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2017-01 Modifications to BAL-003-1.1 | SAR

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Start Date: 09/06/2018
End Date: 09/20/2018

Associated Ballots:

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Hot Answers

We appreciate the new consistent approach applied between all interconnections.

 

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

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ERCOT understands the need to address the existing inconsistencies among different interconnections with respect to the current RCC criteria, but does not necessarily agree with the proposed approach.

Brandon Gleason, On Behalf of: Electric Reliability Council of Texas, Inc., , Segments 2

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Other Answers

The methodology is sound in principle and intent, however the utilization of MSSC may be incorrect.  MSSC is a defined term for reserve planning, and if the intent is to look at interconnection resource loss, then using the term MSSC may mislead entities and result in unintended information being submitted and utilized in the IFRO calculation.  Perhaps not using MSSC, but defining a different term and providing more clarification and instructions are warranted.

Glenn Barry, On Behalf of: Los Angeles Department of Water and Power, , Segments 1, 3, 5, 6

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AEP believes this is a reasonable and transparent methodology to determine the primary variable used to establish an IFRO.

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

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Xcel Energy supports the present N-2 Event and also including the N-2 RAS in the methodology.  The present N-2 event approach has resulted in reliable operations in the West.  Linking reserves to a single credible N-2 event (generation loss or RAS) is reasonable and justifiable.  We are not aware of the basis for the Eastern Interconnection IFROs using the largest event in the last 10 years.  While the goal RLPC consistent across all Interconnections is commendable, it may not be reasonable to expect each to have the same IFRO basis.  If one Interconnection's Frequency Response is declining over several years we would expect their IFRO to be adjusted accordingly.

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

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No Comments

Seattle City Light Ballot Body, Segment(s) 1, 4, 6, 5, 3, 12/2/2016

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

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The proposed RLPC establishes the same basis for all interconnections and eliminates the current higher expectation for the Eastern Interconnection.  We struggle with the statement that establishing a minimum generator governor response for an Interconnection is a primary or important tool to protect itself from an N-2 event.  For the Eastern Interconnection the proposed N-2 event is a loss of 3209 MW and the current required FRO for the Interconnection is 1015 MW/.1 Hz.  The primary protection for a sudden generation loss is established in BAL-002-2(i), if both losses occur with a single BA then the event becomes the second loss. 

In the Eastern Interconnection MSSC1 and MSSC2 are both within a single BA.  Thus the actual event we are protecting ourselves against is MSSC2, MSSC1 is addressed by the BA’s response iaw BAL-002-2(i).

Are we properly defining the event that this standard is assisting the BAs in protecting themselves against?   

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

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

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BPA is in support of replacing the RLPC so that it is consistent across all interconnections. The method presented in the draft Resource Loss Protection Criteria document seems appropriate for determination of the event that each Interconnection should protect against. Specifically, BPA supports the use of either the largest credible and studied (N-2) type contingency that results in a frequency deviation for a known MW loss, or the summation of the two largest MSSCs in an interconnection. While it is not likely that two separate MSSC events would occur at the same time, it seems like a plausible way to derive a number to protect against. The BAL-003 standard should protect against a larger, infrequent event.

BPA suggests the document clarify that credible and studied N-2 events are included in the evaluation. The way the Resource Loss Protection Criteria document is worded makes it seem like only N-2 RAS events are looked at in the list of N-2 events.

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

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sean erickson, On Behalf of: Western Area Power Administration, , Segments 1, 6

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The goal of consistency is commendable, but use of MSSC may result in unintended consequences over the present method.  The term "MSSC" is used for reserve planning, and is associated with specific BAs.  Using this term to determine Interconnection resource loss may result in utilizing values that are too small when calculating IFRO.  For example, the Interconnection loses all of a joint owned unit, but a BA loses only its portion of the unit.  Therefore, the MSSC will understate the size of the loss which may result in calculating an IFRO that is inadequate.  Defining a different term, and providing instruction and clarification regarding its determination, is a better approach - presuming the new term(s) is(are) technically based.

LeRoy Patterson, On Behalf of: Public Utility District No. 2 of Grant County, Washington, , Segments 1, 4, 5, 6

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

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In the Proposal section of the Proposed RLPC document, it states that each BA will submit their two largest resource losses.  It then says that data will include “Initiating event, and Megawatt (MW) loss.  But the proposed revised FRS Form 1 only has one empty box for MSSC1 and MSSC2, presumably for the MW value.  To reduce the potential for confusion, AZPS recommends clarifying the language within the proposal section or the boxes on the FRS Form 1, whichever is the desired result.  

Additionally, on page 4 of Proposed RLPC document, an incorrect acronym RPLC is used in the header.

Michelle Amarantos, On Behalf of: APS - Arizona Public Service Co., , Segments 1, 3, 5, 6

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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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Colby Bellville, On Behalf of: Duke Energy , FRCC, SERC, RF, Segments 1, 3, 5, 6

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ISO Standards Review Committee, Segment(s) 2, 12/1/2017

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RSC no Dominion, Segment(s) 10, 2, 4, 5, 7, 1, 3, 6, 0, 9/17/2018

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Hot Answers

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

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ERCOT disagrees in principle with the proposed approach of using the two largest units as a credible contingency, primarily because the probability of two units located hundreds of miles apart tripping on a single initiating event is extremely low.  This is not a credible risk that should be addressed by the NERC standards. Depending on how the RLPC is determined, if a large Generator or a DC Tie were to be interconnected hundreds of miles away from another large Generator, the proposed RLPC definition would require ERCOT to procure significant additional reserves at great expense in order to protect UFLS against the proposed RLPC.

Brandon Gleason, On Behalf of: Electric Reliability Council of Texas, Inc., , Segments 2

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Other Answers

MSSC is a defined term, and if the intent is to look at interconnection resource loss, then using the term MSSC may mislead entities and result in unintended information being submitted and utilized in the IFRO calculation.  Perhaps not using MSSC, but defining a different term and providing more clarification and instructions are warranted.

 

Example 1:

There is a potential gap in reporting JOU/Dynamically scheduled units.  LADWP has two JOU that are 900 MW (net) each but only receive 600 MW from each, with the remaining energy sinking in other BAs.  It would then be reported as MSSC1 being 600 MW and MSSC2 being 600 MW.  In actuality if both units were lost it would be an 1800 MW resource loss to the interconnection, and not the reported 1200 from MSSC 1 and MSSC 2 specified.  Since MSSC is a defined term, LADWP would not plan to meet a 900 MW resource loss as MSSC. 

  

 

Example 2:

This example may be unique to the Western Interconnection and PDCI operation.  An BA’s operational plans might consider their MSSC as their portion of PDCI schedules (since the sink BA is the reserve responsible entity for schedules that traverse PDCI).  For example a sink entity may have an MSSC1 of 2300 MW to represent their maximum PDCI schedules, however this would be not be all of the schedule on PDCI, and also this would be included as part of the N-2 RAS action generation resource loss reported by a separate entity.  When taking 2300 MW for MSSC1 + 1500 MW for MSSC 2 for another large unit, then the total result would be 3800 MW, larger than the N-2 RAS of 2850 MW.  MSSC is a defined term for reserve planning, which can be different than assessing interconnection resource loss. 

Glenn Barry, On Behalf of: Los Angeles Department of Water and Power, , Segments 1, 3, 5, 6

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AEP believes the proposal leverages existing processes and produces a defendable result.

 

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

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There is no technical justification for using two MSScs as one of the basis for IFRO.  We cannot support going to a MSSC approach without strong technical analysis and supporting historical data.  One suggestion is that there could be an actual event where two concurrent MSSCs exceed the single N-2 then the MSSC could become the basis for 3 years.

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

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No Comments

Seattle City Light Ballot Body, Segment(s) 1, 4, 6, 5, 3, 12/2/2016

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

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

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

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While having two MSSC events happen at the same time is not statistically probable, using the combination of the two largest MSSCs gives a method for determining a known MW amount that the interconnection should plan for in the case of an extreme event. If it happens to be larger than already studied N-2 events, then the higher IFRO should increase reliability.

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

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sean erickson, On Behalf of: Western Area Power Administration, , Segments 1, 6

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MSSC may result in calculating IFRO that is insufficient to cover actual Interconnection events as previously stated.  Joint owned units provide one example of using MSSC and achieving a non-conservative IFRO value.  Another example relates to loss of DC ties, where total transfer may be distributed among multiple BAs resulting in MSSCs being smaller than the Interconnection contingency. 

LeRoy Patterson, On Behalf of: Public Utility District No. 2 of Grant County, Washington, , Segments 1, 4, 5, 6

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

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Although AZPS agrees with the proposal for using the two MSSCs for the basis for an Interconnection’s IFRO, it does not believe the current proposed collection method for this data will result in what the SDT intends to collect for the following reasons:

Following the definition of MSSC, a Balancing Authority who is in a RSG would not have a discrete MSSC.  As the definition states, an MSSC is a Balancing Contingency Event “within the RSG or a BA’s area that is not part of a RSG.”  Therefore those Balancing Authorities inside an RSG would have nothing to report.  Similarly, who will be reporting the MSSC for the RSG since RSGs do not fill out Form 1 and those MSSCs are typically the largest MSSCs.  

A good illustration of this collection method concern is Palo Verde nuclear generating units.  One of these units total output would not be reported by any RSG or BA area that is not part of a RSG as AZPS is part of an RSG, meaning it does not qualify as an entity who has an MSSC.  Hence, this MSSC would not be appropriately captured under the current proposal.  

Additionally, if a Balancing Authority inside an RSG is made to report a value, the revised form does not contemplate when a BA has a different MSSC depending on the time of year.  One reason this can occur is due to Power Purchase Agreements. A BA’s MSSC during one half of the year could be their MSSC2 for the second half of the year.  Here is an illustration:

BA1 MSSC1 500 MW (January – June)

BA1 MSSC2 300 MW (January – June)

BA1 MSSC1 600 MW Power Purchase Agreement (July – December)

BA1 MSSC2 500 MW (July – December) 

In this example, these two resources cannot be combined to serve as both the MSSC1 and MSSC2 for all times of the year.  During January – June the 600 MW unit is BA2’s MSSC.  If BA1 claims the 600 MW unit as their MSSC, it is likely BA2 will claim it as well, resulting in the unit being counted twice.  What should BA1’s MSSC1 and MSSC2?

For these reasons, AZPS recommends that the SDT review and revise the current proposal regarding the reporting of this information. 

Michelle Amarantos, On Behalf of: APS - Arizona Public Service Co., , Segments 1, 3, 5, 6

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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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As it is uncertain where the industry will trend in future years in terms of new resource sizing and large resource retirements, there is the possibility that the magnitude of the Most Severe Single Contingencies will get smaller and possibly more will be based upon loss of transmission.  Duke Energy suggests that the drafting team consider basing the IFRO on the greater of a fixed percentage of the minimum Interconnection load or the two Most Severe Single Contingencies.

Colby Bellville, On Behalf of: Duke Energy , FRCC, SERC, RF, Segments 1, 3, 5, 6

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ISO Standards Review Committee, Segment(s) 2, 12/1/2017

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RSC no Dominion, Segment(s) 10, 2, 4, 5, 7, 1, 3, 6, 0, 9/17/2018

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Hot Answers

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

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Brandon Gleason, On Behalf of: Electric Reliability Council of Texas, Inc., , Segments 2

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Other Answers

Glenn Barry, On Behalf of: Los Angeles Department of Water and Power, , Segments 1, 3, 5, 6

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Though AEP agrees in principal with the overall goal, we must reserve final judgement until more specifics are provided to support the reasoning.

 

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

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Xcel Energy completely agrees that the changes must be technically justifiable.  However, we feel any increase in an Interconnection's IFRO should be driven by actual degradation in an Interconnection's Frequency response and not by a technically unjustified change in the basis.

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

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No Comments

Seattle City Light Ballot Body, Segment(s) 1, 4, 6, 5, 3, 12/2/2016

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

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We concur with keeping the IFRO methodology stable similar to CPS.  At issue is the determination of a significant decline in Frequency Response – will some metric be established?  In addition the technical justification of how a significant decline in Frequency Response indicates a challenge to an Interconnections protection in recovering from a N-2 event isn’t well established.  

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

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

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BPA understands that the IFRO is calculated based on a statistically derived starting frequency and CBR ratio. In general, BPA agrees that the IFRO need not change for minute statistical changes. However if there is a change to the RLPC that would raise the obligation, it makes sense that the change to IFRO happens quickly in order to protect against this event. It would be good to clarify the language to say that the IFRO stays the same year to year unless there is a significant change in Interconnection Frequency Response Performance, the RLPC, or statistical inputs to the IFRO.

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

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sean erickson, On Behalf of: Western Area Power Administration, , Segments 1, 6

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GCPD supports an IFRO methodology that makes changes only when technically justified, and keeps IFRO stable year over year.  However, if IFRO is inadequate to respond to actual, or probable, events; IFRO should continue to change annually to provide reliable operation.  While it is difficult to respond to this question because the interpretation of when "...Interconnection Frequency Response significantly declines" is nebulous, inadequate IFRO may be caused by factors other than a decline in frequency response such as discovering  events that demand significantly more IFRO to respond to the size of the loss.  (e.g. loss of large amounts of resources related to inverter performance related to distributed energy resources) 

LeRoy Patterson, On Behalf of: Public Utility District No. 2 of Grant County, Washington, , Segments 1, 4, 5, 6

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

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Michelle Amarantos, On Behalf of: APS - Arizona Public Service Co., , Segments 1, 3, 5, 6

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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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Colby Bellville, On Behalf of: Duke Energy , FRCC, SERC, RF, Segments 1, 3, 5, 6

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ISO Standards Review Committee, Segment(s) 2, 12/1/2017

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RSC no Dominion, Segment(s) 10, 2, 4, 5, 7, 1, 3, 6, 0, 9/17/2018

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Hot Answers

See comments

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

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Brandon Gleason, On Behalf of: Electric Reliability Council of Texas, Inc., , Segments 2

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Other Answers

Glenn Barry, On Behalf of: Los Angeles Department of Water and Power, , Segments 1, 3, 5, 6

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AEP believes the current methodology could be improved, but simplification itself should not be the primary goal. Rather, the key to success would be to have a well thought-out and documented process.

 

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

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We cannot support removing these variables (for the MDF calculation in particular) from Attachment A until we see where they will be moved, in terms of new documents, and under what venue this analysis will occur.

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

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No Comments

Seattle City Light Ballot Body, Segment(s) 1, 4, 6, 5, 3, 12/2/2016

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

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These details are an essential part of the standard as they directly impact the determination of a BAs FRM.

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

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

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Until phase 2 of this SDT process can occur, BPA does not support changing the core way that IFRO is calculated. In phase 2, the entire methodology of IFRO could be called into question. Until those more thorough discussions happen, it does not make sense to change the IFRO methodology beyond what was suggested for the RLPC. The RLPC should be reviewed annually and IFRO calculated based on the RLPC. Movement towards a new RLPC should be implemented completely, but changes due to small changes in CBR ratio or starting frequency should not require changing the IFRO yearly.

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

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sean erickson, On Behalf of: Western Area Power Administration, , Segments 1, 6

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If these values are used to determine compliance or to determine mandated values/limits, they should be part of the standard. 

LeRoy Patterson, On Behalf of: Public Utility District No. 2 of Grant County, Washington, , Segments 1, 4, 5, 6

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

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In the Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard it states the RLPC for the Eastern Interconnection is “the largest event in the last 10 years.”  But the Proposed Resource Loss Protection Criteria does not provide for this exception.  Please clarify which is correct.

Michelle Amarantos, On Behalf of: APS - Arizona Public Service Co., , Segments 1, 3, 5, 6

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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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Colby Bellville, On Behalf of: Duke Energy , FRCC, SERC, RF, Segments 1, 3, 5, 6

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See resposee to Question 7 and also see attached comments

ISO Standards Review Committee, Segment(s) 2, 12/1/2017

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RSC no Dominion, Segment(s) 10, 2, 4, 5, 7, 1, 3, 6, 0, 9/17/2018

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Hot Answers

As part of the eastern interconnection, we agree with the phased-in approach. This is more impactive with the increasing IFRO but fair to apply the phasing-in in both directions.

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

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Brandon Gleason, On Behalf of: Electric Reliability Council of Texas, Inc., , Segments 2

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Other Answers

How was 10% chosen, and is there a basis for that value.  It is conservative approach to have staged implementation to large reductions in IFRO.  However with IFRO being a reliability measure intended to prevent UFLS what is justification for restricting increases in IFRO greater than 10%? 

Glenn Barry, On Behalf of: Los Angeles Department of Water and Power, , Segments 1, 3, 5, 6

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AEP prefers a gradual change of IFRO in response to real changes in the BPS, and we believe the proposed 10 percent is a reasonable annual limit.

 

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

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We do not support the 2 MSSC approach and thus have no comment.

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

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No Comments

Seattle City Light Ballot Body, Segment(s) 1, 4, 6, 5, 3, 12/2/2016

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

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There’s no justification for establishing a lower FRO for an Interconnection whose MSSC1 and MSSC2 clearly indicate that more FRO is needed to protect that Interconnection from the currently defined event.  If during this phase in an event occurs that the Interconnection can’t respond to is NERC willing to accept the responsibility for requiring less when clearly more was needed?

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

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

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BPA thinks that the staged approach makes sense if the IFRO is lowering. If the IFRO is increasing then the change should happen immediately to support reliability.

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

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The Purpose as written for BAL-003 is: To require sufficient Frequency Response from the Balancing Authority (BA) to maintain Interconnection Frequency within predefined bounds by arresting frequency deviations and supporting frequency until the frequency is restored to its scheduled value. To provide consistent methods for measuring Frequency Response and determining the Frequency Bias Setting.

the question as written would suggest, "except when the delta is large".

If the intent is to limit the decrease in the East as a conservative precaution, then YES, WAPA does agree, but to allow less than required when the new methodology dictates a need for more violates the purpose of the standard

sean erickson, On Behalf of: Western Area Power Administration, , Segments 1, 6

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The concept of this question is wrong on several levels.  First, if the new methodology is technically sound - which remains to be shown - then there is every reason to enforce the new IFRO values at the next annual change because the Eastern Interconnection does not need the present amount for reliable operation, and Hydro Quebec has a reliability risk because it is short. 

Next, what is the technical justification for limiting change to 10% rather than 5%, 7%, 15%, etc.?  Does it provide 80% of the benefit at 20% of the cost or achieve some other merit that warrants the risk that is accepted by using a value that is recognized as inadequate? 

Proposing such a limit calls both the present and proposed methodology into question because one or the other, or perhaps both, must be wrong.  Perhaps separate Interconnection methods provide more reliable results, or at least result in less surplus being required by an Interconnection.  If Hydro Quebec is reliable today, then there is no need to force them to increase IFRO 17% just to treat all Interconnections the same.  Conversely, if they are 17% short, they should correct the deficiency at the next scheduled IFRO change. The real issue is whether the proposed methodology is a better measure to identify necessary IFRO than the old methodology.  If so, why?

LeRoy Patterson, On Behalf of: Public Utility District No. 2 of Grant County, Washington, , Segments 1, 4, 5, 6

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

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Michelle Amarantos, On Behalf of: APS - Arizona Public Service Co., , Segments 1, 3, 5, 6

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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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Colby Bellville, On Behalf of: Duke Energy , FRCC, SERC, RF, Segments 1, 3, 5, 6

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See resposee to Question 7 and also see attached comments

ISO Standards Review Committee, Segment(s) 2, 12/1/2017

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RSC no Dominion, Segment(s) 10, 2, 4, 5, 7, 1, 3, 6, 0, 9/17/2018

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Hot Answers

See comments

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

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Brandon Gleason, On Behalf of: Electric Reliability Council of Texas, Inc., , Segments 2

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Other Answers

Glenn Barry, On Behalf of: Los Angeles Department of Water and Power, , Segments 1, 3, 5, 6

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AEP agrees in principle with the concept.  To be acceptable, the “Procedure” would need to have well-defined steps, boundaries to the use of engineering judgement, clear roles, clear responsibilities, and oversight.

 

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

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Acceptable to move non entity compliance (including non IFRO) to the "Procedure...." document.

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

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No Comments

Seattle City Light Ballot Body, Segment(s) 1, 4, 6, 5, 3, 12/2/2016

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Requirement R1 requires that a “Balancing Authority that is not a member of a FRSG shall achieve an annual Frequency Response Measure (FRM) (as calculated and reported in accordance with Attachment A) that is equal to or more negative than its Frequency Response Obligation (FRO)….”  Since the BA’s FRM must be equal to or more negative than its FRO, the FRO is a compliance obligation.  Compliance obligations should be included in the language of the Standards and Requirements and be subject to the full Standards Drafting Process.

LG&E/KU recommends that the IFRO and FRO calculations be set forth in Attachment A without reference to who is responsible for the administrative task of completing the calculations.  A similar approach can be seen in BAL-001-2 Attachments 1 and 2 where the equations supporting the Requirements in the Standard are set forth.  If the calculations are set forth in Attachment A, then the responsibility for the administrative task of completing the calculations can be stated in the Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard document.

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

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

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

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Because the IFRO calculations are the basis for much of the current BAL-003 standard, the IFRO methodology should stay in Attachment A of the standard. Numbers that may change from year to year should move to the Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard document. However, the methodology and rules for determining and calculating IFRO should stay in the Attachment and not be changed unless it goes through a SAR process.

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

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sean erickson, On Behalf of: Western Area Power Administration, , Segments 1, 6

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Requirement 1 requires a BA's FRM to be calculated in accordance with Attachment A, and that its FRM be "...equal to or more negative than its Frequency Response Obligation (FRO)..."  Hence, FRO is an obligation and should remain in the standard and subject to the standards drafting process.  Keeping the calculations as part of the standard can occur without specifying who is responsible for completing such calculations, though.

LeRoy Patterson, On Behalf of: Public Utility District No. 2 of Grant County, Washington, , Segments 1, 4, 5, 6

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

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Although AZPS agrees in concept to moving these items from Attachment A to the Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard, it would be helpful if the SDT would move this language to the procedure and amend the procedure in a proper draft form for proper review by industry.  This would avoid errors such as:

  • The current posted draft version containing references to itself (last sentence of page 8 “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.”).  
  • Page 4 under subtitle “Monthly”, the link cited is no longer valid.  
  • There are new items that are not redlined, which does not allow the reviewer to recognize what are new concepts. 

Moving the Timeline for Balancing Authority Frequency Response and Frequency Bias Setting Activities from Attachment A to the Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard would be another recommended change since these dates and tasks have changed and have not always been adhered to.  

To allow industry to properly review and evaluate the proposed document, we recommend, at a minimum, an accurate clean version be provided and possibly a redlined version if a meaningful approximation can be constructed.

Michelle Amarantos, On Behalf of: APS - Arizona Public Service Co., , Segments 1, 3, 5, 6

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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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Colby Bellville, On Behalf of: Duke Energy , FRCC, SERC, RF, Segments 1, 3, 5, 6

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See resposee to Question 7 and also see attached comments

ISO Standards Review Committee, Segment(s) 2, 12/1/2017

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RSC no Dominion, Segment(s) 10, 2, 4, 5, 7, 1, 3, 6, 0, 9/17/2018

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Hot Answers

We support the changes as they represent a more stream-lined standard. 

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

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No response.

Brandon Gleason, On Behalf of: Electric Reliability Council of Texas, Inc., , Segments 2

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Other Answers

Glenn Barry, On Behalf of: Los Angeles Department of Water and Power, , Segments 1, 3, 5, 6

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While we appreciate the drafting team’s need for input regarding their efforts, a 14 day turnaround time is not adequate opportunity for industry to provide thoughtful, meaningful feedback on the subject matter.

 

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

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

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No Comments

Seattle City Light Ballot Body, Segment(s) 1, 4, 6, 5, 3, 12/2/2016

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The document Proposed Resource Loss Protection Criteria states, “The MSSC calculation is done in Real-time operations based on actual system configuration.”  This statement is not universally accurate and should be removed.

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

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

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The SPP Standards Review Group (“SSRG”) requests the Standards Drafting Team revise the definition of “Balancing Contingency Event” to include parameters that will expand the single contingencies recognized as a Most Severe Single Contingency (”MSSC”). For example, non-traditional criteria such as a fuel supply with a single point of failure, Joint Owned Units, and multiple units with a common bus should be included as a BCE, so that this additional granularity may be recognized by the BA as a MSSC.

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

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To reiterate, BPA is in support of replacing the RLPC so that it is consistent across all interconnections and that the RLPC should be either the largest credible N-2 resource loss event or the sum of the two largest MSSC’s in an interconnection. BPA supports only changing the IFRO if the RLPC changes, there is a substantial decrease in interconnection performance, or there are statistically significant change in the statistical inputs to the IFRO like the CBR ratio, Starting Frequency, etc.

Aside from adjusting the RLPC, BPA thinks no changes should be made to the core IFRO methodology until Phase 2 of this SAR and that the methodology for the IFRO should be documented in Attachment A of the BAL-003 standard. The IFRO It serves as the basis for the current standard and the core methodology should not change until further discussions are had in the drafting process.

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

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thank you

sean erickson, On Behalf of: Western Area Power Administration, , Segments 1, 6

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The "Proposed Resource Loss Protection Criteria" states, “The MSSC calculation is done in Real-time operations based on actual system configuration.”  While MSSC is updated based on actual system conditions, not all entities calculate MSSC in the manner stated.  Please modify or remove this statement.

LeRoy Patterson, On Behalf of: Public Utility District No. 2 of Grant County, Washington, , Segments 1, 4, 5, 6

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

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IFRO calculation description is somewhat confusing. The last sentence in the first paragraph says:

“A maximum delta frequency (MDF) is calculated by adjusting a starting frequency for each Interconnection by the following: “  

The above sentence is implying that the starting frequency is adjusted by the items which follow up. Is the intent of the sentence is to say that MDF calculation depends upon the follow up items?
I do not see how the follow up items adjust the starting frequency?

Also, it is not clear how the starting frequency is chosen in Table 1. Please clarify.

Also it would help to clarify the basis of CLR values.

Michelle Amarantos, On Behalf of: APS - Arizona Public Service Co., , Segments 1, 3, 5, 6

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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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Colby Bellville, On Behalf of: Duke Energy , FRCC, SERC, RF, Segments 1, 3, 5, 6

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Comment 1:

The drafting team is trying to replicate the process used for CPS1.  The performance level for CPS1 is based on a parameter called epsilon 1 (e1).  The BAL-001 standard was designed such that if frequency performance of the grid degraded, NERC would work with the NERC OC and its subcommittees to identify a new e1 to tighten performance. 

 

In the nearly 20 years of existence, there never has been a need to tighten the BAL-001 and only one case where an Interconnection went through the process to increase their e1.

 

Under the current version of the BAL-003 standard, NERC has to annually file a detailed analysis and suggest changes to the obligations.  Interestingly, the math for the analysis suggests that since the “B value” in the East has improved, its obligation needs to go up.  Additionally, there was no “off ramp” in the standard for the East’s 4500MW contingency that was the largest in 10 years. 

 

 

The drafting team was hoping remove the hardcoding in the BAL-003 attachment and set up a process similar to BAL-001 whereby a reasonable target obligation for an Interconnection would only change it if:

·         Performance drops below a base year by 10%.

·         A new larger credible contingency is identified in an Interconnection.

·         For cases like ERCOT where they use interruptible load as a resource, to adjust if the amount of contracted load changes.

 

 

Comment 2:

 

·         The proposed process is flexible enough to allow the ERO to calculate the mandated values for BAL-003 BUT this process should remain as part of the official Attachment to the Standard (and not be made a Guideline). I propose this because of concerns with how “adjustments” are made. It appears that adjustments come from a small group of people who could be impacted by one or two regions thus those adjustments should be open to the public. For example, there is an adjustment for load (i.e. Credit for Load) value for load that is shed above the minimum UFLS. For the east the UFLS point itself is raised because of the local UFLS of Florida, whereas others are getting credit for this load shedding. This matter should be discussed by the Industry and not simply “include” in a calculation.

·         Terry’s point about the new process being a good step forward is correct. I do believe that the process can be further enhanced if the proposed SDT changes strictly followed their own approach as opposed to having “off-ramps” for changes that indicated more than just marginal changes over a year. And if this approach were to follow a strict simple formula,  all of the all too many references to “except for the EI” would be eliminated and replaced with a defined reliability obligation. As it is today the proposal fails to recognize that the EI frequency performance is in many ways better than other interconnection’s performance. This issue should be discussed in open as part of the formal process or even better as part of an ongoing informal process.

·         Terry’s point about the lack of change over the years also points to the fact that the process should continue to be part of the standard (if the system is stable then sudden changes to the Process should be rare and openly discussed) and any changes should be subject to Industry discussion vis-à-vis a SAR.

·         Terry’s point about the use of the two Most Severe

·         The Procedure language is itself too casual and should be made more direct. The comments in this draft will hopefully add to that clarity.

{C}o   {C}What is BETA?

{C}o   {C}M-4 Point C is a Section heading not a value

{C}o   {C}Are variables “Points” or “Values”

{C}o   {C}Who reports the Most Severe Single Contingency (from section “Changes in Resource Loss Protection” in the ADJUSTMENTS TO INTERCONNECTION FREQUENCY BIA OBLIGATION Guideline

{C}§  {C}The RC who has all of the data but does not necessarily have all of the detailed “changes”

{C}§  {C}The GO who has responsibility for generating resource capacity

{C}§  {C}The TOP who has information on transmission related impacts

{C}§  {C}The PC who has forecast information

{C}o   {C}Is the reporting of the largest resources an Annual calculation of a “daily” calculation (It seems from the text that this may be done each day as he resources change)

 

 

 

In short, the proposal has good intentions but it stills needs work in how it is written and how it can be made even better. (see attached relined document)

 

 

 

Comment 3:

The RLPC should be what it is and then it should be parenthetically noted that it happened to be the largest category C event…  We should not lock ourselves into using only the largest category C event for the preceding 10 years – it varies too much.

 

 

 

 

 

The Credit for Load is not applicable to firm load shed. ERCOT receives the credit because ERCOT has a robust competitive market for demand response to provide response in less than 30 cycles to arrest frequency decay. Any applicable entity that has a demand response program designed to arrest large frequency deviation that responds before UFLS trigger is eligible for credit. Not assigning the LR credit would cause to IFRO requirement to almost more than double while trying to protect against the same RCC or RLPC.   

 

 

 

 

ISO Standards Review Committee, Segment(s) 2, 12/1/2017

Bal-003 (IRC Standards Review Committee without ERCOT).docx

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RSC no Dominion, Segment(s) 10, 2, 4, 5, 7, 1, 3, 6, 0, 9/17/2018

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