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Standards Efficiency Review | SAR 2nd Posting

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Start Date: 08/28/2018
End Date: 09/26/2018

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

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Jamie Monette, On Behalf of: Allete - Minnesota Power, Inc., , Segments 1

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Other Answers

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

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Scott McGough, On Behalf of: Georgia System Operations Corporation, , Segments 3, 4

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AECI supports the comments provided by NRECA.

AECI, Segment(s) 1, 3, 6, 5, 4/30/2018

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Phase I calls for the full retirement of FAC-013-2, it is noted by the NSRF that the current NERC Project 2015-09 is proposing FAC-013-3. The NSRF asks whether FAC-013-3 needs to be referenced from the SAR for future handling, should the FAC-013 -2 retirement be successful.

Similar situation with VAR-001-4.2 E.A. 15. The NSRF notes that VAR-001-5, which has been approved by the NERC Board of Trustees, contains E.A. 15 in Attachment 1.  Does VAR-001-5 E.A.15 need to be referenced from the SAR for future handling, should the VAR-001-4.2 E.A. 15 retirement be successful?

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

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Patti Metro, On Behalf of: National Rural Electric Cooperative Association, , Segments 3, 4

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

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Consumers Energy's position is that PRC-004-5(i) R4 can be removed as long as comments are added to R5 to clarify that a “meaningful investigation must occur to determine the root cause”.  That statement can then be considered for the next SAR committee.

If the statement can’t be considered at the next SAR committee, then Consumers’ position would be to go with leaving R4.

Consumers Energy is in agreement with retirement of the other requirements recommended for retirement.

Consumers Energy Company, Segment(s) 1, 3, 4, 5, 11/29/2017

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Jesus Sammy Alcaraz, On Behalf of: Imperial Irrigation District, , Segments 1, 3, 5

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AEP supports the work and overall recommendations of the Standards Drafting Team with the following qualifiers:

AEP does not agree that PRC-004-5(i) R4 meets the drafting team’s “Evaluation Criteria for Retiring Reliability Standards Requirements”, as the declaration of “no cause found” is made only within this obligation (i.e. “is not redundant”). Regarding the reliability rationale, we would agree that not all investigative actions in and of themselves improve reliability, however the ability to track investigative actions over an extended period of time ensures more riguer is applied to the investigative progress.

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

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

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Diana McMahon, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

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APS agrees with the vast majority of these recommended retirements, but APS disagrees that EOP-005-3 R8 is duplicative of activities covered by the Systematic Approach to Training in Reliability Standard PER-005-2. While system restoration is a reliability-related task that would be included in an entity's training program for its System Operators, it is a risk to assume that all Transmission Operators would provide System restoration training under its operations training program at the frequency and of the scope required under EOP-005-2, R8 (parts 8.1-8.5).

Kelsi Rigby, On Behalf of: Kelsi Rigby, , Segments 1, 3, 5, 6

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Louisville Gas and Electric Company and Kentucky Utilities Company (LG&E/KU) strongly disagrees with the proposed retirement of VAR-001-4.2 R2 because requiring each Transmission Operator to schedule, provide, and have evidence of scheduling sufficient reactive resources to regulate voltage levels under normal and Contingency conditions is necessary for the reliability of the BES. Reactive power resources are required to maintain voltage stability on the BES. Therefore, removing the requirement to ensure that each Transmission Operator schedules and provides sufficient reactive resources and has the documentation that sufficient reactive resources have been scheduled will be harmful to ensuring the reliability of the BES. Instead of retiring VAR-001-4.2 R2, there should be additional guidance (i.e. Implementation Guidance) to suggest how the transmission control center complies with R2.

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

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Wendy Center, On Behalf of: U.S. Bureau of Reclamation, , Segments 1, 5

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On behalf of our City Light SMEs, there were no voiced concerns. 

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

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Exelon Utilities, Segment(s) 1, 3, 5/19/2015

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Cynthia Lee, On Behalf of: Exelon, , Segments 1, 3, 5, 6

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Rebecca Baldwin, On Behalf of: Transmission Access Policy Study Group, NA - Not Applicable, Segments 4

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FMPA, Segment(s) , 10/23/2017

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MOD-001-2: Duke Energy objects to the drafting team’s recommendation to retire MOD-001-2. FERC has not yet ruled on NAESB standards, and eliminating the responsibilities in MOD-001-2 would be in direct conflict with FERC Order 890 and would leave the industry with no consistency on calculation of ATC. Without a consistent method of calculating ATC throughout the industry this would potentially force a BA/TOP to inspect every Tag. This is avoided by having MOD-001-2 enforceable.

FAC-013-2: Duke Energy re-states its disagreement with the proposal regarding FAC-013-2. This standard was developed in response to FERC Directives in Orders 693 and 729. In the Orders,  FERC directed NERC to establish a standard requiring Planning Coordinators to calculate transfer capability in the planning horizon (years one through five) and communicate the results. We disagree with the notion that FAC-013-2 has no bearing on reliability of the BES. In the FAC-013-2 — Planning Transfer Capability White Paper that was drafted during development of the standard, the standard’s benefit to reliability is stated:

“Further, FAC-013-2 requires that a Planning Transfer Capability Methodology Document (PTCMD) be developed for the calculation of Planning Transfer Capabilities (PTC) beyond 13 months in the future to provide additional information for the Planning Coordinator to use in planning for BES reliability.”

Another pertinent excerpt from the White Paper mentions how FAC-013-2 covers aspects of grid reliability not covered in the TPL standards:

“The TPL planning standards do not specify the need to document transfer capability calculation methods that may be used in the planning horizon. To cover that aspect of planning for BES reliability, the FAC-013-2 standard specifies that Planning Coordinators must perform PTC calculations as part of the planning process, that the method must be documented and shared with other entities as specified in the standard.”

Lastly, see the quote from the White Paper below that further illustrates the necessity of FAC-013-2, and how it helps address past concerns from FERC.

“The application of FAC-013-2 will provide PTC values that are an indicator of the robustness of the future transmission system and facilitate communication between adjacent Planning Coordinators. It will result in meeting FERC's concerns regarding transfer capability in the planning horizon and provide important information that Planning Coordinators will be able to apply in their efforts to reliably plan the BES.”

IRO-017 (R3): FERC mandated that RC’s and TP’s coordinate on the impact of known outages on TPL assessment results. It appears that the SDT believes that this can be retired because the TPL standard requires TP’s to send their assessment results to adjacent PC’s and TP”s and anyone else who asks. The result of this retirement may mean that nothing gets to the RC unless they ask and even then it doesn’t require the TP and RC to work together to resolve conflicts.   

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

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We agree with the majority of the retirement recommendations of the SER teams in all but a few instances. These are listed below:

 

INT-009-2.1 R2

The SAR rationale is that it is redundant with NAESB business practices. However, NAESB rules are not applicable in Ontario.  While NAESB is more stringent, during reliability curtailments, system operators require flexibility given to them by INT-010 to manage the e-tags.

IRO-002-5 R4

This requirement is needed for the system operator to manage the grid.

IRO-008-2 R6

Keeping impacted entities informed in a timely fashion is good operating practice.

TOP-001-4 R16

This requirement is needed for the system operator to manage the grid.

TOP-001-4 R17

This requirement is needed for the system operator to manage the grid.

 

In the rationale presented to retire COM-002-4 R2, the SER is assuming or expecting that initial training for each of its operating personnel responsible for the Real-time operation of the interconnected Bulk Electric Systemis being covered in PER-005-2.  PER-005-2 does not prescribe what training entities must include. 

In the rationale presented to retire EOP-005-3 R8, the SER is assuming or expecting that System restoration is a reliability-related task and would be included in an entity's training program for its System Operators. PER-005-2 does not prescribe what training entities must include.

 

FAC-003-4 Requirements R5 and R6: These requirements should be retired because R5 and R6 are controls and good utility practices but do not enhance BES reliability over R1 and R2. R1 and R2 fulfil the purpose of the standard through measurable actions. Also, the NERC Rules of Procedure allow consideration for extenuating circumstances relative to R5.

FAC-008-3 Requirement R8: Requirements R.8.1.2 and R8. 2 are not duplicative of TOP-003-3 or IRO-010-2. FAC-008-3 Requirement R8.2 necessitates that TOs provide to their associated RCs, PCs, TPs, TOs and TOPs the Requirement R8.1.2 “identity of the most limiting equipment of the Facilities,” Requirement R8.2.1 “identity of the existing next most limiting equipment of the Facilities,” and Requirement R8.2.2 “Thermal Rating for the next most limiting equipment identified in Requirement R8, Part 8.2.1,” whereas the TOP-003-3 or IRO-1010-2 standards do not appear to have this requirement. 

IRO-010-2 Requirement R1 specifies the types of data that an RC collects from applicable entities, so that the RC may perform OPAs, RTM and RTAs. The OPA RTM and RTA definitions (in the NERC Glossary of Terms) each mention “Facility Ratings” as an input (into OPA’s, RTM and RTA’s). However, neither IRO-010-2, Requirement R1, nor the OPA, RTM and/or RTA definitions (in the NERC Glossary of Terms) contain the level of specificity in FAC-008-3 Requirement R8 (to “identity the most and the existing next most limiting equipment of the Facilities” and “the Thermal Rating for the next most limiting equipment identified in Requirement R8, Part 8.2.1”). Similarly, TOP-003-3 Requirement R5 requires identified entities to fulfill a data specification provided by a BA or TOP so that OPAs, RTM, and RTA’s may be performed. As in the case of IRO-010-2 Requirement R1 and the OPA, RTM and RTA definitions, TOP-003-3 does not require identification of the most and the existing next most limiting equipment of the Facilities and the Thermal Rating for the next most limiting equipment identified in FAC-008-3 Requirement R8, Part 8.2.1.” 

NUC-001-3 R1: The requirement is administrative in nature, as Requirement R1 actions are inherent in Requirement R2 since each entity “shall have in effect” an agreement.

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

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 We agree with the following comments submitted by TAPS:

 We believe the justifications for the SAR’s proposed retirements are well-explained.  We also believe, however, that several additional requirements should be retired either as part of this SAR or in Phase 2, as set forth below.

 

COM-001-3 R1, R2, R3, R4, R5, R6, R7, R8, R9, R10, R11, R12, and R13 (ALL)

Basic functionality.  This should be part of the certification process for BAs, TOPs and RCs.  For all other entities (DPs and GOs), it is not necessary to require communication to be proven as the RC, TOP or BA will assure that they can make contact with these entities, and all entities have internal and external Interpersonal Communications Capabilities.  This Standard basically states to have primary and back up communications (a phone).  In today's world, basic, daily functionality necessitates multiple avenues of communications such as a land line phone, a cell phone, text messaging, a radio, satellite phone, etc.  This Standard is not necessary for reliability; it only enforces a compliance “gotcha” if a registered entity’s primary communication system fails.  There is not a reliability benefit from COM-001-3, just administrative burden.  Communications are a basic function of every registered entity.  The entire Standard should be retired.

 

COM-002-4 R3

R1 protocols cover all aspects of operating protocols.  If communication is a reliability-related task, then training is covered in PER-005.

 

COM-002-4 R4

R4 and its subrequirements are a control and should not be an auditable item.

 

COM-002-4 R5, R6, R7

There should be no difference between an Operation Instruction under normal conditions and under Emergency conditions.  R1 covers all Operating instructions.  By imposing additional requirements on Operating Instructions that are issued during an emergency, R5, R6, and R7 make it necessary for entities to track whether each Operating Instruction was issued during an Emergency or during normal operations, in order to be able to demonstrate compliance.  This administrative burden does not enhance reliability.

 

EOP-005-3 R3

Verify through NERC Certification program.

 

EOP-008-2 R2

Verify through NERC Certification program.

 

EOP-008-2 R3, R4

NERC Certified Operators can be addressed through Certification Program.  R6 addresses Primary and Backup and can also address the sub-bullets in this Requirement.  Sub-bullets of R4 can be addressed in R8.

 

EOP-010-1 R2

This is for situational awareness only and may be a mitigating feature of R1.  If one K warning is not sent out, it becomes a non-compliance issue.  This is also covered in EOP-011-1, R1.2.1.

 

EOP-010-1 R3.1

R3.1 is contained in R1.  Per part 3.1, this will force the TOP to prove a negative if they did not receive any space weather information. Part 3.2 starts the mitigating processes for GMD events and part 3.3 concludes them.  Part 3.1 is administrative in nature as alone, it does not accomplish anything; parts 3.2 and 3.3 mitigate the GMD.  Recommend part 3.1 be retired.  If not retired, part 3.1 should be modified to clearly state in the requirements or measures that proof of compliance is to show the steps only and entities are not required to prove a null set of data.

 

EOP-011-1 R1 subparts

R1.1 does not enhance or enforce reliability; it is only an auditable item.  R1.2.2, R1.2.3, R1.2.4, R1.2.5, and R1.2.6 are all actions or event types that require actions.  These are all event-specific.  The Operating plan will just say that the operator will do something to mitigate these events.  Then it becomes an auditable item in the Operating Plan, only.  R1 is simple enough: have a plan for emergencies.  Recommend subcomponents be retired.

 

EOP-011-1 R2 subparts

R2.1 does not enhance or enforce reliability; it is only an auditable item.  R2.2.3 and its parts and R2.2.4, R2.2.5, R2.2.6, R2.2.7, R2.2.8 and R2.2.9 are all actions or event types that require actions.  These are all event-specific.  The Operating plan will just say that the operator will do something to mitigate these events.  Then it becomes an auditable item in the Operating Plan.  R2 is simple enough: have a plan for emergencies.  Recommend subcomponents be retired.

 

EOP-011-1 R4

This is common sense.  We do not need a Requirement to state that we have a specific time to update something issued by the RC.  The RC can simply state have an update back by a certain time.  This becomes a time “gotcha” issue during an audit or self report.  This does not support system reliability.

 

EOP-011-1 R5

This is in line with the justification for retiring R4, as this is also common sense.  The RC will act immediately on all emergency notifications.  The time frame of 30 minutes only become an auditable point and does not support reliability.  If the requirement is not retired, at minimum the 30 minute criterion should be deleted.

 

EOP-011-1 R6

This is clearly stated in the Functional model under Real Time actions and does not need to be contained here; the RC will act immediately on all emergency notifications.  Recommend retirement of this Requirement.

 

FAC-002-2 R2, R3, R4, R5

Inherent in R1.

 

FAC-003-4 R4

R4 is a notification process only, without the next step of clearing happening.  This alone does not support reliability.  The clearing of the encroaching vegetation does support reliability and is covered in R1, R2, and R6.

 

FAC-008-3 R1, R2, R3, R6

Generator Facility Ratings are not useful as they are often different from the capability determined through MOD-025. This Standard is usually based solely on the nameplate ratings of components that are covered by this Standard.  Nameplate ratings become irrelevant with MOD-025-2, which captures the true capabilities of the asset. The TP will be notified of MOD-025-2 findings.  If the RC wants to know the MOD-025-2 capabilities, then they can ask for it under IRO-010-2.  The TOP can also request the same information under TOP-003-3.

 

IRO-001-4 R1

This is the basic functionality of an RC, as outlined in the Functional Model.

 

IRO-001-4 R2

Per the Functional Model, the BA, TOP, and GOP have reliability interactions with the RC, hence supporting a secure and stable reliable system.  The DP does not receive instructions from the RC; rather, they receive information from the BA and TOP. 

 

IRO-001-4 R3

This does not need to be a Requirement.  The RC can simply ask whether the registered entity has the ability to accomplish the task.  If the entity can't, the RC will take alternate actions. 

 

IRO-002-5 R3

Requirement 2 already provides for two active paths.  A NERC certification program can ensure that the paths are being used periodically.

 

IRO-008-2 R3

The RC's performance of the analysis is identified in R1.  A separately enforceable requirement that the RC take the common-sense action of informing impacted entities is unnecessary. 

 

IRO-008-2 R4

IRO-018-1 R2, when implemented, will address RTA quality.  The quality process could also assure RTA activity in accordance with utility practice (RTA, RTA backup, etc) without a hard standard-based 30 minute compliance threshold.  Candidate for NERC certification program.

 

IRO-008-2 R5

This requirement supports R2 and process can be verified through NERC Certification (process review).

 

IRO-010-2 R3

Real time data transmission involves telemetry for thousands of points scanned or updated every few seconds.  Retaining evidence of providing this volume of data is burdensome.

 

MOD-033-1 R2

This requires demonstration of the negative and after the fact validation.  This should be part of the Event Analysis process and not a NERC Requirement.

 

NUC-001-3 R9

Requirement is administrative as it only specifies what must be in the agreement.  R9 can be moved to a Guidance document since R9's second bullet states "The Nuclear Plant Generator Operator and the Transmission Entity are responsible for ensuring all the R9 elements are addressed."  An item can be addressed by stating that it is not applicable for the entity.

 

PER-003-1 R1, R2, R3 (ALL)

This Requirement is predicated on the NERC exam which is the responsibility of NERC and the PCGC, not a Registered Entity.  Recommend this Standard be retired.  Operators are trained on competencies.  Competencies can be verified through the training Standards.  Certifications should be verified through the NERC Certification program.

 

PER-004-2 R1

In addition to being redundant with PER-003-1 (which we also recommend be retired), this requirement is part of the Certification process and does not need to be within a Standard.

 

PER-004-2 R2

Already covered by IRO-009 R1/R2.

 

PER-005-2 R5, R6

Operations Support Personnel know their impact on reliability and the task list.  The prep and training used for OSP and the trainers is better spent for their job duties in support of reliability. 

 

PRC-002-2 R1-R12 (ALL)

Disturbance monitoring is for post-event analysis and does not have direct impact on reliability.  Guidelines and best business practices are sufficient to help improve accuracy and coordination.  This very granular and prescriptive standard is not needed.

 

PRC-004-5(i) R2, R3, R5

Only R1 and R6 are required in order to support system reliability and stability.  This Standard has too many time frames within each requirement and only provides a compliance gotcha if not followed.  Time frames don't support reliability.  The intent of this Standard is if you have a mis-operation that you notify everyone involved and fix it so it (hopefully) doesn't happen again.

 

PRC-005-6 R5

For PRC-005 Unresolved Maintenance Items (UMIs) are a low-volume and low-risk population with little to zero proven actual risk.  We are not aware of any events where UMIs were cited as a primary or contributory cause to a BES outage in the Events Analysis program.  Given the low volume of actual documented risk impacts and the low volume of self-logs or spreadsheet Notice of Penalty (SNOPs and NOPs), the UMI definition and requirement should be retired.  If not retired, the UMIs should be modified to clearly state in the requirements or measures that compliance by exception is allowed and that regulated entities are not required to prove a null set of data.

 

TOP-001-4 R1

The basic functionality of a TOP is to operate or direct operation of equipment to maintain reliability.  COM-002-4 clearly indicates that the TOP will be using Operating Instructions.  Please see responses re IRO-001-4 for additional retirement justification.

 

TOP-001-4 R2, R4-R7

Please see responses re IRO-001-4 for retirement justification.

 

TOP-001-4 R3

Requirement language is poorly worded because it is not specifically tied to Operating Instructions issued under TOP-001-4 R1 (i.e., Operating Instructions issued to maintain reliability).  As such, every entity in R3 must maintain a list of every Operating Instruction issued or received, whether the OI was issued for reliability or not.  The NERC Glossary of Terms definition for Operating Instruction pulls in all orders given to others to change the state of a BES Element, which means all planned switching orders issued by the operator, not just OIs issued for reliability.  This requirement would be improved by both limiting the duration Operating Instruction evidence needs to be retained and clarifying that the requirement applies only to OIs from TOP-001-4 R1.  The RSAW for TOP-001-4 R3 must also be corrected because it directs the audit to begin with the list of "all" Operating Instructions.  Please see responses re IRO-001-4 for additional retirement justification.

 

TOP-001-4 R8

Covered by EOP-011 R5 or can be merged with same Requirement.  Please see responses re IRO-001-4 for additional retirement justification.

 

TOP-001-4 R9

EMS quality codes suffice for notifications of RTU outages and were accepted by the RRO.  However, the Regional Entity does not agree.  So now unplanned outages need to be tracked for 30 minute overages for reporting.  This detracts from reliability and does not enhance reliability, especially when these outages are already indicated by quality codes.  Please see responses re IRO-001-4 for additional retirement justification.

 

TOP-001-4 R13

TOP-010-1 R3, when implemented, will address RTA quality.  The quality process could also assure RTA activity in accordance with utility practice (RTA, RTA backup, etc.) without a hard Requirement-based 30-minute compliance threshold.  Candidate for NERC Certification program.

 

TOP-001-4 R21

R20 already provides for two active paths and could address the concept of using the alternate periodically.  A NERC certification program can ensure that the paths are being used periodically.

 

TOP-001-4 R24

R23 already provides for two active paths and could address the concept of using the alternate periodically.  A NERC certification program can ensure that the paths are being used periodically.

 

TOP-002-4 R3

The TOP's performance of the analysis is required by R1.  A separately enforceable requirement that the TOP take the common-sense action of informing impacted entities is unnecessary.  Could be verified through NERC certification.

 

TOP-002-4 R4, R5, and R7

Daily Operating Plans are not needed for BAs.  Generation dispatch information can be gathered and shared through data provision requirements. 

 

TPL-007-1 R1

Administrative.

 

VAR-001-4.1 R1

Duplicative of FAC-014.

 

VAR-001-4.2 R5

All of R5 appears to be administrative and a common-sense operations item.  All entities keep impedance and tap information on their transformers.  There isn't any reason to withhold information if requested, so a mandatory standard backed by sanctions to provide information within 30 days is simply an administrative clock.  It's wasteful of both entity and regulator resources.

 

VAR-002-4.1 R3

Duplicative of other standards requiring data provision.  There is no justification for the 30 minute timing requirement; if a timing requirement is retained, it is not a good reliability practice to require notification "within 30 minutes," but only if status is not restored within 30 minutes.

 

VAR-002-4.1 R4

Duplicative of other standards requiring data provision.  There is no justification for a 30 minute time limit and this becomes a compliance trap.

 

VAR-002-4.1 R5

Duplicative of other standards requiring data provision.

Larry Watt, On Behalf of: Lakeland Electric, , Segments 1, 3, 5, 6

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I support the comments submitted by TAPS and the FMPA.

Patricia Boody, On Behalf of: Patricia Boody, , Segments 1, 3, 5, 6

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Allie Gavin, On Behalf of: International Transmission Company Holdings Corporation - MRO, RF - Segments 1

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JEA appreciates the effort of the SER Team and agrees with the recommendations and rationales to retire the proposed requirements with the exception of two comments:

1. JEA disagrees with the rationale for the retirement of PRC-004-5(i) R4. This requirement applies only when the cause of a Misoperation has not been determined and requires the TO/GO/DP to perform investigative actions every two quarters until a cause is identified OR a declaration is made that no cause was identified. 

a) The SAR states, “Requirement R4 acts as a control to support compliance with requirements R1 & R3.” However, R4 is not a control for determining “whether its Protection System component(s) caused a Misoperation”, but is the next step if the cause of a Misoperation, “for a Misoperation identified in accordance with Requirement R1 or R3”, has not been determined. 

b) The SAR also states, “It is in the best interest of the entity to continue to investigate and detect whether its Protection System components caused a mis-operation”, but this is more than just in the best interest of the entity. R1 requires the entity to “identify whether its Protection System component(s) caused a Misoperation.”

c) The SAR also states, “However, if an entity is unable to determine the cause, further investigation(s) using the same event data are unlikely to lead to identification of the cause.” But, investigative actions do improve reliability if they result in the identification of a cause. If no cause is identified, the TO/GO/DP can simply declare that no cause was identified, thereby satisfying the requirement. 

There may be valid reasons for retiring this requirement (milestone tracking doesn’t improve reliability, this is a typical best practice, etc.), but the reasons listed above are not valid based upon the current standard language.

 

2. JEA disagrees with the rationale for the retirements of COM-002-4 R2, EOP-005-3 R8, and EOP-006-3 R7. These requirements are not duplicated in the current version of PER-005-2. PER-005-2 R1.1 allows for the RC, BA, and TOP to create a list of BES “company-specific Real-time reliability-related tasks based on a defined and documented methodology”, but, if specific tasks are intended, then they should be stated directly. It’s implied that these reliability-related tasks would include communication protocols and system restoration, but PER-005-2 only requires a methodology to be followed rather than setting forth explicit minimum competency requirements which is what the requirements proposed for retirement include. 

Furthermore, there is clear distinction between the “initial training” of COM-002-4 R2 which occurs “prior to that individual operator issuing an Operating Instruction” and the continuous learning of PER-005-2.

Joe McClung, On Behalf of: JEA, FRCC, Segments 1, 3, 5

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IESO thanks the Standard Efficiency Review (SER) teams for all their hard work reviewing and analyzing the NERC Standards and requirements for possible retirements. The IESO agrees with the majority of the retirement recommendations of the SER teams in all but a few instances. These are listed below:

INT-009-2.1 R2

The SAR rationale is that it is redundant with NAESB business practices. NAESB is not regulatory and, therefore, we are not measured by compliance to NAESB. Furthermore, we do not design our business practices around NAESB rules.

While NAESB is more stringent, during reliability curtailments, we need the flexibility given to us by INT-010. This standard allows us to take action to address a reliability need and manage the e-tags after the concern has been addressed – allowing us to manage the e-tags later. We still need this flexibility as the e-tag system does not feed our dispatch tool directly and we would not want to be the “hold up” for a reliability curtailment so we can line up e-tag with our dispatch tools.

IRO-002-5 R4

This is fundamental to how we manage the grid. In the absence of this standard the RC's ability to monitor its BES area may become unavailable or deteriorated with no knowledge to the system operator.

IRO-008-2 R6

When and RC, TOP or BA becomes aware another RC is exceeding an SOL or an IROL that RC, TOP or BA may need to take mitigating actions to maintain reliability, therefore we disagree that with the SAR rationale that this requirement is administrative in nature and does provide reliability benefit. Keeping impacted entities informed in a timely fashion is good operating practice.

TOP-001-4 R16

This is fundamental to how we manage the grid. In the absence of this standard the TOP's ability to monitor its BES area may become unavailable or deteriorated with no knowledge to the system operator.

TOP-001-4 R17

This is fundamental to how we manage the grid. In the absence of this standard the TOP's ability to monitor its BES area may become unavailable or deteriorated with no knoweledge to the system operator.

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

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COM-002-4 R2 –Requires initial training on communication protocols; NERC proposes that R2 be retired as this topic should be covered in a PER-005-2 compliant Systematic Approach to Training program.  Training on ATC communication protocols and tasks to issue and receive op instructions are part of the SCO initial training program. As such, we agree with retirement of COM-002-4 R2.

 

EOP-005-3 R8 – requires annual system restoration training; NERC proposes that R8 be retired as this topic should be covered in a PER-005-2 compliant Systematic Approach to Training program.  Agree as we have three tasks in regards to PSR in the SCO initial training program.  Our continuing education program also has annual PSR training (classroom and DTS). As such, we agree with retirement of EOP-005-3 R8.

 

TOP-001-4 R16-NERC Certified Operators can be addressed through Certification Program and authority is part of the qualification.  PER-005-2 training supports this. As such, we agree with retirement of TOP-001-4 R16.

 

TOP-001-4 R19: the language used to describe how this is managed is through requirements in TOP-003-3 and TOP-002-4. As such, we agree with retirement of TOP-001-4 R19.

 

VAR-001-4 R2: TOP-001 and TOP-002 require the Transmission Operator to identify System Operating Limit exceedances during real-time and next-day conditions, respectively. System Operating Limits include voltage limits and management of reactive resources as described in VAR-001-4 R2 is fulfilled by acting according to the TOP standards. As such, we agree with retirement of VAR-001-4 R2.

 

VAR-001-4 R3: The directive in VAR-001-4.2 R3 is fulfilled as a result of compliance with TOP-001-3 R1, R12 and R14; in that the obligation in R1 to maintain the reliability of its operator area is unachievable by the TO if it does not operate devices to regulate voltage and reactive flow; additionally, TOP-001 R 12 and R14 cover addressing System Operating Limits and Interconnection Reliability Operating Limits, where the definition includes voltage stability ratings and system voltage limits. As such, we agree with retirement of VAR-001-4 R3.

 

Douglas Johnson, On Behalf of: Douglas Johnson, , Segments 1

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PSEG generally agrees with the purpose, scope, and content of the SAR, with the following exceptions:

FAC-003-4 Requirements R5 and R6: These requirements should be retired because R5 and R6 are controls and good utility practices but do not enhance BES reliability over R1 and R2. R1 and R2 fulfil the purpose of the standard through measurable actions. Also, the NERC Rules of Procedure allow consideration for extenuating circumstances relative to R5.

FAC-008-3 Requirement R8: Requirements R.8.1.2 and R8. 2 are not duplicative of TOP-003-3 or IRO-010-2. FAC-008-3 Requirement R8.2 necessitates that TOs provide to their associated RCs, PCs, TPs, TOs and TOPs the Requirement R8.1.2 “identity of the most limiting equipment of the Facilities,” Requirement R8.2.1 “identity of the existing next most limiting equipment of the Facilities,” and Requirement R8.2.2 “Thermal Rating for the next most limiting equipment identified in Requirement R8, Part 8.2.1,” whereas the TOP-003-3 or IRO-1010-2 standards do not appear to have this requirement.

IRO-010-2 Requirement R1 specifies the types of data that an RC collects from applicable entities, so that the RC may perform OPAs, RTM and RTAs.  The OPA RTM and RTA definitions (in the NERC Glossary of Terms) each mention “Facility Ratings” as an input (into OPA’s, RTM and RTA’s).  However, neither IRO-010-2, Requirement R1, nor the OPA, RTM and/or RTA definitions (in the NERC Glossary of Terms) contain the level of specificity in FAC-008-3 Requirement R8 (to “identity the most and the existing next most limiting equipment of the Facilities” and “the Thermal Rating for the next most limiting equipment identified in Requirement R8, Part 8.2.1”).  Similarly, TOP-003-3 Requirement R5 requires identified entities to fulfill a data specification provided by a BA or TOP so that OPAs, RTM, and RTA’s may be performed.  As in the case of IRO-010-2 Requirement R1 and the OPA, RTM and RTA definitions, TOP-003-3 does not require identification of the most and the existing next most limiting equipment of the Facilities and the Thermal Rating for the next most limiting equipment identified in FAC-008-3 Requirement R8, Part 8.2.1.”

NUC-001-3 R1: The requirement is administrative in nature, as Requirement R1 actions are inherent in Requirement R2 since each entity “shall have in effect” an agreement.

PSEG REs, Segment(s) 5, 6, 3, 1, 11/2/2017

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In general Southern Company agrees with the proposed requirements for retirement. However, Southern Company disagrees with the recommendations and rationales to retire the proposed requirements as noted below:

Southern does not agree with the recommendation and rationale to retire BAL-005-1 R4 and R6.  We believe that it is in the best interest of both clarity and reliability to have these requirements in both the BA and TOP standards as these functions are separately registered.

Southern does not agree that NERC should withdraw the petition regarding MOD-001-2.  The  combined effect of both MOD-001-2 and NAESB's WEQ-023 strike the appropriate balance between reliability and market related issues.

Southern Company recommends delaying the retirement of MOD-001-1a, MOD-004-1, MOD-008-1, MOD-028-2, MOD-029-2a and MOD-030-3 until NERC's MOD-001-2 and NAESB's WEQ-023 are approved by the Commission (FERC).  Once approved by the Commission, the industry should have adequate time to ensure a seamless transition to the new construct.    

Southern believes that reliability-related tasks are determined by each individual entity.  There is no obligation in the current NERC Reliability Standards to include the topics covered in EOP-005-3 (R8) or EOP-006-3 (R7) in the reliability related tasks for a TOP.

Southern believes that reliability related tasks are determined by each individual entity.  There is no obligation in a NERC standard requirement to include the topics covered in COM-002-4 R2 in the Reliability Related tasks for a TOP.

Southern does not agree with the rationale for retiring IRO-002-5 R4.  While we agree with the statement in the rationale, it doesn’t cover how an Operator has authority over various entities to direct the cancellation of outages.  It’s not found anywhere else in the NERC standards and for entities where the TOP may be a different company than the RC, an appropriately written NERC standard would help ensure that the RC Operator had the authority to deny a telecommunications outage that affected key operational data provided by the TOP to the RC.

Southern does not agree with the recommendation for IRO-014-3 R3.  R1.1 does not require notification of RCs and leaves it to the discretion of the RC experiencing the emergency to determine who is notified.  Moreover, what if the Emergency being experienced is not covered in an Operating Procedure, Process or Operating Plans?  The rationale assumes that all Operating Plans are generic and would cover all possible Emergencies experienced, but R1 of the standard doesn’t state that.

Southern does not agree with the overall rationale for retiring TOP-001-4 R16 and R17. While we support the wording in the rationale, it doesn’t fully encapsulate how an Operator has authority over entities to direct the cancellation of outages.  This language is not found anywhere else in the NERC Reliability Standards and for entities where the TO and GO may be a different company than the TOP, an appropriately written NERC standard would help ensure that the TOP Operator had the authority to deny a telecommunications outage that affected key operational data provided by the TO and/or GO to the TOP.

Southern Company, Segment(s) 1, 6, 3, 5, 9/1/2016

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

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We agree with all the requirements proposed for retirement and with their rationales, except for the following:

FAC-008-3 R7

We disagree with the rationale. As stated in the Hydro-Québec TransÉnergie's comments on the previous SAR, requirement FAC-008-3 R7 is not entirely redundant to MOD-032, IRO-010 and TOP-003 because the latter requirements to do address all the functions of FAC-008-3 R7.Namely, the TO function is excluded. The rationale should state that the TO function request is not essential to reliability and on that basis it is dropped and the remaining obligations are redundant to the aforementioned alternatives. If that is out of scope of this project, it should be addressed in the follow-on project. We consider that the requirement should be removed, one way or the other.

IRO-002-5 R6

We disagree with the stated rationale. As stated in the Hydro-Québec TransÉnergie's comments on the previous SAR, R6 requires communication over a “redundant infrastructure” which is not mentioned in requirement R5. Arguably, that aspect could be considered redundant to R2. In that case, the recommendation would remain valid.

COM-002-4 R2, EOP-005-3 R8, EOP-006-3 R7

The proposed transfer to PER-005-2 could leave a gap, as per our informal comments on the matter in the previous comment round.

IRO-006-5 R1

The applicable entity in requirement R1 is the RC. IRO-001-4 R2 is not applicable to the RC function. As such, we disagree with the rationale and the recommendation.

IRO-017-1 R3

We disagree on the stated rationale and with the recommendation. Removing R3 shifts the responsability for identifying the affected RC by a plan from the planner to the RC. Therefore, R3 is not duplicative with TPL-001-4 R8.

MOD-020-0 R1

We disagree with the rationale. MOD-020-1 allows operators (RC and TOP) to request information. In contrast, MOD-031-2 does not give RC or TOP the authority to request DSM information. IRO-010-2 does give the RC that authority but does not apply to the RP. So unless the NERC functional model guarantees that the DP has that information, there could be a gap.

 

PRC-004-5(i) R4

We disagree with the rationale and with the recommendation. If t is the case that auditors consider a non-compliance with respect to R2 or R3 a violation regardless of R4, then R4 is indeed useless. Since the intention of the standard was to allow an entity to extend its examination period, R2, R3 and R4 should be rewritten to achieve this intent. Cutting out R4 changes the intention of the standard to provide extensions to entities in order for them to identify causes of misops.

 

Michael Godbout, On Behalf of: Hydro-Qu?bec TransEnergie, NPCC, Segments 1

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Electric Reliability Council of Texas, Inc. (ERCOT) agrees with the recommendations and rationales to retire the following requirements identified in the Standards Authorization Request (SAR):

FAC-008-3 R7, R8

FAC-013-2 R1, R2, R4, R5, R6 (All)

INT-004-3.1 R1, R2, R3 (All)

TOP-001-4 R19, R22

 

ERCOT does not oppose the retirement of the following requirements identified in the SAR, but does not necessarily agree with each stated rationale articulated in support of retirement:

BAL-005-1 R4, R6

COM-002-4 R2

EOP-005-3 R8

EOP-006-3 R7

INT-006-4 R3.1, R4, R5

INT-009-2.1 R2

INT-010-2.1 R1, R2, R3 (All)*

IRO-002-5 R1, R4, R6

IRO-008-2 R6

IRO-014-3 R3

IRO-017 R3

MOD-001-1a R1, R2, R3, R4, R5, R6, R7, R8, R9 (All)

MOD-001-2 R1, R2, R3, R4, R5, R6 (All)

MOD-004-1 R1, R2, R3, R4, R5, R6, R7, R8, R9, R10, R11, R12 (All)

MOD-008-1 R1, R2, R3, R4, R5 (All)

MOD-020-0 R1 (All)

MOD-028-2 R1, R2, R3, R4, R5, R6, R7, R8, R9, R10, R11 (All)

MOD-029-2a R1, R2, R3, R4, R5, R6, R7, R8 (All)

MOD-030-3 R1, R2, R3, R4, R5, R6, R7, R8, R9, R10 (All)

PRC-015-1 R1, R2, R3 (All)

PRC-018-1 R1, R2, R3, R4, R5, R6 (All)

TOP-001-4 R16, R17

VAR-001-4.2 R2, R3

VAR-001-4.2 E.A.15

*Because INT-009-2.1 R1 refers to INT-010-2, it may be preferable to defer consideration of the retirement of the requirements in INT-010-2 to Phase II of Standards Efficiency Review. 

 

ERCOT does not agree with the recommendation and rationale to retire the following standard identified in the SAR for the reasons stated below:

PRC-004-5(i) R4

ERCOT does not support the outright retirement of PRC-004-5(i) Requirement R4 because to do so would eliminate the requirement to investigate in its entirety.  However, ERCOT agrees that the requirement as written may impose unnecessary burden by requiring repeated investigations despite the potential inability of a Transmission Owner, Generator Owner, or Distribution Provider to identify the cause(s) of a Misoperation. 

Brandon Gleason, On Behalf of: Brandon Gleason, , Segments 2

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A. BPA appreciates the opportunity to comment to the NERC Standards Effectiveness Review (SER) team on the path forward specifically concerning MOD-001-2 and the associated MOD standards (MOD-001-1a, MOD-004-1, MOD-008-1, MOD-028-2, MOD-029-2a, MOD-030-3.) BPA does not support the recommendation that NERC withdraw the February 10, 2014 petition to FERC related to MOD-001-2. Although NAESB completed the WEQ-023 Modeling Business Practice Standards which was based on a request from NERC to NAESB to address changes to the NERC MOD-001-2 Reliability Standards not yet ratified by FERC, FERC has not ratified the NAESB BPs. BPA supports the overall effort to migrate the commercial and business aspects of the NERC MOD Reliability Standards into corresponding NAESB Business Practice Standards, a position BPA filed on 09/26/16 in response to the FERC Notice of Proposed Rulemaking (156 FERC ¶ 61,055). In that NOPR, FERC makes clear that the status of the NAESB WEQ-023 Modeling standards and the NERC MOD-001-2 standards are now intertwined. Both are under consideration as part of FERC’s overall inquiry into ATC calculations. This includes Docket No. RM14-7-000, dealing with the original February 10, 2014 petition, as well as a related inquiry into ATC from Docket No. AD15-5-000. BPA recommends FERC address the overall ATC topic currently pending these dockets. FERC guidance on the overall direction of ATC standards is overdue and essential before NERC and/or NAESB invest further resources into companion standards. Because only Regulated utilities fall under the purview of the NAESB business practices, BPA urges NERC to closely collaborate with NAESB so there is a joint recommendation moving forward to FERC if NERC intends to proceed with modifying its approach to the February 10, 2014 petition. 

B. BPA disagrees with the retirement of INT-004-3.1.  NAESB Business Practice Standard WEQ-004 version 3.1 and FERC Docket RM05-5-25 are pending FERC approval.  Additionally, NAESB Business Practices are not enforceable.  Finally, the Pseudo-Tie Coordination Reference Document is just that, a reference document, and also not enforceable.

C. BPA supports the retirement of all other requirments in scope.

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

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William Sanders, On Behalf of: William Sanders, , Segments 1, 5

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Hot Answers

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

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Jamie Monette, On Behalf of: Allete - Minnesota Power, Inc., , Segments 1

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Other Answers

there is value examining the standards/requirements after 10 years of being enforceable.  Data requests may be enforced by NERC Rules of Procedure Section 1600.  A company's compliance culture is known now along with their internal controls.  It makes sense to alleviate administrative burdens by a comprehensive review approach.  We applaud NERC for this important effort.

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

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Scott McGough, On Behalf of: Georgia System Operations Corporation, , Segments 3, 4

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AECI supports the comments provided by NRECA.

AECI, Segment(s) 1, 3, 6, 5, 4/30/2018

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

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Patti Metro, On Behalf of: National Rural Electric Cooperative Association, , Segments 3, 4

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

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Consumers Energy Company, Segment(s) 1, 3, 4, 5, 11/29/2017

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Jesus Sammy Alcaraz, On Behalf of: Imperial Irrigation District, , Segments 1, 3, 5

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

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

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Diana McMahon, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

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Kelsi Rigby, On Behalf of: Kelsi Rigby, , Segments 1, 3, 5, 6

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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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Reclamation applauds this effort to retire duplicate and unnecessary requirements, and suggests a future project to consolidate additional requirements and evaluate the NERC Glossary of Terms for clarity and efficiency.

Wendy Center, On Behalf of: U.S. Bureau of Reclamation, , Segments 1, 5

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On behalf of our City Light SMEs, we believe these requirements should be retired.

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

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Exelon Utilities, Segment(s) 1, 3, 5/19/2015

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Cynthia Lee, On Behalf of: Exelon, , Segments 1, 3, 5, 6

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TAPS appreciates the work of the Standards Efficiency Review Teams in developing this SAR.  We believe the justifications for the SAR’s proposed retirements are well-explained.  We also believe, however, that several additional requirements should be retired either as part of this SAR or in Phase 2, as set forth below.

COM-001-3 R1, R2, R3, R4, R5, R6, R7, R8, R9, R10, R11, R12, and R13 (ALL)
Basic functionality.  This should be part of the certification process for BAs, TOPs and RCs.  For all other entities (DPs and GOs), it is not necessary to require communication to be proven as the RC, TOP or BA will assure that they can make contact with these entities, and all entities have internal and external Interpersonal Communications Capabilities.  This Standard basically states to have primary and back up communications (a phone).  In today's world, basic, daily functionality necessitates multiple avenues of communications such as a land line phone, a cell phone, text messaging, a radio, satellite phone, etc.  This Standard is not necessary for reliability; it only enforces a compliance “gotcha” if a registered entity’s primary communication system fails.  There is not a reliability benefit from COM-001-3, just administrative burden.  Communications are a basic function of every registered entity.  The entire Standard should be retired.

COM-002-4 R3
R1 protocols cover all aspects of operating protocols.  If communication is a reliability-related task, then training is covered in PER-005.

COM-002-4 R4
R4 and its subrequirements are a control and should not be an auditable item.

COM-002-4 R5, R6, R7
There should be no difference between an Operation Instruction under normal conditions and under Emergency conditions.  R1 covers all Operating instructions.  By imposing additional requirements on Operating Instructions that are issued during an emergency, R5, R6, and R7 make it necessary for entities to track whether each Operating Instruction was issued during an Emergency or during normal operations, in order to be able to demonstrate compliance.  This administrative burden does not enhance reliability.

EOP-005-3 R3
Verify through NERC Certification program.

EOP-008-2 R2 
Verify through NERC Certification program.

EOP-008-2 R3, R4
NERC Certified Operators can be addressed through Certification Program.  R6 addresses Primary and Backup and can also address the sub-bullets in this Requirement.  Sub-bullets of R4 can be addressed in R8.

EOP-010-1 R2
This is for situational awareness only and may be a mitigating feature of R1.  If one K warning is not sent out, it becomes a non-compliance issue.  This is also covered in EOP-011-1, R1.2.1.

EOP-010-1 R3.1
R3.1 is contained in R1.  Per part 3.1, this will force the TOP to prove a negative if they did not receive any space weather information. Part 3.2 starts the mitigating processes for GMD events and part 3.3 concludes them.  Part 3.1 is administrative in nature as alone, it does not accomplish anything; parts 3.2 and 3.3 mitigate the GMD.  Recommend part 3.1 be retired.  If not retired, part 3.1 should be modified to clearly state in the requirements or measures that proof of compliance is to show the steps only and entities are not required to prove a null set of data.

EOP-011-1 R1 subparts
R1.1 does not enhance or enforce reliability; it is only an auditable item.  R1.2.2, R1.2.3, R1.2.4, R1.2.5, and R1.2.6 are all actions or event types that require actions.  These are all event-specific.  The Operating plan will just say that the operator will do something to mitigate these events.  Then it becomes an auditable item in the Operating Plan, only.  R1 is simple enough: have a plan for emergencies.  Recommend subcomponents be retired.

EOP-011-1 R2 subparts
R2.1 does not enhance or enforce reliability; it is only an auditable item.  R2.2.3 and its parts and R2.2.4, R2.2.5, R2.2.6, R2.2.7, R2.2.8 and R2.2.9 are all actions or event types that require actions.  These are all event-specific.  The Operating plan will just say that the operator will do something to mitigate these events.  Then it becomes an auditable item in the Operating Plan.  R2 is simple enough: have a plan for emergencies.  Recommend subcomponents be retired.

EOP-011-1 R4
This is common sense.  We do not need a Requirement to state that we have a specific time to update something issued by the RC.  The RC can simply state have an update back by a certain time.  This becomes a time “gotcha” issue during an audit or self report.  This does not support system reliability.

EOP-011-1 R5
This is in line with the justification for retiring R4, as this is also common sense.  The RC will act immediately on all emergency notifications.  The time frame of 30 minutes only become an auditable point and does not support reliability.  If the requirement is not retired, at minimum the 30 minute criterion should be deleted.

EOP-011-1 R6
This is clearly stated in the Functional model under Real Time actions and does not need to be contained here; the RC will act immediately on all emergency notifications.  Recommend retirement of this Requirement.

FAC-002-2 R2, R3, R4, R5
Inherent in R1.

FAC-003-4 R4
R4 is a notification process only, without the next step of clearing happening.  This alone does not support reliability.  The clearing of the encroaching vegetation does support reliability and is covered in R1, R2, and R6.

FAC-008-3 R1, R2, R3, R6
Generator Facility Ratings are not useful as they are often different from the capability determined through MOD-025. This Standard is usually based solely on the nameplate ratings of components that are covered by this Standard.  Nameplate ratings become irrelevant with MOD-025-2, which captures the true capabilities of the asset. The TP will be notified of MOD-025-2 findings.  If the RC wants to know the MOD-025-2 capabilities, then they can ask for it under IRO-010-2.  The TOP can also request the same information under TOP-003-3.

IRO-001-4 R1
This is the basic functionality of an RC, as outlined in the Functional Model.

IRO-001-4 R2
Per the Functional Model, the BA, TOP, and GOP have reliability interactions with the RC, hence supporting a secure and stable reliable system.  The DP does not receive instructions from the RC; rather, they receive information from the BA and TOP.  

IRO-001-4 R3
This does not need to be a Requirement.  The RC can simply ask whether the registered entity has the ability to accomplish the task.  If the entity can't, the RC will take alternate actions.  

IRO-002-5 R3
Requirement 2 already provides for two active paths.  A NERC certification program can ensure that the paths are being used periodically.

IRO-008-2 R3
The RC's performance of the analysis is identified in R1.  A separately enforceable requirement that the RC take the common-sense action of informing impacted entities is unnecessary.  

IRO-008-2 R4
IRO-018-1 R2, when implemented, will address RTA quality.  The quality process could also assure RTA activity in accordance with utility practice (RTA, RTA backup, etc) without a hard standard-based 30 minute compliance threshold.  Candidate for NERC certification program.

IRO-008-2 R5
This requirement supports R2 and process can be verified through NERC Certification (process review).

IRO-010-2 R3
Real time data transmission involves telemetry for thousands of points scanned or updated every few seconds.  Retaining evidence of providing this volume of data is burdensome.

MOD-033-1 R2
This requires demonstration of the negative and after the fact validation.  This should be part of the Event Analysis process and not a NERC Requirement.

NUC-001-3 R9
Requirement is administrative as it only specifies what must be in the agreement.  R9 can be moved to a Guidance document since R9's second bullet states "The Nuclear Plant Generator Operator and the Transmission Entity are responsible for ensuring all the R9 elements are addressed."  An item can be addressed by stating that it is not applicable for the entity.

PER-003-1 R1, R2, R3 (ALL)
This Requirement is predicated on the NERC exam which is the responsibility of NERC and the PCGC, not a Registered Entity.  Recommend this Standard be retired.  Operators are trained on competencies.  Competencies can be verified through the training Standards.  Certifications should be verified through the NERC Certification program.

PER-004-2 R1
In addition to being redundant with PER-003-1 (which we also recommend be retired), this requirement is part of the Certification process and does not need to be within a Standard.

PER-004-2 R2
Already covered by IRO-009 R1/R2.

PER-005-2 R5, R6
Operations Support Personnel know their impact on reliability and the task list.  The prep and training used for OSP and the trainers is better spent for their job duties in support of reliability.  

PRC-002-2 R1-R12 (ALL)
Disturbance monitoring is for post-event analysis and does not have direct impact on reliability.  Guidelines and best business practices are sufficient to help improve accuracy and coordination.  This very granular and prescriptive standard is not needed.

PRC-004-5(i) R2, R3, R5 
Only R1 and R6 are required in order to support system reliability and stability.  This Standard has too many time frames within each requirement and only provides a compliance gotcha if not followed.  Time frames don't support reliability.  The intent of this Standard is if you have a mis-operation that you notify everyone involved and fix it so it (hopefully) doesn't happen again.

PRC-005-6 R5 
For PRC-005 Unresolved Maintenance Items (UMIs) are a low-volume and low-risk population with little to zero proven actual risk.  We are not aware of any events where UMIs were cited as a primary or contributory cause to a BES outage in the Events Analysis program.  Given the low volume of actual documented risk impacts and the low volume of self-logs or spreadsheet Notice of Penalty (SNOPs and NOPs), the UMI definition and requirement should be retired.  If not retired, the UMIs should be modified to clearly state in the requirements or measures that compliance by exception is allowed and that regulated entities are not required to prove a null set of data.

TOP-001-4 R1
The basic functionality of a TOP is to operate or direct operation of equipment to maintain reliability.  COM-002-4 clearly indicates that the TOP will be using Operating Instructions.  Please see responses re IRO-001-4 for additional retirement justification.

TOP-001-4 R2, R4-R7
Please see responses re IRO-001-4 for retirement justification.

TOP-001-4 R3
Requirement language is poorly worded because it is not specifically tied to Operating Instructions issued under TOP-001-4 R1 (i.e., Operating Instructions issued to maintain reliability).  As such, every entity in R3 must maintain a list of every Operating Instruction issued or received, whether the OI was issued for reliability or not.  The NERC Glossary of Terms definition for Operating Instruction pulls in all orders given to others to change the state of a BES Element, which means all planned switching orders issued by the operator, not just OIs issued for reliability.  This requirement would be improved by both limiting the duration Operating Instruction evidence needs to be retained and clarifying that the requirement applies only to OIs from TOP-001-4 R1.  The RSAW for TOP-001-4 R3 must also be corrected because it directs the audit to begin with the list of "all" Operating Instructions.  Please see responses re IRO-001-4 for additional retirement justification.

TOP-001-4 R8
Covered by EOP-011 R5 or can be merged with same Requirement.  Please see responses re IRO-001-4 for additional retirement justification.

TOP-001-4 R9
EMS quality codes suffice for notifications of RTU outages and were accepted by the RRO.  However, the Regional Entity does not agree.  So now unplanned outages need to be tracked for 30 minute overages for reporting.  This detracts from reliability and does not enhance reliability, especially when these outages are already indicated by quality codes.  Please see responses re IRO-001-4 for additional retirement justification.

TOP-001-4 R13
TOP-010-1 R3, when implemented, will address RTA quality.  The quality process could also assure RTA activity in accordance with utility practice (RTA, RTA backup, etc.) without a hard Requirement-based 30-minute compliance threshold.  Candidate for NERC Certification program.

TOP-001-4 R21
R20 already provides for two active paths and could address the concept of using the alternate periodically.  A NERC certification program can ensure that the paths are being used periodically.

TOP-001-4 R24
R23 already provides for two active paths and could address the concept of using the alternate periodically.  A NERC certification program can ensure that the paths are being used periodically.

TOP-002-4 R3
The TOP's performance of the analysis is required by R1.  A separately enforceable requirement that the TOP take the common-sense action of informing impacted entities is unnecessary.  Could be verified through NERC certification.

TOP-002-4 R4, R5, and R7
Daily Operating Plans are not needed for BAs.  Generation dispatch information can be gathered and shared through data provision requirements.  

TPL-007-1 R1 
Administrative.

VAR-001-4.1 R1
Duplicative of FAC-014.

VAR-001-4.2 R5
All of R5 appears to be administrative and a common-sense operations item.  All entities keep impedance and tap information on their transformers.  There isn't any reason to withhold information if requested, so a mandatory standard backed by sanctions to provide information within 30 days is simply an administrative clock.  It's wasteful of both entity and regulator resources.

VAR-002-4.1 R3
Duplicative of other standards requiring data provision.  There is no justification for the 30 minute timing requirement; if a timing requirement is retained, it is not a good reliability practice to require notification "within 30 minutes," but only if status is not restored within 30 minutes.

VAR-002-4.1 R4
Duplicative of other standards requiring data provision.  There is no justification for a 30 minute time limit and this becomes a compliance trap.

VAR-002-4.1 R5
Duplicative of other standards requiring data provision.

Rebecca Baldwin, On Behalf of: Transmission Access Policy Study Group, NA - Not Applicable, Segments 4

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FMPA agrees with the following comments submitted by TAPS:

We believe the justifications for the SAR’s proposed retirements are well-explained.  We also believe, however, that several additional requirements should be retired either as part of this SAR or in Phase 2, as set forth below.

 

COM-001-3 R1, R2, R3, R4, R5, R6, R7, R8, R9, R10, R11, R12, and R13 (ALL)

Basic functionality.  This should be part of the certification process for BAs, TOPs and RCs.  For all other entities (DPs and GOs), it is not necessary to require communication to be proven as the RC, TOP or BA will assure that they can make contact with these entities, and all entities have internal and external Interpersonal Communications Capabilities.  This Standard basically states to have primary and back up communications (a phone).  In today's world, basic, daily functionality necessitates multiple avenues of communications such as a land line phone, a cell phone, text messaging, a radio, satellite phone, etc.  This Standard is not necessary for reliability; it only enforces a compliance “gotcha” if a registered entity’s primary communication system fails.  There is not a reliability benefit from COM-001-3, just administrative burden.  Communications are a basic function of every registered entity.  The entire Standard should be retired.

 

COM-002-4 R3

R1 protocols cover all aspects of operating protocols.  If communication is a reliability-related task, then training is covered in PER-005.

 

COM-002-4 R4

R4 and its subrequirements are a control and should not be an auditable item.

 

COM-002-4 R5, R6, R7

There should be no difference between an Operation Instruction under normal conditions and under Emergency conditions.  R1 covers all Operating instructions.  By imposing additional requirements on Operating Instructions that are issued during an emergency, R5, R6, and R7 make it necessary for entities to track whether each Operating Instruction was issued during an Emergency or during normal operations, in order to be able to demonstrate compliance.  This administrative burden does not enhance reliability.

 

EOP-005-3 R3

Verify through NERC Certification program.

 

EOP-008-2 R2

Verify through NERC Certification program.

 

EOP-008-2 R3, R4

NERC Certified Operators can be addressed through Certification Program.  R6 addresses Primary and Backup and can also address the sub-bullets in this Requirement.  Sub-bullets of R4 can be addressed in R8.

 

EOP-010-1 R2

This is for situational awareness only and may be a mitigating feature of R1.  If one K warning is not sent out, it becomes a non-compliance issue.  This is also covered in EOP-011-1, R1.2.1.

 

EOP-010-1 R3.1

R3.1 is contained in R1.  Per part 3.1, this will force the TOP to prove a negative if they did not receive any space weather information. Part 3.2 starts the mitigating processes for GMD events and part 3.3 concludes them.  Part 3.1 is administrative in nature as alone, it does not accomplish anything; parts 3.2 and 3.3 mitigate the GMD.  Recommend part 3.1 be retired.  If not retired, part 3.1 should be modified to clearly state in the requirements or measures that proof of compliance is to show the steps only and entities are not required to prove a null set of data.

 

EOP-011-1 R1 subparts 

R1.1 does not enhance or enforce reliability; it is only an auditable item.  R1.2.2, R1.2.3, R1.2.4, R1.2.5, and R1.2.6 are all actions or event types that require actions.  These are all event-specific.  The Operating plan will just say that the operator will do something to mitigate these events.  Then it becomes an auditable item in the Operating Plan, only.  R1 is simple enough: have a plan for emergencies.  Recommend subcomponents be retired.

 

EOP-011-1 R2 subparts

R2.1 does not enhance or enforce reliability; it is only an auditable item.  R2.2.3 and its parts and R2.2.4, R2.2.5, R2.2.6, R2.2.7, R2.2.8 and R2.2.9 are all actions or event types that require actions.  These are all event-specific.  The Operating plan will just say that the operator will do something to mitigate these events.  Then it becomes an auditable item in the Operating Plan.  R2 is simple enough: have a plan for emergencies.  Recommend subcomponents be retired.

 

EOP-011-1 R4

This is common sense.  We do not need a Requirement to state that we have a specific time to update something issued by the RC.  The RC can simply state have an update back by a certain time.  This becomes a time “gotcha” issue during an audit or self report.  This does not support system reliability.

 

EOP-011-1 R5

This is in line with the justification for retiring R4, as this is also common sense.  The RC will act immediately on all emergency notifications.  The time frame of 30 minutes only become an auditable point and does not support reliability.  If the requirement is not retired, at minimum the 30 minute criterion should be deleted.

 

EOP-011-1 R6

This is clearly stated in the Functional model under Real Time actions and does not need to be contained here; the RC will act immediately on all emergency notifications.  Recommend retirement of this Requirement.

 

FAC-002-2 R2, R3, R4, R5

Inherent in R1.

 

FAC-003-4 R4

R4 is a notification process only, without the next step of clearing happening.  This alone does not support reliability.  The clearing of the encroaching vegetation does support reliability and is covered in R1, R2, and R6.

 

FAC-008-3 R1, R2, R3, R6

Generator Facility Ratings are not useful as they are often different from the capability determined through MOD-025. This Standard is usually based solely on the nameplate ratings of components that are covered by this Standard.  Nameplate ratings become irrelevant with MOD-025-2, which captures the true capabilities of the asset. The TP will be notified of MOD-025-2 findings.  If the RC wants to know the MOD-025-2 capabilities, then they can ask for it under IRO-010-2.  The TOP can also request the same information under TOP-003-3.

 

IRO-001-4 R1

This is the basic functionality of an RC, as outlined in the Functional Model.

 

IRO-001-4 R2

Per the Functional Model, the BA, TOP, and GOP have reliability interactions with the RC, hence supporting a secure and stable reliable system.  The DP does not receive instructions from the RC; rather, they receive information from the BA and TOP. 

 

IRO-001-4 R3

This does not need to be a Requirement.  The RC can simply ask whether the registered entity has the ability to accomplish the task.  If the entity can't, the RC will take alternate actions. 

 

IRO-002-5 R3

Requirement 2 already provides for two active paths.  A NERC certification program can ensure that the paths are being used periodically.

 

IRO-008-2 R3

The RC's performance of the analysis is identified in R1.  A separately enforceable requirement that the RC take the common-sense action of informing impacted entities is unnecessary. 

 

IRO-008-2 R4

IRO-018-1 R2, when implemented, will address RTA quality.  The quality process could also assure RTA activity in accordance with utility practice (RTA, RTA backup, etc) without a hard standard-based 30 minute compliance threshold.  Candidate for NERC certification program.

 

IRO-008-2 R5

This requirement supports R2 and process can be verified through NERC Certification (process review).

 

IRO-010-2 R3

Real time data transmission involves telemetry for thousands of points scanned or updated every few seconds.  Retaining evidence of providing this volume of data is burdensome.

 

MOD-033-1 R2

This requires demonstration of the negative and after the fact validation.  This should be part of the Event Analysis process and not a NERC Requirement.

 

NUC-001-3 R9

Requirement is administrative as it only specifies what must be in the agreement.  R9 can be moved to a Guidance document since R9's second bullet states "The Nuclear Plant Generator Operator and the Transmission Entity are responsible for ensuring all the R9 elements are addressed."  An item can be addressed by stating that it is not applicable for the entity.

 

PER-003-1 R1, R2, R3 (ALL)

This Requirement is predicated on the NERC exam which is the responsibility of NERC and the PCGC, not a Registered Entity.  Recommend this Standard be retired.  Operators are trained on competencies.  Competencies can be verified through the training Standards.  Certifications should be verified through the NERC Certification program.

 

PER-004-2 R1

In addition to being redundant with PER-003-1 (which we also recommend be retired), this requirement is part of the Certification process and does not need to be within a Standard.

 

PER-004-2 R2

Already covered by IRO-009 R1/R2.

 

PER-005-2 R5, R6

Operations Support Personnel know their impact on reliability and the task list.  The prep and training used for OSP and the trainers is better spent for their job duties in support of reliability. 

 

PRC-002-2 R1-R12 (ALL)

Disturbance monitoring is for post-event analysis and does not have direct impact on reliability.  Guidelines and best business practices are sufficient to help improve accuracy and coordination.  This very granular and prescriptive standard is not needed.

 

PRC-004-5(i) R2, R3, R5

Only R1 and R6 are required in order to support system reliability and stability.  This Standard has too many time frames within each requirement and only provides a compliance gotcha if not followed.  Time frames don't support reliability.  The intent of this Standard is if you have a mis-operation that you notify everyone involved and fix it so it (hopefully) doesn't happen again.

 

PRC-005-6 R5

For PRC-005 Unresolved Maintenance Items (UMIs) are a low-volume and low-risk population with little to zero proven actual risk.  We are not aware of any events where UMIs were cited as a primary or contributory cause to a BES outage in the Events Analysis program.  Given the low volume of actual documented risk impacts and the low volume of self-logs or spreadsheet Notice of Penalty (SNOPs and NOPs), the UMI definition and requirement should be retired.  If not retired, the UMIs should be modified to clearly state in the requirements or measures that compliance by exception is allowed and that regulated entities are not required to prove a null set of data.

 

TOP-001-4 R1

The basic functionality of a TOP is to operate or direct operation of equipment to maintain reliability.  COM-002-4 clearly indicates that the TOP will be using Operating Instructions.  Please see responses re IRO-001-4 for additional retirement justification.

 

TOP-001-4 R2, R4-R7

 

Please see responses re IRO-001-4 for retirement justification.

 

TOP-001-4 R3

Requirement language is poorly worded because it is not specifically tied to Operating Instructions issued under TOP-001-4 R1 (i.e., Operating Instructions issued to maintain reliability).  As such, every entity in R3 must maintain a list of every Operating Instruction issued or received, whether the OI was issued for reliability or not.  The NERC Glossary of Terms definition for Operating Instruction pulls in all orders given to others to change the state of a BES Element, which means all planned switching orders issued by the operator, not just OIs issued for reliability.  This requirement would be improved by both limiting the duration Operating Instruction evidence needs to be retained and clarifying that the requirement applies only to OIs from TOP-001-4 R1.  The RSAW for TOP-001-4 R3 must also be corrected because it directs the audit to begin with the list of "all" Operating Instructions.  Please see responses re IRO-001-4 for additional retirement justification.

 

TOP-001-4 R8

Covered by EOP-011 R5 or can be merged with same Requirement.  Please see responses re IRO-001-4 for additional retirement justification.

 

TOP-001-4 R9

EMS quality codes suffice for notifications of RTU outages and were accepted by the RRO.  However, the Regional Entity does not agree.  So now unplanned outages need to be tracked for 30 minute overages for reporting.  This detracts from reliability and does not enhance reliability, especially when these outages are already indicated by quality codes.  Please see responses re IRO-001-4 for additional retirement justification.

 

TOP-001-4 R13

TOP-010-1 R3, when implemented, will address RTA quality.  The quality process could also assure RTA activity in accordance with utility practice (RTA, RTA backup, etc.) without a hard Requirement-based 30-minute compliance threshold.  Candidate for NERC Certification program.

 

TOP-001-4 R21

R20 already provides for two active paths and could address the concept of using the alternate periodically.  A NERC certification program can ensure that the paths are being used periodically.

 

TOP-001-4 R24

R23 already provides for two active paths and could address the concept of using the alternate periodically.  A NERC certification program can ensure that the paths are being used periodically.

 

TOP-002-4 R3

The TOP's performance of the analysis is required by R1.  A separately enforceable requirement that the TOP take the common-sense action of informing impacted entities is unnecessary.  Could be verified through NERC certification.

 

TOP-002-4 R4, R5, and R7

Daily Operating Plans are not needed for BAs.  Generation dispatch information can be gathered and shared through data provision requirements. 

 

TPL-007-1 R1

Administrative.

 

VAR-001-4.1 R1

Duplicative of FAC-014.

 

VAR-001-4.2 R5

All of R5 appears to be administrative and a common-sense operations item.  All entities keep impedance and tap information on their transformers.  There isn't any reason to withhold information if requested, so a mandatory standard backed by sanctions to provide information within 30 days is simply an administrative clock.  It's wasteful of both entity and regulator resources.

 

VAR-002-4.1 R3

Duplicative of other standards requiring data provision.  There is no justification for the 30 minute timing requirement; if a timing requirement is retained, it is not a good reliability practice to require notification "within 30 minutes," but only if status is not restored within 30 minutes.

 

VAR-002-4.1 R4

 

Duplicative of other standards requiring data provision.  There is no justification for a 30 minute time limit and this becomes a compliance trap.

 

VAR-002-4.1 R5

Duplicative of other standards requiring data provision.

FMPA, Segment(s) , 10/23/2017

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While we disagree with some of the recommendations of the SDT, we agree that the project has merit, and should proceed.

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

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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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Larry Watt, On Behalf of: Lakeland Electric, , Segments 1, 3, 5, 6

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I support the comments submitted by TAPS and the FMPA.

Patricia Boody, On Behalf of: Patricia Boody, , Segments 1, 3, 5, 6

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Allie Gavin, On Behalf of: International Transmission Company Holdings Corporation - MRO, RF - Segments 1

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Joe McClung, On Behalf of: JEA, FRCC, Segments 1, 3, 5

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

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Douglas Johnson, On Behalf of: Douglas Johnson, , Segments 1

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PSEG enthusiastically supports NERC for seeking to eliminate and modify standards requirements to improve their effectiveness and efficiency.

PSEG REs, Segment(s) 5, 6, 3, 1, 11/2/2017

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Southern Company believes NERC should proceed with this project in an effort to identify those current reliability standards that either are duplicative in nature or have little to no impact on improving reliability of the system.

Southern Company, Segment(s) 1, 6, 3, 5, 9/1/2016

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

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Definitely.

Michael Godbout, On Behalf of: Hydro-Qu?bec TransEnergie, NPCC, Segments 1

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Brandon Gleason, On Behalf of: Brandon Gleason, , Segments 2

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None

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

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William Sanders, On Behalf of: William Sanders, , Segments 1, 5

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