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

2015-08 Emergency Operations SAR

Description:

Start Date: 07/21/2015
End Date: 08/19/2015

Associated Ballots:

Ballot Name Project Standard Pool Open Pool Close Voting Start Voting End

Filter:

Hot Answers

In regard to the Project 2015-02 PRT's recommendations, BPA disagrees with:

1 - EOP-004: R1 VSL change increase

2 - EOP-004 Attachment 1: eliminating GOP from reporting, BPA believes it should be by initiating BA or initiating GOP. If a major plant has an internal problem and trips the GOP should do the investigation (not the BA).

3 - EOP-005: Page 5 "#2 Clarity" (version 2 R5 already uses “implementation date”), with  R6 change.

4 - EOP-005: elimination of “Blackstart Resources”from  R7 & R8.  

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

- 0 - 0

EOP-004 – agree with retiring R3 (annual validation of contacts listed in event reporting operating plan) and with suggested changes throughout the standard (providing clarity for who is responsible for reporting)

 

EOP-005 – Agree with the EOP PRT to not retire R12 as it is not duplicative with PER-005-1 R3.

                    Agree with including R7 and R8 into R1

                    Agree with removing R3.1 which was retired by FERC on 1/21/14

                    Agree that R10 could possibly be moved to the PER standards if R12 remains in EOP-005

 

EOP-006 – neutral on retiring R1.2, R1.3, and R1.4 due to redundancy with R1.5

                    Agree with not retiring R10 as it is not captured in PER-005

                    Agree with including R7 and R8 into R1

                    Neutral on recommendation to add time frame for R4 (review of neighboring RC restoration plans)

                    Agree that R9 could possibly be moved to the PER standards if R10 remains in EOP-006

Agree more precise expectations should be included in R10.1 (GOPs must participate in RC training exercise…), would prefer that only black start GOPs must attend the RC restoration training drills

 

EOP-008 – Agree with adding clarity to timing or removing the statement in R1.1

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

- 0 - 0

Other Answers

Dominion NCP, Segment(s) 5, 6, 1, 3, 4/8/2014

- 0 - 0

MRO-NERC Standards Review Forum (NSRF), Segment(s) 3, 4, 5, 6, 1, 2, 5/13/2015

- 0 - 0

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

- 0 - 0

We generally agree with the proposed scope, but would reiterate the following concerns/suggestions which we submitted when we commented on the initial posting of the PRT’s recommendations. We propose that these concerns/suggestions be duly considered during standard drafting:

a.      EOP-004

(IESO comment)  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:

·   The lack of clarity can result in registered entities being found potentially noncompliant 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.

·   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.

·   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. (End of IESO comment)

In the response to comment, the PRT indicates that:

[The EOP PRT will recommend in the SAR for the future drafting team to review recommendations based on the comments received for Attachment 1, but will not suggest specific rewrites. The EOP PRT believes all recommendations have merit and need a thorough review by the future SDT when formed for this standard.]

Also, in the redline recommendations, the PRT proposes that:

[“…Attachment 1 - The EOP PRT recommends the future Standard Drafting Team (SDT) conduct a thorough review of Attachment 1 and consider the following revisions to Attachment 1 for clarity, such as…”;  and “…differing regional data submittal requirements when reviewing EOP-004-2 for revisions.”]

The SAR does not provide any details or specificities on which parts of Attachment 1 will be revised. It is unclear whether or not our specific comments/suggestions will be addressed during the standard drafting phase. We therefore urge the SDT to carefully consider the above comments/suggestions, as proposed in the PRT’s response.

b.      EOP-005

Again, we’d like to reiterate our previous comments below since the SAR does not provide any details or specificities on the treatment to the concerned requirement (R10), in the revised EOP-005 standard, or any other standard that this requirement will be mapped into:

(IESO comment) We do not agree with the proposal to retire Requirement R10 as we do not believe this requirement is duplicative of any requirements in PER-005-2.

We assess that the Independent Expert Panel’s recommendation to retire R10 was based on its assessment that this requirement was duplicative of R3 of PER-005-1, which stipulates that:

R3. At least every 12 months each Reliability Coordinator, Balancing Authority and Transmission Operator shall provide each of its System Operators with at least 32 hours of emergency operations training applicable to its organization that reflects emergency operations topics, which includes system restoration using drills, exercises or other training required to maintain qualified personnel.

This recommendation appeared to be appropriate at that time. However, in PER-005-2 (revised from PER-005-1), the requirement to provide system restoration training no longer exists. In fact, the rationale to remove the minimum training requirement specific to system restoration from PER-005-1 was in part based on the existence of Requirement R10 in EOP-005-2 (and R9 in EOP-006-2).

If Requirement R10 in EOP-005 is removed, then there will not be any requirements to provide system restoration training to operating personnel in any standards. We therefore suggest that this requirement be retained. (End of IESO comment)

Note that the PRT’s response (below) essentially agree with our concern, but the SAR does not provide any clear indication as to the proposed treatment to Requirement R10.

[The EOP PRT does not find that there is adequate justification providing annual system restoration training for System Operators in another standard. Therefore, the EOP PRT recommends that the future SDT evaluate moving R10 into the PER family of standards; and if unable, Requirement R10 will be maintained in EOP‐005.]

c.       EOP-006

Similar to EOP-005, we had a concern with the proposed retirement of Requirement R9. Therefore, we are reiterating our comments on EOP-006, below for the SDT’s consideration:

(IESO comment) We agree with the proposed retirement of Parts R1.2, R1.3 and R1.4, but do not agree with retiring Requirement R9 (which mirrors R10 in EOP-005-2) as we do not believe this requirement is duplicative of any requirements in PER-005-2.

Similar to our comments on the proposed retirement of R10 in EOP-005-2, we assess that the Independent Expert Panel’s recommendation to retire R9 in EOP-006-2 was based on its assessment that this requirement was duplicative of R3 in PER-005-1, which stipulates that:

R3. At least every 12 months each Reliability Coordinator, Balancing

Authority and Transmission Operator shall provide each of its System Operators with at least 32 hours of emergency operations training applicable to its organization that reflects emergency operations topics, which includes system restoration using drills, exercises or other training required to maintain qualified personnel.

The recommendation to retire R9 of EOP-006-2 appeared to be appropriate at that time. However, in PER-005-2 (revised from PER-005-1), the requirement to provide system restoration training to RC operating personnel no longer exists. In fact, the rationale to remove the minimum training requirement specific to system restoration from PER-005-1 was in part based on the existence of Requirement R10 in EOP-005-1, and R9 in EOP-006-2.

If Requirement R9 in EOP-006-2 is removed, then there will not be any requirement to provide system restoration training to operating personnel. We therefore suggest that this requirement be retained.

The PRT’s response is essentially the same as its response to our comment on EOP-005; hence it’s not repeated here.

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

- 0 - 0

ERCOT agrees with the scope, but reiterates its comments and the SRC's comments on the results of the periodic review as well as the SRC's comments on the SAR.

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

- 0 - 0

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

- 0 - 0

Dominion - RCS, Segment(s) 1, 6, 3, 5, 4/6/2015

- 0 - 0

The SRC generally agrees with the proposed scope, but, as it was unclear through the PRT’s responses to comments whether or how such comments would be addressed by the SDT, the SRC would reiterate the following concerns/suggestions that were submitted as comments by the SRC on the initial posting of the PRT’s recommendations. The SRC requests that these concerns/suggestions be duly considered during standard drafting:

a.  EOP-004

The SRC reiterates that the requirement to report loss of load is not needed for reliability, unlike their interruption to BES facility counterparts. 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. The SRC, therefore, suggests 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 through other regulatory authorities. If for whatever reasons the loss of load reporting requirement is retained in Attachment 1, the SRC requests that the SDT seek input from the NERC technical committees 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.

b. EOP-005

The SRC does not agree with the proposal to retire Requirement R10 as the Independent Expert Panel’s recommendation to retire R10 was based on its assessment that this requirement was duplicative of R3 of PER-005-1, which stipulates that:

R3. At least every 12 months each Reliability Coordinator, Balancing Authority and Transmission Operator shall provide each of its System Operators with at least 32 hours of emergency operations training applicable to its organization that reflects emergency operations topics, which includes system restoration using drills, exercises or other training required to maintain qualified personnel.

This recommendation appeared to be appropriate at that time. However, in PER-005-2 (revised from PER-005-1), the requirement to provide system restoration training no longer exists.  If Requirement R10 in EOP-005 is removed, then there will not be any requirements to provide system restoration training to operating personnel in any standards. We therefore suggest that this requirement be retained.

c. EOP-006

Similar to EOP-005, the SRC had a concern with the proposed retirement of Requirement R9. Our comments on EOP-006 are, therefore, reiterated for the SDT’s consideration. 

The SRC does not agree with the proposal to retire Requirement R9 as the Independent Expert Panel’s recommendation to retire R9 was based on its assessment that this requirement was duplicative of R3 of PER-005-1, which stipulates that:

R3. At least every 12 months each Reliability Coordinator, Balancing Authority and Transmission Operator shall provide each of its System Operators with at least 32 hours of emergency operations training applicable to its organization that reflects emergency operations topics, which includes system restoration using drills, exercises or other training required to maintain qualified personnel.

This recommendation appeared to be appropriate at that time. However, in PER-005-2 (revised from PER-005-1), the requirement to provide system restoration training no longer exists.  If Requirement R9 in EOP-005 is removed, then there will not be any requirements to provide system restoration training to operating personnel in any standards. We therefore suggest that this requirement be retained.

 

 

ISO/RTO Council Standards Review Committee, Segment(s) 2, 5/11/2015

- 0 - 0

Scott Langston, On Behalf of: Tallahassee Electric (City of Tallahassee, FL), , Segments 1, 3, 5

- 0 - 0

Karen Webb, On Behalf of: Karen Webb, , Segments 1, 3, 5

- 0 - 0

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

- 0 - 0

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

- 0 - 0

Texas RE agrees that clarifications included in the periodic review should be a starting point for improvement of the Reliability Standrads listed.  Texas RE encourages the SDT selected to review comments in terms of ensuring reliability and clarifying references and requirements.

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

- 0 - 0

Our review team agrees with the scope of this project however, we would suggest to the drafting team to make sure they have implemented a strong differentiation process on what needs to be retired or proposed/recommended for all the standards involved in this project. In the past, there has been confusion in the voting process to where one project has an affliation with other projects in the Stanard Development Process and a negative vote has delayed the entire project due to small details not being communicated effectively. Additionally, we would suggest using the approach taken by the Alignment of Terms Drafting Team (Project 2015-04). They submitted twenty-six terms to be voted on however, the industry had to vote on each individual term. So if the industry voted no for one term or terms, it would call for an re-evaluation for those particular term(s) and not cause a delay to the entire project (unless the changes were significant enough). 

SPP Standards Review Group, Segment(s) , 8/19/2015

- 0 - 0

John Williams, On Behalf of: John Williams, , Segments 1, 3, 5

- 0 - 0

We have the following concerns for EOP-004:

There is a need to clarify the obligations of the Responsible Entities listed in Attachment 1.

On page 10 of EOP-004-2, when there is a loss of firm load ≥300 MW for entities with a previous year’s demand ≥3,000 MW, or ≥200 MW for all other entities, the BA, TOP or DP is held responsible for reporting. It is unclear as to the MW in relation to which particular entity’s previous year’s demand, 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? If all three are obligated to report, the requirement makes it cumbersome and redundant to have all three entities file reports to the recipient entities/authorities.

NPCC--Project 2015-08, Segment(s) 10, 3, 2, 1, 9, 6, 5, 8, 8/19/2015

- 0 - 0

ACES Standards Collaborators - EOP Project, Segment(s) 1, 4, 5, 3, 8/19/2015

- 0 - 0

Hot Answers

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

- 0 - 0

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

- 0 - 0

Other Answers

Dominion NCP, Segment(s) 5, 6, 1, 3, 4/8/2014

- 0 - 0

MRO-NERC Standards Review Forum (NSRF), Segment(s) 3, 4, 5, 6, 1, 2, 5/13/2015

- 0 - 0

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

- 0 - 0

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

- 0 - 0

ERCOT agrees with the functional assignments, but reiterates its comments submitted in response to the periodoc review recommendations that redundancy across functions is inefficient and onerous and should be re-evaluated.

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

- 0 - 0

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

- 0 - 0

Dominion - RCS, Segment(s) 1, 6, 3, 5, 4/6/2015

- 0 - 0

ISO/RTO Council Standards Review Committee, Segment(s) 2, 5/11/2015

- 0 - 0

Scott Langston, On Behalf of: Tallahassee Electric (City of Tallahassee, FL), , Segments 1, 3, 5

- 0 - 0

Karen Webb, On Behalf of: Karen Webb, , Segments 1, 3, 5

- 0 - 0

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

- 0 - 0

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

- 0 - 0

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

- 0 - 0

SPP Standards Review Group, Segment(s) , 8/19/2015

- 0 - 0

John Williams, On Behalf of: John Williams, , Segments 1, 3, 5

- 0 - 0

NPCC--Project 2015-08, Segment(s) 10, 3, 2, 1, 9, 6, 5, 8, 8/19/2015

- 0 - 0

ACES Standards Collaborators - EOP Project, Segment(s) 1, 4, 5, 3, 8/19/2015

- 0 - 0

Hot Answers

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

- 0 - 0

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

- 0 - 0

Other Answers

Dominion NCP, Segment(s) 5, 6, 1, 3, 4/8/2014

- 0 - 0

MRO-NERC Standards Review Forum (NSRF), Segment(s) 3, 4, 5, 6, 1, 2, 5/13/2015

- 0 - 0

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

- 0 - 0

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

- 0 - 0

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

- 0 - 0

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

- 0 - 0

Dominion - RCS, Segment(s) 1, 6, 3, 5, 4/6/2015

- 0 - 0

ISO/RTO Council Standards Review Committee, Segment(s) 2, 5/11/2015

- 0 - 0

Scott Langston, On Behalf of: Tallahassee Electric (City of Tallahassee, FL), , Segments 1, 3, 5

- 0 - 0

Karen Webb, On Behalf of: Karen Webb, , Segments 1, 3, 5

- 0 - 0

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

- 0 - 0

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

- 0 - 0

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

- 0 - 0

SPP Standards Review Group, Segment(s) , 8/19/2015

- 0 - 0

John Williams, On Behalf of: John Williams, , Segments 1, 3, 5

- 0 - 0

NPCC--Project 2015-08, Segment(s) 10, 3, 2, 1, 9, 6, 5, 8, 8/19/2015

- 0 - 0

ACES Standards Collaborators - EOP Project, Segment(s) 1, 4, 5, 3, 8/19/2015

- 0 - 0

Hot Answers

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

- 0 - 0

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

- 0 - 0

Other Answers

Dominion NCP, Segment(s) 5, 6, 1, 3, 4/8/2014

- 0 - 0

MRO-NERC Standards Review Forum (NSRF), Segment(s) 3, 4, 5, 6, 1, 2, 5/13/2015

- 0 - 0

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

- 0 - 0

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

- 0 - 0

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

- 0 - 0

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

- 0 - 0

Dominion - RCS, Segment(s) 1, 6, 3, 5, 4/6/2015

- 0 - 0

ISO/RTO Council Standards Review Committee, Segment(s) 2, 5/11/2015

- 0 - 0

Scott Langston, On Behalf of: Tallahassee Electric (City of Tallahassee, FL), , Segments 1, 3, 5

- 0 - 0

Karen Webb, On Behalf of: Karen Webb, , Segments 1, 3, 5

- 0 - 0

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

- 0 - 0

Without knowing the extent of the changes that will incur from this project, we are unable to provide specific examples of business practices that will be needed, or will need modification as a result of this project. However, it can be reasonably inferred that some business practices such as notification protocols, as well as operational procedures are going to need some modification depending on the extent of the revisions proposed.

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

- 0 - 0

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

- 0 - 0

SPP Standards Review Group, Segment(s) , 8/19/2015

- 0 - 0

John Williams, On Behalf of: John Williams, , Segments 1, 3, 5

- 0 - 0

NPCC--Project 2015-08, Segment(s) 10, 3, 2, 1, 9, 6, 5, 8, 8/19/2015

- 0 - 0

ACES Standards Collaborators - EOP Project, Segment(s) 1, 4, 5, 3, 8/19/2015

- 0 - 0

Hot Answers

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

- 0 - 0

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

- 0 - 0

Other Answers

Dominion NCP, Segment(s) 5, 6, 1, 3, 4/8/2014

- 0 - 0

MRO-NERC Standards Review Forum (NSRF), Segment(s) 3, 4, 5, 6, 1, 2, 5/13/2015

- 0 - 0

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

- 0 - 0

The Ontario Energy Board (Ontario energy regulator) has in place electricity reporting requirements for Ontario distribution providers.  Loss of Supply is an electricity reporting requirement that is filed by Ontario distribution providers to the Ontario Energy Board (and not the Ontario IESO which is the RC, BA and TOP for the Ontario integrated grid).

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

- 0 - 0

The Public Utility Commission of Texas has both emergency and outage reporting forms and requirements.

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

- 0 - 0

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

- 0 - 0

Dominion - RCS, Segment(s) 1, 6, 3, 5, 4/6/2015

- 0 - 0

The Ontario Energy Board (Ontario energy regulator) has in place electricity reporting requirements for Ontario distribution providers.  Loss of Supply is an electricity reporting requirement that is filed by Ontario distribution providers to the Ontario Energy Board.

The Public Utility Commission of Texas has both emergency and outage reporting forms and requirements.

ISO/RTO Council Standards Review Committee, Segment(s) 2, 5/11/2015

- 0 - 0

Scott Langston, On Behalf of: Tallahassee Electric (City of Tallahassee, FL), , Segments 1, 3, 5

- 0 - 0

Karen Webb, On Behalf of: Karen Webb, , Segments 1, 3, 5

- 0 - 0

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

- 0 - 0

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

- 0 - 0

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

- 0 - 0

SPP Standards Review Group, Segment(s) , 8/19/2015

- 0 - 0

John Williams, On Behalf of: John Williams, , Segments 1, 3, 5

- 0 - 0

An effort to coordinate Event Reporting obligations across agencies should be undertaken. Currently, entities are required to report to NERC and to the DOE, potentially in different time frames and with a different level of detail. If these could be made more consistent moving forward, it would reduce the administrative burdens associated with Event Reporting. This should be added to the scope of the SAR for consideration.

The Ontario Energy Board (Ontario energy regulator) has in place electricity reporting requirements for Ontario distribution providers.  Loss of Supply is an electricity reporting requirement that is filed by Ontario distribution providers to the Ontario Energy Board (and not the Ontario IESO which is the RC, BA and TOP for the Ontario integrated grid).

NPCC--Project 2015-08, Segment(s) 10, 3, 2, 1, 9, 6, 5, 8, 8/19/2015

- 0 - 0

ACES Standards Collaborators - EOP Project, Segment(s) 1, 4, 5, 3, 8/19/2015

- 0 - 0

Hot Answers

N/A

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

- 0 - 0

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

- 0 - 0

Other Answers

Dominion NCP, Segment(s) 5, 6, 1, 3, 4/8/2014

- 0 - 0

The NSRF has reviewed the Project page containing the proposed redlined to last approved Standards and believes this is a good starting point for the SDT to complete this project.

MRO-NERC Standards Review Forum (NSRF), Segment(s) 3, 4, 5, 6, 1, 2, 5/13/2015

- 0 - 0

none

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

- 0 - 0

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

- 0 - 0

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

- 0 - 0

The purpose/goal for the SAR associated with Project 2015-08 (Emergency Operations) states in part “…implement the recommendations of the Project 2015-02 EOP PRT to revise EOP-004-2, EOP-005-2, EOP-006-2, and EOP-008-1”.  Page 4 of the Project 2015-02 EOP PRT report on PRC-005-2 has a list of items for consideration.  Our comments below are in response to some of the recommendations made in this report.

Item b states that “the EOP PRT recommends the future SDT consider findings from any future-published reports as they relate to EOP-005-2.” We also suggest reaching out to the North American Transmission Forum for input as appropriate.

Item h states that “the EOP PRT recommends the future SDT review Requirement R6 for clarification of the terms “steady state” and “dynamic simulations, including considering the addition of a Rationale Box.” We believe there is need for practicality regarding the addition of a Rational Box to clarify dynamic simulations . System restoration is not defined as restoring power to each and every load. Rather, EOP-005-2 R1 uses practical language which states that the completion of system restoration is “…a state whereby the choice of the next Load to be restored is not driven by the need to control frequency or voltage…”.

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

- 0 - 0

Dominion - RCS, Segment(s) 1, 6, 3, 5, 4/6/2015

- 0 - 0

ISO/RTO Council Standards Review Committee, Segment(s) 2, 5/11/2015

- 0 - 0

Scott Langston, On Behalf of: Tallahassee Electric (City of Tallahassee, FL), , Segments 1, 3, 5

- 0 - 0

Karen Webb, On Behalf of: Karen Webb, , Segments 1, 3, 5

- 0 - 0

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

- 0 - 0

While Duke Energy supports the project, we have concerns for the potential of “scope creep” due to the broad implications of the EOP-004 attachment on the requirements of reporting. There could be potential for the Drafting Team to become bogged down in trying to coordinate between Event Analysis reporting and OE-417 reporting. The Drafting Team should be given clear direction on what needs to be modified as part of the project.

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

- 0 - 0

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

- 0 - 0

SPP Standards Review Group, Segment(s) , 8/19/2015

- 0 - 0

John Williams, On Behalf of: John Williams, , Segments 1, 3, 5

- 0 - 0

In the Detailed Description section of the SAR, the sentence “There are no market interface impacts resulting from the standard action on the implementation of the Project 2015-02, EOP PRT’s recommendations.” should be revised.  There are no direct impacts to the market interface from “the standard action on the implementation of the Project 2015-02, EOP PRT’s recommendations.”  

“The EOP Periodic Review Team (EOP PRT) is recommending that the future Standards Drafting Team (SDT) revise Requirement 1 part R1.1 to provide clarity, as the team determined it would be difficult to establish a timing requirement to restore primary control center functionality given the range of events that could render the primary control center inoperable”.  Considering a system reliability need for generation, there are entities that have market interface equipment in their primary control center only.  If the primary control center becomes inoperable it will have an effect on how fast an entity is able to get generation online in order for support.  Please change the language to “direct impacts” instead.

It is recognized that continued operation of a market is not a reliability issue; in this situation, manual dispatch should continue to occur.

Suggest that any update to EOP-004-2 should include a re-synchronization of the EOP-004’s Attachment 1 (Reportable Events) with the list of Categories in the ERO’s Event Analysis Process – Version 3 document.  Any change to EOP-004 going forward should consider the latest version of the EAP.

NPCC--Project 2015-08, Segment(s) 10, 3, 2, 1, 9, 6, 5, 8, 8/19/2015

- 0 - 0

We recommend that the drafting team consider whether there are opportunities to carve out lower risk entities from the applicability section in the standard.  This would be consistent with the approaches of the Risk Based Registration initiative by right-sizing compliance responsibilities for low-risk entities.

ACES Standards Collaborators - EOP Project, Segment(s) 1, 4, 5, 3, 8/19/2015

- 0 - 0