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2015-02 EOP Periodic Review | EOP-004-2

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Start Date: 03/27/2015
End Date: 05/11/2015

Associated Ballots:

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See the Unofficial Comment Forms on the Project Page for additional background information

Hot Answers

Daniela Hammons, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

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Brad Ryan, On Behalf of: Berkshire Hathaway - PacifiCorp - WECC - Segments 6

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Other Answers

Dennis Minton, On Behalf of: Dennis Minton, , Segments 1, 3

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John Fontenot, On Behalf of: John Fontenot, , Segments 1, 5

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Matthew Beilfuss, On Behalf of: Wisconsin Energy Corporation, RF, Segments 3, 4, 5

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Leonard Kula, On Behalf of: Independent Electricity System Operator, , Segments 2

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Si Truc Phan, On Behalf of: Hydro-Qu?bec TransEnergie, NPCC, Segments 1

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MRO-NERC Standards Review Forum (NSRF), Segment(s) 3, 4, 5, 6, 1, 2, 4/8/2015

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Colorado Springs Utilities, Segment(s) 1, 3, 6, 5, 5/6/2015

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Dominion Collective Group, Segment(s) 1, 3, 5, 6, 5/7/2015

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

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Brian Bartos, On Behalf of: Brian Bartos, , Segments 1, 3, 5

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Erika Doot, On Behalf of: Erika Doot, , Segments 1, 5

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Joel Wise, On Behalf of: Tennessee Valley Authority - SERC - Segments 1, 3, 5, 6

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

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

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christina bigelow, On Behalf of: christina bigelow, , Segments 2

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NPCC Proj 2015-02 EOP-004-2, Segment(s) 10, 3, 2, 1, 9, 6, 5, 8, 5/11/2015

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Andrew Pusztai, On Behalf of: Andrew Pusztai, , Segments 1

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Molly Devine, On Behalf of: Molly Devine, , Segments 1

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Mark Kenny, On Behalf of: Mark Kenny, , Segments 1, 3, 5

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ACES Standards Collaborators - EOP Project, Segment(s) 1, 4, 5, 3, 5/11/2015

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Michelle D'Antuono, On Behalf of: Michelle D'Antuono, , Segments 5

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

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Paul Malozewski, On Behalf of: Hydro One Networks, Inc., , Segments 1, 3

HYDRO ONE NETWORKS INC. Comment_Report_EOP0042.docx

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Kathleen Black, On Behalf of: DTE Energy, RF, Segments 3, 4, 5

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Payam Farahbakhsh, On Behalf of: Hydro One Networks, Inc., , Segments 1, 3

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SPP Standards Review Group, Segment(s) 1, 3, 5, 5/11/2015

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Jared Shakespeare, On Behalf of: Jared Shakespeare, , Segments 1

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Donald Hargrove, On Behalf of: OGE Energy - Oklahoma Gas and Electric Co., , Segments 1, 3, 5, 6

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ISO/RTO Council Standards Review Committee, Segment(s) 2, 4/13/2015

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

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Andrea Jessup, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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Sergio Banuelos, On Behalf of: Tri-State G and T Association, Inc., MRO, WECC, Segments 1, 3, 5

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Leo Staples, On Behalf of: Leo Staples, , Segments 1, 3, 5, 6

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Joshua Andersen, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

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minh pham, On Behalf of: Los Angeles Department of Water and Power, WECC, Segments NA - Not Applicable

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Terri Pyle, On Behalf of: OGE Energy - Oklahoma Gas and Electric Co., , Segments 1, 3, 5, 6

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Hot Answers

Daniela Hammons, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

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Brad Ryan, On Behalf of: Berkshire Hathaway - PacifiCorp - WECC - Segments 6

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Other Answers

Dennis Minton, On Behalf of: Dennis Minton, , Segments 1, 3

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John Fontenot, On Behalf of: John Fontenot, , Segments 1, 5

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Matthew Beilfuss, On Behalf of: Wisconsin Energy Corporation, RF, Segments 3, 4, 5

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Leonard Kula, On Behalf of: Independent Electricity System Operator, , Segments 2

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Si Truc Phan, On Behalf of: Hydro-Qu?bec TransEnergie, NPCC, Segments 1

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MRO-NERC Standards Review Forum (NSRF), Segment(s) 3, 4, 5, 6, 1, 2, 4/8/2015

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Colorado Springs Utilities, Segment(s) 1, 3, 6, 5, 5/6/2015

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Dominion Collective Group, Segment(s) 1, 3, 5, 6, 5/7/2015

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

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Brian Bartos, On Behalf of: Brian Bartos, , Segments 1, 3, 5

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Erika Doot, On Behalf of: Erika Doot, , Segments 1, 5

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Joel Wise, On Behalf of: Tennessee Valley Authority - SERC - Segments 1, 3, 5, 6

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

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

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christina bigelow, On Behalf of: christina bigelow, , Segments 2

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NPCC Proj 2015-02 EOP-004-2, Segment(s) 10, 3, 2, 1, 9, 6, 5, 8, 5/11/2015

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Andrew Pusztai, On Behalf of: Andrew Pusztai, , Segments 1

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Molly Devine, On Behalf of: Molly Devine, , Segments 1

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Mark Kenny, On Behalf of: Mark Kenny, , Segments 1, 3, 5

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ACES Standards Collaborators - EOP Project, Segment(s) 1, 4, 5, 3, 5/11/2015

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Michelle D'Antuono, On Behalf of: Michelle D'Antuono, , Segments 5

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

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Paul Malozewski, On Behalf of: Hydro One Networks, Inc., , Segments 1, 3

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Kathleen Black, On Behalf of: DTE Energy, RF, Segments 3, 4, 5

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Payam Farahbakhsh, On Behalf of: Hydro One Networks, Inc., , Segments 1, 3

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SPP Standards Review Group, Segment(s) 1, 3, 5, 5/11/2015

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Jared Shakespeare, On Behalf of: Jared Shakespeare, , Segments 1

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Donald Hargrove, On Behalf of: OGE Energy - Oklahoma Gas and Electric Co., , Segments 1, 3, 5, 6

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ISO/RTO Council Standards Review Committee, Segment(s) 2, 4/13/2015

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

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Andrea Jessup, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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Sergio Banuelos, On Behalf of: Tri-State G and T Association, Inc., MRO, WECC, Segments 1, 3, 5

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Leo Staples, On Behalf of: Leo Staples, , Segments 1, 3, 5, 6

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Joshua Andersen, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

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minh pham, On Behalf of: Los Angeles Department of Water and Power, WECC, Segments NA - Not Applicable

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Terri Pyle, On Behalf of: OGE Energy - Oklahoma Gas and Electric Co., , Segments 1, 3, 5, 6

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Hot Answers

Daniela Hammons, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

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Brad Ryan, On Behalf of: Berkshire Hathaway - PacifiCorp - WECC - Segments 6

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Other Answers

Dennis Minton, On Behalf of: Dennis Minton, , Segments 1, 3

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John Fontenot, On Behalf of: John Fontenot, , Segments 1, 5

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With the addition of “Do not report theft unless it degrades normal operation of a Facility” criteria to ‘Damage or Destruction of a Facility’, recommend removal of “Do not report theft unless it degrades normal operation of a Facility” from ‘Physical Threats to a Facility’.  Theft would now be (more appropriately) reportable under a ‘Damage or Destruction’ event.

Matthew Beilfuss, On Behalf of: Wisconsin Energy Corporation, RF, Segments 3, 4, 5

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We agree with the initial recommendation which outlines three clarifying revisions to Attachment 1 of EOP-004-2, but believe that this recommendation falls way short of providing the needed clarity to the obligations of the Responsible Entities listed in Attachment 1. We further believe that certain items listed in Attachment 1 serve to support post-mortem analysis but do not contribute to operating reliability, and may be redundant with similar requirements already stipulated in the Event Analysis Process document. We therefore offer the following comments:

a.      The lack of clarity can result in registered entities being found potentially non-compliant with certain requirements. As an example, on P.10 of EOP-004-2, when there is a loss of firm load ≥ 300 MW for entities with previous year’s demand ≥ 3,000 or ≥ 200 MW for all other entities, the BA, TOP or DP is held responsible for reporting. It is unclear on the size of MW in relation to which particular entity’s previous year’s demand size, and whether or not all three entities are responsible for reporting, or just one of them needs to report, and if so, which one of the three? Also, if it is meant to be one of the three, it is not clear whether or not the location or area within which the load loss occurs would dictate which one of the three entities has that obligation. 

When the loss of load occurs in a distribution system, is it the DP’s obligation to report? Likewise, is the TOP obligated to report when the loss involves those loads that are tapped off the transmission network? Depending on the answer to the above, what is the role of the BA? Finally, if all three are obligated to report, doesn’t the requirement make it cumbersome and redundant when all three entities files reports to the recipient entities/authorities?

We believe that Attachment 1 needs to be revised to clarify the 3000 MW relationship with a specific entity’s previous year’s demand, and to hold a single entity responsible for reporting this type of events. The latter recommendation also applies to other events in Attachment 1 where there are multiple entities listed as having the obligation to take actions.

b.      We believe that the requirement to report loss of load is not needed for reliability, unlike their interruption to BES facility counterparts. Loss of load is usually caused by loss of facilities, or by frequency or voltage excursions resulting from events that are already listed in Attachment 1 (e.g., voltage deviation, generation loss, etc.).  We further believe that while this information is needed for post-mortem event analysis, this information reporting requirement is already stipulated in the Event Analysis Process document, and mandated by local regulatory authorities. Reporting such events to the ERO, the RE and other entities is redundant and does not help to improve operating reliability. Further, since loss of load by itself does not have any impact on the Bulk Electric System reliability, reporting such events is inconsistent with the principle “….to report disturbances and events that threaten the reliability of the Bulk Electric System” as indicated in the Guideline and Technical Basis of the standard. We therefore suggest that this requirement be removed from Attachment 1 as it is not needed for operating reliability and is redundant with the requirement for event analysis stipulated elsewhere or mandated by local regulatory authorities. 

c.       If for whatever reasons the loss of load reporting requirement is retained in Attachment 1, we request the SDT to provide the technical justification for the threshold values of ≥ 300 MW for entities with previous year’s demand ≥ 3,000 or ≥ 200 MW for all other entities. We believe these thresholds are too low to warrant any special attention and reporting burden by the Responsible Entities. For example, an area load of several hundred MW that is normally supplied by two transmission lines may be lost due to one of the lines being out of serviced for maintenance while the other suffering a contingency loss. To avoid having to report such load loss resulting from routine operating practices and recognized contingencies (with respect to design and operating criteria) , we believe the reporting threshold should be raised to a level of at least 1,000 MW. We further suggest the SDT seek input from the NERC technical committees on the threshold values if the SDT should decide to keep this requirement, which we believe is not needed for operating reliability.

Leonard Kula, On Behalf of: Independent Electricity System Operator, , Segments 2

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Si Truc Phan, On Behalf of: Hydro-Qu?bec TransEnergie, NPCC, Segments 1

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NSRF requests clarifying language in Attachment 1, Row 1 on page 8 for the event type “Damage or Destruction of a Facility”.  “Damage or destruction” should apply to an identified CIP-014-1 facility or damage that causes a generation or transmission EEA level 3 event.  At a minimum it should also differentiate between internal fault-generated damage and externally applied damage.

NSRF agrees with the drafting team recommendation to add the phrase “Do not report theft unless it degrades normal operation of a Facility” criteria from ‘Physical Threats to a Facility,’ to ‘Damage or Destruction of a Facility;’ (add to third column of second row on Page 8 of the standard in Attachment 1).  This helps clarify the difference between incidental theft that has little to no system reliability impact and a theft that impacts reliability.

NSRF agrees with the drafting team recommendation to add information in the Guideline and Technical Basis regarding the good practice of physically and digitally surveying control houses following a breach provided it is made clear that this is a good practice and does not become part of the RSAWs where NERC includes requirements beyond what’s required in the NERC requirements.

NSRF agrees with the drafting team recommendation to clarify “initiating entity” along with all the Responsible Entity shall notify “parties” per Requirement R2.  Initiating entity and parties should be clarified to be the entities identified in the Responsible Entity’s EOP-004 disturbance reporting plan.

NSRF does not agree with the drafting team recommendation to change “load” to the defined term “Load” as this changes the meaning of the concrete measurements in Attachment 1.  The loads in Attachment 1 are physical end use load in MW.

NSRF does not understand the PRT statement [page 5 section 3], ("Load is not a physical end use device, but the existence of the capacity to deliver electric energy – MW reduction").  This contradicts the NERC definition of Load (An end-use device or customer that receives power from the electric system) The EOP PRT recommends review by the future SDT of the term “load” in EOP-004-2 and revise to “Load” if the future SDT determines “load” is intended to be the defined term “Load3,” and to review the term for conflict with applicable entity ("Load is not a physical end use device, but the existence of the capability to deliver electric energy – MW reduction"). This change would completely reverse the meaning of event types referencing load reduction, shedding, and loss.

Moreover, this would result in an even more extreme interpretation of generation loss, reducing the threshold from actual specified generation loss to a loss of capacity to deliver electric energy, whether or not the generator is on-line.

  In any event, this section is confusing and the PRTR should devise clearer issues by describing the problem, and proposed solutions for this confusing issue.

MRO-NERC Standards Review Forum (NSRF), Segment(s) 3, 4, 5, 6, 1, 2, 4/8/2015

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We do not think revisions are necessary, the standard is well written.

Colorado Springs Utilities, Segment(s) 1, 3, 6, 5, 5/6/2015

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The recommendation regarding the good practice of physically and digitally surveying control houses following a breach does not belong in this standard. If the EOP PRT thinks it has value, Dominion recommends they forward that recommendation to those developing CIP-014 (physical security).

Dominion Collective Group, Segment(s) 1, 3, 5, 6, 5/7/2015

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

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Brian Bartos, On Behalf of: Brian Bartos, , Segments 1, 3, 5

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The Bureau of Reclamation (Reclamation) agrees with the drafting team's recommendation (1) to include additional information in the Guideline and Technical Basis regarding the good practice of physically and digitally surveying control houses following a breach.  However, Reclamation notes the inclusion of the new term "control houses" and suggests that the drafting team replace the term with "BES facilities" to avoid confusion. 

Reclamation also agrees with the drafting team's recommendation (2) to add the phrase "Do not report theft unless it degrades normal operation of a Facility" to "Damage or destruction of a facility" on page 8 of Attachment 1. 

Reclamation also agrees with the drafting team's recommendation (3) to review page 9 of Attachment 1 for revision of Entity with Reporting Responsibility for proper application of initiating entity.  Reclamation suggests that Reliability Coordinators, Transmission Operators, Balancing Authorities, or Distribution Providers would generally initiate BES Emergencies requiring public appeals for load reduction, system-wide voltage reduction, or manual firm load shedding.     

Erika Doot, On Behalf of: Erika Doot, , Segments 1, 5

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We recommend that the Reliability Standard be revised to require that only one report be required per event. For example, for an event type that is applicable to a RC, BA, and TOP, and an event occurs in the TOP Area, there would not be a requirement for both the TOP and the RC to submit a report. Some Regional Entities have interpreted the current Reliability Standard to require multiple reports if the RC and TOP are not within the same corporate structure.

Joel Wise, On Behalf of: Tennessee Valley Authority - SERC - Segments 1, 3, 5, 6

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

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

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ERCOT agrees with certain recommendations made by the review team, but disagrees with others.  In particular, ERCOT disagrees with the review team’s recommendations as follows:

 

  1. ERCOT respectfully submits that the recommendation for the placement of the language regarding theft from a facility should be included under the “Damage or Destruction Of a Facility” rows or rows 1 and 2 on page 8 of the standard.

  2. Relative to the removal of the GOP from the “Generation Loss” reporting, ERCOT respectfully submits that GOPs will have more data and information regarding the event that caused there facility to go off-line.  This data should be utilized in concert with BA data to evaluate events.  Without GOP level input and insights, event reporting for generation losses may occur at too high of a level to effectively discern trends and threats.

  3. While ERCOT agrees with and supports the review team’s recommendation to review the “Entity with Reporting Responsibility,” it believes that the review missed the opportunity to provide additional guidance to future drafting team efforts beyond the recommendations for GOPs above.  ERCOT would encourage the review to provide additional guidance to the drafting team that places immediate reporting responsibility on the entity closest to or most impacted by an event.  As an example, RCs are required to report events that damage or destroy a Facility, which 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.).  RCs and BAs are often not co-located with Facilities such that they would be in a position to immediately report on damage to a Facility.  In fact, if such damage did not impact the electrical capacity or operation of the Facility, the RC or BA would likely be unaware of any damage to the Facility until notified by the TOP.  The review should provide additional guidance on this issue.

  4. To the extent possible, ERCOT recommends that clarifications or additional criteria, such as those that the review team provided from the Form DOE-417, should be considered for inclusion in Attachment A to EOP-004.  Inclusion of such additional criteria or clarifications would drive consistency in reporting as well as provide guidance and appropriate division regarding initial reporting responsibilities.  In particular, if TOPs are the responsible party for initiating the reporting of events associated with damage to or destruction of a Facility that provides a major interruption or impact and RCs, BAs, or the initiating entity are responsible for reporting the BES emergency based on other defined event types, reporting redundancy would be reduced and the most impacted or appropriate entity would be responsible for reporting.  ERCOT urges the review team to address this issue.

christina bigelow, On Behalf of: christina bigelow, , Segments 2

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Regarding the four bullets that are listed under Item 2c on pages 4 and 5:

First bullet--It is a good idea for adding information for including physically and digitally surveying control houses.  What constitutes a digital survey?  Also, the surveys should not be limited to control houses.  There are installations where freestanding control panels are mounted outside of control houses.

We propose the following wording for the “Event Type” of “Physical threats to a facility” listed in  Attachment 1:

“Physical threat to its Facility excluding weather or natural disaster related threats, which has the potential to degrade the normal operation of the Facility.

OR

Suspicious device or activity at a Facility, where “suspicious activity” means any observed behavior reasonably indicative of criminal intent to degrade normal operation of a BES facility, unless verified to be otherwise within the R2 reporting timeframe (i.e., 24 hours).

Do not report theft unless it degrades normal operation of a Facility.”

It would also be beneficial to define the term “suspicious activity” since it shows up repeatedly throughout the standard.

Third bullet--Agree.

Fourth bullet--Agree.

NPCC Proj 2015-02 EOP-004-2, Segment(s) 10, 3, 2, 1, 9, 6, 5, 8, 5/11/2015

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Andrew Pusztai, On Behalf of: Andrew Pusztai, , Segments 1

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Molly Devine, On Behalf of: Molly Devine, , Segments 1

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Regarding the four bullets that are listed under Item 2c on pages 4 and 5:

First bullet--It is a good idea for adding information for including physically and digitally surveying control houses.  What constitutes a digital survey?  Also, the surveys should not be limited to control houses.  There are installations where freestanding control panels are mounted outside control houses.

Second bullet--Disagree with adding “Do not report theft unless it degrades normal operation of a Facility” to the damage or destruction of a facility.  Any such attempts should be made known to establish possible patterns to aid in prevention of future occurrences.

Third bullet--Agree

Fourth bullet--Agree.

 

Mark Kenny, On Behalf of: Mark Kenny, , Segments 1, 3, 5

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We agree with the EOP PRT’s recommendation to revise EOP-004-2 and we agree that Attachment 1 should be reviewed for consistency in timeframe, MW values, and BES applicability threshold.

ACES Standards Collaborators - EOP Project, Segment(s) 1, 4, 5, 3, 5/11/2015

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Ingleside Cogeneration LP (ICLP) agrees with the three proposed modifications to EOP-004-2’s reportable events table.  In particular, we support the removal of the GOP as a reporting entity for generation outages above a certain capacity level (1000+ MW in ERCOT and Quebec; 2000+ MW elsewhere).  As the PRT has concluded, a GOP submission would capture only a subset of the data available to the Host BA – and could even confuse the recipients if the format or data-types vary.  In addition, the BA or the Events Analysis team could bring the GOP into a post-mortem investigation if further information is needed.

Michelle D'Antuono, On Behalf of: Michelle D'Antuono, , Segments 5

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

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Paul Malozewski, On Behalf of: Hydro One Networks, Inc., , Segments 1, 3

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Kathleen Black, On Behalf of: DTE Energy, RF, Segments 3, 4, 5

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Payam Farahbakhsh, On Behalf of: Hydro One Networks, Inc., , Segments 1, 3

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For a Distribution Provider, R3 is purely administrative in the case where a Distribution Provider has no reporting requirements.  There may be no contacts needed for the DP so the burden of having to provide evidence that shows “no contacts” provides no reliability benefit.  The reliability benefit is found more in the area of the BA or TOP and not a DP with load below 100MW.  We suggest the PRT review the applicability of this requirement.

The VRF’s for R1 and R3 do not seem consistent.  We recommend the review team review the importance of R1 vs R3 to ensure the VRF’s are set appropriately.  It seems more importance is placed on having an updated contact list (R3) versus having an Operating Plan for reporting (R1) due to the different VRF’s.

SPP Standards Review Group, Segment(s) 1, 3, 5, 5/11/2015

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Jared Shakespeare, On Behalf of: Jared Shakespeare, , Segments 1

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Donald Hargrove, On Behalf of: OGE Energy - Oklahoma Gas and Electric Co., , Segments 1, 3, 5, 6

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ISO/RTO Council Standards Review Committee, Segment(s) 2, 4/13/2015

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

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BPA suggests deleting the first bullet under c. Attachment 1 - The EOP PRT recommends the future Standard Drafting Team (SDT) consider the following revisions to Attachment 1 for clarity regarding:
• Include additional information in the Guideline and Technical Basis regarding the good practice of physically and digitally surveying control houses following a breach.

BPA believes this is applicable to security personnel after the fact and primarily to CIP-014 security plans.

Andrea Jessup, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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Sergio Banuelos, On Behalf of: Tri-State G and T Association, Inc., MRO, WECC, Segments 1, 3, 5

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Leo Staples, On Behalf of: Leo Staples, , Segments 1, 3, 5, 6

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Joshua Andersen, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

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minh pham, On Behalf of: Los Angeles Department of Water and Power, WECC, Segments NA - Not Applicable

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Terri Pyle, On Behalf of: OGE Energy - Oklahoma Gas and Electric Co., , Segments 1, 3, 5, 6

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Hot Answers

Daniela Hammons, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

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Brad Ryan, On Behalf of: Berkshire Hathaway - PacifiCorp - WECC - Segments 6

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Other Answers

Dennis Minton, On Behalf of: Dennis Minton, , Segments 1, 3

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John Fontenot, On Behalf of: John Fontenot, , Segments 1, 5

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Related to 1. Paragraph 81:

 

First paragraph last sentence – “Requirement R3, while administrative, does support real-time operations as a function necessary to promote reliability reporting

 

Last paragraph – R3 is a medium VRF level

Matthew Beilfuss, On Behalf of: Wisconsin Energy Corporation, RF, Segments 3, 4, 5

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Please see our proposed retirement of the loss of load reporting requirement under Q1, above.

Leonard Kula, On Behalf of: Independent Electricity System Operator, , Segments 2

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Si Truc Phan, On Behalf of: Hydro-Qu?bec TransEnergie, NPCC, Segments 1

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The EOP PRT justifies retaining Requirement R3, despite it being administrative, as supporting real-time operations as a function necessary to promote reliability.  This justification is inconsistent with both the guidelines of the SDT and the reporting timelines for Requirement R2.

This Standard does not apply to, impact, or otherwise support real-time operations.  The SDT states on page 14 (of EOP-004-2), “The DSR SDT wishes to make clear that the proposed Standard does not include any real-time operating notifications for the events listed in EOP-004 Attachment 1. Real-time communication is achieved is and covered in other standards. The proposed standard deals exclusively with after-the-fact reporting.”  This is reiterated on page 18 in the Introduction of Reporting Concepts.

Requirement R2 requires reporting an event “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…”  The allowance to await the resumption of the normal work week to submit the report clearly shows the reporting requirement has no relation to real-time operations.

Requirement R3 is justified by an assertion that “During Emergency operations, operators should not be burdened with looking up contact information or having invalid phone numbers.”  Again, this Standard is intended to provide after-the-fact reporting, at which time the time it would take to look up a changed contact number will not negatively impact reliability.  This meets Paragraph 81 Criteria B5, Periodic Updates, for requiring periodic updates to a plan without an operational benefit to reliability.

MRO-NERC Standards Review Forum (NSRF), Segment(s) 3, 4, 5, 6, 1, 2, 4/8/2015

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Colorado Springs Utilities, Segment(s) 1, 3, 6, 5, 5/6/2015

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Dominion agrees with IERP that R3 (contact numbers) should either be retired, or at least included within R1. While we don’t disagree that operators should not have to ‘look the numbers up’, R1 could be more prescriptive and explicitly state need to include contact information in the Operating Plan to address the EOP PRT concern (without adding a specifically administrative compliance burden). However, we believe it is already inferred, as we don’t know how one could argue that their Operating Plan is sufficient if it failed to include contact information in its “protocol(s) for reporting”…..  

R3 VRF is Medium; the template says this is High.

Dominion Collective Group, Segment(s) 1, 3, 5, 6, 5/7/2015

- 0 - 0

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

- 0 - 0

Brian Bartos, On Behalf of: Brian Bartos, , Segments 1, 3, 5

- 0 - 0

Reclamation agrees with the drafting team’s recommendation to retain R3 as a standalone requirement that registered entities annually verify contact information included in the Operating Plan to verify its accuracy.  Reclamation agrees with the drafting team’s rationale that during Emergency operations, operators should not be burdened with looking up contact information or having invalid phone numbers.

Erika Doot, On Behalf of: Erika Doot, , Segments 1, 5

- 0 - 0

Joel Wise, On Behalf of: Tennessee Valley Authority - SERC - Segments 1, 3, 5, 6

- 0 - 0

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

- 0 - 0

I disagree with the PRTs recommendation and logic for not retiring R3. They’ve conceded that R3 is administrative. An entity has 24 hours to submit the report. As well, contact information can change at any time, sometimes without notice so verification once annually is ineffective and may falsely imply accuracy. I believe a good practice is to keep a central directory of contact information to which plans refer to. This avoids fragmentation. However, a good practice is for a user to always verify information at its source. This holds true for any type of information. So long as a good description of the entities and the specific departments/personnel and their titles to which need notifying are provided in the plan, the user can look up the contact information and get the most recent information.

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

- 0 - 0

ERCOT disagrees that the validation of contact information provides direct value to reliability.  Further, it believes that it meets all applicable criteria set forth in Attachment 2 to be retired consistent with Paragraph 81 as follows:

  1. The requirement is purely administrative.

  2. The requirement is simply a data validation effort.

  3. The requirement produces documentation that contact numbers were validated and does not directly impact reliability.

  4. The requirement would, at most, trigger entities to periodically update documentation if a contact number changed.

 ERCOT supports the retirement of Requirement R3 consistent with Paragraph 81.

christina bigelow, On Behalf of: christina bigelow, , Segments 2

- 0 - 0

NPCC Proj 2015-02 EOP-004-2, Segment(s) 10, 3, 2, 1, 9, 6, 5, 8, 5/11/2015

- 0 - 0

  • ·        The Independent Expert Review Project (IERP) recommended that Requirement # 3 be retired or combined with Requirement # 1.   The Periodic Review Team suggests that Requirement # 3 not be retired.   ATC does not agree with the Periodic Review Team.  ATC supports the IERP recommendation to retire Requirement # 3.   ATC believes Requirement # 3 is an “administrative” requirement which does meet Paragraph 81 criteria.  Requirement # 1 requires Registered Entities to have an event Reporting Plan which includes the protocol(s) for reporting to applicable regulatory authorities.   ATC believes that Requirement # 1 compels Registered Entities to assure that the protocols,  including contact information,  be maintained  in a condition that supports reliable operations.   Since Requirement # 1 requires protocols for reporting events,  which are assumed to require appropriate, up-to-date contact information, Requirement # 3 appears to be an duplicative and unnecessary requirement.    

 

  • ·       ATC also believes that Requirement # 3 fits into Criterion # B5 of the “Paragraph 81 Criteria” and, as such, warrants the retirement of the Requirement.    

 

  • The Periodic Review Team suggest that it would be inappropriate to combine Requirement # 1 with Requirement # 3 because Requirement # 1 has a “low” VRF and a Requirement # 3 has a  high” VRF.   ATC believes that the Periodic Review Team has erroneously identified that Requirement # 3 has a “medium” VRF.   The VRF for Requirement # 3 is actually listed in the Standard as  “medium.”    Reluctance to combine requirements because the VRFs for the requirements are different is not a reasonable justification for not eliminating or combine requirements.   If Requirements # 3 is not retired, then ATC strongly believes an appropriate action would be to combine Requirement # 1 with Requirement # 3.

 

Andrew Pusztai, On Behalf of: Andrew Pusztai, , Segments 1

- 0 - 0

Molly Devine, On Behalf of: Molly Devine, , Segments 1

- 0 - 0

We agree with the recommendation of the IERT to retire R3 as administrative in nature. Accuracy of an entity’s Operating Plan is inherent in Requirement 1.

Mark Kenny, On Behalf of: Mark Kenny, , Segments 1, 3, 5

- 0 - 0

(1) We disagree with the EOP PRT’s recommendation to keep the annual verification of contact information as stated in Requirement R3 intact.  The Independent Expert Review Project (IERP) correctly identified a requirement that could be combined into R1.  The Operating Plan could be subject to an annual review, which the contact information would be expected to be updated.  This could be outlined in a Measure.

(2) We also question why the PRT is taking an approach of keeping a requirement identified as meeting Paragraph 81 criteria.  We suggest removing the requirement because it is administrative in nature and could be verified through an annual review of the Operating Plan in R1.

(3) If the Operating Plan was required to be verified each year, this would benefit reliability more than just verifying contact information.  The registered entity would need to review the entire plan to determine if any changes need to be made to the procedures, including the contact information.

ACES Standards Collaborators - EOP Project, Segment(s) 1, 4, 5, 3, 5/11/2015

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ICLP believes another effort needs to be made to consolidate Event Reporting requirements across the ERO, the DOE, and ES-ISAC.  Some progress was made during the development stage of EOP-004-2, but there are still efficiencies to be gained.  That project team had to defer progress in this area due to time constraints that no longer exist.

Michelle D'Antuono, On Behalf of: Michelle D'Antuono, , Segments 5

- 0 - 0

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

- 0 - 0

Paul Malozewski, On Behalf of: Hydro One Networks, Inc., , Segments 1, 3

- 0 - 0

Kathleen Black, On Behalf of: DTE Energy, RF, Segments 3, 4, 5

- 0 - 0

Payam Farahbakhsh, On Behalf of: Hydro One Networks, Inc., , Segments 1, 3

- 0 - 0

SPP Standards Review Group, Segment(s) 1, 3, 5, 5/11/2015

- 1 - 0

Jared Shakespeare, On Behalf of: Jared Shakespeare, , Segments 1

- 0 - 0

Donald Hargrove, On Behalf of: OGE Energy - Oklahoma Gas and Electric Co., , Segments 1, 3, 5, 6

- 0 - 0

ISO/RTO Council Standards Review Committee, Segment(s) 2, 4/13/2015

- 0 - 0

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

- 0 - 0

BPA disagrees with the retention of R3 recommendation; it is not necessary to add an administrative process, an annual validation of law enforcement contacts, as a Standard’s Requirement.

Andrea Jessup, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

- 0 - 0

Sergio Banuelos, On Behalf of: Tri-State G and T Association, Inc., MRO, WECC, Segments 1, 3, 5

- 0 - 0

Leo Staples, On Behalf of: Leo Staples, , Segments 1, 3, 5, 6

- 0 - 0

Joshua Andersen, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

- 0 - 0

minh pham, On Behalf of: Los Angeles Department of Water and Power, WECC, Segments NA - Not Applicable

- 0 - 0

Terri Pyle, On Behalf of: OGE Energy - Oklahoma Gas and Electric Co., , Segments 1, 3, 5, 6

- 0 - 0

Hot Answers

Daniela Hammons, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

- 0 - 0

Brad Ryan, On Behalf of: Berkshire Hathaway - PacifiCorp - WECC - Segments 6

- 0 - 0

Other Answers

Dennis Minton, On Behalf of: Dennis Minton, , Segments 1, 3

- 0 - 0

John Fontenot, On Behalf of: John Fontenot, , Segments 1, 5

- 0 - 0

N/A

Matthew Beilfuss, On Behalf of: Wisconsin Energy Corporation, RF, Segments 3, 4, 5

- 0 - 0

We strongly agree with Recommendation 2(b) to improve the clarity for the VSL for Requirement R2 by adding “recognition of” to the threshold of VSL table for Requirement R2 to provide the needed consistency between the requirement and the measure. Absent this phrase, some entities have been found potentially non-compliant with Requirement R2 when these entities did not report the events within 24 hours of their occurrence despite the reporting was made within 24 hours of recognizing that such events met the event type threshold for reporting.

Leonard Kula, On Behalf of: Independent Electricity System Operator, , Segments 2

- 0 - 0

Si Truc Phan, On Behalf of: Hydro-Qu?bec TransEnergie, NPCC, Segments 1

- 0 - 0

MRO-NERC Standards Review Forum (NSRF), Segment(s) 3, 4, 5, 6, 1, 2, 4/8/2015

- 0 - 0

We do not think revisions are necessary, the standard is well written.

Colorado Springs Utilities, Segment(s) 1, 3, 6, 5, 5/6/2015

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As indicated in response to first 2 questions. Dominion does not understand the intent of the PRT’s comment relative to the word load. If the recommendation had stopped at, recommending the SDT determine whether the defined term Load should be used as opposed to the word load, we would have at least understood, please clarify the intent.

Also, Dominion does not understand the intent of the EOP PRT; the inclusion of “…to review the term for conflict with applicable entity..” , please clarity the intent.

Dominion Collective Group, Segment(s) 1, 3, 5, 6, 5/7/2015

- 0 - 0

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

- 0 - 0

Brian Bartos, On Behalf of: Brian Bartos, , Segments 1, 3, 5

- 0 - 0

Erika Doot, On Behalf of: Erika Doot, , Segments 1, 5

- 0 - 0

Joel Wise, On Behalf of: Tennessee Valley Authority - SERC - Segments 1, 3, 5, 6

- 0 - 0

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

- 0 - 0

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

- 0 - 0

ERCOT agrees and disagrees with aspects of the review teams initial recommendations as set forth above.  In addition, the IRC notes its strong support for Recommendation 2(b) to improve the clarity for the VSL for Requirement R2 by adding “recognition of” to the threshold of VSL table for Requirement R2 to provide the needed consistency between the requirement and the measure.  Absent this phrase, entities can be found potentially non-compliant with Requirement R2 when these entities did not report the events within 24 hours of their occurrence despite the reporting being made within 24 hours of recognizing that such events met the event type threshold for reporting.  An example of how this disconnect may occur is the damage to a facility.  In particular, a TOP or GOP may be aware of damage and report such damage, but – if there was not a BA or RC-level notification – the BA or RC would have no knowledge of a reportable event.

christina bigelow, On Behalf of: christina bigelow, , Segments 2

- 0 - 0

NPCC Proj 2015-02 EOP-004-2, Segment(s) 10, 3, 2, 1, 9, 6, 5, 8, 5/11/2015

- 0 - 0

Andrew Pusztai, On Behalf of: Andrew Pusztai, , Segments 1

- 0 - 0

Molly Devine, On Behalf of: Molly Devine, , Segments 1

- 0 - 0

Mark Kenny, On Behalf of: Mark Kenny, , Segments 1, 3, 5

- 0 - 0

(1) The phrase in Requirement R1, “e.g., the Regional Entity, company personnel, the Responsible Entity’s Reliability Coordinator, law enforcement, or other governmental authority” needs to be clarified because it is a series of optional entities and not a requirement to send the event reports to each entity.

(2) We also recommend aligning the DOE event reporting process as close as possible to the NERC Event Analysis process, as the DOE OE-417 and the NERC Brief Report requires limited information.  In addition to aligning the standard, we recommend working with DOE to clear up inconsistencies with terminology with the OE-417 Form, which uses the words “disturbance” and “incident” instead of “event.”

(3) The comment in section 3 regarding applying the definition of Load appears to be contradictory.  On the one hand, it indicates that the standard should use the NERC definition of Load, but on the other hand it indicates that the definition is not adequate.  If the definition is not adequate perhaps it should not apply.  At the very least, if the definition is modified, all standards that use of the definition need to be reviewed to ensure that modification does not unintentionally change the meaning the proposed definition of Load that is used in other reliability standards.

ACES Standards Collaborators - EOP Project, Segment(s) 1, 4, 5, 3, 5/11/2015

- 0 - 0

See comments to Question 2.

Michelle D'Antuono, On Behalf of: Michelle D'Antuono, , Segments 5

- 0 - 0

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

- 0 - 0

Paul Malozewski, On Behalf of: Hydro One Networks, Inc., , Segments 1, 3

- 0 - 0

Kathleen Black, On Behalf of: DTE Energy, RF, Segments 3, 4, 5

- 0 - 0

Payam Farahbakhsh, On Behalf of: Hydro One Networks, Inc., , Segments 1, 3

- 0 - 0

We disagree with the PRT recommendations in the Event Review Report in reference to the Clarity (#2) section a (page 4). They stated that the “relationship between the reporting requirements contained in the Standard and the Department of Energy OE-417 report is clear as written.” However, it also mentioned that EOP-004-2 is used in other jurisdictions outside of the United States. We would suggest listing the specific reporting forms for the other jurisdictions as well as the OE-417 so there is no confusion on what documentation should be used for reporting events no matter the jurisdictions. Also, we would recommend including the listing of reports in the Measurements where applicable to the appropriate RSAW(s).

In addition, we suggest the PRT review the language in R2 to ensure it is clear that the intent of either submitting the EOP-004 Attachment 1 form, or the OE-417 form is to avoid the need to double report.  We understand that the intent is to file the OE-417 if applicable, and if not, then file the EOP-004 Attachment 1 form.  But both are not necessary.  This is understood, however is not clear in the language of the requirements. 

SPP Standards Review Group, Segment(s) 1, 3, 5, 5/11/2015

- 3 - 0

R3:  We disagree with the PRT’s reason and agree with the IERP recommendation to retire R3.  Contact lists are administrative in nature and should not be part of a mandatory reliability standard.  There is no evidence that not having a contact list has caused additional burden to operators.  Further the PRT explanation (p3) states that R3 has a VRF of high.  R3 has a VRF of medium.  We agree with the rest of the PRT revision comments for EOP-004-2.

Jared Shakespeare, On Behalf of: Jared Shakespeare, , Segments 1

- 0 - 0

Donald Hargrove, On Behalf of: OGE Energy - Oklahoma Gas and Electric Co., , Segments 1, 3, 5, 6

- 0 - 0

We agree with Recommendation 2(b) to improve the clarity for the VSL for Requirement R2 by adding “recognition of” to the threshold of VSL table for Requirement R2 to provide the needed consistency between the requirement and the measure. Absent this phrase, some entities have been found potentially non-compliant with Requirement R2 when these entities did not report the events within 24 hours of their occurrence despite the reporting was made within 24 hours of recognizing that such events met the event type threshold for reporting.

ISO/RTO Council Standards Review Committee, Segment(s) 2, 4/13/2015

- 0 - 0

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

- 0 - 0

Andrea Jessup, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

- 0 - 0

Sergio Banuelos, On Behalf of: Tri-State G and T Association, Inc., MRO, WECC, Segments 1, 3, 5

- 0 - 0

Leo Staples, On Behalf of: Leo Staples, , Segments 1, 3, 5, 6

- 0 - 0

Joshua Andersen, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

- 0 - 0

minh pham, On Behalf of: Los Angeles Department of Water and Power, WECC, Segments NA - Not Applicable

- 0 - 0

Terri Pyle, On Behalf of: OGE Energy - Oklahoma Gas and Electric Co., , Segments 1, 3, 5, 6

- 0 - 0

Hot Answers

Daniela Hammons, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

- 0 - 0

Brad Ryan, On Behalf of: Berkshire Hathaway - PacifiCorp - WECC - Segments 6

- 0 - 0

Other Answers

Dennis Minton, On Behalf of: Dennis Minton, , Segments 1, 3

- 0 - 0

John Fontenot, On Behalf of: John Fontenot, , Segments 1, 5

- 0 - 0

N/A

Matthew Beilfuss, On Behalf of: Wisconsin Energy Corporation, RF, Segments 3, 4, 5

- 0 - 0

Leonard Kula, On Behalf of: Independent Electricity System Operator, , Segments 2

- 0 - 0

Hydro-Quebec TranEnergie request that the NERC Drafting Team reconsider the generation loss value from 1,000 MW to 2,000 MW for the Québec Interconnection at the attachment 2 of Generation Loss.

See technical justification attached.

Si Truc Phan, On Behalf of: Hydro-Qu?bec TransEnergie, NPCC, Segments 1

Technical justification EOP-004_FBM.docx

- 0 - 0

The NSRF is recommending the follow change: page 3, second to last paragraph, last sentence, replace emergency with after the fact operations.  

MRO-NERC Standards Review Forum (NSRF), Segment(s) 3, 4, 5, 6, 1, 2, 4/8/2015

- 0 - 0

No Comments.

Colorado Springs Utilities, Segment(s) 1, 3, 6, 5, 5/6/2015

- 0 - 0

Dominion Collective Group, Segment(s) 1, 3, 5, 6, 5/7/2015

- 0 - 0

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

- 0 - 0

Brian Bartos, On Behalf of: Brian Bartos, , Segments 1, 3, 5

- 0 - 0

Erika Doot, On Behalf of: Erika Doot, , Segments 1, 5

- 0 - 0

Add "Actual or Suspected Cyber Events" as an Event Type. With the increase threat on the industry of Cyber Attacks, we believe that this needs to be added as an Event Type in EOP-004-2. While Cyber Threats are included in the DOE-417 report, this type of event should also be captured in the NERC Standards.

Joel Wise, On Behalf of: Tennessee Valley Authority - SERC - Segments 1, 3, 5, 6

- 0 - 0

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

- 0 - 0

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

- 0 - 0

christina bigelow, On Behalf of: christina bigelow, , Segments 2

- 0 - 0

Requirement R3 is administrative, and should be a Paragraph 81 candidate.

Coordination with the Event Analysis Program is imperative if Categories being analyzed are to line-up with those being reported (notification) in EOP-004-2. The original intent was to do this so as to not burden nor confuse industry on what needs to be reported and analyzed. The Process Review team needs to coordinate with the Event Analysis Subcommittee to accomplish this task. This may have to be requested of the SC to correct the standard in order to realign the standard with the EA event categories.

NPCC Proj 2015-02 EOP-004-2, Segment(s) 10, 3, 2, 1, 9, 6, 5, 8, 5/11/2015

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  • ·        The Periodic Review Team has not suggested revisions to the VRFs.   ATC recommends that the Periodic Review Team evaluate the continued appropriateness of the VRFs.  It is difficult to understand why Requirement # 1, which requires the implementation of an overall event Reporting Plan has a “low” VRF while Requirement # 3, which requires that contact information in the Reporting Plan be routinely updated, has a “medium” VRF.

 

  • ·       EOP-004-2 introduces the term “Responsible Entity.”  “Responsible Entity” is currently not defined in the NERC Glossary of Terms. 

 

  • ·       The Periodic Review Team has suggested that “additional information in the Guidance and Technical Basis regarding the good practice of physically and digitally surveying control houses following a breach.”  ATC supports this as a “good practice” but the Guideline and Technical Basis section of any Reliability Standard is not an appropriate place to advocate “good practices.”   This “good practice” also seems irrelevant to EOP-004-2 since this Standard is intended to only define event reporting obligations.

 

  • The Periodic Review Team recommends the review of the term “load” as used in EOP-004-2 be evaluated by any future Standards Development Team.   The Periodic Review Team has suggested that the use of the term “load ” should be applied as intended by the NERC Glossary defined term “ Load.”  ATC does not believe that “load” as used in EOP-004-2 was intended to be applied as pursuant to the “Load” definition on the NERC Glossary of Terms.

Andrew Pusztai, On Behalf of: Andrew Pusztai, , Segments 1

- 0 - 0

Molly Devine, On Behalf of: Molly Devine, , Segments 1

- 0 - 0

Coordination with the Event analysis program is imperative if Categories being analyzed are to line-up with those being reported (notification) in EOP-004-2. Original intent was to do this so as to not burden nor confuse industry on what needs to be reported and analyzed. The Process Review team needs to coordinate with the Event Analysis Subcommittee to accomplish this task. This may have to be requested of the SC to correct the standard in order to realign the standard with the EA event categories.

 

Eversource Proposes that a future SDT consider revising the Event Type, Complete Loss of Monitoring capability description to not include mention of State Estimator or Contingency Analysis. Any clarification as to what the event is describing should be provided in a supplemental guidance document. 

Mark Kenny, On Behalf of: Mark Kenny, , Segments 1, 3, 5

- 0 - 0

(1) We would like to point out that registered entities are required to submit duplicative event reports manually to both the DOE and NERC.  We ask that the EOP PRT make a recommendation for NERC to resolve this duplication issue by coordinating with the DOE to have a portal to submit the Event Report that will copy all interested parties and regulators.

(2) Thank you for the opportunity to comment.

ACES Standards Collaborators - EOP Project, Segment(s) 1, 4, 5, 3, 5/11/2015

- 0 - 0

Michelle D'Antuono, On Behalf of: Michelle D'Antuono, , Segments 5

- 0 - 0

SGE&G agrees with SERC OC comments

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

- 0 - 0

Paul Malozewski, On Behalf of: Hydro One Networks, Inc., , Segments 1, 3

- 0 - 0

Kathleen Black, On Behalf of: DTE Energy, RF, Segments 3, 4, 5

- 0 - 0

Payam Farahbakhsh, On Behalf of: Hydro One Networks, Inc., , Segments 1, 3

- 0 - 0

We suggest that an improvement to event reporting would be to consolidate the submission of EOP-004 forms or OE-417 events by only the RC to NERC/DOE rather than have separate reporting by multiple entities.  This would streamline the process and would eliminate multiple, duplicate reports being provided.  BA, TOP, etc reporting would be submitted to the RC and the RC would submit a consolidated, single report to DOE/NERC.  We ask the PRT to discuss this concept.  The intent of the suggested improvement is to clarify that “if” a BA or TOP is reporting the event to DOE/NERC, then the RC is not obligated to submit the same, matching report for the same event.  If the event covers multiple TOP areas, for example, is there really a need for multiple event reports to be submitted?  If a single event report can be submitted, then why can’t a single report satisfy the intent?

The term ‘load’ is used throughout the standard (especially in attachment 1 and 2). We agree with the recommendation for the future SDT to capitalize the ‘l’ in load. This term should be capitalized as it is defined in both the Glossary of Terms as well as the Rules of Procedure (RoP).

SPP Standards Review Group, Segment(s) 1, 3, 5, 5/11/2015

- 3 - 0

Jared Shakespeare, On Behalf of: Jared Shakespeare, , Segments 1

- 0 - 0

Donald Hargrove, On Behalf of: OGE Energy - Oklahoma Gas and Electric Co., , Segments 1, 3, 5, 6

- 0 - 0

ISO/RTO Council Standards Review Committee, Segment(s) 2, 4/13/2015

- 0 - 0

Texas RE recommends reviewing the Guideline and Technical basis and the Background section as it references CIP-001-1a, which is retired.  Texas RE noticed that the IRO-009 references the IROL violation report in EOP-004-1 but is not in EOP-004-2.

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

- 0 - 0

BPA supports the following recommendation under Definitions: Do any of the defined terms used within the Reliability Standard need to be refined?
Yes
The EOP PRT recommends review by the future SDT of the term “load” in EOP-004-2 and revise to “Load” if the future SDT determines “load” is intended to be the defined term “Load3,” and to review the term for conflict with applicable entity (Load is not a physical end use device, but the existence of the capability to deliver electric energy – MW reduction).

Andrea Jessup, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

- 0 - 0

The PRT is recommending that the future SDT review the evidence retention periods but has not specified exactly which portion or given any reason why they need to be reviewed. What is the PRT recommending for this section and what is their reasoning?

Sergio Banuelos, On Behalf of: Tri-State G and T Association, Inc., MRO, WECC, Segments 1, 3, 5

- 0 - 0

Leo Staples, On Behalf of: Leo Staples, , Segments 1, 3, 5, 6

- 0 - 0

SRP disagrees with the EOP PRT's recommendation to revise the term "load" to "Load". The interpretation of "Load" is not consistent with the definition in the NERC Glossary of Terms. If the PRT is recommending to adjust the definition in the NERC Glossary, that can be pursued. However, SRP recommends refraining from creating a distinct definition for "Load" for this standard that differs from the definition in the NERC Glossary. Standard specific definitions lead to confusion of when to use the definition from the NERC Glossary and the definition in the standard.

Joshua Andersen, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

- 0 - 0

LADWP requests clarification on what a “unique task” will be defined as in the RSAW, maybe even add it to a future version of the NERC Glossary of Terms.

minh pham, On Behalf of: Los Angeles Department of Water and Power, WECC, Segments NA - Not Applicable

- 0 - 0

Terri Pyle, On Behalf of: OGE Energy - Oklahoma Gas and Electric Co., , Segments 1, 3, 5, 6

- 0 - 0