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2014-04 Physical Security

Description:

Start Date: 02/20/2015
End Date: 04/10/2015

Associated Ballots:

Ballot Name Project Standard Pool Open Pool Close Voting Start Voting End
2014-04 Physical Security CIP-014-2 IN 1 ST 2014-04 Physical Security CIP-014-2 02/20/2015 03/27/2015 03/31/2015 04/09/2015

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See the Unofficial Comment Form on the Project Page for additional background information.

Hot Answers

Teresa Krabe, On Behalf of: Lower Colorado River Authority, , Segments 1, 5, 6

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Peter Heidrich, 4/9/2015

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Other Answers

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

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John Fontenot, 2/20/2015

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Silvia Mitchell, On Behalf of: Silvia Mitchell, , Segments 6

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Ken Lindberg, On Behalf of: Bryan Texas Utilities, Texas RE, Segments 5

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Frank McElvain, 2/27/2015

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Amanda Owen, On Behalf of: AEP, Texas RE, SPP RE, RF, Segments NA - Not Applicable

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Ken Lindberg, On Behalf of: Ken Lindberg, , Segments 1, 5

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

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Herb Schrayshuen, On Behalf of: Herb Schrayshuen, , Segments 2

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David Kiguel, 3/18/2015

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Daniel Gacek, Exelon, 1, 3/18/2015

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Allen Wallace, On Behalf of: Allen Wallace, , Segments 3

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Charles Yeung, On Behalf of: Southwest Power Pool, Inc. (RTO), SPP RE, Segments 2

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Dana Wheelock, On Behalf of: Dana Wheelock, , Segments 1, 3, 4, 5, 6

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John Fontenot, 3/26/2015

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John Fontenot, 3/26/2015

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Leonard Kula, Independent Electricity System Operator, 2, 3/30/2015

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

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Brian Shanahan, National Grid USA, 3, 3/31/2015

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Phil Hart, 3/31/2015

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

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Alex Chua, 3/31/2015

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Andrew Pusztai, 4/1/2015

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Stephen Pogue, M and A Electric Power Cooperative, 3, 4/1/2015

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John Fontenot, 4/1/2015

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John Fontenot, 4/1/2015

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Romel Aquino, On Behalf of: Edison International - Southern California Edison Company, , Segments 1, 3, 5, 6

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Romel Aquino, On Behalf of: Edison International - Southern California Edison Company, , 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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Matt Jastram, On Behalf of: Matt Jastram, , Segments 1, 3, 5, 6

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Kaleb Brimhall, 4/2/2015

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Seattle City Light, Segment(s) 1, 3, 4, 5, 6, 4/2/2015

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Michael Brytowski, On Behalf of: Great River Energy, MRO, Segments 1

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

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Donna Turner, On Behalf of: APS - Arizona Public Service Co., WECC, Segments 1, 3, 5, 6

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

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Darnez Gresham, On Behalf of: Berkshire Hathaway Energy - MidAmerican Energy Co., MRO, Segments 1, 3

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christina bigelow, 4/6/2015

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David Jendras, Ameren - Ameren Services, 3, 4/7/2015

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Catherine Wesley, On Behalf of: PJM Interconnection, L.L.C., SERC, RF, Segments 2

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Terry BIlke, 4/8/2015

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

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Bob Reynolds, 4/8/2015

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Duke Ballot Body Members, Segment(s) 1, 5, 6, 4/8/2015

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Greg LeGrave, 4/8/2015

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

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John Merrell, Tacoma Public Utilities (Tacoma, WA), 1, 4/8/2015

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Lee Pedowicz, On Behalf of: Northeast Power Coordinating Council, NPCC, Segments 10

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Kelly Silver, On Behalf of: Con Ed - Consolidated Edison Co. of New York, NPCC, Segments 1, 3, 5, 6

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Tony Eddleman, Nebraska Public Power District, 3, 4/9/2015

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Michael Mertz, On Behalf of: Michael Mertz, , Segments 3

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Molly Devine, 4/9/2015

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Don Schmit, 4/9/2015

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John Williams, 4/9/2015

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Scott Langston, Tallahassee Electric (City of Tallahassee, FL), 1, 4/9/2015

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Chris de Graffenried, 4/9/2015

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Jamison Cawley, Nebraska Public Power District, 1, 4/9/2015

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Jared Shakespeare, 4/9/2015

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Karen Webb, 4/9/2015

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Kent Kujala, 4/9/2015

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Silvia Mitchell, 4/9/2015

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Daniel Herring, On Behalf of: DTE Energy - Detroit Edison Company, , Segments 3, 4, 5

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Daniel Herring, On Behalf of: DTE Energy - Detroit Edison Company, , Segments 3, 4, 5

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ACES Standards Collaborators, Segment(s) 1, 5, 4/9/2015

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Dan Bamber, On Behalf of: ATCO Electric, WECC, Segments 1

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

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Payam Farahbakhsh, Hydro One Networks, Inc., 1, 4/9/2015

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Paul Malozewski, Hydro One Networks, Inc., 3, 4/9/2015

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

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Steve Johnson, 4/9/2015

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Michael DeLoach, 4/9/2015

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Matt Jastram, On Behalf of: Matt Jastram, , Segments 1, 3, 5, 6

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SPP Standards Review Group, Segment(s) 1, 3, 5, 4/9/2015

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Erika Doot, 4/9/2015

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Spencer Tacke, Modesto Irrigation District, 4, 4/9/2015

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Fuchsia Davis, On Behalf of: Bonneville Power Administration - WECC - Segments 1, 3, 5, 6

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ISO/RTO Council Standards Review Committee, Segment(s) 2, 4/9/2015

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Richard Vine, 4/9/2015

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Hot Answers

Teresa Krabe, On Behalf of: Lower Colorado River Authority, , Segments 1, 5, 6

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Peter Heidrich, 4/9/2015

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Other Answers

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

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John Fontenot, 2/20/2015

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Silvia Mitchell, On Behalf of: Silvia Mitchell, , Segments 6

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Ken Lindberg, On Behalf of: Bryan Texas Utilities, Texas RE, Segments 5

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Frank McElvain, 2/27/2015

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Amanda Owen, On Behalf of: AEP, Texas RE, SPP RE, RF, Segments NA - Not Applicable

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Ken Lindberg, On Behalf of: Ken Lindberg, , Segments 1, 5

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

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Herb Schrayshuen, On Behalf of: Herb Schrayshuen, , Segments 2

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David Kiguel, 3/18/2015

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Daniel Gacek, Exelon, 1, 3/18/2015

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Allen Wallace, On Behalf of: Allen Wallace, , Segments 3

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Charles Yeung, On Behalf of: Southwest Power Pool, Inc. (RTO), SPP RE, Segments 2

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Dana Wheelock, On Behalf of: Dana Wheelock, , Segments 1, 3, 4, 5, 6

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John Fontenot, 3/26/2015

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John Fontenot, 3/26/2015

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Leonard Kula, Independent Electricity System Operator, 2, 3/30/2015

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

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Brian Shanahan, National Grid USA, 3, 3/31/2015

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Phil Hart, 3/31/2015

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

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Alex Chua, 3/31/2015

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Andrew Pusztai, 4/1/2015

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Stephen Pogue, M and A Electric Power Cooperative, 3, 4/1/2015

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John Fontenot, 4/1/2015

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John Fontenot, 4/1/2015

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Romel Aquino, On Behalf of: Edison International - Southern California Edison Company, , Segments 1, 3, 5, 6

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Romel Aquino, On Behalf of: Edison International - Southern California Edison Company, , 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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Matt Jastram, On Behalf of: Matt Jastram, , Segments 1, 3, 5, 6

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Kaleb Brimhall, 4/2/2015

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Seattle City Light, Segment(s) 1, 3, 4, 5, 6, 4/2/2015

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Michael Brytowski, On Behalf of: Great River Energy, MRO, Segments 1

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

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Donna Turner, On Behalf of: APS - Arizona Public Service Co., WECC, Segments 1, 3, 5, 6

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

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Darnez Gresham, On Behalf of: Berkshire Hathaway Energy - MidAmerican Energy Co., MRO, Segments 1, 3

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christina bigelow, 4/6/2015

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David Jendras, Ameren - Ameren Services, 3, 4/7/2015

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Catherine Wesley, On Behalf of: PJM Interconnection, L.L.C., SERC, RF, Segments 2

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Terry BIlke, 4/8/2015

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

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Bob Reynolds, 4/8/2015

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Duke Ballot Body Members, Segment(s) 1, 5, 6, 4/8/2015

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Greg LeGrave, 4/8/2015

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

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John Merrell, Tacoma Public Utilities (Tacoma, WA), 1, 4/8/2015

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Lee Pedowicz, On Behalf of: Northeast Power Coordinating Council, NPCC, Segments 10

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Kelly Silver, On Behalf of: Con Ed - Consolidated Edison Co. of New York, NPCC, Segments 1, 3, 5, 6

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Tony Eddleman, Nebraska Public Power District, 3, 4/9/2015

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Michael Mertz, On Behalf of: Michael Mertz, , Segments 3

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Molly Devine, 4/9/2015

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Don Schmit, 4/9/2015

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John Williams, 4/9/2015

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Scott Langston, Tallahassee Electric (City of Tallahassee, FL), 1, 4/9/2015

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Chris de Graffenried, 4/9/2015

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Jamison Cawley, Nebraska Public Power District, 1, 4/9/2015

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Jared Shakespeare, 4/9/2015

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Karen Webb, 4/9/2015

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Kent Kujala, 4/9/2015

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Silvia Mitchell, 4/9/2015

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Daniel Herring, On Behalf of: DTE Energy - Detroit Edison Company, , Segments 3, 4, 5

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Daniel Herring, On Behalf of: DTE Energy - Detroit Edison Company, , Segments 3, 4, 5

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ACES Standards Collaborators, Segment(s) 1, 5, 4/9/2015

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Dan Bamber, On Behalf of: ATCO Electric, WECC, Segments 1

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

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Payam Farahbakhsh, Hydro One Networks, Inc., 1, 4/9/2015

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Paul Malozewski, Hydro One Networks, Inc., 3, 4/9/2015

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

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Steve Johnson, 4/9/2015

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Michael DeLoach, 4/9/2015

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Matt Jastram, On Behalf of: Matt Jastram, , Segments 1, 3, 5, 6

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SPP Standards Review Group, Segment(s) 1, 3, 5, 4/9/2015

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Erika Doot, 4/9/2015

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Spencer Tacke, Modesto Irrigation District, 4, 4/9/2015

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Fuchsia Davis, On Behalf of: Bonneville Power Administration - WECC - Segments 1, 3, 5, 6

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ISO/RTO Council Standards Review Committee, Segment(s) 2, 4/9/2015

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Richard Vine, 4/9/2015

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Hot Answers

Teresa Krabe, On Behalf of: Lower Colorado River Authority, , Segments 1, 5, 6

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The proposed method of addressing the FERC directive to remove the term ‘widespread’ meets the specific language in the Order, however, it leaves the responsible entity and the Regional Compliance Organizations with regulatory uncertainty as to the scope of what constitutes ‘instability’ in regards to Requirement R1. The revised Rationale does little to clarify the issue for the responsible entity and the Regional Compliance Organizations. The Rationale box provides some insight, but does not provide the clarity needed in the standard. FERC stated that only an instability that has a “critical impact on the operation of the interconnection” warrants finding that the facility causing the instability is critical under Requirement R1. The SDT should build off of this concept to provide the needed clarity in the standard. One option would be too revise the requirement and then qualify what constitutes ‘critical impact’ from an operational perspective (for example: the loss would result in exceeding an operating limit). The proposed language for R1 is below.

“…The initial and subsequent risk assessments shall consist of a transmission analysis or transmission analyses designed to identify the Transmission station(s) and Transmission substation(s) that if rendered inoperable or damaged could result in instability that has a critical impact on the operation of the Interconnection, uncontrolled separation, or Cascading within an Interconnection.”

 

The guidance provided in the text box only provides examples of criteria that “may” be considered. Again this provides no regulatory certainty for the responsible entity and the Regional Compliance Organization. Additionally, the guidance reintroduces the concept of an ‘area or magnitude of potential impact’ which was eliminated from the Requirement with the deletion of the term ‘widespread’. This concept should be removed from the guidance. Further, this guidance may introduce unintended consequences and could influence a weakening of the criteria established by the Planning Coordinators in response to R6 of TPL-004-1.

Peter Heidrich, 4/9/2015

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Other Answers

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

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John Fontenot, 2/20/2015

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Silvia Mitchell, On Behalf of: Silvia Mitchell, , Segments 6

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Ken Lindberg, On Behalf of: Bryan Texas Utilities, Texas RE, Segments 5

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The removal of widespread is ok, but there is a larger problem.

The CIP-014-2 Standard is missing some fundamental elements in R1 and R2 to assure reliability if the contemplated contingency were to actually occur, and to be consistent with other standards.  To approve the standard as currently written creates inconsistencies among the entire family of reliability standards.

Station or substation damage would likely include equipment that could currently take as long as 16 months to replace.  With such a lengthy period of time in which a damaged station could be out-of-service, the standard needs to explicitly require determination of limits under the system’s new normal condition, and to accommodate more probable N-1 contingencies.

CIP-014 should also be consistent with other NERC standards, such as TOP-004, which requires operation within known operating limits, and preparing for the next contingency within 30 minutes.  It is unrealistic to expect these limits to be determined in real-time after a substation-out event as contemplated in CIP-014. 

The level of study performed in preparation for a loss of a substation (or station) can vary from one organization to another and not every system limit needs to be determined in advance.  However, minimally, CIP-014 should require that generating units are confirmed to remain stable for the next N-1 contingency, that current IROLs are not degraded in the new normal condition, and that generation contingency reserves remain adequate.

Frank McElvain, 2/27/2015

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Amanda Owen, On Behalf of: AEP, Texas RE, SPP RE, RF, Segments NA - Not Applicable

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Ken Lindberg, On Behalf of: Ken Lindberg, , Segments 1, 5

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

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Herb Schrayshuen, On Behalf of: Herb Schrayshuen, , Segments 2

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 My comment addresses the proposed Implementation Plan.  While accepting that the change in the proposed standard is minor with respect to the currently approved version, it would be advisable to have an effective date that gives a more reasonable time, e.g. 30 days after the applicable date instead of the proposed day immediately after approval or day after the effective date of Version 1.  This in order to permit relevant entities to do any necessary administrative work required for implementation.    

David Kiguel, 3/18/2015

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Exelon agrees with the SDT proposal to remove the term “widespread” from Reliability Standard CIP-014-1. With that change we believe the standard is responsive to the directive and supportive of reliability.

We do not agree that an alternative modification is necessary to meet the concern raised in the Directive. Alternative modifications are likely to delay implementation and lead to new revisions requiring further clarification with no appreciable gain in reliability.

Daniel Gacek, Exelon, 1, 3/18/2015

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The concern with removing the term "widespread" is that it potentially imposes the requirements of the standard upon smaller substations and entities that could have minimal impact on the BES.  While I would prefer a more quantifiable determinant of applicability (customers affected, miles of transmission, load or generation lost, etc.) I believe that widespread is better than no discriminant at all.

Allen Wallace, On Behalf of: Allen Wallace, , Segments 3

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Charles Yeung, On Behalf of: Southwest Power Pool, Inc. (RTO), SPP RE, Segments 2

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Dana Wheelock, On Behalf of: Dana Wheelock, , Segments 1, 3, 4, 5, 6

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John Fontenot, 3/26/2015

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John Fontenot, 3/26/2015

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With the word “widespread” removed, R1 is stating that if rendering a station inoperable results in any instability (large or small), the station should be declared critical.  Depending on the severity of an instability, there may or may not be an impact on the operation of the interconnection.   We are proposing the following modification to R1 to make it clearer in terms of reliability impact on the “Interconnection” in which the assessed facilities lie.

“Each Transmission Owner shall perform an initial risk assessment and subsequent risk assessments of its Transmission stations and Transmission substations (existing and planned to be in service within 24 months) that meet the criteria specified in Applicability Section 4.1.1. The initial and subsequent risk assessments shall consist of a transmission analysis or transmission analyses designed to identify the Transmission station(s) and Transmission substation(s) that if rendered inoperable or damaged could result in a critical impact on the operation of the interconnected (or neighboring) power system by causing instability, uncontrolled separation, or Cascading within an Interconnection.”

Leonard Kula, Independent Electricity System Operator, 2, 3/30/2015

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

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Brian Shanahan, National Grid USA, 3, 3/31/2015

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Phil Hart, 3/31/2015

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

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Alex Chua, 3/31/2015

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Andrew Pusztai, 4/1/2015

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Stephen Pogue, M and A Electric Power Cooperative, 3, 4/1/2015

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John Fontenot, 4/1/2015

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John Fontenot, 4/1/2015

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Romel Aquino, On Behalf of: Edison International - Southern California Edison Company, , Segments 1, 3, 5, 6

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Romel Aquino, On Behalf of: Edison International - Southern California Edison Company, , 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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Matt Jastram, On Behalf of: Matt Jastram, , Segments 1, 3, 5, 6

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Kaleb Brimhall, 4/2/2015

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Seattle City Light supports the proposed revisions expressed in draft CIP-014-2 to remove the undefined term "widespread" and votes affirmative. In particular Seattle supports the new guidance language added to the Standard and supporting documents to explain what is meant by the term "widespread" that would no longer be included in the Standard.

Seattle, however, would support the proposed draft further if the term "widespread" was not simply removed from CIP-014-2 but replaced everywhere by "critical." Although "critical" is no more defined than "widespread," the term is the exact word used by FERC in its Order requesting removal of "widespread" and relates directly to FERC and NERC guidance on the matter.

Seattle City Light, Segment(s) 1, 3, 4, 5, 6, 4/2/2015

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Michael Brytowski, On Behalf of: Great River Energy, MRO, Segments 1

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

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All though we agree the with the removal of the word “widespread” from the standard, we feel leaving the word “instability” in the standard still makes it vague and inconsistent. We suggest that both word “widespread” and “instability” be taken out to read R1 as follows:

“… The initial and subsequent risk assessments shall consist of a transmission analysis or transmission analyses designed to identify the Transmission station(s) and Transmission substation(s) that if rendered inoperable or damaged could result in uncontrolled separation, or Cascading within an Interconnection.

The criticality of a facility to an interconnection is determined by its impact and not by instability. Instability is a symptom and not the final consequence. There are various types of instabilities and with consequence varying from a small 10 W generation tripping to an interconnection braking up and many things in between. There are many other symptoms which are also indicators of cascading such as excessive overload, very low voltages etc. but none of them are called out. So why leave instability in there?

The above proposed wording preserves all of the impact without dwelling on symptoms.

Donna Turner, On Behalf of: APS - Arizona Public Service Co., WECC, Segments 1, 3, 5, 6

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

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FERC Order No. 802 states on page 18: “The definition in Requirement R1 should not be dependent on how an applicable entity interprets the term “widespread” but instead should be modified to make clear that a facility that has a critical impact on the operation of an Interconnection is critical and therefore subject to Requirement R1.”

Rather than merely remove the word “widespread,” NERC could better comply with the FERC order to provide clarity with a simple rearrangement of terms.

By reordering R1 from:

…if rendered inoperable or damaged could result in instability, uncontrolled separation, or Cascading within an Interconnection.

To:

…if rendered inoperable or damaged could result in uncontrolled separation or Cascading within, or the instability of, an Interconnection.

This reorganization maintains all the wording of R1 without introducing any undefined or subjective terms, but more clearly ties the term “instability” to “Interconnection.”  This  better reflects the FERC intention of affecting an interconnection, and by changing the intervening modifier between the terms “instability” and “Interconnection” from “within” to “of” addresses the industry concern that R1, as left without the term “widespread,” could be interpreted as applying to localized areas of instability

Darnez Gresham, On Behalf of: Berkshire Hathaway Energy - MidAmerican Energy Co., MRO, Segments 1, 3

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ERCOT supports and references the comments to be filed by the ISO/RTO Council Standards Review Committee.

christina bigelow, 4/6/2015

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David Jendras, Ameren - Ameren Services, 3, 4/7/2015

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Catherine Wesley, On Behalf of: PJM Interconnection, L.L.C., SERC, RF, Segments 2

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While we agree that the revision addresses the directive, it's unfortunate that this required change muddles common understanding of NERC's terms and definitions.

Terry BIlke, 4/8/2015

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

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Bob Reynolds, 4/8/2015

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Duke Energy would like to thank the SDT for their efforts on this project. In addition, we agree with the changes made by the SDT.

Duke Ballot Body Members, Segment(s) 1, 5, 6, 4/8/2015

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Greg LeGrave, 4/8/2015

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NSRF’s concerns with the proposed changes to CIP-014-2 standard.

1. Removal of the term , “widespread”, from R1 without replacement text in R1  - The qualifying concept of “widespread” was removed from R1 without replacing it with alternate text to address the Commission’s concerns. This approach makes the text in R1 even less defined than the original CIP-014-1 text. For example, the modified text offers no criteria to define the degree of reliability impacts due to instability or uncontrolled separation that would qualify a substation. This approach would allow applicable entites and regulators to interpret even minor or the R1 text to expect a substation to be qualified by local or minor reliability impacts as qualifying a substation.  Addressing the Commission’s concerns by relegating criteria text to the Rationale for R1, rather than including criteria text in R1, allows the text to be disregarded because the rationale will be removed when the standard is finalized. Addressing the Commission’s concerns by relegating text to to the Guidance and Technical Basis section, rather than including text in R1, allows the text to be disregarded because, not being part of R1, the the application of guidance text may be a judgement call. Our concern stems from FERC Order 693, section 253, which states that “. . . compliance will in all cases be measured by determining whether a party met or failed to meet the Requirement given the specific facts . . .”.  Each requirement must be clearly written for entities to follow.  Any wording contained in a Guidance and Technical document is just that, wording.  The words of “the Requirements within a standard define what an entity must do to be compliant”.

Alternate text for R1 to replace2. Limiting the applicability of the term, “widespread””, to just instability – We interpret the qualification that the widespread reliability impact duerefers to “all three qualifying conditions – instability”, “, uncontrolled separation” and “Cascading, not to just instability alone.

3. Insufficient Use of NERC-Defined Terms - Alternate text for “widespread” should incorporatebe added to Requirement R1 and should make as much use of NERC defined-terms and concepts as much as possible. The NERC-defined term of “Adverse Reliability Impact” is used in Criterion 2.3 from Attachment 1 of the CIP-002-5.1 standard andFor example, the NERC-defined concept of “Interconnection Reliability Operating Limit” (IROL) is used in Criterion 2.9 from Attachment 1 of the CIP-002-5.1 standard. The FAC-010-2 standard already allows Planning Coordinators (PCs) to establishdefine criteria and methodology for establishing planning horizon IROLs that are appropriate for the PC’s area and the Interconnection where the limit will be applied.

Based on the preceding comments, 4. Clarification of the term, Interconnection – We interpret that the use of capitalized word “Interconnection” within the Purpose, R1, R1.1 bullet 1 and 2, and associated VSLs refers to any of the Eastern, Western, ERCOT or Quebec Interconnections, not a regional Balancing Authority interconnection or regional Independent System Operator interconnection.

 

NSRF suggests recommends the following wording changes to address the above concerns: 

For Requirement R1, we suggest that the term, “widespread” in R1 be replaced with text like, “. . . if rendered inoperable or damaged could result an Adverse Reliability Impact on the BES within an Interconnection due to instability, uncontrolled separation, or Cascading” or “. .. . if rendered inoperable or damaged could result in the violation of one or more Interconnection Reliability Operation Limits (IROLs) within an Interconnection due to instability, uncontrolled separation or Cascading within, or instability of, an Interconnection”.

Also based on the preceding comments, ATC suggests revising the wording of the draft text in For the R1 Rationale and in the Guidance and Technical Basis section. ATC proposes that the wording near the endSection, we suggest the following modifications:

  • {C}·       Replace the wording of “The Transmission Owner may determine the criteria for critical impact by considering, among other criteria, any of the clarification text be simplified to focusfollowing:  Criteria or methodology used by Transmission Planners or Planning Coordinators in TPL-001-4, Requirement R6; NERC EOP-004-2 reporting criteria; Area or magnitude of potential impact” with text that focuses on the concept on Adverse Reliability Impact or IROLs with language like, “The Transmission Owner should derive the criteria for the R1 risk assessment from the criteria used in the Adverse Reliability Impact definition or the criteria used to establish planning horizon IROLs as inper Requirement R3 of the NERC FAC-010-2 reliability standardReliability Standard.”
  •  Add clarification regarding the four kinds of instability that should be considered with wording like, “The consideration of instability should include all four kinds of instability - steady state voltage instability, steady state angular instability, dynamic voltage instability, and dynamic angular instability.”

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

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Although we agree with removal of the term “widespread” from the standard, we do not find the supporting justification provided in the Rationale for R1 and/or the Guidelines and Technical Basis for R1 to be adequate and/or convincing.  Specifically, we do not find the three proposed criteria for critical impact as particularly instructive to help identify which instability – out of the potentially several instabilities seen in the transmission analyses performed for R1 – would qualify as having a critical impact on the operation of the interconnection.  Without a clear technical guidance on what are the attributes (quantitative and qualitative) of a “critical impact” instability” – that is, only an instability that has a critical impact on the operation of the interconnection, as stated in the March 7, 2014 Order – we do not see how the “excessive uncertainty in identifying critical facilities under R1” due to the undefined term “widespread” has been effectively addressed.  Deletion of “widespread” without replacing it with adequately clear technical guidance on what constitutes a “critical impact instability” for an interconnection has only displaced the excessive uncertainty concern of FERC from “stability” to “critical impact” – it has not resolved it.

Since at least two of the three proposed criteria for critical impact puts the onus on the Transmission Owner (or its Transmission Planner) to determine (quantify) the “area or magnitude of potential impact” or determine how to identify “System instability” per R6 in TPL-001-4,  this approach is prone to result in “critical impact” criteria that differ widely among the numerous Transmission Owners within each of the three Interconnections.  This outcome would be incompatible and inconsistent with FERC’s stated guidance in the March 7, 2014 Order – and reiterated in the November 20, 2014 Order – that “only an instability” that has a “critical impact on the operation of the interconnection” (emphasis added) warrants finding that the facility resulting in the [critical interconnection impact] instability is deemed critical under Requirement R1.

We suggest the following two alternatives to address the above concerns:

1)      Option 1:  Enhance the technical guidance to provide a common Interconnection-wide criterion for what constitutes “critical impact” instability in the Interconnection. This would conceivably be different for each of the three Interconnections, resulting in three “critical impact” instability criteria.  We note that this approach would be similar to what was adopted for the Order 754 stability studies/analyses.  As such, we recommend using “Table C – Performance Measures” in the NERC Order 754 Data Request document as a good paradigm for developing an Interconnection-wide “critical impact” instability criteria.

2)      Option 2:  Modify Requirement R1 to recognize that only an instability that results in Cascading or uncontrolled separation within an Interconnection qualifies as one that has a “critical impact on the operation of the Interconnection”.  This approach implicitly acknowledges that all other instabilities have a limited (local) impact and therefore do not result in widespread instability, and widespread instability is synonymous with Cascading or uncontrolled separation.  The following change in R1 and part 1.1 is suggested:  “….could result in Cascading or uncontrolled separation within an Interconnection caused by (voltage or angular) instability and/or successive failures of overloaded Facilties.”

Aside from the above, we suggest that the following compound sentence in the Rationale as well as Technical Basis be simplified and restructured to remove the existing contextual ambiguities that make comprehending its intent very difficult.

“The requirement is not to require identification of, and thus, not intended to bring within the scope of the standard a Transmission station or Transmission substation unless the applicable Transmission Owner determines through technical studies and analyses based on objective analysis, technical expertise, operating experience and experienced judgment that the loss of such facility would have a critical impact on the operation of the Interconnection in the event the asset is rendered inoperable or damaged.”

Further, we question if this sentence even belongs in the Rationale – it is hard to see how this provides a justification for Requirement R1.  In fact, saying that “The requirement is not to require identification of…” appears to contradict the intent of the following verbiage in R1 “… transmission analyses designed to identify the…”.

Lastly, it appears that the changes made in the following paragraph in the Rationale for R1 have inadvertently resulted in an incomplete/incoherent sentence within the parenthesis.

[It] Requirement R1 also meets the [portion of the] FERC directive [from paragraph 11] for periodic reevaluation of the risk assessment by requiring the risk assessment to be performed every 30 months (or 60 months for an entity that has not identified in a previous risk assessment [any Transmission stations or Transmission substations that if rendered inoperable or damaged could result in widespread instability, uncontrolled separation, or Cascading within an Interconnection]).

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

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John Merrell, Tacoma Public Utilities (Tacoma, WA), 1, 4/8/2015

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With the word “widespread” removed, Requirement R1 implies that if and when a station becomes inoperable and a potential threat for instability (large or small), uncontrolled separation or cascading, the station should be declared critical.  Depending on the severity of an instability, there may or may not be any adverse impact on the operation of the interconnection.  For example, if a station in a pocket or remote area should become inoperable and a potential threat for instability, it may not create any adverse impact on interconnected operations.  Hence, to capture the intent of the requirement such that it addresses facilities that can impact interconnected operations,  suggest modifying R1 as follows (see words underlined and in bold):

 

R1. Each Transmission Owner shall perform an initial risk assessment and subsequent risk assessments of its Transmission stations and Transmission substations (existing and planned to be in service within 24 months) that meet the criteria specified in Applicability Section 4.1.1. The initial and subsequent risk assessments shall consist of a transmission analysis or transmission analyses designed to identify the Transmission station(s) and Transmission substation(s) that if rendered inoperable or damaged could result in a critical impact on the operation of the interconnected power system by causing instability, uncontrolled separation, or Cascading within an Interconnection.

 

For the Rationale Box for R1, we suggest replacing “among other criteria” with “for example.” This wording clarifies that the examples given are merely examples and not the only options for determining critical impact.

 

“[…] the Transmission Owner may determine the criteria for critical impact by considering, for example, any of the following:

  • Criteria or methodology used by Transmission Planners or Planning Coordinators in TPL‐001‐4, Requirement R6
  • NERC EOP‐004‐2 reporting criteria
  • Area or magnitude of potential impact”

 

In paragraph 6 of the FERC Docket No. RD14-6-000, “interconnection” is lower case.  Should “interconnection” as used in the standard’s Rationale for Requirement R1 and in the Guidelines and Technical Basis on page 31 be upper or lower case?

 

To make the wording of the Rationale for Requirement R1 consistent with the wording in RD14-6-000, suggest rewording the second sentence to read”…applicable Transmission Owner determines through objective analysis, technical expertise, and experienced judgment…”R6 Severe VSL: “The Responsible Entity had an unaffiliated third party review the evaluation performed under Requirement R4 and the security plan(s) developed under Requirement R5 but failed to implement procedures for protecting information per Part 6.3” should read “per Part 6.4”.

Lee Pedowicz, On Behalf of: Northeast Power Coordinating Council, NPCC, Segments 10

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Kelly Silver, On Behalf of: Con Ed - Consolidated Edison Co. of New York, NPCC, Segments 1, 3, 5, 6

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Tony Eddleman, Nebraska Public Power District, 3, 4/9/2015

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Michael Mertz, On Behalf of: Michael Mertz, , Segments 3

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Molly Devine, 4/9/2015

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Don Schmit, 4/9/2015

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Removing "widespread" from criteria will leave the Reliability Standard open to "local" impact assessments by the audit teams, which could have exponential implications even for small municipal utilities. Removing the term "widespread" opens the scope of the standard to unlimited interpretation. The term "widespread" has been commonly and generally used since the mandatory and effective date of the NERC Reliability Standards to exclude such common occurrences as a storm moving through the area (daily during the summer in Florida), causing damage up to and including some transmission outages. Would a lightning strike on a bulk power substation causing it to operate be termed instability under the Reliability Standard or would the lightning strike also have to cause the connecting transmission lines to operate? Therefore, does removal of the word "widespread" for consideration of instability mean that every bulk power facility outage, for whatever reason is now in violation of instability? There has to be some degree of limiting language to prevent the unintended spiral that removal of the word "widespread" will cause. Entities are familiar with and understand the use of the term "widespread". Removing this modifier from the scope of assessment will require extensive instruction and scenario analysis to make the scope of the assessment clear.

John Williams, 4/9/2015

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Scott Langston, Tallahassee Electric (City of Tallahassee, FL), 1, 4/9/2015

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Chris de Graffenried, 4/9/2015

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Jamison Cawley, Nebraska Public Power District, 1, 4/9/2015

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Jared Shakespeare, 4/9/2015

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Karen Webb, 4/9/2015

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Kent Kujala, 4/9/2015

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Silvia Mitchell, 4/9/2015

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Daniel Herring, On Behalf of: DTE Energy - Detroit Edison Company, , Segments 3, 4, 5

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Daniel Herring, On Behalf of: DTE Energy - Detroit Edison Company, , Segments 3, 4, 5

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1.      The removal of the undefined term of “widespread” from R1 should have alternate text to address the Commission’s concern(s) and to provide industry with clarity to the applicability of transmission facilities.  While we understand the drafting team’s response to FERC’s directive to remove “widespread,” this language should be modified to make clear that a facility that has a critical impact on the operation of an Interconnection is critical and therefore subject to Requirement R1. This blanket removal of ‘widespread’ from the requirements makes the text in R1 even more vague and subjective than the original CIP-014-1 language that is subject to interpretation and may result in a standard that is not auditable.  By removing the word widespread, there is no clear delineation of reliability impact(s) due to instability or uncontrolled separation that would qualify a substation.  This language change will cause inconsistent implementation across the regions and Transmission Planners or Planning Coordinators.  Furthermore, given the cost implications on a possible Transmission Owner, more clarity and certainty of scope is needed.

 

2.      Adding to the Rationale and Guideline and Technical Basis for Requirement R1 does not address the FERC Directive. The Rationale section while assisting industry to better understand the intention of the PSSDT is not enforceable and will result in an inconsistent R1 implementation across the regions.

 

3.      The PSSDT should refer to NERC defined-terms and concepts, where appropriate. To add clarity to ‘widespread,’ the PSSDT should consider the NERC defined terms of “Adverse Reliability Impact” (Criterion 2.3 from Attachment 1 of the CIP-002-5.1), “Interconnection Reliability Operating Limit” (Criterion 2.9 from Attachment 1 of the CIP-002-5.1), and the FAC-010-2 standard that is in place to assist Planning Coordinators (PC) to establish planning horizon IROLs that are appropriate for the PC’s area and the Interconnections.

 

4.      Thank you for time, attention and consideration regarding these CIP-014-2 comments.

ACES Standards Collaborators, Segment(s) 1, 5, 4/9/2015

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Agree that removing the term widespread removes some subjectivity, however additional clarity on what is meant by the term “instability” would be beneficial in helping entities determine the appropriate critiera to be applied, as part of their risk assessment, in the identification of facilities in-scope to this standard.

Dan Bamber, On Behalf of: ATCO Electric, WECC, Segments 1

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With the deletion of the term “widespread” from CIP-014, the TO must determine whether instability, uncontrolled separation, or Cascading within an Interconnection could occur if the station was damaged or rendered inoperable.   For jointly-owned facilities, i.e., two or more TOs at a Transmission station or Transmission substation, the Standard states the following on page 30 of 39:

“On the issue of joint ownership, the SDT recognizes that this issue is not unique to CIP-014, and expects that the applicable Transmission Owners and Transmission Operators will develop memorandums of understanding, agreements, Coordinated Functional Registrations, or procedures, etc., to designate responsibilities under CIP-014 when joint ownership is at issue, which is similar to what many entities have completed for other Reliability Standards.”

In order to delegate responsibility to a single TO at a jointly-owned facility to make the above cited determination and the remaining Requirements in the Standard, Seminole Electric has the following questions:

(1)    Can a Coordinated Functional Registration agreement (CFR), Joint Registration Organization agreement (JRO), or Memo of Understanding (MOU) be drafted on a station-by-station basis between parties?  Seminole Electric is unaware whether CFRs and JROs can be developed and approved by NERC on a station-by-station basis and requests more information on this issue.

(2)    In delegating responsibility for the Requirements in jointly-owned facilities under CIP-014-2, can an MOU be a sufficient mechanism to delegate authority if drafted sufficiently, or does the drafting team reason that ultimately a CFR or JRO must be executed between the co-owners (multiple TOs) at a station? Seminole Electric has been told that MOUs may be ineffective in delegating responsibility for the Requirements for jointly-owned facilities and that CFRs and JROs should be executed instead.

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

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Payam Farahbakhsh, Hydro One Networks, Inc., 1, 4/9/2015

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Hydro One Networks Inc. supports the comments advanced by the NPCC RSC.

Paul Malozewski, Hydro One Networks, Inc., 3, 4/9/2015

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Hydro-Quebec TransEnergie supports the comments from NPCC-RSC

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

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Western Area Power Administration supports the Bureau of Reclamation comments regarding the removal of "widespread".  Specifically, we request the adoption of language referring to TPL-001-4 R6 for consistency.

Steve Johnson, 4/9/2015

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Michael DeLoach, 4/9/2015

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Matt Jastram, On Behalf of: Matt Jastram, , Segments 1, 3, 5, 6

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The group has a concern in reference to the removal of the term ‘widespread’ in that removing it doesn’t provide any boundries to the scope of the instability or cascading outages. With that being said, this can lead to continued inconsistency throughout the industry. We understand that the Commission has a large concern about the term ‘widespread’ being in the doucmenation and the  group would like to propose alternative language stated as followed:  “instability uncontrolled separation or cascasding that would cause or affect an Operational IROL within the Interrconnection”.

The group also has a concern pertaining to CIP-014 in reference to a Transmission Owner completing their assessment (which is due on or before October 15, 2015) more than 90 days before October 1. There is some confusion on when the verification would be completed (if the assessment was finished June 1). Does the Transmission Owner have 90 days from October 1 or 90 days from June 1? This would be with the assumption that the effective date is October 1. We would like the drafting team to provide more clarity in reference to Requirement R2.2 addressing this issue.

We have a concern about Requirement R4 and its timeline requirement. In the standard’s Rationale Box for R4 (second paragraph), it states “Requirement R4 doesn’t explicitly states when the evaluation has to be completed” however, Requirement R5 development of a security plan(s) depend on this information. We would like for the SDT to provide more detailed information on when the evaluation needs to be completed.

First line of the first paragraph of Requirement R3…. Page 9.  The term ‘control center’ should be capitalized as its shown the Glossary of Terms. Additionally, this applicable for the last sentence of the paragraph.           

First line of the first paragraph of Requirement R5…. Page 11.  The term ‘control center’ should be capitalized as its shown the Glossary of Terms.

SPP Standards Review Group, Segment(s) 1, 3, 5, 4/9/2015

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The Bureau of Reclamation (Reclamation) does not agree with removing the term “widespread” from R1 without adding clarifying language in the text of the standard.  This approach makes the text in R1 even less defined than the original CIP-014-1 text because it offers no criteria of what degree of reliability impacts due to instability or uncontrolled separation is appropriate to determine facilities identified under R1.  This approach could cause a much broader range of facilities to come within the scope of the standard by allow interpretations that even minor or local reliability impacts result in some degree of “instability… within an interconnection.”  Reclamation is concerned that the removal of the term "widespread" could expand the standard to include remote facilities that if lost could impact relatively small and isolated load pockets.  Reclamation suggests that the drafting team include a footnote referencing TPL-001-4 R6 criteria, reference other specific criteria like facilities affecting IROLs, or at least incorporate FERC’s language “has a critical impact on the operation of the interconnection” into the language of R1.  In the alternative, the drafting team could reference a specific area or magnitude of potential impact.  Unlike the rationale statement, clarifying requirement language or a footnote would be an enforceable component the standard if approved by FERC.  The clarifying language would ensure that the scope of facilities identified under R1 would not be dramatically broadened with the removal of the term “widespread.” 

Erika Doot, 4/9/2015

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I am voting NO because I believe the Standard should be very specific as to what constitutes "damaged", if it is not equal to being "inoperable", as used in the Standard.  Also, the Standard needs to be very specific about the method of "transmission analysis" for rendering the station "inoperable", such as complete loss of the station resulting in a three phase fault on the station bus, etc..  The Standard is very specific and clear as how to determine which facilities need to be analyzed (i.e., those exceeding an aggregate weighted value of 3000 as specified in Section 4.1.1.2), and it needs to be just as specific in defining "damaged" and the method of "transmission analysis".

Thank you.

Sincerely,

Spencer Tacke, MID

Spencer Tacke, Modesto Irrigation District, 4, 4/9/2015

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Fuchsia Davis, On Behalf of: Bonneville Power Administration - WECC - Segments 1, 3, 5, 6

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With the removal of the term “widespread,” Requirement R1 implies that, if and when a station becomes inoperable and a potential threat for instability (large or small), uncontrolled separation or Cascading, the station should be declared critical.  However, whether there is an adverse impact on the “operation of the interconnection” depends on the severity of an instability.  In particular, a station or substation may create local instability, but there may or may not have an adverse or critical impact on the “operation of the Interconnection.”  For example, if a station in a pocket or remote area should become inoperable and a potential threat for instability, it may create local instability, but such local instability may not  impact the operation of the interconnected system in any way.  Hence, to declare such a station as “critical” would defeat the purpose of focusing security operations on those stations and substations that have a “critical impact on the operation of the Interconnection.” 

The SRC appreciates that the Standard Drafting Team attempted to provide additional criteria to determine the criticality of impact by provding some guidance in the rationale section for Requirement R1. However, the SRC respectfully suggests that there is a potential that such guidance may result in diverse criteria regarding criticality, which would, in turn, result in substantially different determinations of criticality across and within the Interconnections.  It may also create unintended complications regarding compliance with and activities performed under other reliability standards.  Hence, given the interconnected nature of the grid and the reliability standards with which Transmission Operators and Owners must comply and to ensure that the requirement effectively conveys the intent to address facilities with a “critical impact of the operations of the interconnection” and is able to be applied consistently, the SRC recommends that Requirement R1 be modified as follows (see words in red):

R1. Each Transmission Owner shall perform an initial risk assessment and subsequent risk assessments of its Transmission stations and Transmission substations (existing and planned to be in service within 24 months) that meet the criteria specified in Applicability Section 4.1.1. The initial and subsequent risk assessments shall consist of a transmission analysis or transmission analyses designed to identify the Transmission station(s) and Transmission substation(s) that if rendered inoperable or damaged could cause instability, uncontrolled separation, or Cascading  that could result in critical, adverse impacts to the operation of the interconnected power system.

ISO/RTO Council Standards Review Committee, Segment(s) 2, 4/9/2015

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I support the comments provided by the ISO/RTO Council Standards Review Committee

Richard Vine, 4/9/2015

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