line tripping along with two other lines misoperating and tripping, that is three elements outaged due to a common disturbance, contrary to design. That would be a qualified event.”  Likewise, page 3 states “Protection system misoperations are considered contrary to design.”  We can therefore conclude that protection system operations that operate as designed are not misoperations and not contrary to design.

This is so obvious that it shouldn’t need to be pointed out here, except that the EAP Addendum contradicts this understanding of protection system operations with respect to breaker failures.  In an attempt to collect circuit breaker failure data “through the EA process to facilitate identification of trends with regards to circuit breaker failures… facilities that are tripped due to breaker failure are counted as facilities outaged in determining categorization” regardless of whether that tripping is caused by the correct operation of protection systems.  Examples 5 and 6 explicitly state that lines outaged by correct operation of protection systems are to be counted “since it was a breaker failure.”

While a guidance document can circumvent the plain meaning of “contrary to design” for the voluntary data-gathering EAP, it cannot do so for the EOP-004-4 reliability standard.  This results in differing criteria for evaluating which lost/outaged BES Elements/Facilities count towards the three-element threshold.

Includes Minimum Impact Losses

The NERC Glossary definitions of Elements and Facilities specifically list generators as examples.  BES Elements and BES Facilities include BES generators.  With the revision of the BES definition, Inclusion I4 defines each and all individual dispersed power producing resources as individual BES facilities once they aggregate to greater than 75 MVA and are connected at a voltage of 100 kV or above.

By definition, every outage, contrary to design, of three or more BES wind turbines or solar cells caused by a common disturbance must be reported as a Transmission loss event under EOP-004, even though the loss is labeled as Transmission, contains no transmission elements, and does not meet the threshold for reporting a generation loss.

Blurs Event Types

Transmission loss and Generation loss are distinct Event Types with differing Reporting Thresholds appropriate to the Event Type and Responsible Entity.  Generation loss has BA reporting loss of MW.  Transmission loss has TOP reporting number of BES Elements, presumably transmission elements.  As written, BES Generators are not excluded as BES Elements for Transmission loss.  This blurs the line between Event Types, obligating the TOP to make determinations to file an Event Report each and every time 3 or more BES wind turbines or solar cells and/or a combination thereof with transmission elements that are lost contrary to design due to a common disturbance. The blurred event types and previously identified conflicting guidance is not conducive to a 24 hour reporting requirement.

TOP’s are unlikely to have this level of visibility into wind/solar farms, necessitating GOP’s to report the loss of these BES Elements to their TOP, so the TOP, as the Responsible Entity, can submit the report. The TOP should not have the responsibility of reporting event types for generator disturbances. 

Suggested Remedy

Delete the Transmission loss Event Type from Attachment 1.  Events can and should be analyzed under EAP. The EAP is the preferred method as there is collaboration between the reporting entity and the Regional Entity. The data is collected by the RE and NERC and can be analyzed appropriately and lessons learned developed.

Alternatively, clarify the Transmission loss Threshold for Reporting as follows:

“Unexpected loss within its area, contrary to design, of three or more BES Elements (transmission lines or transformers) caused by a common disturbance (excluding successful automatic reclosing, and as-designed protection system operations for the initiating disturbance).

By explicitly stating “BES transmission lines and transformers” we exclude generators as well as the Elements (circuit breakers, busses, and shunt and series devices) that the EAP Addendum says do not need to be included.  Adding “as-designed protection system operations” as an exclusion reinforces and reiterates the limitation of losses to those “contrary to design.” The qualifier “for the initiating disturbance” prevents a TOP from claiming that lines tripping on zone 3 relaying for a slow or stuck breaker is operating “as-designed.”

Page 12 of 16 , Row 6

Prior to the implementation of COM-001-2 an Event under EOP-004-2 was the complete loss of voice communications.  With the restructuring of COM-001-2 to include the defined terms Interpersonal Communications and Alternate Interpersonal Communications, the Standard provided for actions to be taken for the loss of Interpersonal Communications.  We suggest that the “Complete” loss of voice communications is now the loss of Interpersonal Communications and Alternate Interpersonal Communications and which rises to the level of reporting for an EOP-004 event.

Suggested Change:

Complete loss of Interpersonal Communication and Alternate Interpersonal Communication capability at a BES control center.

MRO-NERC Standards Review Forum (NSRF), Segment(s) 3, 4, 5, 6, 1, 2, 7/14/2016

Project 2015-08_ 3.docx

- 0 - 0

First Recommendation:  Delete the Transmission loss Event Type in Attachment 1.

Rationale: 

  1. The EOP-004 reporting should stay focused on larger events, such as the criteria under Generation loss (Total generation loss, within one minute, of greater than or equal to 2,000 MW for entities in the Eastern or Western interconnection).  Three transmission elements provide a very low threshold identified in the Transmission loss section.  These low impact events can be better handled through the NERC Event Analysis Program (EAP).  The EAP has matured over time and now provides an excellent means to identify and document lessons learned from events. 

  2. The Event Analysis Program (EAP) is providing a back door for changes to the EOP-004 reporting process without changes to the EOP-004 reporting process being vetted through the Standards Development Process. Case in point, an entity recently filed an EAP notification for a slow breaker trip impacting three or more elements and in which all related relaying operated by design. The Regional Entity directed that the entity report under the EOP-004 reporting process. The EOP-004 Event Type clearly states three elements “contrary to design”. With continual changes to the EAP and the dissimilarities in the two processes (EAP/EOP) these changes and differences are clearly leading to confusion for both the reporting entity and the Regional Entities.

  3. The EAP is a robust and documented process that provides for interaction between the Regional Entity and the reporting entity in the classification of Event types. All reporting for NERC/FERC classification of Events can be handled under the EAP process for this Event type, along with the current reporting under TADS and GADS. Lessons Learned are developed through this EAP process for the industry to learn from these events. The Transmission loss Event type under the EOP provides no further benefit and, in fact, as noted creates confusion on application for reporting.

  4. The definition of BES Element in this EOP-004 Event type (Transmission loss) includes generation. The reporting requirement for this Event Type is the TOP. The TOP does not have the visibility to report for the GO and/or the GOP for this Event type and also leads to confusion as to the element count for three elements contrary to design.  In addition, the Event Analysis Program (EAP) uses the definition of “BES Facility” in its application and not “BES Element” as used in the EOP Event type which leads to further confusion in evaluating reporting during an Event.

 

Second Recommendation:  Add “Alternate Interpersonal Communication” to the Event type  “Complete loss of Interpersonal Communication capability at a BES control center.

Rationale:  Prior to the implementation of COM-001-2, an Event under EOP-004-2 was the complete loss of voice communications.  With the restructuring of COM-001-2 to include the defined terms Interpersonal Communications and Alternate Interpersonal Communications, the Standard provides for actions to be taken for the loss of Interpersonal Communications.  We suggest that the “Complete” loss of voice communications is now the loss of Interpersonal Communications and Alternate Interpersonal Communications and which rises to the level of reporting for an EOP-004 event.

 

Suggested Change:

Complete loss of Interpersonal Communication and Alternate Interpersonal Communication capability at a BES control center.

Jamison Cawley, Nebraska Public Power District, 1, 9/7/2016

- 1 - 0

We request that the proposed revision to the category for ‘Complete Loss of Interpersonal Communication Capability at a BES control center’ be clarified to state that the threshold requires loss of both Interpersonal Communication and Alternative Interpersonal Communication capabilities.  We believe that is the intent of the threshold which is consistent with the EAP.  However, since both Interpersonal Communication and Alternative Interpersonal Communication are defined terms it is unclear from the posted Attachment 1 language whether this is the intention of the SDT.  Accordingly, we propose rewording the reporting threshold to:

Complete loss of both Interpersonal Communication and Alternative Interpersonal Communication capabilities at a BES control center.

In addition, the category for a ‘Complete loss of off-site power to a nuclear generating plant (grid supply)’ could be better aligned with the EAP.  The EAP refers to a ‘LOOP event’ which could be referenced here to provide consistency.  Alternatively, the EAP could be updated to better align with the proposed revision.  In addition, the current use of the phrase “complete loss of off-site power” in the Event Type as well as the Threshold for Reporting is problematic for the TO, TOP to be the Entity Responsible for Reporting.  Loss of off-site power (LOOP) is a well-defined term in the nuclear industry and is heavily dependent on in-plant alignments and operating conditions as well as transmission configuration which the TO/TOP has only has a partial awareness of.  Nuclear Plant Interface Requirements are intended to ensure that the NPGO has all of the information necessary to determine the operability of off-site power per the plant license agreement.  Should the existing wording of the Event Type and Threshold for Reporting be kept the Entity with Reporting Responsibility should be changed to the Nuclear Plant Generator Operator rather than the TO/TOP since the TO/TOP does not have the knowledge nor expertise to determine when a loss of off-site power condition exists.  Similar to NERC accepting the DOE OE-417 report there is a higher degree of efficiencies and effectiveness of reporting for the NPGO since loss of offsite power events are reportable to other regulators under plant licensing requirements.  Different Functional Entities independently reporting of the same event to different regulators creates a significant opportunity for confusing or even possibly conflicting information. 

- 0 - 0

We request that the proposed revision to the category for ‘Complete Loss of Interpersonal Communication Capability at a BES control center’ be clarified to state that the threshold requires loss of both Interpersonal Communication and Alternative Interpersonal Communication capabilities.  We believe that is the intent of the threshold which is consistent with the EAP.  However, since both Interpersonal Communication and Alternative Interpersonal Communication are defined terms it is unclear from the posted Attachment 1 language whether this is the intention of the SDT.  Accordingly, we propose rewording the reporting threshold to:

Complete loss of both Interpersonal Communication and Alternative Interpersonal Communication capabilities at a BES control center.

In addition, the category for a ‘Complete loss of off-site power to a nuclear generating plant (grid supply)’ could be better aligned with the EAP.  The EAP refers to a ‘LOOP event’ which could be referenced here to provide consistency.  Alternatively, the EAP could be updated to better align with the proposed revision.  In addition, the current use of the phrase “complete loss of off-site power” in the Event Type as well as the Threshold for Reporting is problematic for the TO, TOP to be the Entity Responsible for Reporting.  Loss of off-site power (LOOP) is a well-defined term in the nuclear industry and is heavily dependent on in-plant alignments and operating conditions as well as transmission configuration which the TO/TOP has only has a partial awareness of.  Nuclear Plant Interface Requirements are intended to ensure that the NPGO has all of the information necessary to determine the operability of off-site power per the plant license agreement.  Should the existing wording of the Event Type and Threshold for Reporting be kept the Entity with Reporting Responsibility should be changed to the Nuclear Plant Generator Operator rather than the TO/TOP since the TO/TOP does not have the knowledge nor expertise to determine when a loss of off-site power condition exists.  Similar to NERC accepting the DOE OE-417 report there is a higher degree of efficiencies and effectiveness of reporting for the NPGO since loss of offsite power events are reportable to other regulators under plant licensing requirements.  Different Functional Entities independently reporting of the same event to different regulators creates a significant opportunity for confusing or even possibly conflicting information. 

- 0 - 0

On Attachment 1 recommend rewording Event Type "Complete Loss of Interpersonal Communications capability at a BES Control Center" to be "Complete loss of Interpersonal Communication and Alternative Communication capability at a staffed BES Control Center".  The COM-001-2 Standard addresses loss of Interpersonal Communication capability. 

Santee Cooper , Segment(s) 1, 9/7/2016

- 0 - 0

Texas RE is concerned that the following proposed changes to EOP-004 Reportable Events could lead to gaps in reliability and confusion among registered entities. 

  • Texas RE is concerned that the proposed revisions eliminate the requirement that Reliability Coordinators (RC) submit event reports in connection with situations in which there are operations outside the IROL for a time greater than the IROL’s Tv (typically 30 minutes).  The management of IROLs is a key aspect of a RC’s constraint management activities.  In particular, situations in which an IROL is exceeded for a period sufficient to trigger an unacceptable risk to the interconnection or other Reliability Coordinator Areas represents a significant systemic event.  While such an exceedance may be investigated in the compliance or enforcement process, there is necessarily a delay in these activities.  The contemporaneous reporting obligations serve to ensure that the NERC regions have immediate knowledge that a significant risk of a cascading outage has occurred, permitting the region or regions to begin steps to identify the root cause and develop appropriate mitigation.  Because such awareness appears critical to the core reliability functions performed within the NERC regions, Texas RE cautions against eliminating this requirement.  At a minimum, Texas RE requests that the SDT provide a rationale for why the IROL Tv event reporting requirement should be removed, including whether the SDT believes that the event reporting aspects of EOP-004 are adequately addressed in other standards. 

  • Texas RE has noted that the SDT proposes to eliminate the event reporting obligations of certain NERC functions.  For example, the proposed revisions would no longer require DPs to report automatic firm load shedding resulting from a BES Emergency.  Similarly, the proposed revisions no longer require GOPs to report generation loss in excess of 1000 MW in the ERCOT region.  Texas RE requests that the SDT provide the rationale for narrowing these event reporting obligations.  If the SDT believes that such reporting obligations are duplicative, Texas RE would also request evidence supporting that assertion.

  • Based on its own engagement with registered entities in the ERCOT region, Texas RE also believes there is some confusion regarding event reporting terms.  In particular, the distinction between “Firm load shedding resulting from a BES Emergency” and “Uncontrolled loss of firm load resulting from a BES Emergency” appears unclear.  “Firm load shedding” could be read to refer solely to intended load shedding events (either manual or automatic).  If so, the SDT may wish to consider replacing the term “uncontrolled” with “unintended” to better capture the distinction between intentional and unintentional firm load shedding. 

  • It appears the “Public appeal” for load reduction ignores localized situations that may still require a localized public appeal that may be better facilitated by a TOP or DP (and actually recognized later in the loss of load issues).  Texas RE requests rationale for the change.

  • Texas RE noticed the event type “Voltage deviation on a Facility” did not include the GOP.   “Voltage deviation on a Facility” could occur at a GOP site as well and should be recognized since the GOP is to maintain that voltage.  Texas RE inquires as to why was the GOP is not included.

  • It appears the eliminated event type “BES Emergency resulting in automatic firm load shedding” is intended to be captured in the event type “Firm load shedding resulting from a BES Emergency”, however the same functions are not captured.  Texas RE requests clarification and rationale from the SDT regarding this change.  Texas RE is concerned the removal of reporting UVLS/UFLS/RAS load shedding reduces situational awareness for the RC and other functional entities. 

  • Texas RE requests rationale for the event type “Complete loss of Interpersonal Communication capability at a BES control center”.  Texas RE is concerned the term “BES control center” is undefined and might cause confusion.  Additionally, it ignores the DP and GOP responsibilities for having Interpersonal Communication. 

  • Texas RE inquires as to why a GOP Control Center is not considered in any of the event thresholds (and why is the undefined term “BES control center” limited to BA, RC, and TOP functions?)

  • For the event type “Firm load shedding resulting from a BES Emergency”, Texas RE inquires if the SDT intends for an event to be reported in a case where a RAS intentionally sheds load in response to a contingency for which the RAS was designed?

  • For the event type “Transmission loss”, Texas RE suggests adding the RC to the reporting responsibility.  This event type implies that the three or more elements that are lost are within a single TOP boundary.  We have numerous examples of events affecting multiple entities and elements outside of a single TOP boundary.

  • To maintain alignment between EOP-004 and the NERC Events Analysis Process, we suggest adding an event type for reporting the failure or misoperation of a RAS.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 9/7/2016

- 0 - 0

I wasn't given the option to skip the survey and support another's response after voting negatively for EOP-004-4. Please accept this response. PSE supports IESO, OGE and LG&E comments. 

We do not agree with the following changes:

 

  1. For the Event Type “Public appeal for load reduction”: It is unclear what “maintain the continuity of the BES” really means. By “continuity”, does it mean “integrity of the BES” or “continuity of supply”? This needs to be revised to be more specific and to improve clarity.

     

  2. Assigning the TOP to be the responsible entity for reporting system wide voltage reduction

     

    Voltage reduction is intended to reduce system demand to address capacity deficiency. While the TOP may be the entity to actually direct actions (e.g. transformer tap changes) to achieve voltage reduction, the BA is the entity that decides and gives the direction to implement the system wide voltage action/measure to achieve a reduction in system demand. We recommend changing it to the BA. Also, similar to the comment above, it is unclear what “maintain the continuity of the BES” really means. By “continuity”, does it mean “integrity” or “continuity of supply”? Either way, we do not see the value added or the necessity of the having this qualifier. We suggest to revise the Event Type to “System wide voltage reduction” or where a qualifier is deemed to add value, change it to “System wide voltage reduction to maintain load supply” or “to meet system demand”.

     

  3. The Event Type “Firm load shedding resulting from a BES Emergency”: the basis for the reporting threshold, i.e., 100 MW, etc. has not been provided. We would appreciate the SDT providing the technical basis/justification other than just because it existed before.

 

Leonard Kula, Independent Electricity System Operator, 2, 8/30/2016

 

LG&E and KU Energy (“LG&E/KU”) appreciates the opportunity to submit this comment for the Standard Drafting Team's consideration.

The reportable event type “Complete loss of Interpersonal Communication capability at a BES control center” has a threshold for reporting of “Complete loss of Interpersonal Communication capability affecting a staffed BES control center for 30 continuous minutes or more.” LG&E/KU proposes the event type be rewritten as “Complete loss of Interpersonal Communication (including Alternative Interpersonal Communication) capability at a BES control center”.  Furthermore, LG&E/KU proposes changing the threshold for reporting to read “Complete loss of Interpersonal Communication (including Alternative Interpersonal Communication) capability affecting a staffed BES control center for 30 continuous minutes or more.”

 

LG&E and KU Energy, Segment(s) 3, 5, 6, 5/26/2016

Lynda Kupfer, 9/7/2016

- 0 - 0

With regard to Attachment 1, a change has been made with respect to the Reporting Responsibility for damage or destruction and physical threats to a facility. Accountability has been moved to the Transmission Owner (i.e. Transmission Operator and Balancing Authority have been removed). If this is deemed to be an Owner versus Operator responsibility, why is the same not true for the GO/GOP functions?

Michelle Amarantos, APS - Arizona Public Service Co., 1, 9/7/2016

- 0 - 0

Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 3, 9/7/2016

- 0 - 0

Duke Energy provides comment on the following Event Types:

Public Appeal for load reduction: The proposed language for this event includes the phrase “to maintain continuity of the BES”. While we agree with the intent of the revisions, we disagree with the verbiage used. We do not believe that maintaining continuity of the BES is a concept that is widely understood by the industry, and suggest that using “to maintain reliability of the BES” would be more widely understood and accepted by the industry.

System-wide voltage reduction to maintain the continuity of the BES: Please see our comment above regarding the use of the phrase “to maintain continuity of the BES”. Also, we request further explanation from the drafting team on singling out the TOP as the entity with reporting responsibility. This concept may be particularly troublesome for vertically integrated entities. Entities that are integrated BA/TOP, either the BA or TOP can initiate voltage reduction. Lastly, the voltage reduction actually takes place on the distribution system, so we request further clarification of the singling out of the TOP only for this event, and request the drafting team consider adding the BA as an entity responsible for reporting for this event type.

Firm load shedding resulting from a BES Emergency: Some ambiguity may exist with having the multiple entities listed as being responsible for reporting per event. For example, a BES Emergency arises wherein an RC directs a BA/TOP to shed firm load. Following the language found in Attachment 1 of this standard, it is unclear whether the RC should file the event report, the BA/TOP would file the event report, or both. Is it the drafting team’s intent to have all or both functions submit an event report. If the intent is just for one report per event type to be filed, some language needs to be added affording entities the opportunity to discuss and decide which function will submit the event report. In the Guidelines and Technical Basis section of this standard, there is a section for Multiple Reports for a Single Organization. Perhaps a section could be added regarding reports involving multiple functions that stems from one event, and who is the responsible party for the reporting.

Uncontrolled loss of Firm load resulting from a BES Emergency: We requests further clarification from the drafting team on the addition of the term “Uncontrolled”, and whether or not using the term now negates the use of the DOE form for NERC reporting. This may result in an entity having to fill out two separate reports. Was this the drafting team’s intent? Also, is the term “Uncontrolled” referring to Operator controlled? Please clarify.

Transmission Loss: There appears to be a disconnect between the definition of BES Element in the NERC standards process, and the NERC Events Analysis process. We feel that a great deal of confusion exists on the reporting for this type of event. We request the drafting team to consider revising the associated language of this event type to help narrow down the intended scope of this event. As of now, the language is so broad that entities spend a considerable amount of time creating reports for this event type, and would greatly benefit by narrowing the scope or revising the language to better demonstrate intended expectations. 

Complete loss of Interpersonal Communication capability at a BES control center: Duke Energy questions the necessity of reporting for this event type. Currently, there is already a NERC standards regarding Interpersonal Communication and actions that must be taken if the capability is lost. Also, an entity is already required to have Alternative Interpersonal Communication as well. Does this reporting of this event type include an event where Alternative Interpersonal Communication capabilities are also lost? The standard already requires that an entity notify neighboring entities of the loss of communications, and now it appears that with this revision, an entity will need to file an event report to NERC regarding the loss, even if the loss has been mitigated. We feel that this reporting requirement is redundant with COM-001 where notifications around the loss of communications is already required. 

Complete loss of monitoring or control capability at a BES control center: Duke Energy requests clarification on the addition of the term “staffed” under Threshold for Reporting for the event type, Complete loss of Interpersonal Communication capability at a BES control center, but the term was not used in the Threshold for Reporting for this event type. The drafting team may have intended to include the term “staffed” to the language of this event but may have overlooked it. If the omission was intentional, please clarify why it was not included for this event type.

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

- 0 - 0

Johnny Anderson, 9/8/2016

- 0 - 0

Joe Tarantino, On Behalf of: Sacramento Municipal Utility District - WECC - Segments 1, 3, 4, 5, 6

- 0 - 0

Hydro One Networks is satisfied with attachment 1. For “Transmission Loss” event type please consider changing “Element” to “Facility” in the description of the Threshold for Reporting (as category 1.a. in the EAP).

- 0 - 0

Hydro One Networks is satisfied with attachment 1. For “Transmission Loss” event type please consider changing “Element” to “Facility” in the description of the Threshold for Reporting (as category 1.a. in the EAP).

- 0 - 0

There are numerous “its” references in the description of the Event Type, but not clear who this is in reference to?  Is it intended to imply that “its” is in referencing the Functional Entity that’s identified in the respective row of the second column – “Entity with Reporting Responsibility”?  Will these always match up?  Are there instances where the reporting entity and the owning entity are different?  For example, in ISO-NE the RC submits all the reports.  This may need some clarity.

 

GOP should be removed from the “Entity with Reporting Responsibility” for the “Physical Threats to its Facility” event type and added to the “Physical threats to its BES control center” event type.  Facility is defined as – “A set of electrical equipment that operates as a single Bulk Electric System Element (e.g., a line, a generator, a shunt compensator, transformer, etc.)” and thus does not capture a GOP control center.  So in order for these critical assets to be captured in the physical threats reporting requirements of the Attachment 1, GOP must be added to the “Physical threats to its BES control center” event type.

 

Same as comment 2 for “Physical threats to its Facility” event type.

 

For the “Public appeal for load reduction” event type, TOP should be added to the “Entity with Reporting Responsibility”.  EOP-001-2.1b, R4 – “R4. Each Transmission Operator and Balancing Authority shall include the applicable elements in Attachment 1-EOP-001 when developing an emergency plan.”

Attachment 1-EOP-001, Elements for Consideration in Development of Emergency Plans

5. Public appeals — Appeals to the public through all media for voluntary load reductions and energy conservation including educational messages on how to accomplish such load reduction and conservation.

“System-wide voltage reduction to maintain the continuity of the BES” event type

a.      BAs and RCs can potentially implement a system-wide VR due to capacity and energy emergencies in accordance with their emergency plans, as required under EOP-002-3.1 - Capacity and Energy Emergencies, so we don’t see why these functions are being excluded from the reporting requirement.       

b.      should be better aligned with the EAP event category 1d –

Recommend –

Threshold for reporting – no change

Event Type –System-wide voltage reduction in accordance with the entity’s emergency plan resulting from a BES Emergency.
 

c.      Threshold requirement of “system wide” should be clarified to specify whose system it is.  This is a similar ambiguity as the one being requested for clarity in item 1 above.  Are we implying that it’s the TOP’s (Entity withy Reporting Responsibility) system?  Are there instances when the requesting entity is a BA/RC requesting a voltage reduction for a particular TOP?  In such cases, would it be reportable and who would be the Entity with reporting responsibility.  Is the intent to require reporting of such events?  Should BAs and RCs be added to the Reporting Entities?

EOP-002-3_1 R6 -  

R6. If the Balancing Authority cannot comply with the Control Performance and Disturbance Control Standards, then it shall immediately implement remedies to do so. These remedies include, but are not limited to:

R6.1. Loading all available generating capacity.

R6.2. Deploying all available operating reserve.

R6.3. Interrupting interruptible load and exports.

R6.4. Requesting emergency assistance from other Balancing Authorities.

R6.5. Declaring an Energy Emergency through its Reliability Coordinator; and

R6.6. Reducing load, through procedures such as public appeals, voltage reductions, curtailing interruptible loads and firm loads.

 

For “Transmission Loss” event type please consider changing “Element” to “Facility” in the description of the Threshold for Reporting (as category 1.a. in the EAP).

 

For the transmission loss category:  The term “contrary to design” should be better defined.  In October 2015 an addendum for Category 1a Events was created for the Event Analysis Process.  This addendum indicates that breaker failure operations are not as intended.  Is the intent to mimic the EA Process?  Also, the term “excluding successful automatic reclosing” does not align with the EA Process language for Transmission loss.

 

NERC Definition of Element - Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit breaker, bus section, or transmission line. An Element may be comprised of one or more components.

NERC Definition of Facility - A set of electrical equipment that operates as a single Bulk Electric System Element (e.g., a line, a generator, a shunt compensator, transformer, etc.

The intent is to capture the outage of three or more Facilities (each Facility can be comprised of two or more Elements), not the underlying Elements. 

 

Loss of firm load (BA, TOP, DP) - Loss of firm load for ≥ 15 Minutes: ≥ 300 MW for entities with previous year’s demand ≥ 3,000 OR ≥ 200 MW for all other entities.

Recommend adding the following qualifiers:

·         This does not include the loss of load when it is caused by “customer actions to protect their systems” and not the utility (e.g. customer’s relays settings to swap over to own generation set higher than the utility’s UFLS/UVLS settings).

·         This excludes radially connected industrial load loss. Design and level of reliability was approved and accepted.

Suggest replacing the “uncontrolled” in the Event Type with the “unintended” language (similar to the EAP category).  “Uncontrolled” implies or may get interpreted as a cascading type of an event, limiting the reporting requirement to only those types of events.

Unplanned BES control center evacuation (RC, BA, TOP) - Unplanned evacuation from BES control center facility for 30 continuous minutes or more.

Add GOP to the Entity with Reporting Responsibility.  Similar reasons specified in the Attachment 1, Item 2 above.  Additionally, if the GOP BES control centers are subject to consideration and classification as High, Medium and Low impact facilities in accordance with the CIP-002 evaluation, they should be considered in this reporting criteria, at least for the GOP’s Control Centers that meet the reporting threshold for “Generation Loss” event type (≥ 2,000 MW for entities in the Eastern, or Western, or Quebec Interconnection OR ≥ 1,000 MW for entities in the ERCOT or Quebec Interconnection); or, as an alternative, High Impact (as classified under the CIP-002) control centers –  CIP-002-5.1 - Attachment 1 Impact Rating Criteria

The criteria defined in Attachment 1 do not constitute standā€alone compliance requirements, but are criteria characterizing the level of impact and are referenced by requirements.

1. High Impact Rating (H) Each BES Cyber System used by and located at any of the following: 1.4 Each Control Center or backup Control Center used to perform the functional obligations of the Generator Operator for one or more of the assets that meet criterion 2.1, 2.3, 2.6, or 2.9.

 

Complete loss of monitoring capability (RC, BA, TOP)- Complete loss of monitoring capability affecting a BES control center for 30 continuous minutes or {more such that analysis capability (i.e., State Estimator or Contingency Analysis) is rendered inoperable.}

 

Add the word “staffed” to the threshold column for “Complete loss of monitoring or control at a BES control center” so that it is consistent with the event Type above it which states: Complete loss of Interpersonal Communication capability affecting a “staffed” BES control center for 30 continuous minutes or more.

 

The BA should also be identified as an “Entity with Reporting Responsibility” for System-wide voltage reduction since according to the functional model the BA may request the TOP or directly address a DP to reduce voltage to ensure balance within its BA area.

Agree with the changes eliminating the bracketed statement as it is not indicative of a complete loss of monitoring capability and has caused confusion throughout the industry.

 

 

 

RSC no Dominion and NextEra, Segment(s) 1, 0, 2, 4, 5, 6, 7, 3, 9/8/2016

- 0 - 0

Comemnts as follows:

  1. At times there may be a need for a Transmission Operator (“TOp”) to implement a public appeal for load reduction in certain areas of their system if there is a system operating limit that can only be controlled by reduced load. Entergy recommends replacing “BA” with initiating Balancing Authority (“BA”) or TOp.

  2. The event types with multiple applicable entities such as, “Firm load shedding resulting from a BES Emergency”, “Uncontrolled loss of firm load resulting from a BES Emergency” and “System separation (islanding)” will most likely have the same event reported multiple times if the BA, TOp, or Reliability Coordinator (“RC”) are different entities. This has in the past been a source of confusion with the same event being reported multiple times. We recommend changing the Entity with Reporting Responsibility for the Event Type. “Firm load shedding resulting from a BES Emergency” to “Initiating RC, BA, or TOp”. We recommend changing the Entity with Reporting Responsibility for Event Type, “Uncontrolled loss of firm load resulting from a BES Emergency” to just BA. We recommend changing the Entity with Reporting Responsibility for the Even Type, “System separation (islanding)” to just the BA. This would eliminate multiple reports for the same event, while still making sure the events are reported.

  3. Under Event Type “Uncontrolled loss of firm load resulting from a BES Emergency” the MW lost amount may be better representative of an impact to a BA if it was a specific percentage of peak load. The current threshold goes from a 10% of total load value for a 3000 MW BA to less than 1% of total load for the bigger BAs.

  4. For Event Type Complete Loss of Interpersonal Communications capability at a BES control center, consider also adding Alternative Communication Capability. This will differentiate the event form a COM standard requirement. On event type include the word “staffed” to match working in the Threshold section. Entergy does not agree that the loss of primary/use of backup control center should be a reportable event. Please provide clarification of this point.  

Oliver Burke, Entergy - Entergy Services, Inc., 1, 9/8/2016

- 0 - 0

We do not agree with the elimination of “BES Emergency requiring” for a public appeal for load reduction.  During periods of very hot weather or other high load situations, even though there is not a BES emergency there are public appeals to exercise conservation to ensure sufficient resources on a regional or statewide basis.  Reporting to NERC of public appeals for load reduction or conservation should only be required for BES emergency conditions as written in the current version.

Jennifer Wright, Sempra - San Diego Gas and Electric, 5, 9/8/2016

- 0 - 0

ERCOT joins the comments of the ISO RTO Council (IRC) Standards Review Committee (SRC).  In addition, ERCOT provides the additional comment below.

 

a.      We ask the SDT to consider setting the reporting criteria for the “Generation loss” event type in ERCOT at 1,400 MW rather than 1,000 MW.  This would align the current reportable MW threshold for ERCOT with the NERC Event Analysis process threshold for a Category 3 event.[1]  As currently written, entities in the Eastern Interconnection are required to report in the event of a Category 3 event with a loss of generation of 2,000 MW or more, while ERCOT would be required to report in the event of a Category 1 event with a loss of generation of 1,000 MW.  Setting the reporting threshold at 1,400 MW for generation loss in ERCOT would establish equitable criteria for reporting in the ERCOT interconnection.

 

[1] http://www.nerc.com/pa/rrm/ea/EA%20Program%20Document%20Library/ERO_EAP_V3_final.pdf

Elizabeth Axson, 9/8/2016

- 0 - 0

We do not agree with the following changes:

a.      For the Event Type “Public appeal for load reduction”: It is unclear what “maintain the continuity of the BES” means. Does “continuity” mean “integrity of the BES” or something else? This needs to be revised to be more specific and to improve clarity.

b.      The phrase “Public appeal for load reduction to maintain continuity of the BES” could also unreasonably expand the number of required reporting instances.  Public appeals are made in many different types of situations.  Reliability Coordinators often make appeals when an emergency is only a possibility and not a likelihood.  In many of these cases, the risk of an emergency condition is somewhat lower and should not rise to the level of concern to justify official event reporting.  SRC therefore recommends that the SDT retain the defined term “BES Emergency” and use the phrase “Public appeal for load reduction in a BES Emergency to maintain integrity of the BES.” 

c.       The SRC also disagrees with assigning the TOP the responsibility for reporting system wide voltage reduction. Voltage reduction is intended to reduce system demand to address capacity deficiency. While the TOP may be the entity to actually direct actions (e.g. transformer tap changes) to achieve voltage reduction, the BA is the entity that decides and gives the direction to implement the system wide voltage action/measure to achieve a reduction in system demand. We recommend making the BA the responsible entity. Further, we don’t agree with making every public appeal for demand reduction a reportable event.  The redline removes the words “BES Emergency requiring…” and we believe that the words should remain so that only voltage reduction associated with BES Emergencies are reportable. ” Also, similar to the comment above, it is unclear what “maintain the continuity of the BES” means. We suggest to revise the Event Type to “Voltage reduction” or where a qualifier is deemed to add value, change it to “Voltage reduction to meet system demand”.

d.      For consistency with comment (b) above "Public Appeal" should remain under the "BES Emergency" heading.

e.      Having proposed the above, the SRC suggests that Public Appeal be removed from the list of Events to be reported since public appeal by its nature require the involvement of media.  This is often done in advance of real time because of the required effort and coordination with media.  Therefore, public appeal is more a cautionary action driven by anticipated conditions, and not actual conditions in real time. Given the nature of the appeal and the involvement of the media, there is sufficient information provided to NERC and the concerned government agencies, making a separate report is thus redundant.

f.        The Event Type “Firm load shedding resulting from a BES Emergency”: the basis for the reporting threshold, i.e., 100 MW, etc. has not been provided. We would appreciate the SDT providing the technical basis for this threshold.

g.      In Attachment 1, the event "Unplanned BES control center evacuation” applies to RC, BA, and TOP.  If the evacuated control center belongs to a TOP, the TOP should have the obligation to report this, and not the RC or BA, which could be one reading of this.  Consistent with the SDT’s use of the word “its” for the second, third, and fourth events listed in Attachment 1 to signify that only the entity experiencing the event has the reporting responsibility, SRC recommends changing the event type description in this case to “Unplanned evacuation of its BES control center.”  Similarly, SRC recommends changing the next two event type descriptions to address this same issue, so that they read “Complete loss of Interpersonal Communication capability at its BES control center” and “Complete loss of monitoring or control capability at its BES control center.”

ISO/RTO Council Standards Review Committee, Segment(s) 2, 8/12/2016

- 0 - 0

Hydro One Networks Inc. is satisfied with Attachment 1.  However, for “Transmission Loss” event type, please consider changing “Element” to “Facility” in the description of the Threshold for Reporting (as per Category 1.a. in the EAP).

Oshani Pathirane, 9/8/2016

- 0 - 0

Regarding Attachment 1: Reportable Events, BPA recommends clarifying the public appeal for load reduction applicable to the BA by specifying "load reduction" with "BA load reduction".

Justin Mosiman, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

- 0 - 0

NV Energy supports the comments made by MRO-NERC Standards Review Forum:

 

Suggestion:  Delete or clarify the Transmission loss Event Type in Attachment 1.

Rationale:  Conflicting Event Analysis Program guidance, NERC Glossary definitions, and dispersed generation combine to make this Event Type confusing and challenging to evaluate within reporting timelines, subject to minimal impact, and requiring TOP’s to have greater visibility of generation resources than they possess.

Conflicting Guidance

Both EOP-004-4 Transmission loss Threshold for Reporting and EAP Category 1a apply to unexpected loss/outage of three or more BES Elements/Facilities contrary to design.

NERC Addendum for EAP Category 1a Events, footnote 2, page 2, explains “contrary to design”:  “If a single line fault results in the faulted line tripping along with two other lines misoperating and tripping, that is three elements outaged due to a common disturbance, contrary to design. That would be a qualified event.”  Likewise, page 3 states “Protection system misoperations are considered contrary to design.”  We can therefore conclude that protection system operations that operate as designed are not misoperations and not contrary to design.

This is so obvious that it shouldn’t need to be pointed out here, except that the EAP Addendum contradicts this understanding of protection system operations with respect to breaker failures.  In an attempt to collect circuit breaker failure data “through the EA process to facilitate identification of trends with regards to circuit breaker failures… facilities that are tripped due to breaker failure are counted as facilities outaged in determining categorization” regardless of whether that tripping is caused by the correct operation of protection systems.  Examples 5 and 6 explicitly state that lines outaged by correct operation of protection systems are to be counted “since it was a breaker failure.”

While a guidance document can circumvent the plain meaning of “contrary to design” for the voluntary data-gathering EAP, it cannot do so for the EOP-004-4 reliability standard.  This results in differing criteria for evaluating which lost/outaged BES Elements/Facilities count towards the three-element threshold.

Includes Minimum Impact Losses

The NERC Glossary definitions of Elements and Facilities specifically list generators as examples.  BES Elements and BES Facilities include BES generators.  With the revision of the BES definition, Inclusion I4 defines each and all individual dispersed power producing resources as individual BES facilities once they aggregate to greater than 75 MVA and are connected at a voltage of 100 kV or above.

By definition, every outage, contrary to design, of three or more BES wind turbines or solar cells caused by a common disturbance must be reported as a Transmission loss event under EOP-004, even though the loss is labeled as Transmission, contains no transmission elements, and does not meet the threshold for reporting a generation loss.

Blurs Event Types

Transmission loss and Generation loss are distinct Event Types with differing Reporting Thresholds appropriate to the Event Type and Responsible Entity.  Generation loss has BA reporting loss of MW.  Transmission loss has TOP reporting number of BES Elements, presumably transmission elements.  As written, BES Generators are not excluded as BES Elements for Transmission loss.  This blurs the line between Event Types, obligating the TOP to make determinations to file an Event Report each and every time 3 or more BES wind turbines or solar cells and/or a combination thereof with transmission elements that are lost contrary to design due to a common disturbance. The blurred event types and previously identified conflicting guidance is not conducive to a 24 hour reporting requirement.

TOP’s are unlikely to have this level of visibility into wind/solar farms, necessitating GOP’s to report the loss of these BES Elements to their TOP, so the TOP, as the Responsible Entity, can submit the report. The TOP should not have the responsibility of reporting event types for generator disturbances. 

Suggested Remedy

Delete the Transmission loss Event Type from Attachment 1.  Events can and should be analyzed under EAP. The EAP is the preferred method as there is collaboration between the reporting entity and the Regional Entity. The data is collected by the RE and NERC and can be analyzed appropriately and lessons learned developed.

Alternatively, clarify the Transmission loss Threshold for Reporting as follows:

“Unexpected loss within its area, contrary to design, of three or more BES Elements (transmission lines or transformers) caused by a common disturbance (excluding successful automatic reclosing, and as-designed protection system operations for the initiating disturbance).

By explicitly stating “BES transmission lines and transformers” we exclude generators as well as the Elements (circuit breakers, busses, and shunt and series devices) that the EAP Addendum says do not need to be included.  Adding “as-designed protection system operations” as an exclusion reinforces and reiterates the limitation of losses to those “contrary to design.” The qualifier “for the initiating disturbance” prevents a TOP from claiming that lines tripping on zone 3 relaying for a slow or stuck breaker is operating “as-designed.”

Page 12 of 16 , Row 6

Prior to the implementation of COM-001-2 an Event under EOP-004-2 was the complete loss of voice communications.  With the restructuring of COM-001-2 to include the defined terms Interpersonal Communications and Alternate Interpersonal Communications, the Standard provided for actions to be taken for the loss of Interpersonal Communications.  We suggest that the “Complete” loss of voice communications is now the loss of Interpersonal Communications and Alternate Interpersonal Communications and which rises to the level of reporting for an EOP-004 event.

Suggested Change:

Complete loss of Interpersonal Communication and Alternate Interpersonal Communication capability at a BES control center.

- 0 - 0

  1. With regard to Attachment 1, the majority of our comments agree with the proposed changes.  However, there are a few event categories that need to be clarified.
  2. We disagree with the deviation from NERC Glossary Terms for the complete loss of monitoring or control capability at a BES control center.  We recommend that the SDT choose the NERC-defined term “Control Center” instead of the current proposal as lower-case “control center.”  The NERC glossary definition would meet the criteria because this event category applies to the RC, BA, and TOP.
  3. We question the removal of the RC reporting IROL violations or SOL violations on WECC Major Transfer Paths.  This is a risk to reliability and NERC should be notified with an event report.
  4. We also question the assignment of the RC, BA, and TOP to have reporting responsibility for Firm load shedding (> 100 MW) resulting from a BES Emergency.  We are not sure if this assignment of three functions provides clarity.  Are there any additional benefits to reliability for having all three entities be required to report a single load shedding event?  We would like the SDT to clarify if there is an option for applicable registered entities to receive credit for reporting if one of the entities involved in a load shedding event reports on their behalf.  The ability to file a report for multiple entities that are party to a single load shedding event would alleviate the burden of having to submit multiple reports for a single event.
  5. We question the assignment of the BA as being solely responsible for reporting public appeals for load reduction, because some BA Areas (such as MISO or SPP) are too large for the BA to initiate such appeals.  We ask the SDT to consider assigning the task to the TOP.
  6. We agree with the current proposal to remove the DP from being required to report any automatic firm load shedding (> 100 MW), as this is covered by the BA, RC, and TOP.
  7. Finally, we agree with the SDT that assigning the TOP as solely responsible for reporting system-wide voltage reduction (of 3% or more) to maintain the continuity of the BES provides more clarity regarding the reporting responsibilities.

ACES Standards Collaborators - EOP Project, Segment(s) 1, 5, 3, 6, 4, 9/8/2016

- 0 - 0

Reclamation agrees with the drafting team’s proposal to eliminate duplicative reporting requirements.  However, Reclamation suggests that reporting should only be required for “complete loss of all interpersonal communication capabilities” at staffed control centers.  Reclamation requests that the drafting team update this line item because as written, the update could require reporting of the loss of any communication system even when a fully functioning backup system is utilized.  

Erika Doot, 9/8/2016

- 0 - 0

Both EOP-004-4 Transmission loss Threshold for Reporting and EAP Category 1a apply to unexpected loss/outage of three or more BES Elements/Facilities contrary to design; however with differing definitions. EAP defines “BES Facility” and EOP-004 defines “BES Element”.

EOP-004 reporting threshold for loss of three elements uses “BES Elements”. The BES definition includes generators, the EOP reporting for the unexpected loss is for the TOP. This is confusing on how to count elements and how the TOP is to get notification of loss of generator elements to report. Actually the TOP should not be required to do so. Transmission loss and Generation loss are distinct Event Types with differing Reporting Thresholds appropriate to the Event Type and Responsible Entity.  Transmission loss has TOP reporting number of BES Elements, presumably transmission elements.  As written, BES Generators are not excluded as BES Elements for Transmission loss. 

In addition, we are finding that the application of the EAP definition/process is being applied to EOP-004 reporting. While an EAP guidance document can circumvent the plain meaning of “contrary to design” for the voluntary data-gathering EAP, it cannot do so for the EOP-004-4 reliability standard.  This results in differing criteria for evaluating which lost/outage BES Elements/Facilities count towards the three-element threshold and an application that ignores the Standards approval process in the NERC Rules of Procedure.

The EAP process has examples for application, provides for collaboration between the entity and the regional entity provides for categorization for the NERC/FERC process and eventual lessons learned.  As noted, the EOP-004 reporting item is confusing (and not correct) by definition and by application. The EOP line item for Transmission Loss needs to be eliminated in favor of the better defined and applied EAP process.

We also request that the category for ‘Loss of Interpersonal Communication Capability’ be clarified to state that the threshold requires loss of both Primary and Alternative Interpersonal Communication Capability.  We believe that is the intent of the threshold, but with the language now in COM-001-2 using ‘primary and Alternative Interpersonal Communication’, we believe the addition would make it as clear as possible.  As currently stated, it requires an interpretation as to whether it means complete loss of ‘just’ Primary or both.  Such as:

Complete loss of both primary and Alternative Interpersonal Communication capability affecting a staffed BES control center for 30 continuous minutes or more.

The category for loss of offsite power to a nuclear generator could be better aligned with the EAP.  The EAP refers to a ‘LOOP event’ which could be referenced here to provide consistency.  We also recommend that the Nuclear Plant Generator Operator be the responsible entity for reporting instead of the TO or TOP. 

SPP Standards Review Group, Segment(s) 0, 9/8/2016

- 0 - 0

Dave Thomas, 9/8/2016

- 0 - 0

Kansas City Power and Light Company endorses and incorporates by reference Nebraska Public Power District’s response in opposition to Question 3.

In addition, we offer the following:

BES Emergency: There is inconsistent use of the NERC Glossary Term, “BES Emergency.” We can only speculate as to the SDT’s intent. For example, removing the term is basically removing the qualifier and expanding the applicability of the event. The opposite would be true, limiting the applicability, by including the term. We would be interested in understanding the SDT’s intent for determining inclusion or exclusion of the term, BES Emergency.

Capitalization:  As noted in our Question No. 1 comments, the words “control center” are used in Attachments. Since the term, “Control Center,” is an approved NERC Glossary Term, we suggest it be capitalized. If the intent of the SDT was not to use the Glossary Term, Control Center, additional definition and parameters are needed to provide clarity to the meaning of “control center.”

- 0 - 0

Hot Answers

Any changes to Event Type from comments above carry down to attachment 2 as well.

Jaclyn Massey, 9/8/2016

- 0 - 0

AECI requests the SDT to revise the term BES control center.  Control Center is already defined in the NERC Glossary of Terms and should be used in lieu of BES control center throughout the attachment.

Mark Riley, 9/8/2016

- 0 - 0

Other Answers

Mike Anctil, 7/27/2016

- 0 - 0

Mary Cooper, On Behalf of: Alameda Municipal Power - WECC - Segments 3, 4

- 0 - 0

Marcus Freeman, On Behalf of: ElectriCities of North Carolina, Inc., SERC, Segments 4

- 0 - 0

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

- 0 - 0

Sing Tay, On Behalf of: OGE Energy - Oklahoma Gas and Electric Co., SPP RE, Segments NA - Not Applicable

- 0 - 0

No suggested changes to the text that has been modified.  In addition, suspious activity must be listed.  Currently, suspicious activity would fall under physical threat to a facility.  Taking pictures or flying a drone over a facility could fall under suspicious activity but not always under a physical threat.  Suggest adding a suspicious activity line with a check box. 

Jeffrey DePriest, DTE Energy - Detroit Edison Company, 5, 8/23/2016

- 1 - 0

Nick Vtyurin, On Behalf of: Manitoba Hydro - MRO - Segments 1, 3, 5, 6

- 0 - 0

RoLynda Shumpert, On Behalf of: SCANA - South Carolina Electric and Gas Co., SERC, Segments 1, 3, 5, 6

- 0 - 0

Jamie Monette, Allete - Minnesota Power, Inc., 1, 8/26/2016

- 0 - 0

“PSEG is pleased to have the opportunity to comment and is in general agreement with the revisions to the standard.  The EOP-004 form (Attachment 2) states “Also submit to other organizations per Requirement R1 “… (e.g., the Regional Entity, company personnel, the Responsible Entity’s Reliability Coordinator, law enforcement, or Applicable Governmental Authority).” We recommend replacing the term “submit” with “report”, or determine if reporting via a different form would meet compliance.  Law enforcement, in particular the Regional Operations centers (ROIC) in New Jersey and Connecticut, have a different form (Suspicious Activity Reporting or SAR form) that is used to report events.  Therefore, replacing the term “submit” with “report” would aid in harmonizing reporting EOP-004 reporting requirements with processes for reporting events to law enforcement.”

PSEG, Segment(s) 5, 6, 1, 3, 3/10/2016

- 0 - 0

Leonard Kula, Independent Electricity System Operator, 2, 8/30/2016

- 0 - 0

Jamie Monette, Allete - Minnesota Power, Inc., 1, 8/30/2016

- 0 - 0

Amy Casuscelli, On Behalf of: Xcel Energy, Inc. - MRO, WECC, SPP RE - Segments 1, 3, 5, 6

- 0 - 0

LG&E and KU Energy, Segment(s) 3, 5, 6, 5/26/2016

- 0 - 0

Refer to comments for #3 above.

Attachment 2, Page 15, 4th bullet, “Unplanned BES control center evacuation” is duplicated on    Page 16, 5th bullet.

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

- 0 - 0

CenterPoint Energy recommends that the “Tasks” in Attachment 2 Event Reporting Form align with the Event Types in Attachment 1 if revised by the SDT.

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

- 0 - 0

Tennessee Valley Authority, Segment(s) 1, 3, 5, 6, 10/5/2015

- 0 - 0

Under section 4, there are two instances of ‘Unplanned BES control center evacuation.’ Remove the first instance so that the order of the list in Attachment 2 matches the Attachment 1.

Quintin Lee, Eversource Energy, 1, 9/6/2016

- 0 - 0

Richard Vine, California ISO, 2, 9/6/2016

- 0 - 0

In the introductory section of the form, the SDT could consider adding the qualifier ‘applicable’ to organizations to clarify that the reporting requirement is not to all the enumerated organizations: “Also submit to other applicable organizations per Requirement R1 “… (e.g., the Regional Entity, company personnel, the Responsible Entity’s Reliability Coordinator, law enforcement, or Applicable Governmental Authority).”

Sean Bodkin, Dominion - Dominion Resources, Inc., 6, 9/6/2016

- 0 - 0

- 0 - 0

Diana McMahon, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

- 0 - 0

Don Schmit, Nebraska Public Power District, 5, 9/7/2016

- 0 - 0

Thomas Foltz, AEP, 5, 9/7/2016

- 0 - 0

Add “, select Option 1” to the voice number as per the note in Attachment 1.

MRO-NERC Standards Review Forum (NSRF), Segment(s) 3, 4, 5, 6, 1, 2, 7/14/2016

- 0 - 0

Jamison Cawley, Nebraska Public Power District, 1, 9/7/2016

- 0 - 0

- 0 - 0

- 0 - 0

Santee Cooper , Segment(s) 1, 9/7/2016

- 0 - 0

Texas RE recommends aligning the event types in Attachment 1 with the tasks in Attachment 2.  For example, Texas RE noticed the event types “System-wide voltage reduction to maintain the continuity of the BES” and “Firm load shedding resulting from a BES Emergency” are included in Attachment 1, but not listed in Attachment 2.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 9/7/2016

- 0 - 0

Lynda Kupfer, 9/7/2016

- 0 - 0

“Unplanned BES control center evacuation” is listed twice on Attachment 2; i.e. as part of the original form (p. 16) and as a new addition (p. 15). Recommend the bullet on p. 16 be retained (as it mirrors the order found in Attachment 1) and the duplicative bullet on p. 15 deleted.

Michelle Amarantos, APS - Arizona Public Service Co., 1, 9/7/2016

- 0 - 0

Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 3, 9/7/2016

- 0 - 0

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

- 0 - 0

Johnny Anderson, 9/8/2016

- 0 - 0

Joe Tarantino, On Behalf of: Sacramento Municipal Utility District - WECC - Segments 1, 3, 4, 5, 6

- 0 - 0

Hydro One Networks is satisfied with attachment 2. The check box item “Unplanned BES control center evacuation” is duplicated

- 0 - 0

Hydro One Networks is satisfied with attachment 2. The check box item “Unplanned BES control center evacuation” is duplicated

- 0 - 0

In the header of the Attachment 2, add “select Option 1” after the voice number provided for the submittal of the form. Similar as in the Attachment 1.

 

Under section 4, there are two instances of “Unplanned BES control center evacuation.” Remove the first instance so that the order of the list in Attachment 2 matches the Attachment 1.

 

Attachment 2 is not required for use and it should be stated in Attachment 2 that it is a guidance document, not tied to compliance. The change to attachment 2 implies that it is a compliance obligation to supply a completed Attachment 2 to all entities listed in the Event Reporting Operating Plan. This is not the case as written in R2 and a correction to either Attachment 2 or the requirement language should be made.

RSC no Dominion and NextEra, Segment(s) 1, 0, 2, 4, 5, 6, 7, 3, 9/8/2016

- 0 - 0

Comment:  Any changes to Event Type from comments above should carry down to Attachment 2 as well.

Oliver Burke, Entergy - Entergy Services, Inc., 1, 9/8/2016

- 0 - 0

For consistency with our comment on Attachment 1, “Public Appeal” and “System-wide voltage reduction” should remain under the “BES Emergency” heading.

Jennifer Wright, Sempra - San Diego Gas and Electric, 5, 9/8/2016

- 0 - 0

Elizabeth Axson, 9/8/2016

- 0 - 0

ISO/RTO Council Standards Review Committee, Segment(s) 2, 8/12/2016

- 0 - 0

Hydro One Networks Inc. is satisfied with Attachment 2. Please also note that the check box item, “Unplanned BES control center evacuation”, is duplicated.

Oshani Pathirane, 9/8/2016

- 0 - 0

Justin Mosiman, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

- 0 - 0

- 0 - 0

  1. We question if there are any compliance impacts if an entity reports within the required timelines, but uses the previous version of the event reporting form.  There are several modifications to Attachment 1.  We would like the SDT to clarify whether reporting an event on the previous version of the form would be a violation.  This seems to be a potential administrative burden, both for the entities submitting the information, and the Regional Entities and NERC that receive the event reports. 
  2. We recommend implementing a reporting software tool on the NERC website, which has the capabilities to notify applicable Regional Entities and the DOE of an event.  This would alleviate the need to include Attachment 2 as part of the standard and would further streamline the process with a centralized portal for all entities to submit event reports.  We ask the NERC standards developer assigned to this project to share this comment with NERC IT department to see if this type of solution is viable.

ACES Standards Collaborators - EOP Project, Segment(s) 1, 5, 3, 6, 4, 9/8/2016

- 0 - 0

Reclamation suggests that reporting should only be required for “complete loss of all interpersonal communication capabilities” at staffed control centers.  Reclamation requests that the drafting team update this line item because as written, the update could require reporting of the loss of any communication system even when a fully functioning backup system is utilized.  

Erika Doot, 9/8/2016

- 0 - 0

SPP Standards Review Group, Segment(s) 0, 9/8/2016

- 0 - 0

Dave Thomas, 9/8/2016

- 0 - 0

Capitalization:  As previously noted in our comments, the words “control center” are used in multiple places. Since the term “Control Center” is an approved NERC Glossary Term, we suggest it should be capitalized. If the intent of the SDT was not to use the Glossary Term, Control Center, additional definition and parameters are needed to provide clarity to the meaning of control center.

- 0 - 0

Hot Answers

Entergy recommends going to a 72 hour reporting deadline to match the final report deadline for the Department of Energy’s form OE-417.

Jaclyn Massey, 9/8/2016

- 0 - 0

Although the implementation plan is not specifically referenced in the survey, AECI requests the SDT to revise the proposed effective date of EOP-004-4.  The revisions to EOP-004-4 require procedural and reporting changes for Responsible Entities.  These modifications should not take a full 12 months to implement and the industry would benefit immediately from the enhanced reporting process.  AECI requests the SDT to revise the implementation plan and establish an effective date that is the first calendar quarter that is three (3) months after the date of applicable governmental authority’s order approving the standard.

Mark Riley, 9/8/2016

- 0 - 0

Other Answers

  1. Event Type 2 and 3 on page 10 (“Physical threats to its Facility” and “Physical threats to its BES control center”) is too broad and will require entities to file a report for any suspicious activity or device within 24 hours. In the Threshold for Reporting column of these Event Types, it would be better to eliminate “OR Suspicious device or activity at a its Facility. Do not report theft unless it degrades normal operation of a Facility.” This elimination would give entities some latitude on determining when a suspicious activity was worthy of a report.

Mike Anctil, 7/27/2016

- 0 - 0

Mary Cooper, On Behalf of: Alameda Municipal Power - WECC - Segments 3, 4

- 0 - 0

Marcus Freeman, On Behalf of: ElectriCities of North Carolina, Inc., SERC, Segments 4

- 0 - 0

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

- 0 - 0

OGE is concerned that the SDT has not looked at some of the CIP standards and how it is tied to the requirements in EOP-004. Currently, there appears to be redundant reporting requirements between CIP-008 and EOP-004. For example, CIP-006 Standard, Part 1.5 states that the Physical Security Plan must describe issuance of an alarm or alert in response to the unauthorized access into or through a Physical Security Access Point, and the alarm or alert must be communicated as identified in the Entity’s CIP-008 BES Cyber Security Incident Response Plan.  The Response Plan includes reporting of the event to the appropriate agencies (including NERC and DOE). This ties in to the Physical Threats event type in Attachment 1 of EOP-004-4. We believe there is some overlap or at least touchpoints between the two standards, although the CIP standards are focused on protection of the cyber assets, it still includes physical access to these cyber assets. We are requesting the SDT to review the latest versions of the CIP standards (specifically CIP-006 and CIP-008) to ensure there is no overlapping or redundant reporting requirements.

Sing Tay, On Behalf of: OGE Energy - Oklahoma Gas and Electric Co., SPP RE, Segments NA - Not Applicable

- 1 - 0

There should be further revisions to Attachment 1. Specifically, “suspicious device or activity” is ambiguous. Further clarification on “suspicious activity” is needed. For example, does this include photography near a Facility? Also, Attachment 1 should specifically cover cyber related suspicious activity – for example, solicitation attempts or phishing calls at Facilities. There should also be instruction on what an Entity should do if they later realize the incident was NOT suspicious – for example, a prior reported incident which, after further investigation, turns out to be innocuous. The effect of using ambiguous terms and no mechanism for correcting incidents post investigation has left the industry with an output that contains more “trash” than value – many incidents that do not truly meet the definition of EOP 004 are sent out via EISAC which leads to the dilution of truly important incidents.

Jeffrey DePriest, DTE Energy - Detroit Edison Company, 5, 8/23/2016

- 0 - 0

Nick Vtyurin, On Behalf of: Manitoba Hydro - MRO - Segments 1, 3, 5, 6

- 0 - 0

RoLynda Shumpert, On Behalf of: SCANA - South Carolina Electric and Gas Co., SERC, Segments 1, 3, 5, 6

- 0 - 0

Jamie Monette, Allete - Minnesota Power, Inc., 1, 8/26/2016

- 0 - 0

PSEG, Segment(s) 5, 6, 1, 3, 3/10/2016

- 0 - 0

Leonard Kula, Independent Electricity System Operator, 2, 8/30/2016

- 0 - 0

Jamie Monette, Allete - Minnesota Power, Inc., 1, 8/30/2016

- 0 - 0

Amy Casuscelli, On Behalf of: Xcel Energy, Inc. - MRO, WECC, SPP RE - Segments 1, 3, 5, 6

- 0 - 0

LG&E and KU Energy, Segment(s) 3, 5, 6, 5/26/2016

- 0 - 0

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

- 0 - 0

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

- 0 - 0

None

Tennessee Valley Authority, Segment(s) 1, 3, 5, 6, 10/5/2015

- 0 - 0

Change ‘control center’ to ‘Control Center’ throughout the document to be consistent with the NERC Glossary

Quintin Lee, Eversource Energy, 1, 9/6/2016

- 0 - 0

For all questions the California ISO supports the comments of the ISO/RTO Council Standards Review Committee

Richard Vine, California ISO, 2, 9/6/2016

- 0 - 0

Sean Bodkin, Dominion - Dominion Resources, Inc., 6, 9/6/2016

- 0 - 0

- 0 - 0

Diana McMahon, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

- 0 - 0

Don Schmit, Nebraska Public Power District, 5, 9/7/2016

- 0 - 0

Thomas Foltz, AEP, 5, 9/7/2016

- 0 - 0

N/A

MRO-NERC Standards Review Forum (NSRF), Segment(s) 3, 4, 5, 6, 1, 2, 7/14/2016

- 0 - 0

Jamison Cawley, Nebraska Public Power District, 1, 9/7/2016

- 0 - 0

- 0 - 0

- 0 - 0

Santee Cooper , Segment(s) 1, 9/7/2016

- 0 - 0

Texas RE requests the SDT provide rationale for each change made to the Standard.  Texas RE would like to better understand the SDT’s reasoning in the changings and how they affect reliability.

 

Additionally, Texas RE requests rationale for the implementation plan.  The Implementation Plan for the proposed EOP-004 provides that “the standard shall become effective on the first day of the first calendar quarter that is twelve (12) months after the effective date of the applicable governmental authority’s order approving the standard, or as otherwise provided for by the applicable governmental authority.”  Given that registered entities presently are required to submit event reports under the current version of EOP-004 and the revised version largely narrows the scope of such reporting activities, it is unclear why a 12-month implementation period is necessary. 

Rachel Coyne, Texas Reliability Entity, Inc., 10, 9/7/2016

- 0 - 0

Lynda Kupfer, 9/7/2016

- 0 - 0

Michelle Amarantos, APS - Arizona Public Service Co., 1, 9/7/2016

- 0 - 0

Please continue the effort to harmonize NERC Event Reporting requirements with DOE reporting requirements as listed on the OE-417. Currently; it is needlessly burdensome to ensure we meet reporting requirements for both NERC and DOE within specified timeframes. This is particularly difficult considering DOE’s 1 or 6 hour submittal requirements and the circumstances a System Operator is likely to be faced with while attempting to submit these reports.

 

Ideally, DOE would defer to NERC for Event Reporting as required by EOP-004; thus alleviating the potential for separate submissions, on separate forms, with different time requirements for submittal.

Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 3, 9/7/2016

- 0 - 0

Duke Energy recommends that the drafting team revisit the language used in the VSL(s) for R2. The revisions posted for R2 include the addition of the phrase “specified in EOP-004-4 Attachment 1 to the entities specified”. The use of “the entities specified”, does not match up with the language used in the VSL(s) for R2 which use the verbiage “to all required recipients” when describing who an event report should be submitted to. We suggest the drafting team consider using identical language in the Requirements and complementing VSL(s).

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

- 0 - 0

No additional comments.

Johnny Anderson, 9/8/2016

- 0 - 0

Joe Tarantino, On Behalf of: Sacramento Municipal Utility District - WECC - Segments 1, 3, 4, 5, 6

- 0 - 0

none

- 0 - 0

- 0 - 0

Change “control center” to “Control Center” throughout the document to be consistent with the NERC Glossary.

RSC no Dominion and NextEra, Segment(s) 1, 0, 2, 4, 5, 6, 7, 3, 9/8/2016

- 0 - 0

Entergy recommends going to a 72 hour reporting deadline to match the final report deadline for the Department of Energy’s form OE-417.

Oliver Burke, Entergy - Entergy Services, Inc., 1, 9/8/2016

- 0 - 0

Jennifer Wright, Sempra - San Diego Gas and Electric, 5, 9/8/2016

- 0 - 0

Elizabeth Axson, 9/8/2016

- 0 - 0

SRC suggests one additional improvement to the baseline language.  The note in Attachment 1 states that "Under certain adverse conditions (e.g. severe weather, multiple events), it may not be possible to report the damage caused by an event and issue a written Event Report within the timing in the standard.  In such cases, the affected Responsible Entity shall notify parties per Requirement R2 and provide as much information as is available at the time of the notification."  However, this exception doesn’t appear in Requirement R2, which is the source of the reporting obligation.  SRC recommends modifying Requirement R2 to explicitly recognize this exception.  Also, the above-noted language in Attachment 1 lacks clarity as to exactly what sort of reporting is required when the responsible entity experiences an adverse condition and also as to when such a report must be provided.  SRC suggests that, when a responsible entity experiences adverse conditions that preclude timely notification of a reportable event, the entity should be allowed to provide either verbal or written notification, and should do so as soon as practicable following the expiration of the 24-hour period for reporting the event.  SRC further suggests that, if verbal notification of the event is provided, the responsible entity should submit written notification of the event as soon as practicable after providing the verbal notification.  To address these concerns, SRC recommends deleting the exception described above from Attachment 1 and adding the following language at the end of R2: “However, if the Responsible Entity experiences an adverse condition (e.g., severe weather, multiple events) that prevents it from submitting an event report before the expiration of the 24-hour reporting period, it shall provide verbal or written notification of the event to the entities specified in its Operating Plan as soon as practicable thereafter.  If the Responsible Entity provides verbal notification pursuant to this exception, it shall provide written notification of the event as soon as practicable thereafter.”

ISO/RTO Council Standards Review Committee, Segment(s) 2, 8/12/2016

- 0 - 0

Oshani Pathirane, 9/8/2016

- 0 - 0

Bonneville Power Administration (BPA) recommends any reference to "BES control center" or "control center" be capitalized and replaced with "BES Control Center" or "Control Center" as a NERC defined term.

Justin Mosiman, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

- 0 - 0

- 0 - 0

Thank you for the opportunity to comment.

ACES Standards Collaborators - EOP Project, Segment(s) 1, 5, 3, 6, 4, 9/8/2016

- 0 - 0

Erika Doot, 9/8/2016

- 0 - 0

SPP Standards Review Group, Segment(s) 0, 9/8/2016

- 0 - 0

PEAK Reliability supports these changes. 

Dave Thomas, 9/8/2016

- 0 - 0

Capitalization: The Standard’s Applicability section states, “…the following functional entities...”

Additionally, the Supplemental Materials, Potential Uses of Reportable Information, the words, “Functional entities” are used.

The term “Functional Entity” is a defined term in the NERC Rules of Procedure, App. 2. Since the references are to Functional Entities defined by the intent and authority under the Rules of Procedure, we suggest functional entity or entities should be capitalized.

- 0 - 0