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2017-01 Modifications to BAL-003-1.1

Description:

Start Date: 12/04/2018
End Date: 01/17/2019

Associated Ballots:

Ballot Name Project Standard Pool Open Pool Close Voting Start Voting End
2017-01 Modifications to BAL-003-1.1 BAL-003-2 IN 1 ST 2017-01 Modifications to BAL-003-1.1 BAL-003-2 12/04/2018 01/02/2019 01/08/2019 01/17/2019
2017-01 Modifications to BAL-003-1.1 BAL-003-2 Non-Binding Poll IN 1 NB 2017-01 Modifications to BAL-003-1.1 BAL-003-2 Non-Binding Poll 12/04/2018 01/02/2019 01/08/2019 01/17/2019
2017-01 Modifications to BAL-003-1.1 Implementation Plan IN 1 OT 2017-01 Modifications to BAL-003-1.1 Implementation Plan 12/04/2018 01/02/2019 01/08/2019 01/17/2019

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Hot Answers

Kevin Salsbury, Berkshire Hathaway - NV Energy, 5, 1/17/2019

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We believe replacing the RCC with the RLPC will bring consistency across all interconnections and will eliminate the need of having a higher expectation from the Eastern Interconnection. Additionally, revising the verbiage associated with the MSSC, as one the basis for IFRO, has improved the overall technicality of the RPLC. 

ACES Standard Collaborations, Segment(s) 1, 3, 6, 4, 1/17/2019

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Other Answers

Maryanne Darling-Reich, On Behalf of: Black Hills Corporation - WECC - Segments 1, 3, 5, 6

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The proposed methodology does appear to produce consistent results; however it represents a resource loss that may not actually manifest itself in practice. It does appear to provide a reasonable margin to reduce the potential for triggering UFLS operation due to insufficient frequency response. We appreciate the efforts of the SDT, however we believe it needs to be recognized that the proposed methodology is based-on (as well as highly dependent-on) the current resource mix and configuration.

Thomas Foltz, AEP, 5, 1/4/2019

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

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

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The California ISO supports the comments of the ISO/RTO Council Standards Review Committee (SRC) and has one additional comment under item 4 below.

Richard Vine, 1/11/2019

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

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SRC, Segment(s) 2, 1/14/2019

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BPA supports replacing the Resource Contingency Criteria (RCC) with the Resource Loss Protection Criteria (RLPC). BPA agrees this methodology is appropriate for determining the magnitude of the resource loss events that each Interconnection should protect against to assure an adequate level of reliability.

BPA suggests that the SDT review the Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard to ensure that the language regarding RLPC matches the Resource Loss Protection Criteria document.

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

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AZPS appreciates the changes that were made that largely address our concerns and many others in the industry. AZPS now largely supports the RLPC with one important distinction. We believe the description of the RLPC is inaccurately described in the first bullet of Chapter 3 of the Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard

“The two largest Balancing Contingency Events due to a single contingency identified using system models in terms of loss measured by megawatt loss in a normal system configuration (N-0). (An abnormal system configuration is not used to determine the RLPC.) ”

We do not believe the intent is two events that are caused by a single contingency, which would be an N-2. Perhaps a better way to state what is intended is the language used in the proposed BAL-003-2, “the two largest potential Balancing Contingency Events that exist within a Balancing Authority identified using system models in terms of loss measured by megawatt loss in a normal system configuration (N-0). (An abnormal system configuration is not used to determine the RLPC.)”

Michelle Amarantos, 1/14/2019

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

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Preston Walker, On Behalf of: PJM Interconnection, L.L.C., SERC, RF, Segments 2

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Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 5, 1/15/2019

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Diana Torres, On Behalf of: Imperial Irrigation District, , Segments 1, 3, 5, 6

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Louisville Gas and Electric Company and Kentucky Uitilities Company (LG&E/KU) generally agree with the proposed methodology. However, Page 1 of the RLPC document contains the statement: “The MSSC calculation is done in Real-time operations based on actual system configuration.”  However, not every BA or RSG determines MSSC in real time – many do not.  We recommend the SDT delete this statement for accuracy.

Louisville Gas and Electric Company and Kentucky Utilities Company, Segment(s) 3, 5, 6, 9/6/2018

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

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

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MRO NSRF, Segment(s) 3, 4, 5, 6, 1, 2, 7/19/2017

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Douglas Webb, On Behalf of: Bryan Taggart, Westar Energy, 1,3,5,6; Bryan Taggart, Westar Energy, 1,3,5,6; Bryan Taggart, Westar Energy, 1,3,5,6; Derek Brown, Westar Energy, 1,3,5,6; Derek Brown, Westar Energy, 1,3,5,6; Derek Brown, Westar Energy, 1,3,5,6; Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., ; Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., ; Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., ; Grant Wilkerson, Westar Energy, 1,3,5,6; Grant Wilkerson, Westar Energy, 1,3,5,6; Grant Wilkerson, Westar Energy, 1,3,5,6; Allen Klassen, Westar Energy, 1,3,5,6; Allen Klassen, Westar Energy, 1,3,5,6; Allen Klassen, Westar Energy, 1,3,5,6

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RSC no Dominion, Segment(s) 10, 2, 4, 5, 7, 3, 1, 0, 6, 1/17/2019

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Sandra Shaffer, Berkshire Hathaway - PacifiCorp, 6, 1/17/2019

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SPP Standards Review Group, Segment(s) 2, 8/30/2018

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Hot Answers

Kevin Salsbury, Berkshire Hathaway - NV Energy, 5, 1/17/2019

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ACES Standard Collaborations, Segment(s) 1, 3, 6, 4, 1/17/2019

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Other Answers

Maryanne Darling-Reich, On Behalf of: Black Hills Corporation - WECC - Segments 1, 3, 5, 6

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Thomas Foltz, AEP, 5, 1/4/2019

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

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

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The California ISO supports the comments of the ISO/RTO Council Standards Review Committee (SRC) and has one additional comment under item 4 below.

Richard Vine, 1/11/2019

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

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The SRC agrees with fixing the IFROs in Attachment A during the remainder of Project 2017-01 assuming the SDT is talking about the minor changes that arise from NERC’s annual frequency analysis, and not that the SDT is precluding the three step change in the East’s IFRO.

SRC, Segment(s) 2, 1/14/2019

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There are several reasons that BPA cannot agree with keeping IFROs as scheduled in the revised Attachment A during the remainder of Project 2017-01.

    • The IFRO First Step for the Western Interconnection includes a Load Credit of 120 MW. There is no Load Credit for a PDCI RAS event.

Alternative approach: BPA asks that the First Step for WECC be recalculated without the Load Credit applied.

    • It is apparent that the First Step IFRO in the BAL-003 redline was calculated as (RLPC - Load Credit) / 10 * MDF

However, it is not apparent how the Max Delta Frequency (MDF) was determined since the tables with subcomponents such as the CBR (C to B ratio) are missing from the standard or a supporting document. The standard does say: “Detailed descriptions of the calculations used in Table 1 below are defined in the Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard.” But the ERO Support of Frequency Response and Frequency Bias Setting Standard does not detail at all how the calculations used in Table 1 are defined, because the calculations were removed from that document.

Alternative approach: BPA recommends that the methodology for determining IFRO and MDF be detailed in Attachment A and that Table 1 be moved to a NERC document that can be updated yearly. The IFRO and MDF are key components of the current standard and the methodology for calculating it must be in Attachment A so that it cannot change without industry vote and FERC approval. BPA supports a change in the IFRO methodology through Phase II of Project 2017-01, at which point Attachment A should be updated.

    • The revised standard states that “**To reduce risk, the Eastern Interconnection IFRO will be stepped down annually from the 2017 value of -1,015 MW/0.1 Hz in -100 MW/0.1 Hz increments. If during the step down process, Interconnection Frequency Response Measure (FRM) declines by more than 10% percent, the ERO will halt the reduction in IFRO until such times that a determination can be made as to the cause of the degradation.”  

      BPA believes that this is not adequate for reliability.

      Alternative approach: BPA recommends that if the Interconnection Frequency Response Measure (FRM) declines by more than 10% percent, the ERO raise the IFRO back to the previous step.

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

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AZPS questions the logic that the newly proposed methodology for IFRO would only be valid to apply this one time until after Phase Two is completed. If it is believed that this IFRO methodology is technically valid, then it should be valid until an approved alternative is determined and approved. AZPS would also suggest leaving the currently determined values based on this methodology out of the actual standard since all of the contributing elements are subject to change based on the procedure and could quickly become inaccurate. It may be more appropriate to publish the currently determined values in the procedure, which can be updated often as necessary, and not in the standard. 

Michelle Amarantos, 1/14/2019

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

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Preston Walker, On Behalf of: PJM Interconnection, L.L.C., SERC, RF, Segments 2

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Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 5, 1/15/2019

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Diana Torres, On Behalf of: Imperial Irrigation District, , Segments 1, 3, 5, 6

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LG&E/KU agrees with keeping IFROs as scheduled in Attachment A, but we recommend the Drafting Team specify that IFROs will be as shown in Table 1 of Attachment A. Additionally, Table 1 should specify the applicable OY for the changes in EI IFRO, rather than the “First, Second, and Final Steps.”

Louisville Gas and Electric Company and Kentucky Utilities Company, Segment(s) 3, 5, 6, 9/6/2018

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

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

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The MRO NSRF agrees with fixing the IFROs in Attachment A during the remainder of Project 2017-01 assuming the SDT is talking about the minor changes that arise from NERC’s annual frequency analysis, and not that the SDT is precluding the three step change in the East’s IFRO.

MRO NSRF, Segment(s) 3, 4, 5, 6, 1, 2, 7/19/2017

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Douglas Webb, On Behalf of: Bryan Taggart, Westar Energy, 1,3,5,6; Bryan Taggart, Westar Energy, 1,3,5,6; Bryan Taggart, Westar Energy, 1,3,5,6; Derek Brown, Westar Energy, 1,3,5,6; Derek Brown, Westar Energy, 1,3,5,6; Derek Brown, Westar Energy, 1,3,5,6; Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., ; Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., ; Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., ; Grant Wilkerson, Westar Energy, 1,3,5,6; Grant Wilkerson, Westar Energy, 1,3,5,6; Grant Wilkerson, Westar Energy, 1,3,5,6; Allen Klassen, Westar Energy, 1,3,5,6; Allen Klassen, Westar Energy, 1,3,5,6; Allen Klassen, Westar Energy, 1,3,5,6

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RSC no Dominion, Segment(s) 10, 2, 4, 5, 7, 3, 1, 0, 6, 1/17/2019

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Sandra Shaffer, Berkshire Hathaway - PacifiCorp, 6, 1/17/2019

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The SPP Standards Review Group (“SSRG”) agrees with the proposal to fix the IFRO while the drafting team works on Phase 2. The 2017 FRAA dynamics study and subsequent filing to FERC confirmed the -1,015 MW/0.1Hz IFRO value to be the reliability limit. Without another dynamics study, we do not support the lowering of the IFRO to the values listed in Attachment A. Additionally, the issue may not be the actual determination of the RLPC, but rather how the IFRO is calculated (considering  that formula results in an IFRO recommendation below previously established limits).

SPP Standards Review Group, Segment(s) 2, 8/30/2018

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Hot Answers

Kevin Salsbury, Berkshire Hathaway - NV Energy, 5, 1/17/2019

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ACES Standard Collaborations, Segment(s) 1, 3, 6, 4, 1/17/2019

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Other Answers

Maryanne Darling-Reich, On Behalf of: Black Hills Corporation - WECC - Segments 1, 3, 5, 6

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While beneficial, the procedure document is not sufficiently complete to be considered a procedure. For completeness’ sake, the document should contain a revision record, a section covering rolls and responsibilities, and a section describing the methods that should be used to limit the reduction of IFRO. While we agree with keeping the document outside the defined process for standards development and balloting, we believe there should still be a rigorous mechanism for when changes are developed, proposed, and potentially adopted.

More specificity is needed in “Chapter 1: Event Selection Process”, as it is not clear what criteria is to be used going forward. The statistical relevance driver used results in a large portion of events selected for the EI, where neither the BAs nor the GO/GOP has had any appreciable influence on frequency response.

Our comments in this section notwithstanding, we acknowledge that our concerns may eventually be addressed as part of Phase 2.

Thomas Foltz, AEP, 5, 1/4/2019

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

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

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The California ISO supports the comments of the ISO/RTO Council Standards Review Committee (SRC) and has one additional comment under item 4 below.

Richard Vine, 1/11/2019

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

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SRC, Segment(s) 2, 1/14/2019

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BPA believes that the IFRO and MDF calculation methodology should be established and detailed in Attachment A so that it is transparent to all parties.  The Table 1 of values, that can change yearly, should be moved to another NERC document that is not subject to the NERC standard development process. Any subsequent IFRO and MDF calculation methodology as determined in Phase II of Project 2017-01 should also reside in Attachment A.

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

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AZPS agrees with the moving of these administrative items from the standard to the procedure. AZPS asks the Drafting Team to provide clarity on whether Form 2s are also required to be submitted and if so, please include in the procedure. And as mentioned in response to Question 2, please consider moving the table which demonstrates what the currently calculated values are for RLPC, CLR, and IFRO for the coming years out of the standard and into the procedure as well.

Michelle Amarantos, 1/14/2019

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

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Preston Walker, On Behalf of: PJM Interconnection, L.L.C., SERC, RF, Segments 2

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Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 5, 1/15/2019

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IID believes that this will simply the FRO and FR settings. Indirectly this can also reduce risk when the FRM is reduced dramatically.

Diana Torres, On Behalf of: Imperial Irrigation District, , Segments 1, 3, 5, 6

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LG&E/KU recommends that the Event Selection Criteria include a consideration for load level at the time of the event.  Load provides a frequency response benefit that is proportional to the amount and type of load on-line at the time of the event. Therefore, events occurring during light load realize less of this benefit, and such events will exhibit greater volatility in frequency excursions.  Selection of too many events during low load periods can skew the results, which will not provide the most accurate view of an interconnection’s “normal” FR capability.

Louisville Gas and Electric Company and Kentucky Utilities Company, Segment(s) 3, 5, 6, 9/6/2018

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

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

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MRO NSRF, Segment(s) 3, 4, 5, 6, 1, 2, 7/19/2017

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Douglas Webb, On Behalf of: Bryan Taggart, Westar Energy, 1,3,5,6; Bryan Taggart, Westar Energy, 1,3,5,6; Bryan Taggart, Westar Energy, 1,3,5,6; Derek Brown, Westar Energy, 1,3,5,6; Derek Brown, Westar Energy, 1,3,5,6; Derek Brown, Westar Energy, 1,3,5,6; Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., ; Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., ; Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., ; Grant Wilkerson, Westar Energy, 1,3,5,6; Grant Wilkerson, Westar Energy, 1,3,5,6; Grant Wilkerson, Westar Energy, 1,3,5,6; Allen Klassen, Westar Energy, 1,3,5,6; Allen Klassen, Westar Energy, 1,3,5,6; Allen Klassen, Westar Energy, 1,3,5,6

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RSC no Dominion, Segment(s) 10, 2, 4, 5, 7, 3, 1, 0, 6, 1/17/2019

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Sandra Shaffer, Berkshire Hathaway - PacifiCorp, 6, 1/17/2019

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SPP Standards Review Group, Segment(s) 2, 8/30/2018

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Hot Answers

The original SAR that brought about the SDT discussed the need for application of governor standards to the GO’s.  NV Energy recognizes that no reference to this item from the SAR is addressed in Phase 1, or in the proposed changes coming in Phase 2.  In its Notice of Proposed Rulemaking (NOPR) on Primary Frequency Response (Docket No. RM16-6-000), FERC stated that proposed modifications to Generator Interconnection Agreements for both large and small generating facilities (both synchronous and non-synchronous) would require new generators to install, maintain, and operate equipment capable of providing primary frequency response as a condition of interconnection.  FERC recognized that “[w]hile NERC Reliability Standard BAL-003-1.1 establishes requirements for balancing authorities, it does not include any requirements for individual generator owners or operators,” and that “[w]hen considered in aggregate, the primary frequency response provided by generators within an Interconnection has a significant impact on the overall frequency response.”  NV Energy would like to see additional information from the SDT on why this FERC-identified, and SAR objective, is not currently being addressed in either Phase of the revisions to BAL-003.

Kevin Salsbury, Berkshire Hathaway - NV Energy, 5, 1/17/2019

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We believe adding 1) a revision history section to the Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard and 2) an informative section describing the method that industry receives the information regarding the changes associated with the procedure or RLPC; would improve the overall effectiveness of this procedure. 

ACES Standard Collaborations, Segment(s) 1, 3, 6, 4, 1/17/2019

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Other Answers

Maryanne Darling-Reich, On Behalf of: Black Hills Corporation - WECC - Segments 1, 3, 5, 6

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Thomas Foltz, AEP, 5, 1/4/2019

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SRP supports the proposed revisions and does not have additional comments for the SDT.

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

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

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Table 1, which starts on page 12 and ends on page 13 of the proposed standard reflects a value of 120MW as “Credit for Load Resources” for the Western Interconnection.  The California ISO suggests that this number be validated as accurate at this point in time.

Richard Vine, 1/11/2019

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Xcel Energy would like to ensure that the proposed change to the C point to 20 seconds instead of 12 seconds (as specified on Page 1 of the Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard document is consistently changed throughout the document.  For example, it is not clear if the language on page 1 in 3b needs modification (“18 seconds”), and page 2 item 5 (“18 seconds”).

Also, we would like to understand how proposed changes to the Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard document will gather input from industry and also any approved changes publicized, if not through the standards process (ie standards development distribution lists).

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

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SRC, Segment(s) 2, 1/14/2019

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BPA noticed in review of the revised standard that the Violation Severity Levels are less restrictive. This change was not in the list of modifications at the start of this document. BPA cannot agree with less restrictive VSLs in combination with the current median FRM score utilized for compliance.

BPA feels that if an entity does not meet the median it should be at the severe VSL. However, in order to move onto Phase II of the 2017-01 project, BPA suggests the following approach until Phase II can be completed

Alternative Approach: BPA suggests that the VSLs for R1 be made more restrictive.  Lower Level between 1% and 5%, moderate 5% to 10%, high 10% to 15% and Severe greater than 15%.  

In WECC, the majority of selected frequency events have loss of less than 1000 MW with a nadir of 59.9 Hz or greater (less than or equal to 100 mHz deviation.)  If an entity cannot comply with the median FRM, that entity has high probability of never being able to respond adequately to an event the size of the RLPC.  If multiple entities have an FRM less than the median, the interconnection is at a high risk of underfrequency load shed when a loss as great as the RLPC occurs.  Therefore, BPA believes the VSLs must be more restrictive than the proposed to support interconnection reliability.

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

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AZPS would like to point out that the changes made to the Violation Severity Levels for R1 unintentionally created multiple outcomes based on certain criteria. The way the Moderate, High, and Severe VSLs are described, a Balancing Authority could have a less negative FRM than its FRO reflected in MW/0.1 Hz that qualifies for multiple levels. For example, if a BA had a deficiency between 31-45 MW, it could qualify as both Moderate and High. Deficiencies of 46 MW or greater could qualify as both Moderate and Severe. The use of the word “or” allows for this dilemma. AZPS does not recommend removing the word “or,” but rather completing the ranges with the levels to eliminate this confusion. 

Michelle Amarantos, 1/14/2019

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Any further reduction in frequency response is not acceptable.

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

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PJM thanks and supports the BAL-003-1 Standard Drafting Team’s draft revisions to BAL-003-1 in Phase 1; and supports the development of the Standards Authorization Request in Phase 2 information as it pertains to correcting the applicable entity that controls and provides frequency response, and other related information. PJM believes generators providing primary frequency response is an essential reliability need for both real-time and restoration conditions. A generator requirement across the Interconnections can ensure the necessary frequency response. PJM conducted a stakeholder process in 2018 for primary frequency response requirements for generators, however was unable to reach stakeholder consensus. One of the concerns raised from our members was that this is an Interconnection product, and as such PJM encourages NERC to continue this discussion in the Standard Drafting Team process.

Preston Walker, On Behalf of: PJM Interconnection, L.L.C., SERC, RF, Segments 2

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Ozan Ferrin, Tacoma Public Utilities (Tacoma, WA), 5, 1/15/2019

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IID, a relatively small BA in the western interconnection does not see major issues with the proposed SDT changes.

Diana Torres, On Behalf of: Imperial Irrigation District, , Segments 1, 3, 5, 6

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LG&E/KU believes the Frequency Response Standard Background Document goes beyond explaining “the rationale and considerations for the Requirements of this standard and their associated compliance information.”

As written, the Background Document promotes the concept of frequency responsive reserves, as detailed in the Good Practices and Tools section. We believe that the Drafting team should remove the Good Practices and Tools section from the Background Document, as it strays from the document’s intended purpose. If necessary, the Good Practices and Tools section could be included in the Reliability Guideline Primary Frequency Control.

Louisville Gas and Electric Company and Kentucky Utilities Company, Segment(s) 3, 5, 6, 9/6/2018

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

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Duke Energy’s “Affirmative” vote for Phase 1 of this Project, is based in large part on our support for the continuation of the Project into Phase 2. We appreciate the work performed by the drafting team thus far, and look forward to Phase 2 of the Project.

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

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MRO NSRF, Segment(s) 3, 4, 5, 6, 1, 2, 7/19/2017

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N/A

Douglas Webb, On Behalf of: Bryan Taggart, Westar Energy, 1,3,5,6; Bryan Taggart, Westar Energy, 1,3,5,6; Bryan Taggart, Westar Energy, 1,3,5,6; Derek Brown, Westar Energy, 1,3,5,6; Derek Brown, Westar Energy, 1,3,5,6; Derek Brown, Westar Energy, 1,3,5,6; Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., ; Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., ; Harold Wyble, Great Plains Energy - Kansas City Power and Light Co., ; Grant Wilkerson, Westar Energy, 1,3,5,6; Grant Wilkerson, Westar Energy, 1,3,5,6; Grant Wilkerson, Westar Energy, 1,3,5,6; Allen Klassen, Westar Energy, 1,3,5,6; Allen Klassen, Westar Energy, 1,3,5,6; Allen Klassen, Westar Energy, 1,3,5,6

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RSC no Dominion, Segment(s) 10, 2, 4, 5, 7, 3, 1, 0, 6, 1/17/2019

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Sandra Shaffer, Berkshire Hathaway - PacifiCorp, 6, 1/17/2019

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SPP Standards Review Group, Segment(s) 2, 8/30/2018

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