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Individual or group.  (50 Responses)
Name  (31 Responses)
Organization  (31 Responses)
Group Name  (19 Responses)
Lead Contact  (19 Responses)
Contact Organization  (19 Responses)
Question 1  (50 Responses)
Question 1 Comments  (50 Responses)
Question 2  (47 Responses)
Question 2 Comments  (50 Responses)
 
Group
Northeast Power Coordinating Council
Guy Zito
Northeast Power Coordinating Council
No
Suggest adding “Protection System Components including” in the beginning. This is because the word “components” has been used extensively throughout the standard and there is no mention of what constitutes a protection system component in the standard. The word “component” does find mention in FAQs, however, it is recommended to mention it in the body of the standard. The revised definition should read as follows: Protection System Components including Protective relays, communication systems necessary for correct operation of protective functions, voltage and current sensing devices providing inputs to protective relays and associated circuitry from the voltage and current sensing devices, station dc supply, and control circuitry associated with protective functions from the station dc supply through the trip coil(s) of the circuit breakers or other interrupting devices. An alternative definition for Protection System to eliminate the need to capitalize “component”: The collective components comprised of protective relays, communication systems necessary for correct operation of protective functions, voltage and current sensing devices providing inputs to protective relays and associated circuitry from the voltage and current sensing devices, station dc supply, and control circuitry associated with protective functions from the station dc supply through the trip coil(s) of the circuit breakers or other interrupting devices. There is not enough clarity on whether a Distribution Provider (DP) will be able to clearly identify which protection system components it does own and needs to maintain. Many DPs own and/or operate equipment identified in the existing or proposed definition. However, not all such equipment translates into a transmission Protection System. The definition needs clarification on when such equipment is a part of the transmission protection system. This is critical since NPCC had proposed a SAR to this effect which was not accepted by NERC citing that this concern will be incorporated in the revised standard. Also, reference should be made to Project 2009-17 in which Y-W Electric Association, Inc. (Y-WEA) and Tri-State Generation and Transmission Association, Inc. (Tri-State) requested an interpretation of the term "transmission Protection System" and specifically whether protection for a radially-connected transformer protection system energized from the BES is considered a transmission Protection System and is subject to these standards.
No
The time provided for the first phase “at least six months” is too open ended and does not give entities a clear timeline. Suggest 1 year for the first phase. Suggest phasing out the second phase in stages.
Group
SERC Protection and Control Sub-committee (PCS)
Joe Spencer - SERC staff and Phil Winston - PCS co-chair
SERC Reliability Corp.
Yes
We agree that the definition provides clarity and will enhance the reliability of the Protection Systems to which it is applicable; however, we believe there should be a direct linkage of the definition’s effective date to the approval and implementation schedule of PRC-005-2. Since this new definition is directly linked to the proposed revised standard, it would be premature to make this definition effective prior to the effective date of the new standard.
No
As noted above, the implementation plan should be linked to the approval of PRC-005-2. Since this new definition is directly linked to the proposed revised standard, it would be premature to make this definition effective prior to the effective date of the new standard.
Individual
Jack Stamper
Clark Public Utilities
Yes
 
No
While the drafting team has done a great job of simplifying the implementation plan from the original draft 1 language, the current language has some ambiguities. I do not understand what the term “the end of the first calendar quarter six months following regulatory approvals” means. What is wrong with just saying “within nine months (or six months or twelve months) following regulatory approvals? Using the current language I would be inclined to assume it is six months so I can avoid a dispute (and quite possibly a notice of alleged violation) over a date. Also, I am not sure what the term “the end of the first complete maintenance and testing cycle described in the entity’s program description” means. It is quite likely that a registered entity will make the required definition change to its maintenance program (at approximately six months) and wind up with devices that need to be tested. Is the implementation plan attempting to provide some allowed time delay so the registered entity will not be out of compliance even though it has devices that are now beyond the maximum testing interval due to the definition change? The existing language implies that within approximately six months of regulatory approval, the maintenance program needs to be changed to incorporate the revised definition for Protection System. However, the effective date for the revised maintenance program is going to be some date that corresponds with the end of the first complete maintenance and testing cycle in that program. I really don’t understand what that time period is and I believe the drafting team needs to put in something that clears up this confusion. By testing cycle do you mean “maximum interval” as shown in the PRC-005 table? Do you mean the “maximum interval” that a registered entity includes in their maintenance program? If so, do you intend the implementation to be a different date for protection devices depending on the maximum testing interval? Or do you envision some date beyond the six months where the entire maintenance program (with the definition change) becomes effective and any registered entities with out-of-compliance issues would need to file mitigation plans?
Individual
Dan Roethemeyer
Dynegy Inc.
Yes
 
Yes
 
Individual
Robert Ganley
Long Island Power Authority
No
LIPA suggests adding “Protection System Components including” in the beginning. This is because the word “components” has been used extensively throughout the standard and there is no mention of what constitutes a protection system component in the standard. The word “component” does find mention in FAQs, however, it is recommended to mention it in the main standard. Also, LIPA proposes a change in the proposed definition (changing "voltage and current sensing inputs" to "voltage and current sensing devices providing inputs"). The revised definition should read as follows: Protective System Components including Protective relays, communication systems necessary for correct operation of protective functions, voltage and current sensing devices providing inputs to protective relays and associated circuitry from the voltage and current sensing devices, station dc supply, and control circuitry associated with protective functions from the station dc supply through the trip coil(s) of the circuit breakers or other interrupting devices. There is not enough clarity on whether a Distribution Provider (DP) will be able to clearly identify all protection system components it owns and needs to maintain. This is critical since NPCC had proposed a SAR to this effect which was not accepted by NERC citing that this concern will be incorporated in the revised standard.
No
The time provided for the first phase “at least six months” is too open ended and does not give entities a clear timeline. LIPA suggests 1 year for the first phase. It is also suggested phasing out the second phase in stages.
Group
PacifiCorp
Sandra Shaffer
PacifiCorp
Yes
 
Yes
 
Group
Pacific Northwest Small Public Power Utility Comment Group
Steve Alexanderson
Central Lincoln
No
It is still unclear whether relays that respond to mechanical inputs, such as sudden pressure relays, are included in the proposed definition as protective relays. While PRC-005-2 R1 limits the scope of that particular standard to protection systems that sense electrical quantities, it is remains unclear in other standards that use the defined term whether mechanical input protections are included. We suggest that “Protective Relay” also be defined, and that the definition clearly exclude devices that respond to mechanical inputs in line with the NERC interpretation of PRC-005-1 in response to the CMPWG request.
Yes
 
Group
PNGC Power
Margaret Ryan
PNGC Power
No
It is still unclear whether relays that respond to mechanical inputs, such as sudden pressure relays, are included in the proposed definition as protective relays. While PRC-005-2 R1 limits the scope of that particular standard to protection systems that sense electrical quantities, it is remains unclear in other standards that use the defined term whether mechanical input protections are included. We suggest that “Protective Relay” also be defined, and that the definition clearly exclude devices that respond to mechanical inputs in line with the NERC interpretation of PRC-005-1 in response to the CMPWG request.
Yes
 
Group
Southern Company Transmission
JT Wood
Southern Company
Yes
We agree that the definition provides clarity and will enhance the reliability of the Protection Systems to which it is applicable. However, we feel that there needs to be a direct linkage of the definition’s effective date to the approval and implementation schedule of PRC-005-2. Since this new definition is directly linked to the proposed revised standard, it would be premature to make this definition effective prior to the effective date of the new standard.
No
The revised definition should not be made effective until the revised PRC-005-2 is in effect. There is no definite reliability benefit to balloting this definition prior to the revised standard. If balloted and approved, entities would definitely have to modify their Protection System Maintenance and Testing Program methodology, but there is no obligation to or guarantee of any additional maintenance being performed. PRC-005-2 includes this definition, the maintenance activities, and the intervals that will ensure execution of the maintenance and testing.
Individual
Lauri Dayton
Grant County PUD
No
1) We note that the definition of a “Protection System” has been expanded to include the trip coils and what used to be confined to batteries has now been expanded to “station DC supply.” “Trip coils” is an improvement. Inasmuch as the mark-up changing “DC” to “dc” is intended to communicate a more general term as opposed to a strict definition, it leaves room for differing opinions among auditors as to what all should be included. We support the change to exclude battery chargers since the rationale for their inclusion was never clear. The battery itself will be, without exception, the “first responder” to provide DC power to a Protection System. However, battery chargers have not been excluded under the FAQs. 2) The SPCTF’s effort to define applicability in terms of “Facilities” is confusing. Additionally, it is unclear how the terms “component,” “element” and “Facility” are intended to relate to one another. An assumption may be that one or more components (which are physical assets) can comprise an “element,” one or more of which can be associated with an identifiable function, aligning with the five Protection System Equipment Categories, found in SPCTF’s “PROTECTION SYSTEM MAINTENANCE—A Technical Reference, dated Sept. 13, 2007, and that “Facility” is as used in 4.2.1 of the Standard Development Roadmap, dated May 27, 2010. Please provide guidance on the terms relate to one another. 3) The structure of the proposed standard is less clear than the existing standard PRC-005-1 because of the potential for ambiguity between the definition of Protection System and how the term “Facilities” is applied. A suggested resolution would be to revise the definition of Protection System to resolve this ambiguity or to delete reference to 86 lockouts and auxiliary relays in the description of “Facilities.” If the 86 lockout relays are to be included, they should be added as part of the DC Control Circuitry “element” (as found in the NERC Glossary) of the circuit that energizes the 86 relay, thus placing it within the definition of a “Protection System.”—once—and therefore in a manner that would require only one scheduled maintenance to be performed if the testing schemes are properly set up. We do agree, however, that sudden pressure relays, reclosing relays, and other non fault detecting relays such as loss of cooling relays should not be referenced as part of the “dc control circuitry” Element.
No
There needs to be more clarity concerning the role of the 3 year audit during the implementation phase. Do the audit tests consist of varying proportions of -1 criteria and -2 criteria?
Individual
Fred Shelby
MEAG Power
Yes
 
Yes
 
Individual
James A. Ziebarth
Y-W Electric Association, Inc
No
The application of this definition to Reliability Standards NUC-001-2, PER-005-1, PRC-001-1, and PRC-004-1 results in confusion as to whether relays with mechanical inputs are included or excluded from this definition. PRC-005-2_R1 contains language limiting its applicability to relays operating on electrical inputs only, but the remaining standards that rely on this definition are not so specific. This being the case, it would make much more sense to clearly define what devices are actually meant in the glossary definition rather than leaving it up to each individual standard to do so.
Yes
 
Individual
Armin Klusman
CenterPoint Energy
No
CenterPoint Energy believes the proposed definition of “Protection System” is technically incorrect. The present definition does not include trip coils of interrupting devices, such as circuit breakers; and correctly so, as trip coils are components of the interrupting device. A Protection System has correctly performed its function if it provides tripping voltage up to the circuit breaker trip coil. From that point, the circuit breaker can fail to timely interrupt fault current due to several factors, such as a binding mechanism that affects breaker clearing time, a broken pull rod, a bad insulating medium, or bad trip coils. Local breaker failure protection, or remote backup protection, is installed to address the various possible causes of circuit breaker failure. For correctness, the definition of “Protection System” should be “Protective relays, communication systems necessary for correct operation of protective functions, voltage and current sensing inputs to protective relays and associated circuitry from the voltage and current sensing devices, station dc supply, and control circuitry associated with protective functions from the station dc supply UP TO THE TERMINALS OF the trip coil(s) of the circuit breakers or other interrupting devices.”
 
Individual
Andrew Z.Pusztai
American Transmission Company
Yes
 
No
ATC does not agree to the implementation plan proposed. While it makes common sense to proceed with R1 prior to proceeding with implementing R2, R3, and R4, the timeline to be compliant for R1 is too short. It will take a considerable amount of resources to migrate the maintenance plan from today’s standard to the new standard in phase one. ATC recommends that time to develop and update the revised program be increased to at least one year followed by a transition time for the entity to collect all the necessary field data for the protection system within its first full cycle of testing. (In ATC’s case would be 6 years) To address phase two, ATC believes human and technological resources will be overburdened to implement this revised standard as written. The transition to implementing the new program will take another full testing cycle once the program has been updated. Increased documentation and obtaining additional resources to accomplish this will be challenging. Implementation of PRC-005-2 will impact ATC in the following manner: a. Increase costs: double existing maintenance costs. b. Since there will be a doubling of human interaction (or more), it is expected that failures due to human error will increase, possibly proportionately. c. Breaker maintenance may need to be aligned with protection scheme testing, which will always contain elements that are include in the non-monitored table for 6 yr testing. d. ATC is developing standards for redundant bus and transformer protection schemes. This would allow ATC to test the protection packages without taking the equipment out of service. Further if one system fails, there is full redundancy available. With the current version of PRC-005-2, ATC would need to take an outage to test the protection schemes for a transformer or a bus, there is not an incentive to install redundant schemes. ATC is working with a condition based breaker maintenance program. This program’s value would be greatly diminished under PRC-005-2 as currently written. Consideration also needs to be given for other NERC standards expected to be passed and in the implementation stage at the same time, such as the CIP standards.
Individual
Eric Ruskamp
Lincoln Electric System
No
LES believes the proposed definition of Protection System as written remains open to interpretation. LES offers the following Protection System definition for the SDT’s consideration: “Protection System” is defined as: A system that uses measurements of voltage, current, frequency and/or phase angle to determine anomalies and trips a portion of the BES and consists of 1) Protective relays, and associated auxiliary relays, that initiate trip signals to trip coils, 2) associated communications channels, 3) current and voltage transformers supplying protective relay inputs, 4) dc station supply, excluding battery chargers, and 5) dc control trip path circuitry to the trip coils of BES connected breakers, or equivalent interrupting device, and lockout relays.
Yes
 
Group
E.ON U.S.
Brent Inebrigtson
E.ON U.S.
Yes
 
No
The first phase is only 3 months (per Implementation Plan) to update the program, not the 6 months as listed in this question. E.ON U.S. recommends that it should be a minimum of 6 months, regardless.
Individual
Kasia Mihalchuk
Manitoba Hydro
Yes
 
No
The proposed implementation stage of 6 months is much too stringent and an 18 month window is suggested.
Individual
Edward Davis
Entergy Services
Yes
 
No
We agree with the definition, however we do not agree with the implementation plan. We believe implementation of the definition needs to coincide with the implementation of Standard PRC-005-2. To do otherwise, will cause entities to address equipment, documentation, work management process, and employee training changes needed for compliance twice within an unreasonably short timeframe. Additional time, 12 months minimum, will be needed to fully assess and address the necessary maintenance program documentation changes, maintenance system tool revisions, and personnel training needed to incorporate this new definition into our program.
Individual
James Sharpe
South Carolina Electric and Gas
Yes
The new definition effective date should be directly linked to the approval and implementation schedule of PRC-005-2 to avoid any possible compliance issues under the current PRC-005 standard.
Yes
 
Individual
Jon Kapitz
Xcel Energy
No
We recommend modifying the language to remove circuit breakers altogether: “…through the trip coil(s) of the circuit breakers or other interrupting devices.”
No
The implementation plans for both the definition and standard are confusing. Does this imply a "clean slate" approach can be used? i.e. do entities have up to the first interval window to complete the maintenanceor must they have it complete on day 1 of the standard and again by the first interval? It also appears that the implmentation plans are conflicting whereby one requires full compliance and the other allows 6 months...the definition implmeentation plan also refer to a basis document though the standard does not require one.
Group
Bonneville Power Administration
Denise Koehn
BPA, Transmission Reliability Program
Yes
 
Yes
 
Individual
Scott Kinney
Avista Corp
No
The modified definition of Protection System now refers to “functions” rather than “devices.” What are the “functions?” This new term adds confusion without being defined in the standard.
Yes
 
Individual
Amir Hammad
Constellation Power Generation
No
Constellation believes that this definition is to verbose, which can lead to unintended interpretations. Constellation is concerned with the term sensing inputs, which may infer that testing on instrument transformers must be completed while they are energized. This proves difficult at a generating facility where most testing is completed during planned outages when this equipment is not energized.
No
This does not match the implementation proposed for PRC-005-2. The implementation plan for revising the program is 6 months based on the “definition implementation” but R1 in PRC-005-2 has a 3 month implementation plan.
Individual
Jeff Nelson
Springfield Utility Board
Yes
 
Yes
 
Group
Western Area Power Administration
Brandy A. Dunn
Western Area Power Administration - Corporate Services Office
Yes
 
Yes
 
Group
WECC
Tom Schneider
Western Electricity Coordinating Council
Yes
 
Compliance agrees only if the original “Protection System” definition is in place for the interim implementation period, so that only the changes and or additions to the “Protection System” definition are covered under the proposed implementation plan.
Individual
Michael R. Lombardi
Northeast Utilities
Yes
 
No
The time provided for the first phase “at least six months” is too open ended and does not give entities a clear timeline. Northeast Utilities suggests 1 year for the first phase.
Group
Arizona Public Service Company
Jana Van Ness, Director Regulatory Compliance
Arizona Public Service Company
No
The change to the definition relative to the voltage and current sensing devices is too prescriptive. Methods of determining the integrity of the voltage and current inputs into the relays to ensure reliability of the devices should be up to the discretion of the utility.
Yes
 
Individual
John Bee
Exelon
Yes
 
No
PECO would like to have the implementation plan provide at least 1 year for full implementation of the new standard. This will provide adequate time for development of documentation, training for all personnel, and testing then implementation of the new process (es).
Individual
Barb Kedrowski
We Energies
Yes
 
No
Wisconsin Electric does not agree with the six-month implementation requirement in the first phase. It is our position that a longer adjustment time is needed for entities to update their maintenance programs to implement the new definition. The new definition results in a significant increase in the scope of affected equipment and the documentation required to implement the program, and requires additional resources beyond present levels, including hiring and training. We estimate that this effort will require three years to fully implement.
Group
FirstEnergy
Sam Ciccone
FirstEnergy Corp.
Yes
The definition is ready for ballot with the addition of auxiliary relays to the definition of protective relays. There is a potential for an entity to determine that auxiliary relays do not perform a protection function since they typically do not sense fault current. Furthermore, one could determine that the term "circuitry" only refers to the wiring to connect the various DC devices together. We suggest adding "auxiliary relays necessary for correct operation of protective devices" to improve clarity of the definition. With regard to the change from the current definition phrase "station batteries" to the new definitions phrase "station DC supply", it may not be clear to the reader that this includes battery chargers. To alleviate future interpretation issues, we suggest adding a clarifying statement at the end of the definition, such as "The station DC supply includes the battery, battery charger, and other DC components". The acronym "dc" should be capitalized.
Yes
 
Individual
Jianmei Chai
Consumers Energy Company
No
1. It is unclear whether “voltage and current sensing inputs” include the instrument transformer itself, or does it pertain to only the circuitry and input to the protective relays? 2. It is not clear what is included in the component, “station dc supply” without referring to other documents (the posted Supplementary Reference and/or FAQ) for clarification. The definition should be sufficiently detailed to be clear. 3. If Protection Systems trip via AC methods, are those systems, and the associated control circuitry included?
No
For entities that may not have included all elements reflected in the modified definition within their PRC-005-1 program, 6-months following regulatory approvals may not be sufficient to identify all relevant additional components, develop maintenance procedures, develop maintenance and testing intervals, develop a defendable technical basis for both the procedures and intervals, and train personnel on the newly implemented items. We propose that a 12-month schedule following regulatory approvals may be more practical.
Group
Santee Cooper
Terry L. Blackwell
SC Public Service Authority
Yes
We agree with the proposed definition. However, the effective date of this definition should be linked to the implementation schedule of PRC-005-2. This definition should not be made effective prior to the new standard.
No
The implementation plan should be linked to the approval of PRC-005-2. The definition should not be made effective prior to the new standard.
Individual
Art Buanno
ReliabilityFirst Corp.
Yes
The definition should probably include interrupting devices as the Protection System is of little value if the fault cannot be interrupted.
Yes
 
Group
Florida Municipal Power Agency
Frank Gaffney
Florida Municipal Power Agency
Yes
Because the definition changes the scope of what a protection system covers, increasing that scope, the definition should not be balloted separately from PRC-005-2 so that the industry knows what is being committed to. For instance, the circuitry connecting the voltage and current sensing devices to the relays is a scope expansion. station DC supply increases the scope to include the charger, etc. This scope increase needs to have an appropriate implementation period.
No
As stated in response to Question 1, it is inappropriate to change the definition o Protection System for PRC-005-1 and the new definition should wait for the new standard. In all honesty, the new PRC-005-2 lays out the program anyway, so, any change to the definition needs to be accompanied by a the commitment associated with that change.
Individual
Greg Rowland
Duke Energy
No
It is unclear whether the revised definition includes PTs and CTs, but it does include the wiring. We don’t see a way to list the wiring in R1.1 and provide supporting compliance evidence. We believe the phrase “and associated circuitry from the voltage and current sensing devices” should be struck from the definition.
No
Definition should be implemented concurrently with PRC-005-2.
Group
Public Service Enterprise Group ("PSEG Companies")
Kenneth D. Brown
Public Service Electric and Gas Company
No
Based on review of ballot pool comments there are still too many questions that should be resolved prior to submittal for ballot. It is suggested that a specific reference to the supplementary reference document figures 1 & 2 and the legend be added. That would further define the protection system components and scope boundary.
No
- The draft implementation plan general considerations have a requirement to identify all the protection system components addressed under PRC-005-1 and PRC-005-2 for potential audits while modifying the existing programs. The standard revision will require extensive reviews and possibly add significant amounts of components to the program. This is listed as a requirement without a specific deadline other than supplying the information as part of an audit. If an audit is scheduled or announced early in the implementation period the evidence is required. The requirement for identifying all the components in the implementation process should have a time specified with bases for the starting point. - Where additional definition of a protection system scope boundary is determined as a result of the standard revisions, the implementation plan completion requirement should be at the end of next maintenance interval of that added protection system component. There may be situations where additional scope as determined by the additions or revisions to the standard and/or supporting reference material (e.g., an auxiliary contact input in a tripping scheme) would require going back and taking equipment out of service to perform that one check. To keep the maintenance and outage schedules coordinated the new requirements should be at the end of current cycles, not beginning.
Group
The Detroit Edison Company
Daniel Herring
NERC Compliance
No
The definition should clarify whether current and voltage transformers themselves are included.
No
This implementation plan and the one for PRC-005-2 should be consistent.
Individual
Thad Ness
American Electric Power
No
The term "station" should either be defined or removed from the definition, as it implies transmission and distribution assets while the term "plant" is used to define generation assets. It would suffice to simply refer to the "DC Supply".
No
As written, the implementation plan only specifies a time frame for entities to update their documentation for PRC-005-1 and PRC-005-2 compliance. The implementation plan also needs to give entities a time frame to address any required changes to their documentation for other standards that use the term "Protection System", including but not limited to NUC-001-2, PER-005-1, PRC-001-1, etc.
Individual
Rex Roehl
Indeck Energy Services
No
It presumes that all relays in a plant are Protective Systems that affect BES reliability. As discussed at the FERC Technical Conference on Standards Development, the goal of the standards program is to avoid or prevent cascading outages--specifically not loss of load. The purpose of PRC-005-2 uses the term in its global sense but there is no subset of the Protection Systems that affect reliability. PRC-005 R1 requires identification of all components. With the broad definition proposed, and no separate term for only relays and other components that have been identified as affecting reliability, confusion results. If this term has its global meaning, then another term, such as Reliability Protection Systems, should be instituted to avoid confusion.
No
The definition should not be implemented separate from PRC-002-2. The PRC-002-2 implementation plan would be adequate.
Individual
Claudiu Cadar
GDS Associates
No
- The inserted wording “and associated circuitry from the voltage and current sensing devices” implies that the maintenance program will include the verification, monitoring, etc. of the wiring from the voltage/current sensing devices which requirement will be a bit excessive under current presentation of the standard. See comment on the standard as well. - SDT’s additional wording such as “from the station DC supply through the trip coil(s) of the circuit breakers or other interrupting devices” can be a bit of an issue as the coils could be good at time of verification and testing, but can fail right after or due to the testing. We recommend to change the Protection System definition to read “up to the trip coils(s)” instead the word “through”
 
Individual
Terry Bowman
Progress Energy Carolinas
No
See comment associated with question 2.
No
Progress Energy does not believe that the definition should be implemented separately from and prior to the implementation of PRC-005-2. We believe there should be a direct linkage between the definition’s effective date to the approval and implementation schedule of PRC-005-2. Since this new definition should be directly linked to the proposed revised standard, it would be premature to make this new definition effective prior to the effective date of the new standard. We believe that changes to the maintenance program should be driven by the revision of the PRC standard, not by the revision of a definition.
Group
Hydro One
Sasa Maljukan
Hydro One Networks, Inc.
No
Hydro One suggests adding “Protection System Components including” in the beginning. This is because the word “components” has been used extensively throughout the standard and there is no mention of what constitutes a protection system component in the standard. The word “component” does find mention in FAQs, however, it is recommended to mention it in the main standard. The revised definition should read as follows: Protective System Components including Protective relays, communication systems necessary for correct operation of protective functions, voltage and current sensing devices providing inputs to protective relays and associated circuitry from the voltage and current sensing devices, station dc supply, and control circuitry associated with protective functions from the station dc supply through the trip coil(s) of the circuit breakers or other interrupting devices. There is not enough clarity on whether a Distribution Provider (DP) will be able to clearly identify which all protection system components does it own and need to maintain. This is critical since NPCC had proposed a SAR to this effect which was not accepted by NERC citing that this concern will be incorporated in the revised standard. Also, reference should be made to Project 2009-17 in which Y-W Electric Association, Inc. (Y-WEA) and Tri-State Generation and Transmission Association, Inc. (Tri-State) requested an interpretation of the term "transmission Protection System" and specifically whether protection for a radially-connected transformer protection system energized from the BES is considered a transmission Protection System and is subject to these standards.
No
The time provided for the first phase “at least six months” is too open ended and does not give entities a clear timeline. HYDRO ONE suggests 1 year for the first phase. Also, HYDRO ONE suggests phasing out the second phase in stages.
Individual
Kirit Shah
Ameren
Yes
We agree that the definition provides clarity and will enhance the reliability of the Protection Systems to which it is applicable; however, we suggest that a Glossary term for Protective Relay be added in order to clarify in all standards inclusion of relays that measure voltage, current, frequency and/or phase angle to determine anomalies, as stated in PRC-005-2 R1. We believe there should be a direct linkage of the definition’s effective date to the approval and implementation schedule of PRC-005-2. Since this new definition is directly linked to the proposed revised standard, it would be premature to make this definition effective prior to the effective date of the new standard. We agree that the voltage and current inputs at the protective relays correctly identifies that component, that this excludes the instrument transformer itself. We suggest replacing "to" with "at", and omitting "and associated circuitry from the voltage and current sensing devices."
No
As noted above, the implementation plan should be linked to the approval of PRC-005-2. Since this new definition is directly linked to the proposed revised standard, it would be premature to make this definition effective prior to the effective date of the new standard. Otherwise, entities must address equipment, documentation, work management process, and employee training changes needed for compliance twice within an unreasonably short timeframe. If PRC-005-2 receives regulatory approval in 1st quarter 2011, PSMP implementation along with this revised definition should be effective at the beginning of 2012 to coincide with the calendar year. These nine months will be needed to fully assess and address the necessary maintenance program documentation changes, maintenance system tool revisions, and personnel training needed to incorporate this new definition into our program.
Group
Pepco Holdings, Inc. - Affiliates
Richard Kafka
Pepco Holdings, Inc.
No
It is still unclear whether relays that respond to mechanical inputs, such as sudden pressure relays, are included in the proposed definition as protective relays. While PRC-005-2 R1 limits the scope of that particular standard to protection systems that sense electrical quantities, it remains unclear in other standards that use the term “Protection System” (such as PRC-004) whether devices responding to mechanical inputs are included. As such, we suggest that the term “Protective Relay” also be defined, and that the definition clearly exclude devices that respond to mechanical inputs in line with the NERC interpretation of PRC-005-1 in response to the CMPWG request.
No
The 6 month time frame to update the revised maintenance and testing program is too short. Specifically identifying and documenting each component not presently individually identified in our maintenance databases, auxiliary relays, lock-out relays, etc. will require a major effort. We recommend at least one year.
Individual
Hugh Conley
Allegheny Power
Yes
 
Yes
 
Individual
Scott Berry
Indiana Municipal Power Agency
Yes
 
No
The second part of the implementation effective date does not make sense and might be wrong. The second part talks about implementing any addtional maintenance and testing (required in R2 of PRC-005-1- Transmission and Generation Protection system Maitenance and Testing); this is refering to version 1 of the standard and there should be no additional maintenance and testing added from version 1 of the standard, just version 2 which is the new version. Overall, the wording on this implementation plan needs to be made more clear about how the implementation plan will work.
Group
NERC Staff
Mallory Huggins
NERC
Yes
Still, to make sure the reference to dc supply is more generic than just “station dc supply,” NERC staff suggests the following modified definition of Protection System: "Protective relays, communication systems necessary for correct operation of protective functions, voltage and current sensing inputs to protective relays and associated circuitry from the voltage and current sensing devices, and any dc supply or control circuitry associated with the preceding devices."
Yes
 
Individual
Terry Habour
MidAmerican Energy Company
No
The definition is expanded and clarified in the language of PRC-005-2. These changes should be incorporated in the definition to insure it is used consistently in PRC-005 and any other standards where it appears. The following is a suggested revised definition: “Protection System” is defined as: A system that uses measurements of voltage, current, frequency and/or phase angle to determine anomalies and to trip a portion of the BES to provide protection for the BES and consists of 1) Protective relays for BES elements and, 2) Communications systems necessary for correct BES protection system operations and, 3) Current and voltage sensing devices supplying BES protective relay input and, 4) Station DC supply to BES protection systems excluding battery chargers, and 5) DC control trip paths to the trip coil(s) of the circuit breakers or other interrupting devices for BES elements.
No
The protection system definition implementation plan should be consistent with the implementation plan of PRC-005-2 R1. Actual maintenance requirements implementation should be as required by the PRC-005-2 implementation plan and should not be included in the implementation plan for the protection system definition.
Individual
Martin Bauer
US Bureau of Reclamation
Yes
 
No
The Time Horizons are too narrow for the implementation of the standard as written. The SDT appears to have not accounted for the data analysis associated with performance based systems. The data collection, analysis, and subsequent decisions associated development of a maintenance program and its justification do not occur overnight especially with larger utilities. In addition, this new standard will require complete rewrite of an entities internal maintenance programs. The internal processes associated with these vary based on the size of the entity and its organizational structure. Since this standard is so invasive into the internal decisions concerning maintenance, the standard should allow at least 18 months for entities to rewrite their internal maintenance programs to meet the program development requirements and 18 months to train the staff in the new program, incorporate the program into the entities compliance processes, and to implement the new program.