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2015-02 EOP Periodic Review | EOP-005-2

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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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Joshua Andersen, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 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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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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Maryclaire Yatsko, On Behalf of: Seminole Electric Cooperative, Inc., FRCC, Segments 1, 3, 4, 5, 6

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

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NPCC Proj 2015-02 EOP-005-2, Segment(s) 10, 3, 2, 1, 9, 6, 5, 8, 5/11/2015

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

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PSEG, Segment(s) 1, 3, 5, 6, 5/11/2015

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

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

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

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

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

HYDRO ONE NETWORKS INC. Comment_Report_EOP0052.docx

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

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PPL NERC Registered Affiliates, Segment(s) 3, 1, 5, 6, 5/11/2015

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

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

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

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Leo Staples, On Behalf of: Leo Staples, , 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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Brad Ryan, On Behalf of: Berkshire Hathaway - PacifiCorp - WECC - Segments 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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Joshua Andersen, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 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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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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Maryclaire Yatsko, On Behalf of: Seminole Electric Cooperative, Inc., FRCC, Segments 1, 3, 4, 5, 6

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

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NPCC Proj 2015-02 EOP-005-2, Segment(s) 10, 3, 2, 1, 9, 6, 5, 8, 5/11/2015

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

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PSEG, Segment(s) 1, 3, 5, 6, 5/11/2015

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

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

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

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

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

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

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PPL NERC Registered Affiliates, Segment(s) 3, 1, 5, 6, 5/11/2015

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

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

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

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Leo Staples, On Behalf of: Leo Staples, , 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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Brad Ryan, On Behalf of: Berkshire Hathaway - PacifiCorp - WECC - Segments 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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SRP does not support the recommendation to retire R10.  EOP-005-2 is applicable to Distribution Providers, wheras PER-005-2 is not.  The retirement of that requirement would lead to a reliability gap.  SRP recommends retaining R10 in EOP-005-2.

Joshua Andersen, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 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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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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CSU agrees with the recommendations of the IERP for retirement of requirements.  All requirements that the IERP recommended retiring need to be retired.

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

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Maryclaire Yatsko, On Behalf of: Seminole Electric Cooperative, Inc., FRCC, Segments 1, 3, 4, 5, 6

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

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AEP agrees that the 90 day window within Requirement R4 needs clarification, specifically, that the plan be updated before the system modification. As part of this effort, the drafting team might consider incorporating the window into R4 itself, rather than as a sub requirement.

AEP believes that “Effective Date” should be used within R5.
 

AEP recommends modifying R7 to remove the “restoration plan” redundancy. For example, revising it to state “Following a Disturbance in which one or more areas of the BES shuts down, *pursuant to Requirement R1*, each affected Transmission Operator shall implement its restoration plan.”

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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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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  • ATC disagrees with the Periodic Review Team’s recommendation that Requirement # 6 be modified with a rationale statement requiring monitoring specific parameters within a dynamic simulation.  Requirement 6.2 already states that voltage and frequency will be controlled within levels.

 

·       ATC has a concern with the Periodic Review Teams recommendation to significantly extend the burden of the dynamic analyses related to R6.  The Periodic Review Team’s wording suggests a dynamic study time extension beyond the transient time period studies of 15 – 25 seconds to a midterm type study which may require an additional mid-term study package.  ATC suggest that the Periodic Review team clarify its position on whether it needs more time than the typical dynamic study timeframe or whether the drafting team was referring to additional studies rather than the time length in seconds of the dynamic studies.

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

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Regarding Item a. on page 4--The Drafting Team should not only consider clarifying the 90 calendar days, but should also consider revising Requirement R4 to eliminate the “unplanned” and “planned” wording.  A suggested revision:

…after identifying any BES physical or operating modification that would change the implementation of its restoration plan.

The Drafting Team should consider developing a formal definition for restoration plan for inclusion in the NERC Glossary.

Item b.--Agree. 

Item c.--Agree.

Item d.--Agree.

Item e.--Agree.  In the proposed Rationale Box, it should be explained that dynamic simulations should be done for System changes within a specified time frame.  This may require the addition of a Part to requirement R6, or a revision to requirement R4.

Item f.--Agree.

Item g.--Agree.

Item h.--Agree.

Item i.--Agree.

Item j.--Agree.

NPCC Proj 2015-02 EOP-005-2, Segment(s) 10, 3, 2, 1, 9, 6, 5, 8, 5/11/2015

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

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PSEG, Segment(s) 1, 3, 5, 6, 5/11/2015

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Regarding Item a.--The Drafting Team should not only consider clarifying the 90 calendar days, but should also consider revising the requirement to eliminate the “unplanned” and “planned” wording.  A suggested revision:

…after identifying any System modification that would change the implementation of its restoration plan.

Item b.--Agree.  

Item c.--Agree.

Item d.--Agree.

Item e.--Agree.  In the proposed Rationale Box, it should be explained that dynamic simulations should be done for System changes within a specified time frame.  This may require the addition of a Part to requirement R6, or a revision to requirement R4.

Item f.--Agree.

Item g.--Agree.

Item h.--Agree.

Item i.--Agree.

Item j.--Agree.

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

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

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(1)   We disagree with the recommendation to add a rationale box to the standard.  The PRT recommendations should either be to substantively change the content, add an application guideline section, or issue a guidance document outside the standards development process.  Rationale boxes are removed from the standard after they become finalized.  Adding a guideline section would be a better option.

(2)   We also disagree with the PRT’s recommendation to strike “Blackstart Resources” and replace it with “the restoration plan, pursuant to R1.”  The title of this standard is “System Restoration from Blackstart Resources.”  Why is the team considering removing the underlying purpose of the standard?

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

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

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

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

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These comments are submitted on behalf of the following PPL NERC Registered Affiliates: LG&E and KU Energy, LLC; PPL Electric Utilities Corporation, PPL EnergyPlus, LLC; PPL Generation, LLC; PPL Susquehanna, LLC; and PPL Montana, LLC. The PPL NERC Registered Affiliates are registered in six regions (MRO, NPCC, RFC, SERC, SPP, and WECC) for one or more of the following NERC functions: BA, DP, GO, GOP, IA, LSE, PA, PSE, RP, TO, TOP, TP, and TSP.

We do not agree with the PRT’s recommendation to add the proposed rationale box to R6.  Specifically, we do not agree with the first sentence of the rationale box that “Dynamic simulations should simulate your frequency and voltage response beyond the transient period of time” assuming that the “transient period of time” is referring to the dynamic simulation associated with bringing the first blackstart unit online.  Dynamic simulations are not necessary after this initial simulation as a steady state study can be performed, increasing load/generation in pre-determined amounts, to verify the system restoration plan.

PPL NERC Registered Affiliates, Segment(s) 3, 1, 5, 6, 5/11/2015

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

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R6, R7 and R8:  We agree with the PRT comments for future SDT language only because R6, R7 and R8 refer to the restoration plan as developed in R1 which specifies an area of the BES is shut down and Blackstart resources are required to restore the shut down area to service.

R4:  We am neutral on the PRTs comments.  We're not aware of confusion regarding the 90 calendar days to send in a revised restoration plan to the RC if the modifications change the TOPs restoration plan.  Although one could argue when the 90 days starts – after permanent changes are made or after they are expected to be permanent or …???

R18:  although not mentioned in the PRT comments, it is suggested that the requirement be specific for Gen Operators with black start resources.  A similar comment will be made for EOP-006-2.

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

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Texas RE does not agree with retiring Requirement R10.  See item number two.

Texas RE is inquiring if the Periodic Review Team reached out to the EEI, APPA, BPA, and NERC to understand more about “unique tasks”?

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

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

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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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BPA disagrees with (e) regarding R6 as there are too many variations in a networked system to do a dynamic simulation beyond the transient time.  BPA also disagrees with (f) regarding R7, and (g) regarding R8 - the Standard’s purpose is written for “…Restoration from Blackstart Resources..” and the PRT is wording exceeds that with the elimination wording.

 

BPA agrees with the rewrite of M5.   

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

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Leo Staples, On Behalf of: Leo Staples, , 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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Brad Ryan, On Behalf of: Berkshire Hathaway - PacifiCorp - WECC - Segments 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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PER-005-2 does not call for the training on blackstart procedures. Only if identified by the entity as a reliability related task would the system operators receive training. Additionally, removal of this requirement would create a gap with DPs that are part of a TOP restoration plan as PER-005-2 is not applicable to the DP registration.  

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

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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Please note that Systematic Approach to Training is based on the entity’s BES Reliability Related Tasks.  The EOP PRT has made a good point that R10 is duplicative.

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

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Yes this should be retired.

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

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Maryclaire Yatsko, On Behalf of: Seminole Electric Cooperative, Inc., FRCC, Segments 1, 3, 4, 5, 6

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

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R10 should not be retired unless the training of plant operators is included in PER-005-2.  Please reference PER-005-2, 4.1.5.1, where it states…

Generator Operator that has:
 

4.1.5.1 Dispatch personnel at a centrally located dispatch center who receive direction from the Generator Operator’s Reliability Coordinator, Balancing Authority, Transmission Operator, or Transmission Owner, and may develop specific dispatch instructions for plant operators under their control. These personnel do not include plant operators located at a generator plant site or personnel at a centrally located dispatch center who relay dispatch instructions without making any modification.

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 PRT’s recommendation to retire the training requirements in R10 as duplicative of the training program requirements established in PER-005-2.

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

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We do not agree that EOP-005 R10 is redundant with the PER-005-2. The mapping of PER-005-1 R3 to PER-005-2 R4 is specific to RCs, BAs, TOPs, and TOs that have operational authority or control over Facilities with "established IROLs", or has "established protection systems or operating guides to mitigate IROL violations", shall use simulation technology. The intent of PER-005-2 R4 is the implementation of simulation technology to train on IROLs if the entity meets criteria "(1) and (2)" of R4, NOT to train on "system restoration".

PER-005-2 R4 does not address the "annual" training on system restoration. System restoration may have to be performed as the result of an IROL, but system restoration training is different than training on IROLs. Also, an entity may use simulation technology as part of their training program to train on system restoration, but it is not required in EOP-005-2 R10.

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

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

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ERCOT does not agree with the proposal to retire Requirement R10 as it is not duplicative of any requirements in PER-005-2 since its revision.   Specifically, 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. ERCOT, therefore, suggests that this requirement be retained.

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

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

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NPCC Proj 2015-02 EOP-005-2, Segment(s) 10, 3, 2, 1, 9, 6, 5, 8, 5/11/2015

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

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PSEG, Segment(s) 1, 3, 5, 6, 5/11/2015

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

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

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(1)   We agree that R10 should be retired.  This is already covered in PER-005-2 systematic approach to training.

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

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

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

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

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PPL NERC Registered Affiliates, Segment(s) 3, 1, 5, 6, 5/11/2015

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

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R10:  We disagree with the PRT retirement recommendation for R10.  System restoration is a very low probability high risk scenario with tremendous implications to the BES.  As such, specific training is necessary to be identified.  There is no requirement within proposed PER-005-2 to annually train on restoration.

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

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Texas RE does not agree with retiring Requirement R10.  Requirement R10 specifically requires training for Blackstart and other system-restoration processes.  The EOP PRT suggests that these duties are covered by the upcoming PER-005-2 Standard.  While the PER-005-2 standard does require that personnel be trained for normal and emergency operations of the BES, PER-005-2 does not require any specific type of training in regards to Blackstart/system-restoration. This is problematic because the PER-005-2 standard does not directly replace EOP-005-2 R10, and leaves potential gaps when determining compliance.  Registered Entities could be allowed to forgo Blackstart training, while still being compliant with PER-005-2.  The requirement to perform Blackstart training will be lost if EOP-005-2, R10 is retired.

Texas RE is concerned that gaps in training could occur since entities would not have to specifically comply with the subrequirements of R10, which are necessary to understand if system restoration is needed. If a company does not consider the R10 items as ““BES company-specific Real-time reliability-related tasks” per PER-005-2, compliance may be met but reliability will suffer.

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

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SCE&G agrees with SERC OC's comments:

We do not agree that EOP-005 R10 is redundant with the PER-005-2. The mapping of PER-005-1 R3 to PER-005-2 R4 is specific to RCs, BAs, TOPs, and TOs that have operational authority or control over Facilities with "established IROLs", or has "established protection systems or operating guides to mitigate IROL violations", shall use simulation technology. The intent of PER-005-2 R4 is the implementation of simulation technology to train on IROLs if the entity meets criteria "(1) and (2)" of R4, NOT to train on "system restoration".

PER-005-2 R4 does not address the "annual" training on system restoration. System restoration may have to be performed as the result of an IROL, but system restoration training is different than training on IROLs. Also, an entity may use simulation technology as part of their training program to train on system restoration, but it is not required in EOP-005-2 R10.

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

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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.

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

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

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

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EOP-005-2 R10 requires training to be conducted on the restoration plan, to include many specific items.  If PER-005 is accurately followed, a Training Gap Analysis will discover the need to conduct the exact training that is specified in EOP-005-2 R10.  This requirement should be deleted in future versions of EOP-005.  At a minimum this requirement should be moved to a future PER-005 Reliability Standard in an effort to consolidate all of the Real-Time System Operator training requirements into only one standard.

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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Brad Ryan, On Behalf of: Berkshire Hathaway - PacifiCorp - WECC - Segments 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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Joshua Andersen, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 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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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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CSU agrees with the recommendations of the IERP for retirement of these requirements.  These requirements need to be retired.

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

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Maryclaire Yatsko, On Behalf of: Seminole Electric Cooperative, Inc., FRCC, Segments 1, 3, 4, 5, 6

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R7 calls for implementing the restoration plan when “…in which one or more areas of the BES shuts down and the use of Blackstart Resources is required…”. If the disturbance does not result in one or more areas of the BES shutting down or use of Blackstart Resources there is no expectation that the TOP implement its restoration plan.

R8 – Dominion does not agree with EOP PRT’s recommendation to retain R8. R8 requires the TOP synchronize with neighboring TOP areas “…or in accordance with the established procedures of the Reliability Coordinator”… R1.3 requires the TOP’s restoration plan include Procedures for restoring interconnections with other Transmission Operators under the direction of the Reliability Coordinator. There is no improvement to reliability gained by having the TOP bear compliance burden for both, R1.3and R8. R8 is inferred to be incorporated in R1.3.

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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I agree with the IERP recommendations and reasons except the one for R12. R12 can stay.

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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  • ·        ATC supports the Periodic Review Team’s recommendation to retire Requirements # 10 and all associated Sub-Requirements.

 

The Periodic Review Team does not endorse the recommendations of the Independent Expert Review Project (IERP) to retire Recommendations # 7, 8, and 12.   ATC believes the judgment of the IERP is prudent and, as such, ATC does supports the retirement of Requirements # 7, 8, and 12.

 

  • Requirement # 7 simply requires the “implementation” of the Registered Entity’s “restoration plan” following a Disturbance in which one or more areas of the BES shuts down and the use of Blackstart Resources is required.  ATC agrees with the IERP that implementation of the restoration plan is a logical action that is defined in each Registered Entity’s restoration plan that does not require a stand-alone requirement.
  • ATC believes that Requirements # 8 should be retired,  as recommended by the IERP since it is redundant with R1.3.   R1.3 requires a Transmission Owner to have a restoration plan with accompanying procedures approved by the Reliability Coordinator for restoring interconnections with other Transmission Operators under the direction the Reliability Coordinator.   ATC believes Requirement # 8  essentially requires the same obligations as defined in R1.3 and, as such, Requirement # 8 should be retired.
  • ATC believes Requirement # 12 should be retired, as recommended by the IERP. Requirement # 12 is not about testing the plan but drilling the personnel on execution of the plan.  Therefore, it is ATC’s opinion that Requirement # 12 is a training requirements which is accommodated by Reliability Standard PER-005.

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

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Recommend that Requirements R7 and R8 be incorporated into Requirement R1.  Agree that the already approved industry terminology “develop, maintain and implement” should be incorporated into EOP-005-2.  By adding that terminology in Requirement R1, the language of Requirements R7 and R8 can be moved to Requirement R1.  This is consistent with the structure of other reliability standards [e.g., EOP-001-2.1b R2 (and future successor EOP-011-1, Requirements R1 and R2), EOP-010-1 Requirements R1 and R3, and TOP-004-2 Requirement R6].  Therefore, recommend retiring Requirements R7 and R8, and moving the language of Requirements R7 and R8 into Requirement R1.  Requirement R1 should be revised as follows:

·         The first sentence in Requirement R1 should be revised to state: "Each Transmission Operator shall develop, maintain and implement           a restoration plan that is approved by its Reliability Coordinator.”

·         Part R1.3 should be revised to state: "Procedures for restoring interconnections with other Transmission Operators with authorization             from and under the direction of the Reliability Coordinator."

·         A new part should be added to R1 (best placed as Part R1.9, with the currently effective Part R1.9 renumbered to become Part 1.10).             The new part should state: "Restoration strategies to facilitate restoration if the restoration plan cannot be executed as expected."

NPCC Proj 2015-02 EOP-005-2, Segment(s) 10, 3, 2, 1, 9, 6, 5, 8, 5/11/2015

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

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PSEG, Segment(s) 1, 3, 5, 6, 5/11/2015

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Recommend that Requirements R7 and R8 be incorporated into Requirement R1.  Agree that the already-approved industry terminology “develop, maintain and implement” should be incorporated into EOP-005-2.  By adding that terminology in Requirement R1, the language of Requirements R7 and R8 can be moved to Requirement R1.  This is consistent with the structure of other reliability standards [e.g., EOP-001-2.1b R2 (and future successor EOP-011-1, Requirements R1 and R2), EOP-010-1 Requirements R1 and R3, and TOP-004-2 Requirement R6].  Therefore, recommend retiring Requirements R7 and R8, and moving the language of Requirements R7 and R8 into Requirement R1.  Requirement R1 should be revised as follows:

·         The first sentence in Requirement R1 should be revised to state: "Each Transmission Operator shall develop, maintain and implement a restoration plan that is approved by its Reliability Coordinator.”

·         Part R1.3 should be revised to state: "Procedures for restoring interconnections with other Transmission Operators with authorization from and under the direction of the Reliability Coordinator."

·         A new part should be added to R1 (best placed as Part R1.9, with the currently effective Part R1.9 renumbered to become Part 1.10).  The new part should state: "Restoration strategies to facilitate restoration if the restoration plan cannot be executed as expected."

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

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

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(1)   If there are requirements in a standard that meet Paragraph 81 criteria, which is supported by the Independent Expert Review Panel, the PRT should seriously consider retiring the applicable requirements.  Is the PRT saying that the IERP recommendation to retire the requirements was made without merit?

(2)   Requirements R1.3 and R8 are redundant and we recommend the redundancy be removed.  Requirement R1.3 compels the plan to require RC approval prior to resynchronization and to adhere to that during implementation.  Requirement R8 is the implementation requirement that compels the same thing as R1.3. 

(3)   We disagree with the two-hour training requirement in R11.  It should be defined in terms of what the training must cover, rather than prescribe any amount of time.  It’s isn’t the amount of time that matters; it’s whether the appropriate information is conveyed and understood.

(4)   We do not understand how R12 can be viewed as a testing requirement.  R12 is clearly a training requirement and R6 is clearly a testing requirement.  R6 is intended to test the capability of the plan to make sure it works accordingly.  R12 is intended to ensure that the TOP System Operators are capable of carrying out its plan in coordination with the RC by exercising their capabilities, which is duplicative with PER-005-1 R3 since it deals with training during system restoration using drills and exercises.

(5)  The Requirement R6 recommendation needs to clarify the timeframe of the dynamic study to determine if additional studies are needed.  We have concerns with the drafting team recommendation to significantly extend the burden of the dynamic analyses related to R6.  The drafting team wording suggests a dynamic study time extension beyond the transient time period studies of 15 – 25 seconds to a midterm type study which may require an additional mid-term study package.  We suggest that the drafting team clarify its position on whether it needs more time than the typical dynamic study timeframe or whether the drafting team was referring to additional studies rather than the time length in seconds of the dynamic studies.  The drafting team also appears to be asking for a dynamic study after every load and generation addition which significantly multiplies the number of dynamic studies required.  We suggest the drafting team consider a reliability criteria to distinguish between verifying the ability for the black start plan to perform correctly and the addition of unnecessary dynamic studies.  NERC requirements such as EOP-005-2 R13 are written for separately registered NERC functions.  We request that the drafting team clarify if an entity is registered for more than one NERC registration in a requirement that it is unnecessary to have “internal agreements” within the registered entity.  To require this is duplicative and unnecessarily burdensome, which would meet Paragraph 81 criteria.

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

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

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

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

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PPL NERC Registered Affiliates, Segment(s) 3, 1, 5, 6, 5/11/2015

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We disagree with the PRT’s interpretation that R12 is a testing requirement.  If the PRT feels R12 is a testing requirement, then the PRT should suggest a revision making this clear.  R16 contains testing requirements and appropriate language.  The use of the phrase “drill, exercise, or simulation” in R12 supports the intent of “training” based on the Webster’s definition of “drill”.  Also, operators who participate in drills conducted by the RC typically are awarded Continuing Education Hours associated with an approved ILA.  This also leads us to the conclusion that this participation is more training in nature.  We believe there is also some testing of processes and procedures that occurs, but we disagree that the intent of the requirement is to test.  We recommend the PRT review this conclusion.  R12 is not clearly either a training or testing requirement.  If the intent is for testing, then we recommend the language in R12 be clarified to include what the intent of the testing shall include and if documentation of the test results is required.  If the intent is to ensure TOPs participate in activities designed to ensure familiarity and consistency of execution of the plan, then we believe R12 should be retired as it is redundant with PER-005-1 R3.

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

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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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We recommend that Requirements R7 and R8 be incorporated into Requirement R1.  We agree that the already-approved industry terminology “develop, maintain and implement” should be incorporated into EOP-005-2.  By adding that terminology in Requirement R1, the language of Requirements R7 and R8 can be moved to Requirement R1.  This is consistent with the structure of other reliability standards [e.g., EOP-001-2.1b R2 (and future successor EOP-011-1, Requirements R1 and R2), EOP-010-1 Requirements R1 and R3, and TOP-004-2 Requirement R6].  Therefore, we recommends retiring Requirements R7 and R8, and moving the language of Requirements R7 and R8 into Requirement R1.  Specifically, Requirement R1 should be revised as follows:

·       The first sentence in Requirement R1 should be revised to state: "Each Transmission Operator shall develop, maintain and implement a restoration plan that is approved by its Reliability Coordinator.”

·       Part R1.3 should be revised to state: "Procedures for restoring interconnections with other Transmission Operators with authorization from and under the direction of the Reliability Coordinator."

A new part should be added to R1 (best placed as Part R1.9, with the currently effective Part R1.9 renumbered to become Part 1.10).  The new part should state: "Restoration strategies to facilitate restoration if the restoration plan cannot be executed as expected."

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

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Tri-State agrees with the recommendations for requirements R7 and R12. We also agree that R8 is not duplicative but we're not clear on how the recommendations are meant to improve R8. It seems they are recommending similar language for R8 as the language suggested for R7 but there isn't much to "develop, maintain and implement" since it is just a small part of the plan.

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

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BPA believes the first bullet for the R7 recommendation is not clear: current language does use the word "implement" and this meets the requirement of an action verb.  No change to R7 is required.

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

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Leo Staples, On Behalf of: Leo Staples, , 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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Brad Ryan, On Behalf of: Berkshire Hathaway - PacifiCorp - WECC - Segments 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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Joshua Andersen, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 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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We generally agree with the proposed revisions except the proposed retirement of Requirement R10 as noted under Q2, 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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MRO-NERC Standards Review Forum (NSRF), Segment(s) 3, 4, 5, 6, 1, 2, 4/8/2015

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CSU agrees with the recommendations of the IERP for retirement of requirements.  All requirements that the IERP recommended retiring need to be retired.

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

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Maryclaire Yatsko, On Behalf of: Seminole Electric Cooperative, Inc., FRCC, Segments 1, 3, 4, 5, 6

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

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As stated in our response to question #2, R10 should not be retired unless the training of plant operators is included in PER-005-2.

 

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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Reclamation disagrees with the PRT’s assertion that there is no industry confusion associated with the term “unique tasks” in R11.  Reclamation agrees with the comments submitted by the American Public Power Association, Edison Electric Institute, and Bonneville Power Administration during Federal Energy Regulatory Commission review of EOP-005-2. R11 requires TOPs, as well as Transmission Owners and Distribution Providers, to provide a minimum of two hours of System restoration training every two calendar years to their field switching personnel identified as performing unique tasks associated with the Transmission Operator’s restoration plan that are outside of their normal tasks.  Reclamation recommends that this training requirement be eliminated as encompassed within PER-005-2.  In the alternative, Reclamation recommends that the PRT update its recommendation and the future standards drafting team provide examples of “unique tasks” associated with restoration that may be outside of normal transmission switching tasks for clarification.

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

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No based on answer to questions 2.

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

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(i) Please see comments in the response to Question 3 regarding the retirement of Requirements R7 and R8, and incorporation of their language into Requirement R1.  Once this is done, the EOP PRT’s recommendations under 2.f. and 2.g. become moot.

(ii) The terms “plans” and “procedures” are appropriately used throughout the standard and, therefore, no revisions to those terms are needed.

(ii) The second sentence in the EOP PRT’s recommendation under 2.e. should be revised to conform to the first sentence, by adding the word “clarified:” “In addition, the EOP PRT recommends that the future SDT verify that the RSAW is appropriate to capture the clarified intent of the requirement.”

 

NPCC Proj 2015-02 EOP-005-2, Segment(s) 10, 3, 2, 1, 9, 6, 5, 8, 5/11/2015

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

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PSEG, Segment(s) 1, 3, 5, 6, 5/11/2015

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

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

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(1)   We agree with the initial recommendation that EOP-005-2 should be revised.

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

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

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

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

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See the comments above.

PPL NERC Registered Affiliates, Segment(s) 3, 1, 5, 6, 5/11/2015

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See comments above regarding R12. 

We agree with the intended clarification on “dynamic simulation” in relation to R6.  The use of the phrase “dynamic simulation” has led to much confusion amongst the industry and should be addressed.  Perhaps once the intended type of simulation has been decided, we suggest submission of a SAR with either a new, defined term or update an existing definition if needed and that definition aligned across the appropriate documents such as Rules of Procedure.

We would like to see further guidance on the intention of what “unique tasks” should be considered for R11.  While we agree that there has been little public issue reported regarding this topic of unique tasks, we feel there is little consistency among TOPs, TOs, and DPs in their interpretation.  This ranges from no unique tasks identified in one TOP area while a neighbor TOP for a system of similar size and configuration may identify several tasks that are unique.  We believe there is inconsistency in application of the intent of the R11 requirement. We also suggest removing the specific two hour requirement regarding the training.  We suggest instead to include the phrase “adequate training” instead. Since some entities unique tasks are perhaps minor, two hours of training may be excessive.  Also, the requirement language should be clarified to ensure the training that is required is actually relevant to the unique task.  This issue is also in R17 regarding the GOP’s required training.  The requirement is unclear in what the training must include.  We also ask for removal of the two hour requirement in R17 and perhaps replace with the phrase “adequate training”.

In R7, we request that the PRT review this requirement for clarity regarding the intent.  The intent of the “strategies” is unclear.  Specifically we ask for direction in what constitutes the expected strategies the Standard expects a TOP to have.  We do not suggest the requirement specifically dictate required details of the strategies. Perhaps some guidance can be put into the Guidelines section of the Standard providing a brief discussion of what types of activities would be beneficial to include in the strategy as documented in the plan.

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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Texas RE does not agree with the retirement of Requirement R10.

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

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No, based on answer to question #2

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

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We generally agree with the proposed revisions except the proposed retirement of Requirement R10 as noted under Q2, above.

 

In addition:

 

(i) Please see comments above, regarding the retirement of Requirements R7 and R8, and incorporation of their language into Requirement R1.  Once this is done, the EOP PRT’s recommendations under 2.f. and 2.g. become moot.

 

(ii) We believe that the terms “plans” and “procedures” are appropriately used throughout the standard and, therefore, no revisions to those terms are needed.

 

(iii) The second sentence in the EOP PRT’s recommendation under 2.e. should be revised to conform to the first sentence, by adding the word “clarified:” “In addition, the EOP PRT recommends that the future SDT verify that the RSAW is appropriate to capture the clarified intent of the requirement.”

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

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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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Please change to wording of the question to clearly indicate the framework of the question is the initial recommendation decision regarding reaffirm/revise/retire of a Standard.  

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

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Leo Staples, On Behalf of: Leo Staples, , 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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PacifiCorp has concerns with the drafting team recommendation to significantly extend the burden of the dynamic analyses related to R6.  It appears that the drafting team wants studies that extend beyond the transient time period studies of 15 – 25 seconds to a midterm type study which may require an additional mid-term study package.  PacifiCorp suggests that the drafting team clarify its position on whether it needs more time than the typical dynamic study timeframe (find this value out from PTI) or whether the drafting team was referring to additional studies rather than the time length in seconds of the dynamic studies.

The drafting team also appears to be asking for a dynamic study after every load and generation addition which significantly multiplies the number of dynamic studies required. PacifiCorp suggests the drafting team consider a reliability criteria to distinguish between verifying the ability for the black start to perform correctly and the addition of unnecessary dynamic studies.

Brad Ryan, On Behalf of: Berkshire Hathaway - PacifiCorp - WECC - Segments 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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Joshua Andersen, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 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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Leonard Kula, On Behalf of: Independent Electricity System Operator, , Segments 2

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This standard puts a lot of emphasis on Blackstart Resources but there are no requirements for other critical components such as synchronizing devices, for example:

–     Identify the synchronisation points used for system restoration

–     Require a fully operational synchronisation device for each synchronisation point

–     Require regular maintenance of the synchronisation devices

–     Require synchronisation drills or exercises

R1: There is no reference to the formation of an island on the BES in the context of the TOP restoration plan which seems to be incoherent with R1 of EOP-006-2.

R1.4: There are no clearly defined criteria for the identification of Black Start Resources. In the  Directory D8 from NPCC (NPCC D8),  a Blackstart Resource is used to restore a clearly identified “minimum basic power system”. In this standard the resource must just be part of the TOP restoration plan (NERc definition).

R1.4: The term “megavar capacity” is not defined (not a NPCC or NERC term).

R6.1: The term “dynamic capability” is not defined (not a NPCC or NERC term).

HQT changed to Active & Reactive power maximum capability instead. Same philosophy as D1, D2,D5,D8 on Capacity and D9 on Operating Capability.

R7 and R8: The implementation of the TOP restoration plan is based on the use of Blackstart Resource to instigate the restoration and there is no reference to the formation of an island on the BES (R1 of EOP-006-2) for invoking the TOP restoration plan.

R11: The term “field switching personnel” needs to be clarified. Most switching operations are nowadays performed by remote control (e.g. a TO control centre) so “field” can refer to personnel in a “lower level” remote control facility and not uniquely a roving operator in the field or an operator manning an installation?

There seems to be a consensus regarding the “unique tasks” (e.g, synchronisation of islands, emergency switching operations such as “open all breakers”) so it would be appropriate to define these unique tasks or list typical examples.

R15: There is an incoherence between the 24 hour delay cited here and the 15 minute delay cited in the NPCC D8 (section 5.7.1.2) for the loss of a critical component (Blackstart Resource). In the NPCC D8 the delay of 24 hours is for loss of redundancy of a critical component. A 24 hour delay for the loss of a critical component seems to be too long.

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

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The NSRF agrees with the drafting team recommendation to clarify EOP-005-2 R1.4 and what exactly is meant by “type” of unit.  Is this the fuel source or make / model?

 

 

The NSRF agrees with the drafting team recommendation to clarify that an “electronic or written” plan is available.

 

The NSRF has concerns with the drafting team recommendation to significantly extend the burden of the dynamic analyses related to R6.  The drafting team wording suggests a dynamic study time extension beyond the transient time period studies of 15 – 25 seconds to a midterm type study which may require an additional mid-term study package.  The NSRF suggests that the drafting team clarify its position on whether it needs more time than the typical dynamic study timeframe or whether the drafting team was referring to additional studies rather than the time length in seconds of the dynamic studies.

 

The drafting team also appears to be asking for a dynamic study after every load and generation addition which significantly multiplies the number of dynamic studies required.  The NSRF suggests the drafting team consider a reliability criteria to distinguish between verifying the ability for the black start plan to perform correctly and the addition of unnecessary dynamic studies.

 

The NSRF agrees with the Independent Expert Review that EOP-005-2 R1.3 and R8 are duplicative and can be retired.  Alternately, R1.3 can be revised to incorporate R8 with no loss of reliability.

 

 

The NSRF agrees with the drafting team recommendation to request clarity on unique tasks (page 6, paragraph 18).

 

The NSRF agrees with the drafting team recommendation to keep EOP-005-2 R12.  EOP-005 R12 is different than the training requirement in PER-005.

 

The NSRF notes that NERC requirements such as EOP-005-2 R13 are written for separately registered NERC functions.  The NSRF requests that the drafting team clarify if an entity is registered for more than one NERC function [vertically integrated] in a requirement that it is unnecessary to have “internal agreements” within the registered entity.  To require this is duplicative and unnecessarily burdensome according to Paragraph 81.

 

The NSRF suggests that EOP-005-2 R7 be clarified with respect to implementing a restoration strategy.  The NSRF recognizes the need for an alternative to strictly following the Restoration Plan explicitly as conditions could be changing rapidly as entities work to restore the grid from a blackout.  However, the restoration plan is the strategy or a combination of strategies to systematically restore an entity’s system from a blackout.  Is the intent of the requirement for TOPs to look for deficiencies in their plans and have strategies for the identified deficiency such as alternative black start paths if the primary black start path was damaged?

 

The NSRF proposes to modify EOP-005-2 Requirements R11 and R17 which both require two hours of training every two years for field switching personnel performing unique tasks and generator operator responsible for the startup process from blackstart unit, respectively. Industry experience suggests that two hours every two years isn’t necessary.  Most entities have field personnel and generator operators involved fully or partially in their restoration drills.  The specific training that falls under R11 and R17 does not require a timeframe.  The NSRF suggests replacing the two hour requirement with “at least every 2 calendar years” similar to the following:

 

R11. Each Transmission Operator, each applicable Transmission Owner, and each applicable Distribution Provider shall provide a System restoration training every 2 calendar years to their field switching personnel identified as performing unique tasks associated with the Transmission Operator’s restoration plan that are outside of their normal tasks.

 

R17. Each Generator Operator with a Blackstart Resource shall provide trainingar every 2 calendar years to each of its operating personnel responsible for the startup of its Blackstart Resource generation units and energizing a bus. The training program shall include training on the following: [Violation Risk Factor = Medium] [Time Horizon = Operations Planning]

R17.1. System restoration plan including coordination with the Transmission Operator.

R17.2. The procedures documented in Requirement R14.

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

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No Comments

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

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Maryclaire Yatsko, On Behalf of: Seminole Electric Cooperative, Inc., FRCC, Segments 1, 3, 4, 5, 6

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

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Support the EOP PRT’s recommendation that the future SDT review and address industry confusion regarding the application of “unique tasks.”  However, clarification is needed (examples should be provided).  Without clarification, “unique tasks” could be interpreted differently throughout the industry. 

This standard puts a lot of emphasis on Blackstart Resources but there are no requirements for other critical components such as synchronizing devices.  For example:

– Identify the synchronization points used for system restoration

– Require a fully operational synchronization device for each synchronization point

– Require regular maintenance of the synchronization devices

– Require synchronization drills or exercises

R1: There is no reference to the formation of an island on the BES in the context of the TOP restoration plan which seems to be inconsistent with R1 of EOP‐006‐2.

R1.4: There are no clearly defined criteria for the identification of Black Start Resources. In the Directory D8 from NPCC (NPCC D8), a Blackstart Resource is used to restore a clearly identified “minimum basic power system”. In this standard the resource must just be part of the TOP restoration plan (NERC definition).

R1.4: The term “megavar capacity” is not defined.

R6.1: The term “dynamic capability” is not defined.  Active and Reactive power maximum capability has been used elsewhere.

 

R7 and R8: The implementation of the TOP restoration plan is based on the use of Blackstart Resources to initiate the restoration, and there is no reference to the formation of an island on the BES (R1 of EOP‐006‐2) for invoking the TOP restoration plan.

R11: The term “field switching personnel” needs to be clarified. Most switching operations are currently performed by remote control (e.g. a TO control center) so “field” can refer to personnel in a “lower level” remote control facility and not uniquely a roving operator in the field or an operator manning an installation.

There seems to be a consensus regarding the “unique tasks” (e.g, synchronization of islands, emergency switching operations such as “open all breakers”) so it would be appropriate to define these unique tasks or list typical examples.

NPCC Proj 2015-02 EOP-005-2, Segment(s) 10, 3, 2, 1, 9, 6, 5, 8, 5/11/2015

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

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PSEG recommends that the team consider rewriting R4 to improve clarity regarding the application of the 90-day period in R4.  As written, R4 addresses (in one sentence) two restoration plan update items that a TOP must perform: (1) the restoration plan must be updated within 90 calendar days after identifying any unplanned System modifications are identified, and (2) the restoration plan must be updated prior to implementing a planned BES modification.  The phrase “, that would change the implementation of its restoration plan” appears to apply to both types of changes.

There is no time frame specified for updating the restoration plan for a planned BES modification, although one could infer that “90 calendar days” is intended be the same time frame for both unplanned and planned modifications.  Furthermore, the distinction between “System modifications” for unplanned changes and “BES modifications” for planned changes is confusing.

PSEG suggests the following rewrite:

R4.  Each Transmission Operator shall update its restoration plan to reflect System modifications that would change the implementation of its restoration plan; provided that such changes shall be made within 90 calendar days after the Transmission Operator identifies any unplanned permanent System modifications or within 90 calendar days prior to the Transmission Operator implementing planned System modifications. [Violation Risk Factor = Medium] [Time Horizon = Operations Planning]

     R4.1.    Each Transmission Operator shall submit its revised restoration plan to its Reliability Coordinator for approval within the same 90 calendar day period.

PSEG, Segment(s) 1, 3, 5, 6, 5/11/2015

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

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

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(1) The issue related to the applicability of the standard to a TOP that does not have Blackstart Resources within its TOP Area.  The phrase “regardless of whether the Blackstart Resource is located within the TOP’s system…” might infer the TOP’s plan must include restoration activities from specific Blackstart Resources in another system which is not necessary and should be clarified.  For example, a small TOP that relies on a larger TOP as a resource for restoration does not need to include that large TOPs Blackstart Resources in its restoration plan.  If the TOP restoration plan does not have any Blackstart Resources listed, but does identify which generators to start, the TOP should have a supplemental plan on how to provide startup power from at least one adjacent TOP to the identified generators.

(2) The PRT should clarify EOP-005-2 R11 and what “unique tasks associated with the TOP’s restoration plan” means and whether field switching personnel should still be required to have a minimum of two hours of system restoration training every two years.  This requirement could be retired as it would be covered in the systematic approach to training of PER-005-2.

(3) We disagree with the recommendations to use the phrase “develop, maintain and implement” language for R7 and R8, which are requirements for implementing the development and maintenance requirements that are contained in R1. 

(4) Finally, we recommend clarifying EOP-05-2 R18, where each GOP must participate in the RC’s restoration drills, exercises, or simulations, as requested.  The issue is whether RC invitations to restoration training are considered requests that trigger compliance concerns for GOPs who may not be an applicable entity to this standard or do not operate a Blackstart Resource.

(5) Thank you for the opportunity to comment.

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

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

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

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

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PPL NERC Registered Affiliates, Segment(s) 3, 1, 5, 6, 5/11/2015

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In general, the Standard as written seems to be awkward in dealing with the situation where a TOP who either does not have a Blackstart Resource within their area, or who does not have an ownership stake in the Blackstart Resource.  The TOP or GOP cannot be forced to enter into a relationship that makes some of these requirements applicable.  How can the TOP have a compliance obligation for equipment that they don’t own or control?  R9 is an example where the TOP is required to have testing requirements for the Blackstart Resource.  R6.1 can also be problematic in testing that the resource meets the desired real and reactive power requirements if the TOP does not own the resource.  R13 also forces a TOP and GOP to enter into a contractual agreement if the TOP and GOP are not both a part of the same affiliated company.

It also is not clear when the TOP restoration plan is considered to be in effect.  Similar to EOP-006 where the RC plan is clearly outlined as to when it begins and ends, we suggest the PRT review R1 for clarity on the meaning of the phrase “when the next choice of load to be restored is not driven by the need to control frequency or voltage regardless of whether the Blackstart Resource is located within the TOP’s system.” 

In R4, we look for additional guidance on the intent of the type and magnitude of system changes that would require the plan to be updated and provided to the RC.

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

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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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We generally support the EOP PRT’s recommendation that the future SDT review industry confusion regarding the application of “unique tasks.”  Some ISO’s system restoration staff has struggled with this term, so any clarity that can be provided (including examples) would be appreciated.  If the future SDT believes that the term does not require clarification, then it should confirm that entities have discretion in interpreting it.

 

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

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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

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j. Paragraph 24

Clarification of FERC NOPR comments by BPA: BPA is not confused about what tasks BPA personnel do or apply for restoration as described further in the NOPR comments.  BPA commented that maybe the industry could benefit from clarity on what defines a "unique task."  

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

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

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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

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

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