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2016-04 Modifications to PRC-025-1 | PRC-025-2

Description:

Start Date: 07/25/2017
End Date: 09/08/2017

Associated Ballots:

Ballot Name Project Standard Pool Open Pool Close Voting Start Voting End
2016-04 Modifications to PRC-025-1 PRC-025-2 IN 1 ST 2016-04 Modifications to PRC-025-1 PRC-025-2 07/25/2017 08/23/2017 08/29/2017 09/08/2017

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Hot Answers

Laurie Williams, PNM Resources - Public Service Company of New Mexico, 1, 9/8/2017

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Theresa Rakowsky, 9/8/2017

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Other Answers

Manitoba Hydro, Segment(s) 5, 3, 6, 1, 8/8/2017

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Glen Farmer, Avista - Avista Corporation, 5, 8/23/2017

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

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AEP recommends the SDT use the same frame of reference for both the Option 5a in Table 1 and Figure A.  As currently written, Table 1 states “The overcurrent element shall not infringe upon…” while Figure A states “Option 5b – Resource capability shall not infringe on…”.

Thomas Foltz, AEP, 5, 8/24/2017

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Entergy/NERC Compliance, Segment(s) 1, 5, 3/1/2017

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Tom Haire, 8/29/2017

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

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More clarity is needed on the implementation of Option 5b.  “Resource capability” should be defined such that this value can be clearly determined.  A detailed example for Option 5b which uses a plot similar to Figure A that discusses “documented tolerances” would be helpful.

DTE Energy - DTE Electric, Segment(s) 5, 4, 3, 2/27/2017

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Leonard Kula, Independent Electricity System Operator, 2, 9/1/2017

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Neil Swearingen, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

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Not applicable to BPA.

Aaron Cavanaugh, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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PPL NERC Registered Affiliates, Segment(s) 3, 1, 5, 6, 2/9/2017

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Laura Nelson, IDACORP - Idaho Power Company, 1, 9/6/2017

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Eleanor Ewry, 9/6/2017

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Elizabeth Axson, 9/6/2017

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Donald Lock, 9/6/2017

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

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As written, NERC Reliability Standard PRC-025-2 Generator Relay Loadability does not account for equipment limitations of the generator step-up transformer or generation lead line that would not allow an entity to set it’s protective relays to the level as specified within the standard.  The SDT needs add additional option for these application that is similar to option 5B.

George Brown, Acciona Energy North America, 5, 9/6/2017

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OPG is of the opinion that there is a discrepancy between the Relay setting criteria description for option 5b in Table 1 and the description contain in the Figure A, which should be corrected. Instead of “Option 5b – Resource Capability shall not infringe on the lower tolerance of the protective device” we recommend Figure A should state the following “Option 5b – Protective device overcurrent element settings lower tolerance tripping characteristic shall not infringe on the Resource capability”

Additional clarification is required regarding if asynchronous resource capability accounts for forcing & boosting effects on the steady state fault current (not the subtransient and transient).

David Ramkalawan, 9/7/2017

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Cynthia Lee, Exelon, 5, 9/7/2017

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Alyssa Hubbard, 9/7/2017

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The overcurrent element setting of 130% of the calculated current derived from the maximum aggregate nameplate MVA output at rated power factor is appropriate in most cases.  Texas RE recommends keeping the 130% threshold for overcurrent elements and allow for exceptions in those cases where entities are limited by manufacturer requirements or physical limitations.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 9/7/2017

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Jennifer Hohenshilt, Talen Energy Marketing, LLC, 6, 9/7/2017

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Donald Hargrove, OGE Energy - Oklahoma Gas and Electric Co., 3, 9/7/2017

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Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 3, 9/7/2017

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N/A

Normande Bouffard, 9/7/2017

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RSC no Con-Edison, Segment(s) 10, 2, 4, 5, 6, 7, 1, 3, 9/7/2017

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FMPA, Segment(s) , 8/2/2017

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Tennessee Valley Authority, Segment(s) 1, 3, 5, 6, 9/7/2017

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Option 5b is helpful and a clear improvement.  However, Option 5b isn’t a complete solution.  Not all solar and wind facilities are new.  Some wind / solar facilities won’t have an outside source that remains in business to provide internal capability curves.  Therefore, Option 5 should allow a simulation option where entities can show through a verified model (MOD-026 / MOD-027) that the wind / solar farm will remain on-line for widespread voltage depressions which drives the 130% overcurrent margin reliability requirement.

MRO NSRF, Segment(s) 3, 4, 5, 6, 1, 2, 6/14/2017

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ACES Standards Collaborators, Segment(s) 1, 5, 3, 4, 6, 9/7/2017

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Option 5b is helpful and a clear improvement. In addition, Reclamation recommends that Option 5 should allow a simulation option where entities can show through a verified model (MOD-026 / MOD-027) that the generator will remain on-line for widespread voltage depressions which drives the 130% overcurrent margin reliability requirement. Or, as approved in PRC-024-2, if Option 5 cannot be satisfied for older equipment, a statement such as, “Document the identification of regulatory or equipment limitations.”

Richard Jackson, U.S. Bureau of Reclamation, 1, 9/7/2017

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Southern Company, Segment(s) 1, 3, 5, 6, 8/3/2016

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Ann Carey, 9/7/2017

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Option 5b is helpful and a clear improvement.  However, Option 5b isn’t a complete solution.  Not all solar and wind facilities are new.  Some wind / solare facilities won’t have an outside source that remains in business to provide internal capability curves.  Therefore, Option 5 should allow a simulation option where entities can show through a verified model (MOD-026 / MOD-027) that the wind / solar farm will remain on-line for widespread voltage depressions which drives the 130% overcurrent margin reliability requirement.

Darnez Gresham, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 9/7/2017

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What is the need for option 5a with 5b being an option? Option 5b shows the correct way protective relays should be set and coordinated with equipement. If the protection can be set above the capability of the equipement output, what would be the reason to set the pickups at 130% above MVA unless you want a fault to cause more damage to the equipement being the clearing time could be delayed?

Jamie Monette, Allete - Minnesota Power, Inc., 1, 9/7/2017

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The SPP Standards Review Group has a concern that Figure A (page 32 redline version) doesn’t provide enough clarity on its purpose in reference to Option 5b. Additionally, we have a concern that the figure is missing the appropriate labeling methodology. We would ask the drafting team to provide more clarity in the Application Guideline Section of the Standard in reference to the figure’s significance to Option 5b as well as including the appropriate labeling methodology.

SPP Standards Review Group, Segment(s) , 9/7/2017

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Russell Noble, Cowlitz County PUD, 3, 9/8/2017

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Hot Answers

Laurie Williams, PNM Resources - Public Service Company of New Mexico, 1, 9/8/2017

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Theresa Rakowsky, 9/8/2017

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Other Answers

Manitoba Hydro, Segment(s) 5, 3, 6, 1, 8/8/2017

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Glen Farmer, Avista - Avista Corporation, 5, 8/23/2017

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

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Thomas Foltz, AEP, 5, 8/24/2017

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Entergy/NERC Compliance, Segment(s) 1, 5, 3/1/2017

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Tom Haire, 8/29/2017

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

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DTE Energy - DTE Electric, Segment(s) 5, 4, 3, 2/27/2017

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Leonard Kula, Independent Electricity System Operator, 2, 9/1/2017

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Neil Swearingen, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

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Aaron Cavanaugh, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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PPL NERC Registered Affiliates, Segment(s) 3, 1, 5, 6, 2/9/2017

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Laura Nelson, IDACORP - Idaho Power Company, 1, 9/6/2017

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Eleanor Ewry, 9/6/2017

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Elizabeth Axson, 9/6/2017

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Donald Lock, 9/6/2017

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

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Unfortunately, the addition of “e.g.” does not add clarity.  The SDT needs to clearly state what protection function each option in Table 1 applies to.

George Brown, Acciona Energy North America, 5, 9/6/2017

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David Ramkalawan, 9/7/2017

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With respect to phase directional instantaneous overcurrent supervisory elements (67 or 50) – associated with current-based communication protection systems please consider the following

  1. These relays will be affecting loading/generator loadability  only if communication system fail and there is a disturbance on the grid.  The Standard should not assume both events at the same time. 

  2. Calculations performed to calculate the settings for these type of relays show  that the settings are very close to the 3-phase fault current contributed from the generator in cases where sub-transient reactance of the machine is at a high value.  This will compromise the protection scheme because the changes proposed will make the protection scheme very insensitive. In case of a high resistance phase-to-ground fault, the protection scheme will not pick up the fault at the generator end.  In some extreme cases, the fault detector relay (67 or 50),  if set according to the current draft PRC-025 guidelines, may have to depend on the field forcing provided by the Automatic Voltage Regulator (AVR) before the fault current reaches the setpoint.  This will induce unnecessary delays in the protective action and may cause more damage to the BES element.

  3. Exelon proposes the following changes:

    1. These types of relays (67 or 50) should be deleted from the scope of this Standard for the reasons described above.

    2. If there is an issue with communication protection systems such that the pilot protection scheme acts like a simple overcurrent relay, and that condition is alarmed, then it is reasonable to require an entity to correct this condition within a short period of time.  Suggest the SDT add a requirement to correct such a condition within a certain timeframe.  For example the condition shall be corrected within a calendar quarter and if not resolved then the setpoints of 67 or 50 should be raised to a certain value.

    3. If SDT still wants to keep these relays within scope in spite of the reasoning/alternatives provided above, the the existing setting criteria the following should be added:
      “Minimum of the criteria 15a (or 15b) or 25% of the sub-transient current contribution from the generator using a pre-fault voltage of 1.0 and generator sub-transient unsaturated reactance and the main power transformer positive sequence reactance.

Cynthia Lee, Exelon, 5, 9/7/2017

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Alyssa Hubbard, 9/7/2017

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Rachel Coyne, Texas Reliability Entity, Inc., 10, 9/7/2017

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Jennifer Hohenshilt, Talen Energy Marketing, LLC, 6, 9/7/2017

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Donald Hargrove, OGE Energy - Oklahoma Gas and Electric Co., 3, 9/7/2017

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Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 3, 9/7/2017

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Normande Bouffard, 9/7/2017

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RSC no Con-Edison, Segment(s) 10, 2, 4, 5, 6, 7, 1, 3, 9/7/2017

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67 and 50 elements/relays should be out of scope due to the possibility of creating a protection sheme that may not pick up when it should.  See comments from Exelon.

FMPA, Segment(s) , 8/2/2017

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Tennessee Valley Authority, Segment(s) 1, 3, 5, 6, 9/7/2017

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The NERC standard refers to relays and the Table 1 heading refers to relays, but Pickup was struck and Option 5 refers to overcurrent elements.  Where the standard refers to “elements” please add the word “PRC-025 relay” in front to clearly state that only “PRC-025 relays” are applicable, not control systems, not protective algorithms, and not fuses.

If the drafting team meant to include more protective elements than relays, the NERC standard needs to clearly state the protective elements covered.  NERC standards are written to zero defect and subject matter experts must clearly understand where the law applies.  Until NERC standards allow some room for some small amount of error to be corrected without incurring a violation such as the six sigma or cyber security standards, NERC compliance standards and boundaries must be absolutely clear.

MRO NSRF, Segment(s) 3, 4, 5, 6, 1, 2, 6/14/2017

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ACES Standards Collaborators, Segment(s) 1, 5, 3, 4, 6, 9/7/2017

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The NERC standard refers to relays and the Table 1 heading refers to relays, but “pickup” was struck and Option 5 refers to overcurrent elements. Where the standard refers to “elements,” Reclamation recommends the drafting team insert the words “PRC-025 relay” to clearly state that only PRC-025 relays are applicable, not control systems, protective algorithms, or fuses.

If the drafting team meant to include more protective elements than relays, Reclamation recommends that the standard clearly state the applicable protective elements. This standard is written to zero-defect and subject matter experts must clearly understand where it does and does not apply. Unless the standard allows some room for a small amount of error to be corrected, the compliance thresholds must be absolutely clear.

Richard Jackson, U.S. Bureau of Reclamation, 1, 9/7/2017

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Southern Company, Segment(s) 1, 3, 5, 6, 8/3/2016

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Ann Carey, 9/7/2017

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The NERC standard refers to relays and the Table 1 heading refers to relays, but Pickup was struck and Option 5 refers to overcurrent elements.  Where the standard refers to “elements” please add the word “PRC-025 relay” in front to clearly state that only “PRC-025 relays” are applicable, not control systems, not protective algorithms, and not fuses.

 

If the drafting team meant to include more protective elements than relays, the NERC standard needs to clearly state the protective elements covered.  NERC standards are written to zero defect and subject matter experts must clearly understand where the law applies.  Until NERC standards allow some room for some small amount of error to be corrected without incurring a violation such as the six sigma or cyber security standards, NERC compliance standards and boundaries must be absolutely clear.

Darnez Gresham, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 9/7/2017

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Jamie Monette, Allete - Minnesota Power, Inc., 1, 9/7/2017

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SPP Standards Review Group, Segment(s) , 9/7/2017

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Russell Noble, Cowlitz County PUD, 3, 9/8/2017

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Hot Answers

Laurie Williams, PNM Resources - Public Service Company of New Mexico, 1, 9/8/2017

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Theresa Rakowsky, 9/8/2017

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Other Answers

Manitoba Hydro, Segment(s) 5, 3, 6, 1, 8/8/2017

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Glen Farmer, Avista - Avista Corporation, 5, 8/23/2017

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

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Thomas Foltz, AEP, 5, 8/24/2017

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Entergy/NERC Compliance, Segment(s) 1, 5, 3/1/2017

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Tom Haire, 8/29/2017

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

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DTE Energy - DTE Electric, Segment(s) 5, 4, 3, 2/27/2017

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Leonard Kula, Independent Electricity System Operator, 2, 9/1/2017

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Neil Swearingen, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

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Aaron Cavanaugh, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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PPL NERC Registered Affiliates, Segment(s) 3, 1, 5, 6, 2/9/2017

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Laura Nelson, IDACORP - Idaho Power Company, 1, 9/6/2017

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Eleanor Ewry, 9/6/2017

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Elizabeth Axson, 9/6/2017

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Donald Lock, 9/6/2017

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

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It is an improvement and adds additional clarity.

George Brown, Acciona Energy North America, 5, 9/6/2017

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David Ramkalawan, 9/7/2017

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Cynthia Lee, Exelon, 5, 9/7/2017

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Alyssa Hubbard, 9/7/2017

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Rachel Coyne, Texas Reliability Entity, Inc., 10, 9/7/2017

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Jennifer Hohenshilt, Talen Energy Marketing, LLC, 6, 9/7/2017

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No.  There is a discussion in the Technical Guidance section that discusses the inclusion of collector system protective elements.  However, Table 1 uses the NERC capitalized term “Element” which specifically excludes collector systems via NERC and industry agreement in 2014.  This is documented in the NERC bulk Electric System Definition Reference Document dated April 2014, see the cover page and page 21 of 85.

Donald Hargrove, OGE Energy - Oklahoma Gas and Electric Co., 3, 9/7/2017

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Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 3, 9/7/2017

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Normande Bouffard, 9/7/2017

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RSC no Con-Edison, Segment(s) 10, 2, 4, 5, 6, 7, 1, 3, 9/7/2017

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FMPA, Segment(s) , 8/2/2017

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Tennessee Valley Authority, Segment(s) 1, 3, 5, 6, 9/7/2017

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No.  There is a discussion in the Technical Guidance section that discusses the inclusion of collector system protective elements.  However, Table 1 uses the NERC capitalized term “Element” which specifically excludes collector systems via NERC and industry agreement in 2014.  This is documented in the NERC bulk Electric System Definition Reference Document dated April 2014, see the cover page and page 21 of 85.

Link: http://www.nerc.com/pa/RAPA/BES%20DL/bes_phase2_reference_document_20140325_final_clean.pdf 

Please state that Technical Guidance is for examples only, guidance isn’t enforceable and cannot alter the scope of compliance.

See attached document for diagrams.

MRO NSRF, Segment(s) 3, 4, 5, 6, 1, 2, 6/14/2017

Project 2016-04 PRC-025-2Final.docx

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ACES Standards Collaborators, Segment(s) 1, 5, 3, 4, 6, 9/7/2017

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Figure 3 of the Guidelines and Technical Basis section discusses the inclusion of collector system protective elements; however, the NERC defined term “Element” specifically excludes collector systems in accordance with the NERC bulk Electric System Definition Reference Document dated April 2014; see page 21 of 85. http://www.nerc.com/pa/RAPA/BES%20DL/bes_phase2_reference_document_20140325_final_clean.pdf

Reclamation recommends that the Guidelines and Technical Basis document state that it is an example only and is not enforceable, or remove the discussion on collector system protection elements.

If the drafting team intended to include collector system protective elements for zero-defect compliance monitoring and change management, Reclamation recommends the standard be revised to clearly state “PRC-025 collector system” or “PRC-025 collector system relay elements” throughout the standard, including the Applicability Section.

Richard Jackson, U.S. Bureau of Reclamation, 1, 9/7/2017

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Southern Company, Segment(s) 1, 3, 5, 6, 8/3/2016

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Ann Carey, 9/7/2017

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There is a discussion in the Technical Guidance section that discusses the inclusion of collector system protective elements.  However, Table 1 uses the NERC capitalized term “Element” which specifically excludes collector systems via NERC and industry agreement in 2014. 

 

Darnez Gresham, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 9/7/2017

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Jamie Monette, Allete - Minnesota Power, Inc., 1, 9/7/2017

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SPP Standards Review Group, Segment(s) , 9/7/2017

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Russell Noble, Cowlitz County PUD, 3, 9/8/2017

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Hot Answers

Laurie Williams, PNM Resources - Public Service Company of New Mexico, 1, 9/8/2017

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While it is not typical for a generator to be rated higher than the line connecting the GSU to the transmission system, PSE has concerns with setting the relays for the line based on the generator ratings.  Protective relays should be set according to the equipment that they are intended to protect (i.e. line relays should be set to protect the line, transformer relays should be set to protect the transformer, and generator relays should be set to protect the generator).  Setting a line relay to protect a generator, particularly when the line might be rated lower than the generator could result in damage to the line, and could potentially result in reduced reliability.

Theresa Rakowsky, 9/8/2017

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Other Answers

This sentence is confusing: “Simulated line voltage coincident with the highest Reactive Power

output achieved during field‐forcing in response to a 0.85 per unit of the line nominal voltage at the remote end of the line prior to field‐forcing”

Consider changing to: “Simulated line voltage at the relay location coincident with the highest Reactive Power output achieved during field‐forcing in response to a 0.85 per unit of the line nominal voltage at the remote end of the line prior to field‐forcing”???

Manitoba Hydro, Segment(s) 5, 3, 6, 1, 8/8/2017

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Glen Farmer, Avista - Avista Corporation, 5, 8/23/2017

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

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Thomas Foltz, AEP, 5, 8/24/2017

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Entergy/NERC Compliance, Segment(s) 1, 5, 3/1/2017

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Tom Haire, 8/29/2017

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

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DTE Energy - DTE Electric, Segment(s) 5, 4, 3, 2/27/2017

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Leonard Kula, Independent Electricity System Operator, 2, 9/1/2017

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Neil Swearingen, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

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Aaron Cavanaugh, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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PPL NERC Registered Affiliates, Segment(s) 3, 1, 5, 6, 2/9/2017

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Laura Nelson, IDACORP - Idaho Power Company, 1, 9/6/2017

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While it is not typical for a generator to be rated higher than the line connecting the GSU to the transmission system, PSE has concerns with setting the relays for the line based on the generator ratings.  Protective relays should be set according to the equipment that they are intended to protect (i.e. line relays should be set to protect the line, transformer relays should be set to protect the transformer, and generator relays should be set to protect the generator).  Setting a line relay to protect a generator, particularly when the line might be rated lower than the generator could result in damage to the line, and could potentially result in reduced reliability.

Eleanor Ewry, 9/6/2017

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Elizabeth Axson, 9/6/2017

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Entities that took NERC at their word in performing calculations and (where necessary) making changes under PRC-025-1 should be “grandfathered” for PRC-025-2.

Donald Lock, 9/6/2017

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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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Tri-State would like clarification on the phrase "and on the remote end of the line" used in the Relay Type column of Option 14. Looking at the red-lined language under "Figure 1" of the guidelines section, our understanding is that relay R3 is applicable only if it is set with an element directional toward the transmission system or is non-directional. If relay R3 is set directed toward the generator, it is not applicable. If that is the case we recommend splitting up the language between the 2 scenarios and adding a figure to make it clear. As it is currently written, it isn't clear that only the 1st of those scenarios is displayed in Figure 1. 

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

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George Brown, Acciona Energy North America, 5, 9/6/2017

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David Ramkalawan, 9/7/2017

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Cynthia Lee, Exelon, 5, 9/7/2017

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Alyssa Hubbard, 9/7/2017

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Rachel Coyne, Texas Reliability Entity, Inc., 10, 9/7/2017

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Entities that performed calculations per NERC guidance and (where necessary) making changes under PRC-025-1 should be "grandfathered" for PRC-025-2.

Jennifer Hohenshilt, Talen Energy Marketing, LLC, 6, 9/7/2017

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Donald Hargrove, OGE Energy - Oklahoma Gas and Electric Co., 3, 9/7/2017

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Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 3, 9/7/2017

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N/A

Normande Bouffard, 9/7/2017

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RSC no Con-Edison, Segment(s) 10, 2, 4, 5, 6, 7, 1, 3, 9/7/2017

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FMPA, Segment(s) , 8/2/2017

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Tennessee Valley Authority, Segment(s) 1, 3, 5, 6, 9/7/2017

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MRO NSRF, Segment(s) 3, 4, 5, 6, 1, 2, 6/14/2017

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ACES Standards Collaborators, Segment(s) 1, 5, 3, 4, 6, 9/7/2017

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Richard Jackson, U.S. Bureau of Reclamation, 1, 9/7/2017

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Southern Company, Segment(s) 1, 3, 5, 6, 8/3/2016

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Ann Carey, 9/7/2017

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Darnez Gresham, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 9/7/2017

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No because if you have multiple radial lines exporting the power from a generator, each line may not have the capability of carry the full power output of the generator. Engineers should have the ability to study individual installations and set the protection correctly for the equipment installed.

Jamie Monette, Allete - Minnesota Power, Inc., 1, 9/7/2017

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SPP Standards Review Group, Segment(s) , 9/7/2017

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Russell Noble, Cowlitz County PUD, 3, 9/8/2017

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Hot Answers

Laurie Williams, PNM Resources - Public Service Company of New Mexico, 1, 9/8/2017

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Theresa Rakowsky, 9/8/2017

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Other Answers

It would provide added clarity to include “non-directional” in front of “phase instantaneous overcurrent supervising elements (e.g. 50)” and “phase time overcurrent relay (e.g. 51)”.

Manitoba Hydro, Segment(s) 5, 3, 6, 1, 8/8/2017

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Glen Farmer, Avista - Avista Corporation, 5, 8/23/2017

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

- 0 - 0

Thomas Foltz, AEP, 5, 8/24/2017

- 0 - 0

Entergy/NERC Compliance, Segment(s) 1, 5, 3/1/2017

- 0 - 0

Tom Haire, 8/29/2017

- 0 - 0

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

- 0 - 0

The term “pickup” clearly indicates what part of the overcurrent device setting needs to meet the criteria.  Perhaps this term can be retained for current operated devices.

DTE Energy - DTE Electric, Segment(s) 5, 4, 3, 2/27/2017

- 0 - 0

Leonard Kula, Independent Electricity System Operator, 2, 9/1/2017

- 0 - 0

“Pickup” setting indicates the minimum operating value. Please retain the leading term “Pickup”.

Neil Swearingen, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

- 0 - 0

Aaron Cavanaugh, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

- 0 - 0

PPL NERC Registered Affiliates, Segment(s) 3, 1, 5, 6, 2/9/2017

- 0 - 0

- 0 - 0

Laura Nelson, IDACORP - Idaho Power Company, 1, 9/6/2017

- 0 - 0

Eleanor Ewry, 9/6/2017

- 0 - 0

Elizabeth Axson, 9/6/2017

- 0 - 0

Donald Lock, 9/6/2017

- 0 - 0

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

- 0 - 0

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

- 0 - 0

George Brown, Acciona Energy North America, 5, 9/6/2017

- 0 - 0

David Ramkalawan, 9/7/2017

- 0 - 0

See comments provided in the response to Question 2 above.

Cynthia Lee, Exelon, 5, 9/7/2017

- 0 - 0

Alyssa Hubbard, 9/7/2017

- 0 - 0

Texas RE noticed the term “Overcurrent Element Pick-up Tolerance” still exists in Attachment 1 Figure A.  Is this the SDT’s intention?

Rachel Coyne, Texas Reliability Entity, Inc., 10, 9/7/2017

- 0 - 0

Jennifer Hohenshilt, Talen Energy Marketing, LLC, 6, 9/7/2017

- 0 - 0

Donald Hargrove, OGE Energy - Oklahoma Gas and Electric Co., 3, 9/7/2017

- 0 - 0

Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 3, 9/7/2017

- 0 - 0

Normande Bouffard, 9/7/2017

- 0 - 0

RSC no Con-Edison, Segment(s) 10, 2, 4, 5, 6, 7, 1, 3, 9/7/2017

- 0 - 0

FMPA, Segment(s) , 8/2/2017

- 0 - 0

Tennessee Valley Authority, Segment(s) 1, 3, 5, 6, 9/7/2017

- 0 - 0

- 0 - 0

The applicability section states that PRC-025 applies to relays.  Removing “Pickup” suggests the drating team is looking for additional protective elements in addition to relays.  If the SDT plans to consider more than PRC-025 protective relays, the applicability criteria needs to be adjusted in addition to removing “Pickup”.  Relays or what is meant by relay for PRC-025 needs to be clearly defined so compliance can clearly identify when compliance has been met. 

MRO NSRF, Segment(s) 3, 4, 5, 6, 1, 2, 6/14/2017

- 0 - 0

ACES Standards Collaborators, Segment(s) 1, 5, 3, 4, 6, 9/7/2017

- 0 - 0

If Pickup is not removed:

Reclamation recommends the SDT provide clarifying language describing what removing “Pickup” means. Pickup for PRC-025 refers to “PRC-025 Relays,” meaning actual relays at the individual generators with pickup settings. This does not include 1) any individual generator control systems, 2) collector system protective relays that may be installed on the padmount transformers, or 3) collector system protective relays on the radial collectors at the collector substation.

If Pickup is removed:

Reclamation recommends the SDT decide what protective relays are to be included and explicitly specify them. The applicability section states that PRC-025 applies to relays. Removing “Pickup” suggests the drafting team is looking for protective elements in addition to relays. If the SDT intends to include more than PRC-025 protective relays, the applicability criteria must be adjusted in addition to removing “Pickup.”

Reclamation recommends the PRC-025 Applicability section should specifically reference 1) individual generator control systems that may trip the individual power producing resource, 2) collector system protective relays that may be installed on the padmount transformers, or 3) collector system protective relays on the radial collectors at the collector substation.

Richard Jackson, U.S. Bureau of Reclamation, 1, 9/7/2017

- 0 - 0

Southern Company, Segment(s) 1, 3, 5, 6, 8/3/2016

- 0 - 0

Ann Carey, 9/7/2017

- 0 - 0

The applicability section states that PRC-025 applies to relays.  Removing “Pickup” suggests the drating team is looking for additional protective elements in addition to relays.  If the SDT plans to consider more than PRC-025 protective relays, the applicability criteria needs to be adjusted in addition to removing “Pickup”.  Relays or what is meant by relay for PRC-025 needs to be clearly defined so compliance can clearly identify when compliance has been met. 

Darnez Gresham, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 9/7/2017

- 0 - 0

The setting that has to be met per the standard is the pickup setting, the standard does not talk about timing, just pickup, so why remove pickup from the table.

Jamie Monette, Allete - Minnesota Power, Inc., 1, 9/7/2017

- 0 - 0

SPP Standards Review Group, Segment(s) , 9/7/2017

- 0 - 0

Russell Noble, Cowlitz County PUD, 3, 9/8/2017

- 0 - 0

Hot Answers

Laurie Williams, PNM Resources - Public Service Company of New Mexico, 1, 9/8/2017

- 0 - 0

Theresa Rakowsky, 9/8/2017

- 0 - 0

Other Answers

Manitoba Hydro, Segment(s) 5, 3, 6, 1, 8/8/2017

- 0 - 0

Glen Farmer, Avista - Avista Corporation, 5, 8/23/2017

- 0 - 0

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

- 0 - 0

Thomas Foltz, AEP, 5, 8/24/2017

- 0 - 0

Entergy/NERC Compliance, Segment(s) 1, 5, 3/1/2017

- 0 - 0

Tom Haire, 8/29/2017

- 0 - 0

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

- 0 - 0

DTE Energy - DTE Electric, Segment(s) 5, 4, 3, 2/27/2017

- 0 - 0

Leonard Kula, Independent Electricity System Operator, 2, 9/1/2017

- 0 - 0

Neil Swearingen, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

- 0 - 0

Aaron Cavanaugh, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

- 0 - 0

PPL NERC Registered Affiliates, Segment(s) 3, 1, 5, 6, 2/9/2017

- 0 - 0

- 0 - 0

Laura Nelson, IDACORP - Idaho Power Company, 1, 9/6/2017

- 0 - 0

Eleanor Ewry, 9/6/2017

- 0 - 0

Elizabeth Axson, 9/6/2017

- 0 - 0

Donald Lock, 9/6/2017

- 0 - 0

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

- 0 - 0

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

- 0 - 0

George Brown, Acciona Energy North America, 5, 9/6/2017

- 0 - 0

David Ramkalawan, 9/7/2017

- 0 - 0

Cynthia Lee, Exelon, 5, 9/7/2017

- 0 - 0

Alyssa Hubbard, 9/7/2017

- 0 - 0

Rachel Coyne, Texas Reliability Entity, Inc., 10, 9/7/2017

- 0 - 0

Jennifer Hohenshilt, Talen Energy Marketing, LLC, 6, 9/7/2017

- 0 - 0

Donald Hargrove, OGE Energy - Oklahoma Gas and Electric Co., 3, 9/7/2017

- 0 - 0

Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 3, 9/7/2017

- 0 - 0

Normande Bouffard, 9/7/2017

- 0 - 0

RSC no Con-Edison, Segment(s) 10, 2, 4, 5, 6, 7, 1, 3, 9/7/2017

- 0 - 0

FMPA, Segment(s) , 8/2/2017

- 0 - 0

Tennessee Valley Authority, Segment(s) 1, 3, 5, 6, 9/7/2017

- 0 - 0

- 0 - 0

MRO NSRF, Segment(s) 3, 4, 5, 6, 1, 2, 6/14/2017

- 0 - 0

ACES Standards Collaborators, Segment(s) 1, 5, 3, 4, 6, 9/7/2017

- 0 - 0

Richard Jackson, U.S. Bureau of Reclamation, 1, 9/7/2017

- 0 - 0

Southern Company, Segment(s) 1, 3, 5, 6, 8/3/2016

- 0 - 0

Ann Carey, 9/7/2017

- 0 - 0

Darnez Gresham, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 9/7/2017

- 0 - 0

I do not agree with application of this standard. Protection should be set up and coordinated for individual installs not by generitc percentages above MVA nameplates. Setting criteria should not be enforced by NERC unless NERC is willing to take responsibility for any equipment damage from settings being set to high.

Jamie Monette, Allete - Minnesota Power, Inc., 1, 9/7/2017

- 0 - 0

SPP Standards Review Group, Segment(s) , 9/7/2017

- 0 - 0

Russell Noble, Cowlitz County PUD, 3, 9/8/2017

- 0 - 0

Hot Answers

Laurie Williams, PNM Resources - Public Service Company of New Mexico, 1, 9/8/2017

- 0 - 0

Theresa Rakowsky, 9/8/2017

- 0 - 0

Other Answers

The 36 months may not be long enough to replace the relays depending on the number of relays that have been identified for  replacement. Suggest a change to 60 months, or “prorated” (The implementation period will be different based on the number of protection units that have been identified for replacement).

Manitoba Hydro, Segment(s) 5, 3, 6, 1, 8/8/2017

- 1 - 0

 This does not allow for time needed to make any changes based on the new revision.  Altering the calculations and re-reviewing current changes that have been made in accordance with PRC-025-1 will take time.  Any non-compliant relays found due to the new revision may cause a delay in our ability to comply.  We would request that more time be given to allow for proper implemenation of this new revision. 

Glen Farmer, Avista - Avista Corporation, 5, 8/23/2017

- 2 - 0

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

- 0 - 0

Depending on the date that version 2 would eventually be approved, it is possible that that the version 2 enforcement date, for those assets explicitly in scope under version 1, could actually be earlier than the existing version 1 enforcement date. AEP recommends that the version 2 enforcement date should have the exact same enforcement date as in version 1 for those assets already explicitly in scope under version 1. As an example, the table below shows what would happen if the effective date for version 2 of PRC-025 were to be June 1 of 2018. As shown in the table provided, the version two enforcement dates for assets already explicitly in scope under version one, both for assets where no removal or replacement is necessary and for assets requiring removal or replacement, would be sooner that their corresponding enforecement dates under version one.

 

Requirement

Effective Date

Enforcement Date

PRC-025-1 R1 (No removal or replacement necessary)

10/01/14

10/01/19

PRC-025-2 R1 Assets Already Explictly in Scope (No removal or replacement necessary)

06/01/18

06/01/19

PRC-025-1 R1 (Requires removal or replacement)

10/01/14

10/01/21

PRC-025-2 R1  Assets Already  Explictly in Scope (Requires removal or replacement)

06/01/18

05/31/21

AEP has chosen to vote negative on the proposed draft of PRC-025-2, driven by our concerns related to the proposed implementation plan.

Thomas Foltz, AEP, 5, 8/24/2017

- 2 - 0

Entergy/NERC Compliance, Segment(s) 1, 5, 3/1/2017

- 0 - 0

Tom Haire, 8/29/2017

- 0 - 0

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

- 0 - 0

DTE Energy - DTE Electric, Segment(s) 5, 4, 3, 2/27/2017

- 0 - 0

Leonard Kula, Independent Electricity System Operator, 2, 9/1/2017

- 0 - 0

Neil Swearingen, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

- 0 - 0

Aaron Cavanaugh, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

- 0 - 0

PPL NERC Registered Affiliates, Segment(s) 3, 1, 5, 6, 2/9/2017

- 0 - 0

- 0 - 0

Laura Nelson, IDACORP - Idaho Power Company, 1, 9/6/2017

- 0 - 0

Eleanor Ewry, 9/6/2017

- 0 - 0

Elizabeth Axson, 9/6/2017

- 0 - 0

The Implementation Plan should not require taking a special outage for PRC-025, and should therefore allow at least five years to make relay settings changes, and seven years to install new devices.

Donald Lock, 9/6/2017

- 0 - 0

The Implementation Period should align with the existing Implementation Period of PRC-025-1 because that is what utilities have been working toward.

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

- 1 - 0

As currently written, it appears the implementation plan can actually shorten the current timeframes to become compliant with PRC-025. If PRC-025-2 was approved and became effective prior to 10/1/18, entities would have less time to comply with the 2 scenarios under "Load-responsive protective relays subject to the standard" in the implementation plans. Currently entities have until 10/1/19 to comply when they will be making a setting change to meet the setting criteria and 10/1/21 to comply when they will be removing/replacing the relay to meet the setting criteria. Tri-State recommends adding language similar to the commonly used "shall become effective on the later of XXXX or the first day of the XX calendar quarter". That would prevent entities from losing time they might have already planned on having to become complaint with PRC-025-1.

Additionally, can the SDT explain why they changed the timeframes (from 60 and 84 months to 12 and 36 months respectively) under "Load-responsive protective relays subject to the standard" but not the ones under "Load-responsive protective relays which become applicable to the standard" provided in the implementation plans.

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

- 1 - 0

George Brown, Acciona Energy North America, 5, 9/6/2017

- 0 - 0

OPG recommends changing the implementation plan since there is no correlation between the number of the relays requiring replacement and the arbitrary implementation period. We suggest the implementation period to be a function of the number of relays involved. Alternate graded approach is also possible i.e. 25, 50, 75 & 100% corresponding to 5 years.

David Ramkalawan, 9/7/2017

- 0 - 0

Cynthia Lee, Exelon, 5, 9/7/2017

- 0 - 0

Implementation Period should align with the existing Implementation Period of PRC-025-1 because that is what utilities have been working toward.   

Alyssa Hubbard, 9/7/2017

- 0 - 0

The proposed Implementation Plan is consistent with the timelines for compliance with PRC-025-1.  Texas RE suggests the SDT clarifies that entities making a determination that replacement or removal is necessary, triggering the 36-month compliance window, should document those conclusions.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 9/7/2017

- 0 - 0

The Implementation Plan should not require taking a special outage for PRC-025, and should therefore allow at least five years to make relay settings changes, and seven years to install new devices.

Jennifer Hohenshilt, Talen Energy Marketing, LLC, 6, 9/7/2017

- 0 - 0

Donald Hargrove, OGE Energy - Oklahoma Gas and Electric Co., 3, 9/7/2017

- 0 - 0

Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 3, 9/7/2017

- 0 - 0

Normande Bouffard, 9/7/2017

- 0 - 0

RSC no Con-Edison, Segment(s) 10, 2, 4, 5, 6, 7, 1, 3, 9/7/2017

- 0 - 0

FMPA, Segment(s) , 8/2/2017

- 0 - 0

TVA does not agree that a 12-month implementation period is sufficient for changes to relay settings that now may be required due to the new applicability of the 50 (instantaneous overcurrent) element in PRC-025-2 Draft 1.  The original PRC-025-1 implementation plan allowed 5 years from approval to implement settings changes.  This 5-year period was sufficient for implementing new relay settings, even for nuclear units which are tied to refueling outage schedules.  TVA has seven nuclear units.  Some other entities have even more.  It is unreasonable to expect nuclear units to schedule additional outages that could be required within the proposed 1-year implementation period, just to perform relay settings changes.

Tennessee Valley Authority, Segment(s) 1, 3, 5, 6, 9/7/2017

- 2 - 0

- 0 - 0

The SDT was not clear with its first implementation that collector systems were in scope as Technical Guidance cannot alter the scope of compliance and the applicability section 4.2.5 by itself did not make it clear that non-BES collector systems were being included contrary to the NERC Bulk Electric System Definition Reference Document dated April of 2014.  Entities need another 60 months to staff and build systems of record supporting zero defect compliance monitoring and change management on non-BES collector systems.

MRO NSRF, Segment(s) 3, 4, 5, 6, 1, 2, 6/14/2017

- 0 - 0

The current standard’s implementation plan states that the entity must be compliant by October 2019, or by October 2021 for the removal or replacement of applicable relays.  The proposed implementation plan only identifies the retirement of the previous standard and does not provide a transition period between revisions.  We propose incorporating a clause that begins the compliance period no earlier than October 2019, and no earlier than October 2021 for the removal or replacement of applicable relays.

ACES Standards Collaborators, Segment(s) 1, 5, 3, 4, 6, 9/7/2017

- 0 - 0

Unless the SDT clarifies that the PRC-025 applicability section refers only to PRC-025 relays on 1) substation Bulk Electric System (BES) elements and 2) individual power producing resource relays at the BES generators, and that all collector system protective relays are excluded, the first implementation of PRC-025-1 was not clear and entities will need 60 months to staff and build systems to support zero-defect compliance monitoring and change management.

Richard Jackson, U.S. Bureau of Reclamation, 1, 9/7/2017

- 0 - 0

Southern Company, Segment(s) 1, 3, 5, 6, 8/3/2016

- 0 - 0

It would be beneficial for maintenance requirement to align with PRC-005 maintenance requirement since time between scheduled outages for generation units can be as long as 36 months.

Ann Carey, 9/7/2017

- 0 - 0

The SDT was not clear with its first implementation that collector systems were in scope as Technical Guidance cannot alter the scope of compliance and the applicability section 4.2.5 by itself did not make it clear that non-BES collector systems were being included contrary to the NERC Bulk Electric System Definition Reference Document dated April of 2014.  Entities need another 60 months to staff and build systems of record supporting zero defect compliance monitoring and change management on non-BES collector systems.

Darnez Gresham, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 9/7/2017

- 0 - 0

Jamie Monette, Allete - Minnesota Power, Inc., 1, 9/7/2017

- 0 - 0

SPP Standards Review Group, Segment(s) , 9/7/2017

- 0 - 0

Russell Noble, Cowlitz County PUD, 3, 9/8/2017

- 0 - 0

Hot Answers

Laurie Williams, PNM Resources - Public Service Company of New Mexico, 1, 9/8/2017

- 0 - 0

Theresa Rakowsky, 9/8/2017

- 0 - 0

Other Answers

Manitoba Hydro, Segment(s) 5, 3, 6, 1, 8/8/2017

- 0 - 0

Glen Farmer, Avista - Avista Corporation, 5, 8/23/2017

- 0 - 0

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

- 0 - 0

Thomas Foltz, AEP, 5, 8/24/2017

- 0 - 0

Entergy/NERC Compliance, Segment(s) 1, 5, 3/1/2017

- 0 - 0

Tom Haire, 8/29/2017

- 0 - 0

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

- 0 - 0

DTE Energy - DTE Electric, Segment(s) 5, 4, 3, 2/27/2017

- 0 - 0

Leonard Kula, Independent Electricity System Operator, 2, 9/1/2017

- 0 - 0

Neil Swearingen, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

- 0 - 0

Aaron Cavanaugh, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

- 0 - 0

PPL NERC Registered Affiliates, Segment(s) 3, 1, 5, 6, 2/9/2017

- 0 - 0

- 0 - 0

Laura Nelson, IDACORP - Idaho Power Company, 1, 9/6/2017

- 0 - 0

Eleanor Ewry, 9/6/2017

- 0 - 0

Elizabeth Axson, 9/6/2017

- 0 - 0

Donald Lock, 9/6/2017

- 0 - 0

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

- 0 - 0

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

- 0 - 0

George Brown, Acciona Energy North America, 5, 9/6/2017

- 0 - 0

David Ramkalawan, 9/7/2017

- 0 - 0

Cynthia Lee, Exelon, 5, 9/7/2017

- 0 - 0

Alyssa Hubbard, 9/7/2017

- 0 - 0

Texas RE recommends changing the “and” to an “or”.  Additionally, Texas RE requests the SDT consider providing a justification of the “Long Term Planning” time horizon as it has a significant impact on Penalty calculations.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 9/7/2017

- 0 - 0

Jennifer Hohenshilt, Talen Energy Marketing, LLC, 6, 9/7/2017

- 0 - 0

Donald Hargrove, OGE Energy - Oklahoma Gas and Electric Co., 3, 9/7/2017

- 0 - 0

Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 3, 9/7/2017

- 0 - 0

Normande Bouffard, 9/7/2017

- 0 - 0

RSC no Con-Edison, Segment(s) 10, 2, 4, 5, 6, 7, 1, 3, 9/7/2017

- 0 - 0

FMPA, Segment(s) , 8/2/2017

- 0 - 0

Tennessee Valley Authority, Segment(s) 1, 3, 5, 6, 9/7/2017

- 0 - 0

- 0 - 0

MRO NSRF, Segment(s) 3, 4, 5, 6, 1, 2, 6/14/2017

- 0 - 0

We believe a performance-based criteria could be established for the Violation Severity Levels for this standard, similar to what is present for NERC Reliability Standard PRC-005-6.  In that standard, the severity is based on a specific percentage of Components the applicable entity failed to maintain in accordance with minimum maintenance activities and maximum maintenance intervals.  We recommend using the same criteria for this standard.

ACES Standards Collaborators, Segment(s) 1, 5, 3, 4, 6, 9/7/2017

- 0 - 0

Reclamation recommends there is a need for high/moderate/low VSLs based on the number of relays impacted by the standard. Reclamation recommends a VSL similar to that for PRC-005-6 R3 and R4. Reclamation recommends the following VSLs:

Requirement Number - R1

Lower VSL - The entity failed to apply settings in accordance with PRC-025-2 Attachment 1: Relay Settings, on fewer than 5% of its load-responsive protective relays.

Moderate VSL - The entity failed to apply settings in accordance with PRC-025-2 Attachment 1: Relay Settings, on 5% to less than 10% of its load-responsive protective relays.

High VSL - The entity failed to apply settings in accordance with PRC-025-2 Attachment 1: Relay Settings, on 10% to less than 15% of its load-responsive protective relays.

Severe VSL - The entity failed to apply settings in accordance with PRC-025-2 Attachment 1: Relay Settings, on 15% or more of its load-responsive protective relays.

 

 

 

 

Richard Jackson, U.S. Bureau of Reclamation, 1, 9/7/2017

- 0 - 0

Southern Company, Segment(s) 1, 3, 5, 6, 8/3/2016

- 0 - 0

Ann Carey, 9/7/2017

- 0 - 0

Darnez Gresham, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 9/7/2017

- 0 - 0

Stating that this is a severe VSL and high VRF is way more severe than the actual risk for not being in compliance with PRC-025-2 especially for asynchronous generators. If the settings and studies are done correctly there is no risk of false tripping even if the pickups are not as high as the requirements in this standard.

Jamie Monette, Allete - Minnesota Power, Inc., 1, 9/7/2017

- 0 - 0

SPP Standards Review Group, Segment(s) , 9/7/2017

- 0 - 0

Russell Noble, Cowlitz County PUD, 3, 9/8/2017

- 0 - 0

Hot Answers

Laurie Williams, PNM Resources - Public Service Company of New Mexico, 1, 9/8/2017

- 0 - 0

Theresa Rakowsky, 9/8/2017

- 0 - 0

Other Answers

Manitoba Hydro, Segment(s) 5, 3, 6, 1, 8/8/2017

- 0 - 0

Glen Farmer, Avista - Avista Corporation, 5, 8/23/2017

- 0 - 0

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

- 0 - 0

Thomas Foltz, AEP, 5, 8/24/2017

- 0 - 0

These options, and other options, which use the phrase “gross MW reported to the Transmission Planner” needs clarity. That values are reported to the Transmission Planner annually. These values change somewhat, annually. Should Transmission Owners re-evalute that data and the settings derived from that data annually? I believe the spirit of PRC-025 is met with a one-time implmenetation based on this generator data. There should be no burden on Transmission Owners to re-evaluate this geneator data every year and re-calculate setitngs every year. Even if the Transmission Owner chooses to calculate settings on data more conservative than what is reported to the Transmission Planner, there should not be a requirement against annually chaning data.

Entergy/NERC Compliance, Segment(s) 1, 5, 3/1/2017

- 0 - 0

Tom Haire, 8/29/2017

- 0 - 0

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

- 0 - 0

DTE Energy - DTE Electric, Segment(s) 5, 4, 3, 2/27/2017

- 0 - 0

Leonard Kula, Independent Electricity System Operator, 2, 9/1/2017

- 0 - 0

Neil Swearingen, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

- 0 - 0

Aaron Cavanaugh, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

- 0 - 0

PPL NERC Registered Affiliates, Segment(s) 3, 1, 5, 6, 2/9/2017

- 0 - 0

- 0 - 0

Laura Nelson, IDACORP - Idaho Power Company, 1, 9/6/2017

- 0 - 0

Eleanor Ewry, 9/6/2017

- 0 - 0

Elizabeth Axson, 9/6/2017

- 0 - 0

Entities that took NERC at their word in performing calculations and (where necessary) making changes under PRC-025-1 should be “grandfathered” for PRC-025-2.

Donald Lock, 9/6/2017

- 0 - 0

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

- 0 - 0

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

- 0 - 0

George Brown, Acciona Energy North America, 5, 9/6/2017

- 0 - 0

David Ramkalawan, 9/7/2017

- 0 - 0

See comments and alternative approaches to meet the intent of the Standard in response to Question 2 above.

Cynthia Lee, Exelon, 5, 9/7/2017

- 0 - 0

Alyssa Hubbard, 9/7/2017

- 0 - 0

Texas RE does not have comments on this question.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 9/7/2017

- 0 - 0

 Entities that performed calculations per NERC guidance and (where necessary) making changes under PRC-025-1 should be "grandfathered" for PRC-025-2.r

Jennifer Hohenshilt, Talen Energy Marketing, LLC, 6, 9/7/2017

- 0 - 0

Donald Hargrove, OGE Energy - Oklahoma Gas and Electric Co., 3, 9/7/2017

- 0 - 0

Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 3, 9/7/2017

- 0 - 0

N/A

Normande Bouffard, 9/7/2017

- 0 - 0

RSC no Con-Edison, Segment(s) 10, 2, 4, 5, 6, 7, 1, 3, 9/7/2017

- 0 - 0

FMPA, Segment(s) , 8/2/2017

- 0 - 0

Tennessee Valley Authority, Segment(s) 1, 3, 5, 6, 9/7/2017

- 0 - 0

- 0 - 0

Not as proposed.  Cost efficiency can be achieved by focusing on the right impactful objectives.  Focus on common-mode design issues and exclude zero defect compliance monitoring / change management for individual collector systems or individual dispersed power producing resources.

The NSRF suggests the SDT modify the applicability section to concentrate of common-mode design issues affecting 75 MVA or more of aggregated dispersed power resource generators.  Zero defect compliance monitoring and change management for collector systems and individual generators should be clearly excluded similar to PRC-005-6.

This appropriately focuses compliance efforts on the measurable impacts of common mode design issues and reduces the administrative burden of explicitly tracking and monitoring individual dispersed power producing resources.

MRO NSRF, Segment(s) 3, 4, 5, 6, 1, 2, 6/14/2017

- 0 - 0

We believe the standard is too inclusive of all load-responsive protective relays.  The applicability of this standard should be reflective of other PRC Standards, such as NERC Reliability Standard PRC-019-2, and based on the BES definition and gross nameplate ratings of generation Facilities.

ACES Standards Collaborators, Segment(s) 1, 5, 3, 4, 6, 9/7/2017

- 0 - 0

Cost efficiency would be achieved by focusing on the correct impactful objectives, such as common-mode design issues, while excluding zero-defect compliance monitoring/change management for individual collector systems or individual dispersed power producing resources.

For example, without an outside source to provide internal capability curves, Option 5 may be extremely labor intensive to develop and maintain to zero-defect.

Zero-defect compliance monitoring and change management for collector systems and individual generators should be clearly excluded similar to PRC-005-6. Reclamation recommends the SDT modify the applicability section to concentrate on common-mode design issues affecting 75 MVA or more of aggregated dispersed power resource generators. This appropriately focuses compliance efforts on the measurable impacts of common-mode design issues and reduces the administrative burden of explicitly tracking and monitoring individual dispersed power producing resources.

Richard Jackson, U.S. Bureau of Reclamation, 1, 9/7/2017

- 0 - 0

Southern Company, Segment(s) 1, 3, 5, 6, 8/3/2016

- 0 - 0

Ann Carey, 9/7/2017

- 0 - 0

Not as proposed.  Cost efficiency can be achieved by focusing on the right impactful objectives.  Focus on common-mode design issues and exclude zero defect compliance monitoring / change management for individual collector systems or individual dispersed power producing resources.

 

The NSRF suggests the SDT modify the applicability section to concentrate of common-mode design issues affecting 75 MVA or more of aggregated dispersed power resource generators.  Zero defect compliance monitoring and change management for collector systems and individual generators should be clearly excluded similar to PRC-005-6.

 

This appropriately focuses compliance efforts on the measurable impacts of common mode design issues and reduces the administrative burden of explicitly tracking and monitoring individual dispersed power producing resources.

Darnez Gresham, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 9/7/2017

- 0 - 0

Jamie Monette, Allete - Minnesota Power, Inc., 1, 9/7/2017

- 0 - 0

SPP Standards Review Group, Segment(s) , 9/7/2017

- 0 - 0

Russell Noble, Cowlitz County PUD, 3, 9/8/2017

- 0 - 0

Hot Answers

Laurie Williams, PNM Resources - Public Service Company of New Mexico, 1, 9/8/2017

- 0 - 0

Theresa Rakowsky, 9/8/2017

- 0 - 0

Other Answers

Manitoba Hydro, Segment(s) 5, 3, 6, 1, 8/8/2017

- 0 - 0

Glen Farmer, Avista - Avista Corporation, 5, 8/23/2017

- 0 - 0

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

- 0 - 0

Thomas Foltz, AEP, 5, 8/24/2017

- 0 - 0

Entergy/NERC Compliance, Segment(s) 1, 5, 3/1/2017

- 0 - 0

Tom Haire, 8/29/2017

- 0 - 0

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

- 0 - 0

DTE Energy - DTE Electric, Segment(s) 5, 4, 3, 2/27/2017

- 0 - 0

Leonard Kula, Independent Electricity System Operator, 2, 9/1/2017

- 0 - 0

Neil Swearingen, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

- 0 - 0

Aaron Cavanaugh, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

- 0 - 0

PPL NERC Registered Affiliates, Segment(s) 3, 1, 5, 6, 2/9/2017

- 0 - 0

- 0 - 0

Laura Nelson, IDACORP - Idaho Power Company, 1, 9/6/2017

- 0 - 0

Eleanor Ewry, 9/6/2017

- 0 - 0

Elizabeth Axson, 9/6/2017

- 0 - 0

Donald Lock, 9/6/2017

- 0 - 0

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

- 0 - 0

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

- 0 - 0

George Brown, Acciona Energy North America, 5, 9/6/2017

- 0 - 0

David Ramkalawan, 9/7/2017

- 0 - 0

Cynthia Lee, Exelon, 5, 9/7/2017

- 0 - 0

Alyssa Hubbard, 9/7/2017

- 0 - 0

Rachel Coyne, Texas Reliability Entity, Inc., 10, 9/7/2017

- 0 - 0

Jennifer Hohenshilt, Talen Energy Marketing, LLC, 6, 9/7/2017

- 0 - 0

Donald Hargrove, OGE Energy - Oklahoma Gas and Electric Co., 3, 9/7/2017

- 0 - 0

Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 3, 9/7/2017

- 0 - 0

No from a technical point of view, but there might be some regional variances with the version approved by the Regie de l'Énergie du Québec.

Normande Bouffard, 9/7/2017

- 0 - 0

RSC no Con-Edison, Segment(s) 10, 2, 4, 5, 6, 7, 1, 3, 9/7/2017

- 0 - 0

FMPA, Segment(s) , 8/2/2017

- 0 - 0

Tennessee Valley Authority, Segment(s) 1, 3, 5, 6, 9/7/2017

- 0 - 0

- 0 - 0

No, but the SDT should check to see if the inclusion of collectors sytem(s) could infringe on state jurisdictions.

MRO NSRF, Segment(s) 3, 4, 5, 6, 1, 2, 6/14/2017

- 0 - 0

ACES Standards Collaborators, Segment(s) 1, 5, 3, 4, 6, 9/7/2017

- 0 - 0

Reclamation recommends that the SDT check to see if the inclusion of collector systems could infringe on state jurisdictions.

Richard Jackson, U.S. Bureau of Reclamation, 1, 9/7/2017

- 0 - 0

Southern Company, Segment(s) 1, 3, 5, 6, 8/3/2016

- 0 - 0

Ann Carey, 9/7/2017

- 0 - 0

No, but the SDT should check to see if the inclusion of collectors sytem(s) could infringe on state jurisdictions.

Darnez Gresham, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 9/7/2017

- 0 - 0

Jamie Monette, Allete - Minnesota Power, Inc., 1, 9/7/2017

- 0 - 0

SPP Standards Review Group, Segment(s) , 9/7/2017

- 0 - 0

Russell Noble, Cowlitz County PUD, 3, 9/8/2017

- 0 - 0

Hot Answers

Laurie Williams, PNM Resources - Public Service Company of New Mexico, 1, 9/8/2017

- 0 - 0

Theresa Rakowsky, 9/8/2017

- 0 - 0

Other Answers

Manitoba Hydro, Segment(s) 5, 3, 6, 1, 8/8/2017

- 0 - 0

Glen Farmer, Avista - Avista Corporation, 5, 8/23/2017

- 0 - 0

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

- 0 - 0

Thomas Foltz, AEP, 5, 8/24/2017

- 0 - 0

Entergy/NERC Compliance, Segment(s) 1, 5, 3/1/2017

- 0 - 0

Tom Haire, 8/29/2017

- 0 - 0

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

- 0 - 0

DTE Energy - DTE Electric, Segment(s) 5, 4, 3, 2/27/2017

- 0 - 0

Leonard Kula, Independent Electricity System Operator, 2, 9/1/2017

- 0 - 0

Neil Swearingen, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

- 0 - 0

Aaron Cavanaugh, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

- 0 - 0

PPL NERC Registered Affiliates, Segment(s) 3, 1, 5, 6, 2/9/2017

- 0 - 0

- 0 - 0

Laura Nelson, IDACORP - Idaho Power Company, 1, 9/6/2017

- 0 - 0

Eleanor Ewry, 9/6/2017

- 0 - 0

Elizabeth Axson, 9/6/2017

- 0 - 0

Donald Lock, 9/6/2017

- 0 - 0

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

- 0 - 0

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

- 0 - 0

George Brown, Acciona Energy North America, 5, 9/6/2017

- 0 - 0

David Ramkalawan, 9/7/2017

- 0 - 0

Cynthia Lee, Exelon, 5, 9/7/2017

- 0 - 0

Alyssa Hubbard, 9/7/2017

- 0 - 0

Texas RE requests this question be included for each project.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 9/7/2017

- 0 - 0

Jennifer Hohenshilt, Talen Energy Marketing, LLC, 6, 9/7/2017

- 0 - 0

Donald Hargrove, OGE Energy - Oklahoma Gas and Electric Co., 3, 9/7/2017

- 0 - 0

Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 3, 9/7/2017

- 0 - 0

Hydro-Québec TransÉnergie has proposed calculations and simulations for a particular configuration.

Normande Bouffard, 9/7/2017

- 0 - 0

RSC no Con-Edison, Segment(s) 10, 2, 4, 5, 6, 7, 1, 3, 9/7/2017

- 0 - 0

FMPA, Segment(s) , 8/2/2017

- 0 - 0

Tennessee Valley Authority, Segment(s) 1, 3, 5, 6, 9/7/2017

- 0 - 0

- 0 - 0

MRO NSRF, Segment(s) 3, 4, 5, 6, 1, 2, 6/14/2017

- 0 - 0

ACES Standards Collaborators, Segment(s) 1, 5, 3, 4, 6, 9/7/2017

- 0 - 0

Richard Jackson, U.S. Bureau of Reclamation, 1, 9/7/2017

- 0 - 0

Southern Company, Segment(s) 1, 3, 5, 6, 8/3/2016

- 0 - 0

It would be beneficial for maintenance requirement to align with PRC-005 maintenance requirement since time between scheduled outages for generation units can be as long as 36 months.

Ann Carey, 9/7/2017

- 0 - 0

Darnez Gresham, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 9/7/2017

- 0 - 0

Jamie Monette, Allete - Minnesota Power, Inc., 1, 9/7/2017

- 0 - 0

SPP Standards Review Group, Segment(s) , 9/7/2017

- 0 - 0

Russell Noble, Cowlitz County PUD, 3, 9/8/2017

- 0 - 0

Hot Answers

I was not able to log my vote in SBS despite being in the ballot pool and attempting to vote affirmative before the ballot close time.  Please contact me to ensure this issue is remedied. 

Laurie Williams, PNM Resources - Public Service Company of New Mexico, 1, 9/8/2017

- 0 - 0

Theresa Rakowsky, 9/8/2017

- 0 - 0

Other Answers

Manitoba Hydro, Segment(s) 5, 3, 6, 1, 8/8/2017

- 0 - 0

Glen Farmer, Avista - Avista Corporation, 5, 8/23/2017

- 0 - 0

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

- 0 - 0

AEP has chosen to vote negative on the proposed draft of PRC-025-2, driven by our concerns related to the proposed implementation plan (detailed in our response to Q7).

AEP recommends a more appropriate per unit voltage level of 0.85 per unit, rather than 1.0 per unit, for options 13a, 13b, 17, and 18 within Table 1.

In the Applicability section, all references to “3.2, Facilities” should instead be “4.2, Facilities.”

Thomas Foltz, AEP, 5, 8/24/2017

- 0 - 0

Entergy/NERC Compliance, Segment(s) 1, 5, 3/1/2017

- 0 - 0

Section 4.2.5 should have a minimum threshhold. 

Section 4.1 should reference 4.2 not 3.2

Tom Haire, 8/29/2017

- 0 - 0

Duke Energy recommends the drafting team consider adding another option (perhaps 13c) that would address the high side UAT overcurrent settings under this standard. We suggest adding:

“Where there is only one UAT low side protective device that is set at a minimum 135% of the UAT nameplate or 135% or greater than load operating at .85 per unit voltage, the UAT high side protective device must be set equal to or coordinate with the low side protective device.”

The issue this would address is the prudent protection settings and compliance of the high side overcurrent with the standard. In some instances, the high side overcurrent is coordinating with the low side overcurrent. Currently, there is nothing that is addressing the low side. We feel that this is a technical flaw in the standard, which should be addressed.

Also, there are some instances where some BES UAT’s with high side fuses will operate at less that 150% UAT ratings. Based on these instances, we feel that fuses should be considered as an addition to the relay type category.

We suggest that the drafting team consider making the changes referenced above to correct the technical errors, or remove references to the UAT in the standard altogether.

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

- 0 - 0

none

DTE Energy - DTE Electric, Segment(s) 5, 4, 3, 2/27/2017

- 0 - 0

Leonard Kula, Independent Electricity System Operator, 2, 9/1/2017

- 0 - 0

Neil Swearingen, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

- 0 - 0

Aaron Cavanaugh, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

- 0 - 0

Section 4.1 (Functional Entities) references the Elements listed in Section 3.2 (Facilities); however, Section 3.2 (Facilities) does not exist within the PRC-025-2 – Generator Relay Loadability proposed standard document.  Section 4.1 (Functional Entities) should instead be updated to reference the Elements listed in Section 4.2 (Facilities).

PPL NERC Registered Affiliates, Segment(s) 3, 1, 5, 6, 2/9/2017

- 0 - 0

Please clarify if switch-onto-fault is meant to be included in Attachment 1: Relay Settings. Exclusion #1 states, “Any relay elements that are in service only during start up.” Is switch-onto-fault included as an element that is only service during start up? PRC-023 specifically addresses switch-onto-fault in Attachment A as applicable to the standard; addressing switch-on-to-fault in PRC-025 would provide consistency and clarity between the two similar standards. 

- 0 - 0

Laura Nelson, IDACORP - Idaho Power Company, 1, 9/6/2017

- 0 - 0

Eleanor Ewry, 9/6/2017

- 0 - 0

Elizabeth Axson, 9/6/2017

- 0 - 0

Donald Lock, 9/6/2017

- 0 - 0

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

- 0 - 0

Tri-State would like to point out that there seems to be an error in "Section 4.1 Functional Entities" where the sub bullets are referencing section "3.2, Facilities." That should be "4.2, Facilities."

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

- 0 - 0

As written, NERC Reliability Standard PRC-025-2 Generator Relay Loadability does not account for equipment limitations of the generator step-up transformer or generation lead line that would not allow an entity to set it’s protective relays to the level as specified within the standard.  The SDT needs add additional option for these application that is similar to option 5B.

George Brown, Acciona Energy North America, 5, 9/6/2017

- 0 - 0

OPG recommend that instead of “relay location” to use “relay associated instrument transformers (PT’s/CT’s) location”.

Clarification are recommended for the cases where the protective device settings are not achievable due to additional possible constrictions related to the supply path associated equipment. This can be achieved by defining the “resource” in Option 5b.

David Ramkalawan, 9/7/2017

- 0 - 0

None. Thank You

Cynthia Lee, Exelon, 5, 9/7/2017

- 0 - 0

Alyssa Hubbard, 9/7/2017

- 0 - 0

Texas RE inquires about the use of the Application Guideline as there are several changes in the works with regards to attached documents.  Texas RE’s understanding is that any guidance as to how to comply with a standard will go through the Implementation Guidance process.  Any technical basis will be in a Technical Rationale document.  How does the Application Guidance in PRC-025-2 fit in with the new schematic?

 

In addition, Texas RE requests the technical reason that the GO might provide a base setting on capability that is higher than what is reported to the Transmission planner, as noted in Attachment 1.

 

Texas RE also noticed the following grammatical issues/typos:

  • The header still has “-1” throughout Standard. 

  • Applicability section 4.1 references “3.2, Facilities” which does not exist.  It should reference “4.2, Facilities”.

  • Facility section 4.2.4 has two sentences that conflict.  The first sentence says “used exclusively to export”; the second sentence says “may also supply”. If an element is used exclusively for something, that precludes it from also including something else.

  • The Compliance Monitoring Process section is incorrectly numbered as “8” (and subparts 8.1, 8.2, etc.).

Rachel Coyne, Texas Reliability Entity, Inc., 10, 9/7/2017

- 0 - 0

Jennifer Hohenshilt, Talen Energy Marketing, LLC, 6, 9/7/2017

- 0 - 0

The SDT should modify the applicability section to concentrate on common-mode design issues affecting 75 MVA or more of aggregated dispersed power resource generators.  Zero defect compliance monitoring and change management for collector systems and individual generators should be clearly excluded as in PRC-005-6.

This appropriately focuses compliance efforts on the measurable impacts of common mode design issues and reduces the administrative burden of explicitly tracking and monitoring individual dispersed power producing resources.

Donald Hargrove, OGE Energy - Oklahoma Gas and Electric Co., 3, 9/7/2017

- 1 - 0

In Table 1, Relay Type column, for Options 14, 15, 16, 17, 18, and 19, consider changing “…installed on the high-side of the GSU transformer and [on the] remote end of the line” to something like “…installed on the high-side of the GSU transformer and/or [on the] remote end of the line” or “…installed on the high-side of the GSU transformer, including [on the] remote end of the line.”  A simple ‘and’ suggests that relaying at both locations may be required.

Marc Donaldson, Tacoma Public Utilities (Tacoma, WA), 3, 9/7/2017

- 0 - 0

Normande Bouffard, 9/7/2017

- 0 - 0

RSC no Con-Edison, Segment(s) 10, 2, 4, 5, 6, 7, 1, 3, 9/7/2017

- 0 - 0

Table 1 seems to explicity require specific reach settings and does not address how to comply with the standard if using a quad element and not a mho element, even though a quad element is uncommon in generator relays.  Additionally, there is not a clear path in the standard regarding load encroachment blocking.  Load encroachment blocking is mentioned in the PRC-025-1 Application Guideline and the the NERC SPCS report “Considerations for Power Plant and Transmission System Protection Coordination” but is absent in the standard. 

FMPA, Segment(s) , 8/2/2017

- 0 - 0

Several times the term “Real Power output” is defined in the proposed standard as “100% of the aggregate generation gross MW capability reported to the Transmission Planner.”  TVA believes that it can be difficult to determine what is meant by “capability reported to the transmission planner,” and would like to see the standard clarify on which reporting mechanism or process this generation capability is normally expected to be based.  A Transmission Planner can have multiple capabilities reported for one unit.  For example, a MOD-025 capability verified by test or operational data, versus a planned capability that reflects a modification to be implemented in the near future.

Tennessee Valley Authority, Segment(s) 1, 3, 5, 6, 9/7/2017

- 0 - 0

- 0 - 0

Member entities, regulators, and regional entities need to have the same pictures and concepts so that potential staff and cost effectiveness discussions can be considered.  Consider the following individual dispersed power producing resource picture discussed at the PRC-025 SDT.

For clarity, consider comparing impacts in terms of PRC-025 devices to PRC-005 devices.  Discuss PRC-025 “protective elements” or devices (which can be more than relays) expected by the PRC-025 drafting team. 

As an example, a GE wind turbine can have two nacelle breakers / relays and a molded case breaker /relay at the base of the wind tower, creating three “protective elements” or devices per wind turbine.  Each wind turbine has a 690 / 34,500 volt padmount transformer with a low-side and high-side fuse potentially creating three more “protective elements” or devices per padmount if included in the PRC-025 protective element definition.  Each radial collector can handle approximately 20 - 30 MVA and typically has 10 – 15 turbines per single radial collector breaker.  All of these items (and potentially more, given the “smart crowbar” example from the recent NERC lessons learned) would have to be tracked for zero defects, such as perfect settings, coordinated, and perfect knowledge of changes.

Extrapolating the above example for approximately 3,000 wind turbines you could easily have a PRC-025 program that quickly surpasses the workload of a PRC-005-6 program:

  1. Wind turbine protective elements (breakers CB1, CB2, and CB3 per turbine) = 3*3,000 turbines = 9,000 protective elements to track and coordinate.

  2. Other wind turbine protective elements such as smart crowbars = 1 smart crowbar * 3,000 turbines = 3,000 protective elements to track and coordinate.

  3. Each wind turbine has a padmount transformer that may need to be tracked and coordinated = 3,000 padmount transformers to track and coordinate.

  4. Padmount protective elements such as fuses (one high-side and one low-side) if included in a future protective element definition = 2*3,000 padmount transformers = 6,000 protective elements to track and coordinate.

  5. Radial collector breakers = 300 radial collector breakers assuming on average each collector breaker serves approximately 10 MVA of wind generation and coordinate.

In this 3,000 wind turbine example there are 21,300 “protective elements” to track and maintain to zero defect for PRC-025.  Exclude the padmount transformer fuses, and the number drops by 6,000 devices to 15,300.  Excluding the padmount transformers and fuses drops the number to 12,300 devices to track and coordinate.  This doesn’t include the substation System Protection devices that we already consider at the substation. 

What benefit is derived from zero defect compliance monitoring and change management of individual PRC-025 protective elements versus addressing common mode design issues

Below are some possible comments on PRC-025 to focus on the important reliability impacts of common-mode design issues versus individual resources or protective elements.

Proposed Solution:

1.       Request that the PRC-025 standards drafting team consider the following applicability section changes to differentiate between significant Bulk Electric System (BES) Impacts that risk the loss of 75 MVA or more versus the loss of individual collectors or individual generators.

Replace the proposed Applicability section 3.2.5

3.2.5          Elements utilized in the aggregation of dispersed power producing resources

With:

3.2.5        Dispersed Power Producing Resource collector system common design mode issues that risk the loss of 75 MVA or more for a single event.

3.2.6        Protection elements used in aggregating dispersed BES generation from the point where those resources aggregate to greater than 75 MVA to a common point of connection at 100kV or above are excluded except for common design mode issues identified for 3.2.5.

2.       Request that the PRC-025 standards drafting team consider defining “Protective element” for PRC-025 means, “protective tripping relays, protective tripping padmount relays, or protective generator control system trips designed to limit individual generator damage on the collector system.  Protective element excludes fuses.

3.       Request that the PRC-025 standards drafting team consider defining a NERC Dispersed Power Producing Resource Collector System such as:

Collector System:  Radial facilities used to aggregate dispersed power producing resources designed primarily to deliver such aggregate capacity to a common point of connection at a voltage of 100 kV or above.

4.       Request that the PRC-025 standards drafting team consider modifying the existing NERC definition of “Element” and “Facility” to separate plant issues from individual generator issues (thanks to Darnez for this item): 

NERC Defined Element:  Any electrical device with terminals that may be connected to other electrical devices such as a generator, an individual generator, an individual dispersed power producing resource, transformer, circuit breaker, bus section, or transmission line. An Element may be comprised of one or more components.

NERC Defined Facility:  A set of electrical equipment that operates as a single Bulk Electric System Element (e.g., a line, a generator generating plant or aggregate dispersed power producing plant, a shunt compensator, transformer, etc.)

Please see attached document for diagram.

MRO NSRF, Segment(s) 3, 4, 5, 6, 1, 2, 6/14/2017

Project 2016-04 PRC-025-2Final.docx

- 0 - 0

  1. Section 4.1 identifies functional entities that are applicable to this standard.  These entities apply load-responsive protective relays at the terminal ends of the Elements identified in Section 3.2, Facilities. However, we believe the applicability of these Facilities are listed under Section 4.2.  We observe this inconsistency throughout the standard.
  2. This project continues to run independent of the current implementation plan identified for NERC Reliability Standard PRC-024-1.  Although the phased-in implementation of this standard is still on-going, it very probable that a registered entity has already developed a complete compliance program that addresses the current version of this standard.  We simply ask the SDT to acknowledge this possibility.
  3. We thank you for this opportunity to provide these comments.

ACES Standards Collaborators, Segment(s) 1, 5, 3, 4, 6, 9/7/2017

- 0 - 0

Reclamation recommends the SDT clarify the definition of Unit Auxiliary Transformer (UAT) in footnote 1 on page 3 of 112 of the standard to state that a Unit Auxiliary Transformer does not include excitation supply power potential transformers.

Reclamation recommends the SDT clarify what benefit is derived from zero-defect compliance monitoring and change management of individual PRC-025 protective elements versus addressing common mode design issues.

Reclamation recommends the SDT clarify the definition of Unit Auxiliary Transformer (UAT) in footnote 1 on page 3 of 112 of the standard to state that, “a Unit Auxiliary Transformer does not include excitation supply power potential transformers.”

For clarity, Reclamation recommends the SDT state the PRC-025 “protective elements” or devices (which can be more than relays) expected to be in scope. Reclamation recommends the SDT evaluate the impact of PRC-025 in terms of the number of PRC-025 devices, similar to the impact of PRC-005. All of these items (and potentially more, based on the recent NERC Lesson Learned, “Loss of Wind Turbines due to Transient Voltage Disturbances on the Bulk Transmission System”) would have to be tracked for zero defects, such as perfect settings and perfect knowledge of changes. This could result in an entity’s PRC-025 program being the same or greater size and workload as its PRC-005-6 program.

Following are some possible solutions to help focus on the important reliability impacts of common-mode design issues versus individual resources or protective elements.

Proposed Solutions:

1. Reclamation recommends that the drafting team consider the following applicability section changes to differentiate between significant Bulk Electric System (BES) Impacts that risk the loss of 75 MVA or more and the loss of individual collectors or individual generators.

Reclamation recommends replacing the proposed Applicability section 3.2.5

3.2.5 Elements utilized in the aggregation of dispersed power producing resources.

with:

3.2.5 Dispersed Power Producing Resource collector system common design mode issues that risk the loss of 75 MVA or more for a single event.

3.2.6 Protection elements used in aggregating dispersed BES generation from the point where those resources aggregate to greater than 75 MVA to a common point of connection at 100kV or above are excluded except for common design mode issues identified in 3.2.5.

2. Reclamation recommends that the drafting team consider defining “protective element” as, “protective tripping relays, protective tripping padmount relays, or protective generator control system trips designed to limit individual generator damage on the collector system.” A protective element excludes fuses.

3. Reclamation recommends that the drafting team consider adding a NERC Glossary defined term of “Dispersed Power Producing Resource Collector System” such as:

Collector System: Radial facilities used to aggregate dispersed power producing resources designed primarily to deliver such aggregate capacity to a common point of connection at a voltage of 100 kV or above.

4. Reclamation recommends that the drafting team consider modifying the existing NERC Glossary definitions of “Element” and “Facility” to separate plant issues from individual generator issues as follows:

Element: Any electrical device with terminals that may be connected to other electrical devices such as an individual generator, an individual dispersed power producing resource, transformer, circuit breaker, bus section, or transmission line. An Element may be comprised of one or more components.

Facility: A set of electrical equipment that operates as a single Bulk Electric System Element (e.g., a line, a generating plant or aggregate dispersed power producing plant, a shunt compensator, transformer, etc.)

Richard Jackson, U.S. Bureau of Reclamation, 1, 9/7/2017

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Figure examples should be added to show examples of “elements utilized in the aggregation of dispersed power producing resources” for clarity as the BES definition excludes these elements from the BES. 

Southern Company, Segment(s) 1, 3, 5, 6, 8/3/2016

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Ann Carey, 9/7/2017

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Member entities, regulators, and regional entities need to have the same pictures and concepts so that potential staff and cost effectiveness discussions can be considered.  Consider the following individual dispersed power producing resource picture discussed at the PRC-025 SDT.

For clarity, consider comparing impacts in terms of PRC-025 devices to PRC-005 devices.  Discuss PRC-025 “protective elements” or devices (which can be more than relays) expected by the PRC-025 drafting team. 

As an example, a GE wind turbine can have two nacelle breakers / relays and a molded case breaker /relay at the base of the wind tower, creating three “protective elements” or devices per wind turbine.  Each wind turbine has a 690 / 34,500 volt padmount transformer with a low-side and high-side fuse potentially creating three more “protective elements” or devices per padmount if included in the PRC-025 protective element definition.  Each radial collector can handle approximately 20 - 30 MVA and typically has 10 – 15 turbines per single radial collector breaker.  All of these items (and potentially more, given the “smart crowbar” example from the recent NERC lessons learned) would have to be tracked for zero defects, such as perfect settings, coordinated, and perfect knowledge of changes.

Extrapolating the above example for approximately 3,000 wind turbines you could easily have a PRC-025 program that quickly surpasses the workload of a PRC-005-6 program:

  1. Wind turbine protective elements (breakers CB1, CB2, and CB3 per turbine) = 3*3,000 turbines = 9,000 protective elements to track and coordinate.

  2. Other wind turbine protective elements such as smart crowbars = 1 smart crowbar * 3,000 turbines = 3,000 protective elements to track and coordinate.

  3. Each wind turbine has a padmount transformer that may need to be tracked and coordinated = 3,000 padmount transformers to track and coordinate.

  4. Padmount protective elements such as fuses (one high-side and one low-side) if included in a future protective element definition = 2*3,000 padmount transformers = 6,000 protective elements to track and coordinate.

  5. Radial collector breakers = 300 radial collector breakers assuming on average each collector breaker serves approximately 10 MVA of wind generation and coordinate.

  6.  

    In this 3,000 wind turbine example there are 21,300 “protective elements” to track and maintain to zero defect for PRC-025.  Exclude the padmount transformer fuses, and the number drops by 6,000 devices to 15,300.  Excluding the padmount transformers and fuses drops the number to 12,300 devices to track and coordinate.  This doesn’t include the substation System Protection devices that we already consider at the substation. 

     

    What benefit is derived from zero defect compliance monitoring and change management of individual PRC-025 protective elements versus addressing common mode design issues?

     

    Below are some possible comments on PRC-025 to focus on the important reliability impacts of common-mode design issues versus individual resources or protective elements.

     

    Proposed Solution:

     

    1.       Request that the PRC-025 standards drafting team consider the following applicability section changes to differentiate between significant Bulk Electric System (BES) Impacts that risk the loss of 75 MVA or more versus the loss of individual collectors or individual generators.

     

    Replace the proposed Applicability section 3.2.5

    3.2.5          Elements utilized in the aggregation of dispersed power producing resources.

     

    With:

    3.2.5        Dispersed Power Producing Resource collector system common design mode issues that risk the loss of 75 MVA or more for a single event.

    3.2.6        Protection elements used in aggregating dispersed BES generation from the point where those resources aggregate to greater than 75 MVA to a common point of connection at 100kV or above are excluded except for common design mode issues identified for 3.2.5.

     

    2.       Request that the PRC-025 standards drafting team consider defining “Protective element” for PRC-025 means, “protective tripping relays, protective tripping padmount relays, or protective generator control system trips designed to limit individual generator damage on the collector system.  Protective element excludes fuses.

     

    3.       Request that the PRC-025 standards drafting team consider defining a NERC Dispersed Power Producing Resource Collector System such as:

     

    Collector System:  Radial facilities used to aggregate dispersed power producing resources designed primarily to deliver such aggregate capacity to a common point of connection at a voltage of 100 kV or above.

     

    4.       Request that the PRC-025 standards drafting team consider modifying the existing NERC definition of “Element” and “Facility” to separate plant issues from individual generator issues (thanks to Darnez for this item): 

     

    NERC Defined Element:  Any electrical device with terminals that may be connected to other electrical devices such as a generator, an individual generator, an individual dispersed power producing resource, transformer, circuit breaker, bus section, or transmission line. An Element may be comprised of one or more components.

     

    NERC Defined Facility:  A set of electrical equipment that operates as a single Bulk Electric System Element (e.g., a line, a generator generating plant or aggregate dispersed power producing plant, a shunt compensator, transformer, etc.)

     

Darnez Gresham, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 9/7/2017

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 All settings should be based off load ability and equipment ratings like option 5b allows. Setting elements to arbitrary values called out in PRC-025 is not good sound engineering and poor practice for protecting electrical equipment. Settings should be based on IEEE standards and studies preformed by the professional licensed engineer developing the settings.

Jamie Monette, Allete - Minnesota Power, Inc., 1, 9/7/2017

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SPP Standards Review Group, Segment(s) , 9/7/2017

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Applicability Section 4.1 references "3.2, Facilities."  This appears to be a typographical error; consider correcting to reference "4.2 Facilities.

Russell Noble, Cowlitz County PUD, 3, 9/8/2017

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